Eric Hagen - Vice President of Investor Relations 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 Chuck LaCouture - Vice President of Marketing J.

Douglas Lang - Vice President of Reservoir Engineering & Acquisitions Mark R. Williams - Senior Vice President of Exploration and Development

John Freeman - Raymond James & Associates, Inc., Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division David R.

Tameron - Wells Fargo Securities, LLC, Research Division Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division Biju Z.

Perincheril - Jefferies & Company, Inc., Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Hsulin Peng - Robert W.

Baird & Co. Incorporated, Research Division Jason A.

Wangler - Wunderlich Securities Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division

Thanks, Lacey. Good morning and welcome to Whiting Petroleum Corporation's Fourth Quarter and Full Year 2012 Earnings Conference Call.

On the call for Whiting this morning is the Whiting management team. During this call, we'll review our results for the fourth quarter of 2012 and then discuss the outlook for the first quarter and full year 2013.

The conference call is being recorded and will also be available on our website at www.whiting.com. To access the call and webcast, please click on the Investor Relations box and then click on the webcast link.

Please note the forward-looking statements disclaimer, discussion of non-GAAP measures and reserve and resource information on Slide 2. Also take note that our Form 10-K for the 12 months ended December 31, 2012, is expected to be filed later today.

Reconciliations of non-GAAP measures we refer to and 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.

Thanks, Eric, and good morning, everyone. We're pleased to report that 2012 was another record year for Whiting and our shareholders.

Whiting's production in the fourth quarter averaged 86,055 BOEs per day, a 22% increase over the fourth quarter of 2011 and a 4% increase over the third quarter of 2012. Production for 2012 averaged 82,540 BOEs per day, which represents another 22% increase over 2011's total production.

Adding back the 4,500 BOE per day that was conveyed to the Whiting USA Trust II in March 2012, our production in 2012 was up 28% over 2011. Whiting is currently a company projected to grow at a sustainable 14% and preparing to shift to a higher growth rate through monetization of some assets.

We see only an approximate 400 million 2013 outspend, which we can easily cover with our liquidity. Keep in mind that our borrowing base facility is a $2.5 billion facility with only $1.2 billion drawn against it at 12/31/2012, so $1.3 billion remains.

Further, the monetizations that we expect we'll cover, in our opinion, at least 2x the outspend. Moving to Slide 4, the largest contributor to our production growth has been our North Dakota operations.

This has led us to become the top oil producer in the state for the month of December. According to the December 2012 oil and gas production report published by the North Dakota State Industrial Commission, Whiting was the #1 oil producer in North Dakota at 66,156 barrels per day.

Those are true oil barrels, not BOEs. Now I'd like to talk about several wells that highlighted our fourth quarter.

We drilled another prolific well at our Tarpon prospect in McKenzie County, North Dakota. The Tarpon Federal 21-4-13H (sic) [21-4-3H] flowed 6,879 BOEs per day from the Middle Bakken formation.

This is the third best well drilled to date in the Williston Basin, the first being our Tarpon Federal 21-4H well with an initial production rate of 7,009 BOEs per day. Further, our Redtail prospect in the DJ Basin is emerging as another major resource play for us.

In the fourth quarter, we completed the Wild Horse 02-0214H in the Niobrara B formation, flowing 660 BOEs per day. This well was drilled on a 640-acre spacing unit, while most of our wells will be drilled on a 960-acre spacing unit.

Moving to Slide 5, we see a breakdown of our production by region. Please note that 73% of our total production is coming from our core Rocky Mountain region, and more than 60% is coming from the Bakken, Pronghorn Sand and Three Forks formations in the Williston Basin.

Moving to Slide 6, you'll see a summary of our year end 2012 proved reserves. 80% of our proved reserves are crude oil, 10% are NGLs and 10% are natural gas.

97% of our proved reserves are located in our Rocky Mountain Permian Basin and Mid-Continent region. Adding back the 10,000 of the 10,600,000 BOEs of proved reserves we conveyed to the Whiting USA Trust #II, our proved reserves were up 13% year-over-year.

81.5 million BOEs of proved reserves were added in 2012, organically through exploration and development of which 66.4 million BOEs were new Bakken and Three Forks reserve. Moving to Slide 7, we provide a breakdown of our proved, probable and possible reserves along with a corresponding PV10 value.

On Slide 8, we show our 2013 capital budget. As in 2012, the lion's share of our CapEx is expected to be directed to the Northern Rockies, specifically for drilling the Middle Bakken, Three Forks and Pronghorn Sand in the Williston Basin.

Slide 9 is a new slide that shows our drilling inventory as of December 31, 2012. Based on independent engineering and internal estimates, we project we have a total of 9,661 gross and 4,503 net potential future drilling locations.

These consist of 7,556 gross and 3,623 net primary locations identified in our reserve base and 2,105 gross and 880 net prospective locations supported by successful exploration drilling that's already occurred or extensive geoscience, primarily our evaluation of core in the area. The identified primary locations at the top of the slide represent future well locations in areas where we have extensively explored or developed, such as Sanish, Pronghorn, Hidden Bench and Redtail.

The lower half of the slide titled Identified Prospective Locations reflect areas where we plan higher density pilots and exploration to test new objectives. At our 2013 pace of 175 net wells annually, this equates to 18 years of drilling from only our Williston Basin and Central Rockies locations and 26 years of drilling, including our prospective locations.

Slide 10 provides a summary of the geoscience we have conducted to identify our prospective locations. As you can see, we put our in-house core lab to good use.

Core data has allowed us to validate our geological mapping and to better quantify the potential from new and existing objectives. Moving to Slide 11, we provide an overview of our plays in the Williston Basin, where we control more than 700,000 net acres.

We've broken out our acreage into 3 core areas: the Southern Williston Basin, which encompasses our Pronghorn and Lewis & Clark prospects; the Western Williston Basin, which includes Hidden Bench, Tarpon, Missouri Breaks and Cassandra; and our Sanish area, which also includes the Parshall field. Slide 12 shows that our primary development and prospective drilling plans by area in the Williston Basin, in addition to current development plans, identified as black well locations, it indicates high-density drilling potential as gray well locations, and new objectives as white.

Of note is a new prospective formation, the lower Bakken silt, which is primarily present at our Hidden Bench prospect. The lower Bakken silt is situated between the Middle Bakken and upper Three Forks.

We plan to bracket this formation with as many as 8 wells above and 7 wells below the lower Bakken silt. Moving to Slide 13, you'll see our Southern Williston prospect area.

Highlighting recent drilling results at our Pronghorn prospect was a completion of the MARSH 34-18PH well, which flowed at an initial rate of 2,340 BOEs per day from the Pronghorn Sand. The Marsh well was drilled in the eastern portion of the prospect in Stark County, North Dakota, which demonstrates that this area can compete with the Western part of the field, where most drilling has occurred to date.

We intend to conduct a higher density pilot program at Pronghorn. Our plan is to drill 6 Pronghorn Sand wells per 1,280-acre spacing unit, which is up from our initial plan of 3 wells per spacing unit.

Slide 14 shows our Western Williston Basin prospect area. At Tarpon, we have implemented pad drilling with plans to drill 3 wells off of each pad.

Of note, at Hidden Bench, was the completion of the Cherry State 21-16H. This well was completed in the Middle Bakken formation on December 19, 2012, flowing 2,810 BOEs per day.

The well was drilled in the southeastern portion of Hidden Bench. Slide 15 shows our Sanish Field and the Parshall field area, highlighting recent results at Sanish was the completion of the Fladeland 14-33H well, which was completed in the Middle Bakken formation, flowing 3,220 BOEs per day.

This wing well's 7,279-foot lateral was frac-ed in a total of 22 stages. The Sanish Field has the highest OOIP of any place in the Williston Basin.

Consequently, we plan to initiate a higher density pilot program. This could add an additional 3 Middle Bakken wells per spacing unit or 176 net wells.

We also plan to re-frac several wells at Sanish in 2013. Slide 16 refers to our Red River play.

At Big Island, we have identified more than 50 vertical Red River prospects using 3-D seismic. Our most recent completion at Big Island, the Katherine 33-23, flowed 593 BOEs per day from the Upper Red River "D" zone.

We plan a horizontal Red River "D" well in mid-2013. Our other Red River play is the Starbuck prospect.

They're currently shooting a 283-square-mile 3-D seismic shoot at Starbuck in order to identify seismic anomalies in the upper Red River "D" zone. This shoot was approximately 60% complete at the end of January.

We hold 104,000 gross and 92,000 net acres in the Starbuck prospect, which is located in Roosevelt County, Montana. On Slide 17, you can see the typical production profiles for the Middle Bakken, Pronghorn Sand and Three Forks formations.

Please note that, on average, EURs are in the 400,000 to 600,000 BOE range. This slide has been updated for information as of December 31, 2012.

Slide 18 shows that according to the North Dakota Industrial Commission, Whiting's average well drilled across the Williston Basin remains the most productive during the first 12 months of production of all operators in the basin. I'd like to point out that the majority of our wells in 2012 were drilled outside of our Sanish Field, and we continue to maintain this ranking.

As you can see on Slide 19, our 30-, 60- and 90-day average production rate from the Bakken, Pronghorn Sand and Three Forks in 2012 were 32%, 26% and 19% higher than in 2011. This is further supported by Slide 20.

As you can see from this slide, our 30-, 60- and 90-day rates in our new development areas of Pronghorn, Lewis & Clark and Hidden Bench, actually exceeded our average well in the Sanish Field in 2012. In other words, our productivity is increasing as we move into new areas.

Slide 21 shows that current takeaway capacity from the Williston Basin is more than 1 million barrels per day compared to current production of approximately 830,000 barrels per day. The recent increases in offtake capacity are largely due to additional rail.

We're currently moving about 30% of our oil production in the basin via rail. The excess capacity has led to much narrow differentials in the Williston Basin.

In the fourth quarter, our Bakken crew sold at a $4.70 per barrel differential to NYMEX oil prices. On Slide #22 and 23, we provide some facilities updates.

The Robinson Lake plant inlet gas rate increased to 67 million cubic feet of gas per day in the fourth quarter. At the Belfield Plant, the inlet gas rate increased to 18 million cubic feet of gas per day during the fourth quarter.

Jim Brown will highlight our exploration results outside of the Bakken and our 2 EUR projects.

Let's start on Slide 24 with our Redtail prospect in Weld County, Colorado where we target the Niobrara formation. This play is looking better every day.

We believe that EURs at Redtail will approach 300,000 BOE at a completed well cost between $4 million and $5.5 million. This 300,000 BOE EUR is consistent with other operators in the immediate area.

As you can tell by the map, our Redtail prospect appears to be in the sweet spot of the play. On Slide 25, we detail our development plan for Redtail.

We have submitted the plan to the Colorado Oil and Gas Commission to drill up to 8 wells in the Niobrara B and 4 wells in the A zone for 640-acre and 960-acre spacing unit. We currently have one rig, one drilling rig running at Redtail.

We plan to add a second rig around mid-year that will begin a high-density pad style drilling, and a third rig towards the end of the year. We plan to construct a new gas processing plant at our Redtail prospect.

Construction is expected to be completed in early 2014. The plant's planned inlet capacity is 15 million cubic feet of gas per day.

Slide 26 shows our Big Tex project located on the Eastern side of the Delaware Basin. We have established production from the Wolfcamp on the 3 corners of our acreage block and recently have experienced some encouraging results.

The May 2502H was completed late December as a horizontal Upper Wolfcamp well, flowing 674 barrels of oil per day. The well's peak 30-day average was 397 barrels of oil per day.

We own a 100% working interest and an 80% net revenue interest in the well. This well was completed utilizing a cemented liner and a plug and perv completion.

Now, I will turn to our EUR project. The Postle and North Ward Estes fields.

Combined, they represent 39% of Whiting's total proved reserves and 19% of our current production. Fourth quarter production from Postle and North Ward Estes totaled 16,350 BOE per day.

Net production from our North Ward Estes field averaged 8,540 BOE per day in the fourth quarter of 2012. One of the largest phases at North Ward Estes, Phase 3B, which has been on CO2 injections since late 2011, is beginning to see a production response.

Current production from the field is about 9,000 BOE per day. Mike Stevens, our CFO, will now discuss our financial results in the fourth quarter of 2012.

On Slide #30, you'll see our fourth quarter 2012 adjusted net income available to common shareholders was $97.9 million or $0.83 per diluted share. Our discretionary cash flow in the fourth quarter totaled a record $381.7 million.

This total represented a 16% increase over the $328.8 million in the fourth quarter of 2011 and an 11% increase over the third quarter 2012. On Slides #39 and 40, we show reconciliations to these non-GAAP measures.

Our guidance for the first quarter and full year 2013 is detailed on Slide #31. We've set our oral differential guidance lower than 2012 levels to reflect the recent narrowing of differentials in the Northern Rockies.

On Slide #32, our fourth quarter EBITDA margin remained consistent at 66% of our blended realized price per BOE. Slide #33 shows that we continue to maintain a strong balance sheet with total long-term debt of $1.8 billion and a debt-to-capitalization ratio of 34%.

Slide #34 shows that our 2 senior sub notes are trading above par. It also shows that we are well within all of the covenants in our credit agreement and bond indentures.

Slide #35 shows our crude oil hedge position, including the new 3 way oil collars that we put on for 2013. We are now 62% hedged on our oil production for the last 9 months of 2013.

On Slide #36, you'll see our strong fixed price gas contracts that continue to net us over $5 per MCF. I'll turn the call back over to Jim Volker.

In summary, in December 2012, Whiting was the #1 oil producer in North Dakota, which also happens to be the second-largest oil producing state in the nation. We are a high-margin oil company and our production is on track to grow, in our opinion, at least somewhere between 12% to 16% in 2013 and may grow at a more rapid rate after any monetization event.

We're encouraged by the continuing results at our Williston Basin and Redtail prospects, and estimate that we could have nearly 26 years of future drilling inventory across all our location. Operator, please open up the conference call for questions.

The first question I had, Jim, you alluded to the fact that any projected outspend you have, the asset monetizations would well more than offset that. Along those lines, if we could get maybe some update on where we stand on Postle?

Well what I can say now today, John, is that we're fielding strong interest. And that both from, I would say, the people who would like to buy, make an outright purchase there, people who want to -- us to continue to operate it for them, but where they would own a large interest in the property, perhaps 90% or so.

And of course, we continue to evaluate and have strong interest from a number of underwriters in a royalty trust there. So we're evaluating all of those.

We have a number of excellent opportunities that we can capitalize on there. I don't have anything to announce at this point.

I would say we're getting down to the decision point sometime in the near future. But the asset itself, I'd like to say, continues to outperform all of the original projections that we made for it.

And we love that asset. So if we're going to monetize it in some way, I can assure you we're going to get the great value there and that it's going to make a great asset for someone either that we sell it to, someone that we bring in as a partner or for investors through a royalty trust.

We certainly intend to make sure that, that asset is not owned by us. It's owned by somebody else who truly understands it, and we'll do very well with it.

It continues to be owned by us in part. After some sort of monetization, I can assure you that we'll continue to do the great job that we have with it so far.

Having more than doubled the production from when we acquired it.

Great. And then moving to Tarpon, obviously another huge well there.

And as you move to pad drilling, I'm wondering if you could give some color on -- in your 2013 budget of the wells that you've got for the Northern Rockies, what percentage or ballpark number on the wells you're expecting to drill at Tarpon this year in your budget?

Well, currently, I think, I'd refer you to Page 12. In our presentation there, you can see what's happened at Tarpon.

We're continuing to infill on what we've already recognized as opportunities there. That's a prolific reservoir.

We feel like we're doing an effective job drilling the Middle Bakken with 3 wells per spacing unit. We have 4 operated spacing units and we plan to essentially drill that out during 2013.

We also have opportunity in the Three Forks there, which we will be pursuing probably in the following year. What's really interesting at Tarpon is that we have identified well there, as well as Cassandra, another drilling opportunity.

We believe that the second bench of the Three Forks has received a good charge from the Bakken shale there, and we're seeing good saturations from core data that we've collected there at Tarpon. And so we think we've got an additional objective there to pursue, and that's probably going to be either late this year or 2014.

And we think we can get up to 3 wells per station unit in there. The thing to recognize about Tarpon is it's heavily fractured, that explains the high rates that we've got.

And so that's -- the well density there is somewhat less than some of the other areas that we're drilling.

I'm just looking at your inventory. In a way, the primary and prospective location is more than doubled what you had before.

Then I'm looking at your reserve, in a sense, resource base is up about 3% or so. What is the disconnect, and why the resource potential did not increase, almost doubled in a way?

Could you -- somebody explain it to me?

I can explain it to you, Jack. It's Eric Hagen.

I think you're comparing apples and oranges. I mean, our 3P numbers were fairly constant year-over-year.

And typically, within the 3P, we're just promoting reserves from possible into probable to proved. And then we're replenishing with what are actually termed resource location.

So the big increase really was in that resource category, which is largely reflected in the prospective locations we identified, and to some extent, in the primary locations.

Jack, to help clarify that, I would say that we don't have, in our current reserve base, the locations that you see there under the identified prospective locations. So we haven't added those in yet.

It's basically something that's occurred over the last 6 months of 2012, as we have seen the potential for everything that you see in the far right-hand column there. Meaning, 3 additional wells in the Upper Three Forks per 1280, 4 Bakken silt wells and 4 Bakken -- Middle Bakken wells per 1280, 4 Lower Three Forks per 1280, 3 Lower Three Forks per 1280.

So these are all additional locations that can be drilled as a result of the results that we've seen so far and the reservoir engineering that we've done and the core that we've taken. So those are basically new objectives, then we go into the higher density locations.

The Pronghorn Sand, higher density, that's 3 more additional Pronghorn Sand. The higher density at Sanish, that's 3 additional Middle Bakkens.

I was pleased to -- going to say, remind those friends that we have on the call here that, Sanish has the highest OOIP of any place in the Williston Basin. I hope you'll pardon me for sort of reminding everyone about that.

And that's why we have the ability to drill another 191 wells there. So it's a great opportunity, and we'll be adding those into our resource base here in the first half of 2013.

Okay. One more question for me.

Could you update us on the new venture area that you're involved in anything? When we might hear something more about what you are doing?

Well, we do have a couple of stealth plays. We're -- frankly, we've drilled a couple of tests, and we're encouraged by the results.

Some of our acreage money that you see in our budget is going into picking up more acreage in those 2 areas. And I would estimate that we'll have something definitive to tell you by the end of the second quarter when we've got some test results for you on at least -- some extended tests on at least one of those areas.

Can you talk about well cost per basin? And kind of what -- I know it varies from region to region, but as far as Bakken goes, what you had in '12, and then what you're targeting or budgeting for '13?

Well, I guess I'll let Jim Brown answer that. I'll begin by saying that we typically have a well cost there that, in comparison to the AFEs we see from other operators, it's about $2 million per well less.

So our average well cost there across the basin is running, which is outside the Sanish, where we have lower well costs. But outside of Sanish, it's running in the $8 million to $8.5 million range.

And typically, the $2 million save that we have there comes roughly from -- roughly $1.5 million that we save on the frac and roughly $0.5 million that we save on the drilling side. On the frac, it's basically -- we save that as a result of being able to do our fracs in one day using a sliding sleeve approach.

And then, of course, the efficient drilling operation that we have where we've worked very hard and long with the contractors to get not only the type of equipment, but the type of crews out there. Put them through the training so that they know what needs to be done literally on every 500 foot of hole between surface and our 20,000-foot TD.

10,000 feet deep, 10,000 feet horizontally, you know that. So that the drilling operation never stops, never slows down.

Supplies, parts, chemicals, repairs, everything is delivered in a timely manner, and that we're drilling with the right pit, the right weight on the bit and the right mud system in order to get that well to TD. As you know, we've drilled hundreds of wells in the basin now.

We think we have an excellent idea about what needs to be done in each one of our prospect areas. And frankly, we believe that there's still more efficiencies out there for us to work on.

And they come primarily on the drilling side and some on the completion side. So I think, both as a result of being more efficient, as well as a result of the supply of services improving, that we're going to continue to bring our costs down, and some even more efficient.

Jim, would you please supplement my answer?

Sure. Jim, you did a pretty good job of covering most of what we're working on.

But we do have one other initiative going on right now in the Williston Basin. We call that our build to POP, and the POP stands for put-on production, and it does a lot.

And we, across our operations and drilling guys, are working on this. They're the same team that worked on our DWOP program to decrease our actual drilling time.

We're trying to reduce our overall cycle time from when we first build the location till we get the well on production. And I can tell you, we're about halfway through this project right now, and we pulled about 23 days out of that cycle time.

So we're going to continue to push this project forward this summer into -- well, throughout the rest of the year. But what we're seeing is we're pulling about another $175,000 out of the costs of the Sanish well, which already, Sanish is on the low end.

We think we're getting about $0.5 million out of the cost of our Pronghorn well, and we're just going to expand this program across all of our operations. So not only are we saving cost, but we're getting these wells on production much quicker than we have in the past.

And on this note, Dave, just for your models, that we gave a breakdown by area of well cost, which as Jim Volker indicated, is on the low end. It's about $6.5 million in Sanish and on the high end, it's about $8.5 million in our Hidden Bench areas where it's deeper and hotter and we have to use ceramics and stronger materials.

And this year, our budget is for -- it's around $7.7 million, so about $8 million a well, if you divide our CapEx divided by net wells, which is pretty consistent with what we've been running the past few quarters.

Okay, all that color was very helpful. And Jim Volker, since you went there, let me ask a question to you.

You said AFEs that others are submitting look like they're higher than yours. Is that -- how is it in a time of rising price environment, AFEs go up, et cetera?

When you're doing experiments or exploration, AFEs come in higher, but in the development area, are you seeing cost overruns on AFEs? Or are you just seeing AFEs, initial AFEs submitted at 10 versus 8?

Well, my comment was -- Dave, was primarily directed to the fact that when the AFE comes in, it's higher.

Okay, okay. That's helpful.

Rail -- or just takeaway capacity. And back to last, I guess, maybe third quarter, there was talk of potentially trying to -- or maybe agreements that were going to take oil to the coast, East Coast, in particular.

Now the differentials changed with the takeaway. Seems like the bargaining power, obviously was done up by year end, but can you talk a little bit about how you're thinking about that today?

And if you're still getting those same type of inquiries?

Yes, we are. I simply point to the fact here that is, we recently executed another fixed differential at around $5 to move crude over to the Philadelphia refining complex.

And so we've done that with the people who own it and the financial intermediary there who helped them with their financing. And so, it's worked out well for us, I see continued strong interest there.

Essentially as the Bakken crude replaces the imported Brent quality crude that came in there, and that continues to narrow our pricing differential.

I want to add, Dave, it's just that our -- a lot of other operators have talked about having flexibility between moving their crude by rail or pipeline. And we certainly have that in our Pronghorn area.

And Chuck, if you could help me with what the 2 rail facilities that are...

Bakken Oil Express and BakkenLink.

So Bakken Oil Express and BakkenLink are basically right next to our new Belfield oil terminal. So we have a lot of flexibility to get into rail right there.

We're moving about 30% by rail.

Okay, good. I've got 3 or 4 more questions, but let me just ask one.

The PV10 up 3% after-tax year-over-year, can you guys comment on that a little bit? I want to [indiscernible] I would have expected it up a little higher than that.

Dave, oil prices were down a few bucks. And also, we had a revision on the GAAP side about 70 Bcf, about 10 million BOE equivalent.

And I think that was accounted for the main reason why it didn't go up as much. Doug, any thoughts on that?

No. I would just -- I guess, just to remind everybody, I'm sure -- remember that, Dave and other callers or other listeners on the call today, is that the SPEs, Society of Petroleum Engineers has published a QRM [ph] management guidelines for reserved estimates and bookings.

And also, of course, the SEC has their own requirements for reserved booking. And essentially, what that requires us to do and what our, in-effect, consultant has to do is to have high confidence that any of our proved reserve estimates will be more likely to increase than decrease.

So obviously, you have to evaluate that as you book reserves. Some are new in particular, other high reserves we booked.

They're in newer areas, so just because of the lack of more production history on the PDP wells in that area, we have to be more conservative. So as our reserve categories are always a changing mix of different categories of wells and so forth.

But clearly, as we book new reserves in our POP category, and even the proved developed reserves that we're assigning reserves to in the newer prospect areas, we have to be more cautious and, I guess, conservative in our bookings. So we're real cautious of that, and I know we're criticized for being conservative sometimes, but that's the way we run our business, and it may have some effect to what you're talking about there.

It looks to me like in the third quarter, we might have been seeing some signs that Sanish Field, the production there looked like it was maybe starting to plateau. So I was a little surprised to see it growing again in the fourth quarter.

I know you don't want to give guidance on a field-by-field basis, but it's obviously your biggest field. So I'm just wondering what you expect from Sanish this year?

Do you think it's being close to a...

I don't think we want to give -- we don't want to give a guidance field by field, Mike. I mean, we're a big company.

We're running 6 or so rigs out of 20 in Sanish. And we want people to focus on the overall results in the basin and in our field of company-wide Williston Basin production.

For -- this has been going on for over a year now. People have been saying Sanish is going to peak or decline, and every quarter it hasn't.

So I just don't think we want to get into that. Mike, we're forecasting every field.

But I will try to help you there, Mike, by saying look, as you can see on Page 6, we think there is another 190 wells to drill there. So we say we're pretty proud of Sanish.

And it's the field that keeps on giving, and it's the highest OOIP of any field in the Williston Basin. So we have without, I guess, let's say, answering your question directly, we do have high hopes for Sanish in 2013 and 2014.

And I think it'll be borne out as you see us do this higher density drilling that we talk about, both there and at Pronghorn. People are just starting, I think, to understand the true bounty of the Bakken and how long it's going to be there and how good it's going to be there.

I appreciate that, Jim. Switching over to the Niobrara.

You've showed 1,200 drilling locations there. You've really just reported on a handful of wells.

I guess, can you talk about what's giving you the confidence in making those assumptions that you'll have 1,200 locations?

Mark Williams has been revving his engine in preparation for answering that question. So if you don't mind, I'll turn it over to him.

So the Niobrara has -- we look at right now as Whiting being in the transition from an exploration program into a development program. What we've really seen is this is driven by a lot by the rockwork that we've done there.

The oil in place in that reservoir is tremendous, and it's up over 35 million barrels per section and the...

It is above twice the Bakken.

Correct. And so the challenge for us and all the operators in Niobrara is the Niobrara B zone in particular, and the A for that matter is a chuck.

What that really means is it's got a lot of porosity, 12%, 13% porosity. But the porosity basis are extremely small.

So the challenge is to figure out how to get all of that oil out of relatively tight rock. And what we've done is we've sort of taken a three-pronged approach there.

One of them is, we believe that by drilling on tighter density that we can fracture more of the rock than we can by single wells alone. In other words, we get the effect of what we call synergistic frac-ing there.

So prong one is to essentially drill that well on 8 wells per spacing unit rather than the 4, with the idea that we can get the effect of frac-ing this, kind of essentially shattered the reservoir throughout our spacing unit. The second one, as we've seen a very strong correlation between higher frac sizes, higher frac volumes, I should say, and a better performance.

So that's the other thing. And we started to see very good consistency in our results with that.

We've got 4 wells now that are up over 500 barrel a day wells. And so we're shifting.

We're adding on a second rig that's going to be doing development drilling. And with the idea of going right to -- taking some of the learnings that Jim Brown just talked about from our Bakken program and applying them right from the get-go in our Redtail development program.

So we're going to be doing, focusing on 4 pads starting in April and May of this year with the second rig. We'll probably add on a third rig towards the end of August, and we're just very encouraged by the results.

You could also look at Noble's results immediately to the south, that they're seeing similar results in their East Pony unit. And we just think we've hit the sweet spot in the basin and we're going to start developing it.

Yes. Since Mark's already mentioned it.

I'll expand on it a little bit. I mean, one of the great things that's happening here is that we're learning from watching offset operators.

The one that Mark mentioned has announced an over 90-well drilling program there, but essentially has inter-fingered with our acreage position. And they're planning to do at least as many, if not more, wells than we are.

I'd call your attention again to Page 6 of the news release. And the far right-hand column there where we talk about 8 wells in the Niobrara B, and up to 4 wells in the Niobrara A has potential as well.

Another operator has actually filed a permit that will allow them to drill an even greater number of wells within a drilling spacing unit, as long as they meet the normal state setbacks. So it may be that, in some cases, people will end up drilling perhaps 10, perhaps 12, maybe even 14 or so wells per drilling spacing unit.

And again, as Mark said, it's because it's such a rich, that it's high OOIP formation with relatively tight permeability. So key seems to be getting in there and drilling it on close spacing, keeping your costs down, getting it with big fracs and really getting in there and perhaps drilling 2 or 3 wells and then frac-ing them all at the same time.

All of those things are things that our friendly competitors are doing, and that we're planning as well. We have very high hopes for that sweet spot of the Niobrara up there.

We've got in with a large and a moderate cost acreage position. And what I'd like to call, "Easy 8."

Meaning, 80% or better NRIs and a good portion of our acreage position out there. So all of those things are working for us, Mike.

Good. And it's just the A and the B zone at this point.

Codell is not really a prospective out there, is it?

We drilled one Codell well very early in our program. We got okay results, but it didn't look like it was worth developing at that point.

What we've seen across the basin, not in our area in particular, but other areas, is that Codell was very prolific, we see some or a lot properties where we are. But we recognize now, that if we're going to make the Codell work, we're going to have to put very large fracs on it.

Some of the other operators out there put fracs that are 3 and 4 times as large as the one that we did, this is 2.5 years ago, and so it's also quite tight, very much like the Niobrara. So we look at that as upside.

We have not yet captured that, but I think you'll see us drill a couple of Codell wells later this year and see what we can do with it.

Okay. And then just one last one for me on the Niobrara.

The well costs, I think, Jim Brown mentioned $4 million to $5.5 million, a pretty wide range. What are the differences on those book ends in terms of the assumptions for the wells?

The difference is our 640 spacing unit versus the 960 spacing unit. So that's the difference right there.

Jim, I appreciate how you laid out the drilling inventory and their prospective locations. Some interesting concepts you talked about in terms of -- based on core data.

Can you talk about what are the timing of testing some of those concepts, for example, the tighter spacing in Pronghorn or the lower Bakken silts and then bench some of those concepts?

Well, we have a number of people here who'd like to answer that in addition to me. So I guess I'll let Mark take off, then Jim will follow up.

Okay. So the kind of 2 things are going back to that Slide 12.

The potential high density infills. Those are the gray wells on there.

What that really is all about is the recognition that when you go through and do the oil in place calculations through most of the properties and looking at most of the operators in the basin, including ourselves, at the current density that we're drilling, we're getting about 10%, maybe as much as 11% or 12% recovery, of the oil in place. The question has always been we've drilled at these wells based on essentially no interference.

But the question in our minds here over the last several months and last year or so, and not just ourselves but other operators, is what happens? How do we increase that recovery efficiency?

And so the idea here is to drill a series of pilots, and we're going to be doing that in both Hidden Bench, Pronghorn, Sanish, possibly Missouri Breaks as well. But to go in and drill on higher densities, essentially doubling the density and the better reservoirs in there to demonstrate our ability to increase that recovery efficiency, get it up from 10% or 11% up to somewhere around 20%.

And what that means is breaking up more rock. And we don't believe that with the current spacing that we're on, that we're getting all of the oil that's out there.

So that's really what this is all about. We have these pilots, one in Hidden Bench, one in Pronghorn, 4 of them in our Sanish Field.

You saw them all labeled on the maps that we showed you here in the Investor Presentation, that we're going doing that here over the next several months. So especially Hidden Bench and Pronghorn, we'll get those things done probably by mid-year.

If those are successful, as we expect them to be, we'll be able to capitalize that, go into full development mode on this higher density spacing towards the latter part of the year and certainly into 2014.

Got it. So it'll be towards the end of the year, this year, that we'll get some production data from these pilots?

Yes, I'd say third quarter, we'll start to see the results of all of this. And then it's going to take a little bit of planning to go ahead and re-space a lot of this.

We're actually looking at the possibility of re-spacing Sanish right now. There's no reason not to do that.

And so at any rate, we're try to make sure that all of that happens as efficiently as possible. But I think as the terms of actually getting in the development mode, we're going to be talking about the latter part of this year or early next year before we can actually drill on that higher density.

Just to highlight something for you, Biju. When we look at Pages 13 through 15 there, you'll see little red-dashed squares.

Those are the actual locations where we're going to be doing these higher density pilot programs. And we go into some detail there as to exactly what we're doing within each spacing unit in order to do these pilots.

And as Mark says, yes, we'll have, I think, good results from those to talk to you about by the time we get to the third quarter.

Got it. And then in the Niobrara, have you completed any wells on the A zone?

And any results you can share there?

I'd say this about the Niobrara A. The reservoir properties are -- everybody's good as they are in the Niobrara B.

And actually the sweet spot for the Niobrara A is in our acreage position. If you look at it across the basin, we believe that we have the best Niobrara A across the basin.

The main challenge there is simply that the thicknesses is a little less than it is in the B. Actually, we're about half the thickness.

But we think as we go in into development mode, there's a good chance that we'll be able to develop the A as well. We have drilled 2 Niobrara A tests.

The results of those are encouraging. It's not as good as the Niobrara B yet, but we're still working on it, is what I'd say there.

And we think there is a good chance that we'll be able to add a significant amount of the A in. We're not counting in our development program right now, we're talking a little bit about that earlier.

We have about 350 wells that we're counting right now in this Phase 1 development area that we're going into development mode on right now. That's essentially all Niobrara B, but we have the -- we think there's a good chance we'll be adding some A into that as we get further into the year.

And just to expand on what Mark said, one of those A wells was it came out a little bit lower IP than our typical B well. But when you get out 60 days, it was actually producing it as good, if not at slightly better rates.

So we've seen pretty encouraging results rate-wise on that well as well.

Got it. And then one more question for me if I could.

On the well spacing you're talking about for in the B zone, can you talk about sort of, I guess, on some work you've done to determine the drainage pattern. I guess, what's the confidence level that you're not going to have interference at the very tight spacing you're talking about?

So there's really 2 things that we've done. One is -- Jim Brown could chime in on this as well, but we've done microseismic surveys there, both surface micro seismic, which gives us a feel for the area that we're affecting by our frac jobs.

We've also done vertical well micro seismic, which tells us what our frac height is. And so we've spent quite a bit of money on science on that trying to figure that out.

So that's one thing. The other thing we have done is extensive core analysis.

And so what that is a combination of those 2 things, really tells us that the area that we're affecting by our stimulations in the -- around our Niobrara B wells is very small. In the Bakken wells, we have sort of 700-foot frac wings.

In the Niobrara, we're probably talking about 200- to 300-foot frac wings, and that's probably at maximum. And the other thing is we don't think that all of the area around the wellbore that we're drilling is really getting a good stimulation.

So that leaves a relatively small area that actually has been frac-ed in the wells we drilled so far, to date. And so the plan by drilling higher density is really just to break up more of the rock.

That's the whole idea there.

Just to kind of summarize for you there, Biju, if you think about it as when we do a frac, there's the frac wing coming out in the arrowhead shaped manner, with the fatter part of the arrowhead obviously backflows to the wellbore. After studying that through the micro seismic, what we can tell now is that the proper spacing is 8 wells per spacing unit or essentially, 80-acre spacing.

And that, we believe, will not have any interference in any event. Some people, as I mentioned earlier, are contemplating even going down to perhaps 40-acre spacing.

I'd like to add just one more thing in there, if I could. The other thing is recovery efficiency.

When you start, we focused a lot on it here recently. When you look at the EURs of even our best wells in Redtail right now and you compare to the oil in place, we're looking at about 3.5% or 4% recovery efficiency, which is a very low number and tells us what our challenges is.

It's really to break up more of that reservoir rock, see if we can get it up to 10% or 15%, and that's the whole idea behind drilling these on very high density. We're hoping to get some synergistic effect by drilling these wells on very high density and simply break up more of the rock.

And if you look at our competitors, Noble has probably got -- Noble and Anadarko, I think, have got the most experience further over in Wattenberg, and they're drilling on extremely high density. Jim, do you want to?

[indiscernible] And we drilled 2 pilots. We drilled one pilot on 80-acre spacing with 2 B wells.

We drilled another one on an 80-acre spacing with an A and a B well. So we've got those, and that's also given us some confidence that we can go ahead and drill this on much tighter spacing.

Just one more follow-up on the Niobrara. I know a lot -- you all as well as other operators have de-risked a lot of the southern portion of the acreage.

Are you all assuming 100% of the acreage works? Or what gives you more confidence on the Northern side?

There's really 2 things to consider there. If you look at all of our acreage at Redtail, we have what we call a Phase 1 area and a Phase 2 area.

The Phase 1 area is where we've been drilling. And why is that?

The reason really is because that's where we have 3-D seismic data. We shot a 3-D survey a little over a year ago, and in this play, unlike a lot of resource plays, 3-D seismic is absolutely critical for geo-steering.

You've got to have that, mainly, it's because there's a lot of small faults that you've got to navigate around. And so that's where we focused our drilling so far.

We are currently in the process of shooting our Phase 2 area, probably get that survey back some time this summer. But this is up where we drilled our 2-mile well, but a very good well.

We haven't had a single 2-D line in there that allowed us to drill that well. But that area, we see as being as good as the Phase 1 area.

We simply don't have the ability to go in and develop it until we get the 3-D shot.

And the Phase 1 is about -- I think about 70% of our acreage mark is in that 60%, 70% roughly?

60%.

Yes. So that's kind of -- give you an idea.

Yes, that's helpful. And then going to the Sanish, you talk about potentially refrac-ing some of these wells.

One, have you all done this before or maybe some of your neighbors? And what are you all expecting the wells to kind of back to original rates?

Or what's the kind of thought there?

I think for re-frac-ing these wells, we're hoping to get a bump over what we've done right now. I don't think we're going to see the original rates at all, but it doesn't cost us that much to re-frac it.

Jim?

Yes. You have to remember, way back in the early days at Sanish, the first, I don't know, year or so, the wells we frac-ed up there, we only frac-ed with 10 stages, because that was the technology for sliding sleeves.

So we've got a lot of potential out there. So I mean, when you say back to original rate, I don't think that's out of the question.

I think that's something that we could see if we can get in here and frac these wells in a more efficient manner. That's what we're trying to tackle right now.

Okay, and then one final one. You talked about the Bakken realizations, just being -- I've asked about, I think, it was around $4 off of TI, what are you all seeing thus far in 2013?

About the same as before, but down than the low -- our company-wide differential in January was around $5. The Bakken was slightly better than that.

Regarding your monetization effort, I know you updated us on the Postle field, can you tell us if the joint venture or midstream monetization are still on the table? And if so, what -- any -- can you give us an update?

Well, again, we have strong interest in some of our prospect areas. I guess they're all liked by the people who are looking at potential joint venture with us.

I chuckle from time to time, simply because some people like 1 area or 2 or 3 areas and not others in it, and then somebody else comes in and they like the ones that the prior party didn't like. So a lot of it frankly has to do with who is looking and what their base of knowledge is.

So for example, we have some Permian players who really like Big Tex. We have some people who really like the Niobrara.

We have other people who like our Bakken and Red River plays. So again, we're still in the sorting-out phase with those people.

And some of them also like the opportunity to be involved with one of our monetizations so that they could get perhaps, both some proved developed producing reserves, as well as do some drilling with us. So I'm sorry, I can't tell you exactly what metric we're going to get per BOE or how much of a promote we're going to get.

But I can tell you that based upon the interest, I'm very happy with the across-the-board level of interest that we're seeing and I believe that it'll be excellent in the event that we -- when we do monetize one of those assets or bring in a joint venture partner, it'll help us in the sense that it'll help drive our -- for the promote, will drive our F&D per BOE down. And of course, I'm going to say thank you for asking this question because I think it shows that essentially our strategy here is, rather than to outspend our cash flow at 50% or 60% or 80%, as some of our friendly competitors are doing, ours is only going to be in the range of perhaps, as I said in my opening comments, perhaps only about $400 million, which is a relatively low percentage when we see our discretionary cash flow for the year.

It's somewhere around $1.8 billion. So I see that as a relatively strong strategy because it keeps us from taking the risks that some people have fallen prey to.

You need only look at what happened to the people who were strong on natural gas and pursued the growth at any cost, and now they're caught with debt that they've turned out and the value of the debt's not going down along with the value of their natural gas reserve. So in our opinion, not outspending our cash flow by more than about $400 million.

And then, I'm going to say, monetizing some assets that we -- that unlock value, that are not being, in our opinion, correctly valued within Whiting, like our EUR and like our -- and I have to say, I think the EUR would come a little sooner than would the monetization of our midstream business. But both of those unlock value for us and allow us then to switch gears that is, accelerate the pace of our drilling without putting ourselves in the position of a big overspend.

I'm leaving ourselves subject to risk in the event of a decline in oil prices, like there was a decline in natural gas prices. Frankly, I don't expect a decline in oil prices.

I believe that the world economy is coming back. And I think you need only to listen to sort of the headlines over the last couple of days here to see that, worldwide, things are getting stronger.

And I think that's going to be, that's going to bode well for oil pricing. But nevertheless, we haven't taken, we haven't subjected the company to those kinds of risks.

And I hope that there are people out there who understand, as I think you do, by virtue of the fact you're asking this question, that it's a better approach, it's a safer approach, it's a more well-reasoned approach, in my opinion, in going out and overspending, terming out a bunch of debt and then being subject to problems in the event that there is some sort of price decline out there. I think we're going to be able to accelerate growth, and at the same time, not subject ourselves to having to put on a lot of debt, term out a lot of debt.

And that, in my opinion, is a better way to build net asset value. It may be lumpy, but in my opinion, it's a safer approach.

Lumpy in the sense that you harvest those assets, that when you do monetize them, those tend to be lumpy monetizations, but they really can drive your growth for the next 2 or 3 years.

Right. So I agree with that.

The monetization could unlock value for you guys, hence the question. Though I do want to kind of get a better feel for it.

So in your current '13 guidance, do you -- are you assuming the -- like $400 million, given the $400 million of roughly $400 million of outspend, is that the proceeds that you are -- that's embedded in your guidance? So such that if you get north of that, because I think you mentioned 2x, potentially 2x outspend, I mean, you would have room to accelerate...

It's not in the -- the acceleration is not -- they're coming from the monetization, it's not in our guidance at this time. Not in our guidance.

Oh, not in guidance. Okay, got it.

Okay. And then I guess the follow-up question, just want -- I guess in previous quarter, the CapEx dollar amount was -- that was initially suggested.

Wasn't that lower than the $2.2 billion? And I know balance sheet's strong, you guys -- there's no extra funding there.

But I was just wondering if you can give us some more color as to what, I guess, the rationale behind the additional CapEx dollar? What are oil price, whatnot?

And also, where is the incremental CapEx dollar going to work to?

There's a lot of questions in there. I'll try to answer them.

The one thing I'd like to point out to you is that, if you look at our CapEx, there's about 35% of it that, right now, is not essentially drilling and completion related. So keep that in mind, in other words, if you look at Page 7 of the news release, that would include the $150 million, the $178 million, the $82 million, the $108 million and the $240 million, which is essentially oriented toward EOR, which is more of a plateau-type situation than a growth situation.

So try to keep that in mind. Try to keep in mind that the money that we think we're putting there, especially into land, for example, is going to expand the 2, I call them stealth plays, that we haven't discussed yet.

But where we've drilled a couple of test wells and we're encouraged with the results. so we're adding there to our acreage position.

You won't -- and those adds, I'm going to say, will be something that we will enjoy drilling on in late 2013, and essentially looking for growth from them in 2014 and beyond. In terms of getting you to think about our capital, just I think what we're doing here is we're being very honest with the market.

And we're saying, "Wait a minute, look at the spend rate in the fourth quarter. It's really a continuation of that rate."

I noticed some other companies are out there saying that they're going to cut back on their CapEx and yet grow. I think that's a challenge.

I think what we're doing here is saying, "Look, we're currently spending at about that rate." And frankly, we've just discussed, should we have some sort of monetization event, you could expect to see our CapEx in the second half of the year even go up a little more, but we haven't taken that into consideration in our guidance yet for production.

So hopefully, we're on the conservative side, just like we were last year. You may remember we came out of around 16%, 17% midpoint of guidance and we did over 22% year-over-year.

So this year, we're out with about 14% midpoint, and we hope to do the same thing again.

Just to be clear, Hsulin, when we initially mentioned $1.8 billion, we were running about 20 rigs, and we have talked about dropping 2 or 3 rigs out of the program to cut back to $1.8 billion. And now that we have seen strong interest in these assets and have visibility on the potential monetization.

We felt more confident just leaving our capital program constant, running about 20 rigs, which gets you to that. Well, this year it was $2.1 billion.

We're assuming a little bit higher next year, $2.2 billion, to be conservative. And then if we do get a big monetization, and Jim did suggest it could be as much as twice or more, our $400 million outspend, obviously, we would have sufficient capital if we wanted to, for example, drill a few more test wells at Big Tex, where we've had very good results on our latest well.

But basically, our CapEx spend right now, our trend, we think, is very defensible. It's in line, as Jim noted, with our fourth quarter.

And we think our guidance is conservative as was last year's initial guidance.

I just had one question. On Big Tex, how long do you think you're going to sit and evaluate before you look and bring in a rig back in?

Would it be a second quarter or even a second half event, or maybe even within the fourth quarter?

Second half.

Second half? And is there -- would there be, again, just a program which 1 or 2 rigs have come in and get a few more test wells and see what you have before maybe developing, starting maybe '14?

Yes. And Mark will elaborate.

So. The well that Jim alluded to, our May 2502, we've made several changes in our approach to completing these wells, as well as our drilling objectives, we moved our drilling objectives up there in the Wolfcamp, and we're directly targeting the source rock in the upper part of the Wolfcamp right now.

The combination of that, going to cemented liners at plug and perf completions has made a pretty significant difference in that well. We've got -- we believe that we can take that and apply that to other areas.

The flowback results from that well has been very positive. I mean, it looks, if I add, the test will be a game changer, frankly.

And so we've identified 2 additional locations where we'd like to try that. We're still in kind of the wait-and-watch mode right now.

I guess I'd like to encourage Jim to say second quarter rather second half on that, but I tend to get ahead of those things sometimes. But at any rate, we do think we've got a lot more running room on there on Big Tex.

I think we've seen some good positive results, as well as some of the offset that operators built to the south of us, and immediately to the northwest. So I think we're starting to unlock the Wolfcamp there.

Thank you, Mike.

Just a quick one on Missouri Breaks. First well there came on strong at over 1,300 BOE a day.

What's the read through here to the whole 66,000-acre position? Does this go a long way to derisking that position in your eyes?

And what do you think, how does this acreage ultimately pump versus what you have in your more Eastern Bakken acreage, or it's just too early to tell?

I'd say this about Missouri Breaks. Our focus there has -- during the past year, has been to define it geologically.

And to be perfectly blunt about it, a very far west edge of our Missouri Breaks acreage is sort of the limit of where the Bakken is productive. We understand that now.

And really, we've done a fair bit to sort of shore up our acreage position more on the eastern side, and then it actually picked up a lot of acreage going into the North Dakota side. That's the part we think is -- that we had good drilling results from and that, we believe, is going to work going forward.

So that's essentially what our focus is here going forward is to switch -- once we get our position HPP out there. And we still got some more work to do, drilling one well per space unit.

And a better part of that whole thing, just -- I'd say, somewhere around 3/4 of our acreage position. Then we'll see us going into development mode.

And I think as you see on our -- this slide that we have here, the development slide, I feel very confident that we're going to be able to drill 4 wells per spacing unit in the Middle Bakken there. And the results we've seen from core in the upper part of the Three Forks, especially here on the Eastern side, are also good.

And it gives us some encouragement that we'll be able to develop the Three Forks there as a separate reservoir. As you can see, the Lower Bakken shale is somewhat thin there.

We're probably overlapping a little bit when we frac those 2 zones, but breaking up more rock is better. And so at any rate, we're still sort of early in that play, and we got a lot of acreage there.

And you'll see us just essentially HPP-ing our acreage position though most of the year. We think it's really going to come on for us in terms of a big development play in 2014.

Thank you, operator. I'd like to thank all the Whiting employees and directors for a job well done in 2012, and for our fast start, 2013, and for the exciting plans that we have for 2013 and beyond into 2014.

Eric?

Mark Williams and I will be presenting at the Raymond James Investor Conference in Orlando, March 4th. And Jim Brown will be presenting at Howard Weil in New Orleans on March 18.

And then Jim Volker will present at the IPAA Conference in New York City on April 15. And we look forward to seeing you at these events.

And thanks for dialing in to the call.

And in closing, we want to thank all of you on the call, as always, for your new and continuing interest in Whiting Petroleum Corporation. We look forward to meeting with you again soon.

All the best.