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Whiting Petroleum (NYSE:WLL)

Q1 2012 Earnings Call

April 26, 2012 11:00 am ET

Executives

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

Analysts

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

Will Green - Stephens Inc., Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

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

Brian T. Velie - Capital One Southcoast, Inc., Research Division

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

Gray Peckham - Susquehanna Financial Group, LLLP, Research Division

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

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2012 Whiting Petroleum Corporation Earnings Conference Call. My name is Laura, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I'd now like to turn the conference over to your host for today, Eric Hagan, VP of Investor Relations. Please proceed.

Eric Hagen

Thanks, Laura. Good morning, and welcome to Whiting Petroleum Corporation's First Quarter 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 first quarter of 2012 and then discuss the outlook for the remainder of the year. This conference call is being recorded and will also be available 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 webcast link.

Please note the forward-looking statements disclaimer and discussion of non-GAAP measures on Slide #1. Please take note that our Form 10-Q for the 3 months ended March 31, 2012 is expected to be filed tomorrow. 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.

James J. Volker

Thanks, Eric. Good morning, everyone. Thanks for joining. Whiting is off to a great start this year, with first quarter production of 14% over the fourth quarter of 2011, which topped the high end of the guidance. Also, we were able to raise our full year production guidance despite the conveyance of 4,500 BOEs per day for the Whiting USA Trust II. We now project 17% to 22% growth over 2011 versus our prior forecast of 14% to 20%. In other words, due to our strong drilling results, we should more than replace the Trust volumes we sold in the first quarter. Also, we announced several notable exploration wells at our DJ Basin Niobrara and Permian Basin Wolfcamp plays and we're expanding our activity in those areas.

Now let's move to the slide. Slide #2 summarizes the current key statistics for Whiting. Please note the decline in long-term debt. The debt-to-total cap is now down to 28.5%. And also, please note the increase of production to 80,700 BOEs per day.

Slide #3 is a breakdown of our production by region. First quarter production having averaged, to be exact, 80,747 BOEs per day or again, a 14% increase versus the fourth quarter of 2011.

Slide #4 breaks down our proved reserves, which totaled 345 million BOEs. 86% of our reserves are oil and only 31% are proved undeveloped.

Slide #5 provides a breakdown of our proved reserves by region, and the associated PV10 value at SEC 2011 pricing. As you can see, our total proved PV10 value is $7.4 billion.

Slide #6, our probable and possible reserves and PV10 value. These are also based on independent engineering and we're one of the few companies that provide this information based on independent engineering. Our total probable and possible PV10 value is $3.1 billion. Therefore, our 3P PV10 value is $10.5 billion.

Slide #7 provides Whiting's internal estimate of the resource potential beyond the 3P category. This totals 479 million BOEs for the PV10 value of $4.7 billion.

Our Slide 8 shows how we break out by region the 3P and resource drilling locations that underpin our reserve and resource estimates. Focusing on our Williston Basin area for a moment, we have over 2,500 drilling locations which represents over 10 years of inventory at our current pace.

Moving to Slide 9, you can see our revised 2012 CapEx budget. We've increased our 2012 budget to $1.8 billion from $1.6 billion. Of the incremental $200 million of capital expenditures, $91 million is expected to be invested in non-operated drilling, $37 million is directed to expand drilling in our Big Tex area in the Permian Basin, $36 million is allocated to increase activity in our Redtail Niobrara prospect in the DJ Basin, $27 million is allocated to increase leasehold and $9 million to facility. This revised budget reflects the high pace of activity in the Williston Basin as demonstrated in our strong first quarter production growth and our recent exploration successes in new areas.

On Slide 10, we provide an overview of our Williston Basin plays. We control 701,751 net acres in the play, an increase of more than 20,000 net acres versus our year-end update. The line on this map ties for the cross-section on the next slide.

The Slide 11 cross-section shows the reservoirs we target in each of our Williston Basin plays. At Lewis & Clark and Pronghorn, we target the Pronghorn Sand and upper Three Forks horizon, which we can tap with 1 wellbore. In Hidden Bench, Tarpon, Missouri Breaks and Starbuck, we have dual targets in the Middle Bakken and upper Three Forks formations. We plan to test our first lower Three Forks well at our Hidden Bench area in May.

Slides 12 and 13 give our Sanish Bakken and Three Forks type curves, which are our independent reserve engineers prepared from our year-end reserve report.

On Slide 14, our 2 typical production profiles for non-Sanish field Bakken or Pronghorn Sand Three Forks wells. The production profile EURs range from 600,000 BOEs to 350,000 BOEs, which we believe reflect the range of our Lewis & Clark, Pronghorn, Hidden Bench, Tarpon and Cassandra prospect wells. Average well cost is currently estimated at $7 million. As you can see, these wells have excellent economics at current oil price.

Slide 15 provides a comparison of our 2011 results to our new Pronghorn area at our Sanish -- to our Sanish Bakken results. So here, again, we're comparing Pronghorn to our Sanish Bakken. As you can see, Pronghorn delivered results very similar to the Bakken in terms of productivity. And again, we express our thanks to our technical staff for finding the sweet spots in the Bakken Three Forks hydrocarbon system.

Slide 16 shows that Whiting continues to lead the pack in terms of cumulative production during the first 6 months from all Bakken and Three Forks wells drilled in North Dakota. Our average 6-month production is 4,000 barrels BOEs higher than the second ranked operator and over 27,000 BOEs better than the average of the next 25 operators.

Please note on Slide 17, the 412,000 barrels per day of planned expansion for the Williston Basin for the balance of 2012. This should bring total takeaway capacity to over 1 million barrels per day by year-end 2012, and go a long way toward relieving the high differentials we experienced in the first quarter of 2012.

In summary, the multiple discoveries we made in 2011 in our Western Williston Basin areas are now moving into the development mode, which is driving production growth above our initial expectations. In addition, we're also experiencing growing success in our emerging plays outside the Bakken.

To present our exploration results outside the Bakken and discuss our EOR projects, I'll introduce Jim Brown, Whiting's President and Chief Operating Officer.

James T. Brown

Let's start on Slide 18 with our Big Tex prospect. We are encouraged with our recent results at Big Tex. We tested our first horizontal Wolfcamp well to the Big Tex North 301H at 440 BOE per day on March 17. Subsequent to the initial test, production from the well has remained over 400 BOE per day. We also completed our first vertical Wolfcamp well. We IP-ed the Stewart 101 at 232 BOE per day from the Wolfcamp. We have increased our planned 2012 capital spending and drilling activity at Big Tex to a 17-well program from a 13-well program. These wells will be a mixture of vertical Wolfcamp and Wolfbone wells, horizontal Wolfcamp well and horizontal Bone Spring wells.

Slide 19 shows our Redtail prospect in Weld County, Colorado where we target the Niobrara formation. We're encouraged by our recent completions at Redtail. The WildHorse 16-42H produced at a daily rate of 430 BOEs from the Niobrara B zone. Approximately 2 miles northeast of the WildHorse 16-42H, the Wolf 35-2623H was completed with an additional -- excuse me, initial production rate of 426 BOE per day. Due to these favorable drilling results, we plan to increase our drilling activity at Redtail in the second half of 2012. Our previous 8-well drilling program has been increased to 17 wells.

Now I'd like to turn over to our 2 EOR projects, the Postle and North Ward Estes fields. Combined, they represent 39% of Whiting's total proved reserves and 21% of our current production. First quarter production from Postle and North Ward Estes totaled 17,135 BOE per day. On Slide 21, you can see the production forecast from the proved, probable and possible reserves at North Ward Estes. During the first quarter, the field averaged 8,830 BOE per day or 9% higher than its first quarter 2011 average rate of 8,120 BOE per day. Our first quarter 2012 -- excuse me, I skipped a page.

On Slide 22, Slide #22 details the development phases for our North Ward Estes field. We still have 116 million BOEs of probable and possible reserves to capture, primarily between now and 2016. In addition to this, we have 148 million BOE of potential reserve at our Ross project, where we initiated our pilot this quarter.

Slide 23 details the capital forecast associated with capturing these reserves.

Now I'd like to turn the call over to Mike Stevens, our CFO, to discuss our financial results in the first quarter of 2012 and our guidance for the second quarter and full year of 2012.

Michael J. Stevens

Our first quarter 2012 adjusted net income available to common shareholders was $122 million or $1.03 per diluted share. Our discretionary cash flow in the first quarter totaled a record $351.9 million. This compared to the first quarter 2011 adjusted net income available to common shareholders of $99.7 million or $0.84 per diluted share and discretionary cash flow of $284.1 million. On Slides #33 and #34, we show reconciliations to these non-GAAP measures.

Our guidance for the second quarter and full year 2012 is detailed on Slide #25. The main changes are that we've increased our production guidance in spite of the Trust sale to account for our strong start for the year. We now forecast second quarter production of 76,925 to 81,320 BOEs per day. We've also adjusted our LOE per BOE downward to account for the Trust sale. We have increased our differential forecast as high differentials continued into April and then contracted in May.

Slide #26 shows that we continue to deliver some of the best cash margins in the business, $49.19 per BOE in the first quarter of 2012.

Slide #27 shows that we have delivered steady double-digit production growth.

On Slide #28, you can see we continued to maintain a strong balance sheet with total long-term debt of $1.24 billion and we have improved our total debt-to-total capitalization ratio to 28.5%.

Slide #29 shows that our 2 senior sub notes are trading above par. It also shows that we're well within all the covenants in our credit agreement and our bond indentures.

You'll see our current hedge position on Slide #30. We are 45% hedged on our oil production for 2012 with collars at average $67 floors and $109 ceiling.

With the recent slide in natural gas prices, I wanted to highlight Slide #31 to show our fixed-price marketing contracts for natural gas. In 2012, we have about 20% of our natural gas under contract at wellhead price in excess of $5.40 per Mcf.

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

James J. Volker

Great. Thanks, Mike. In summary, Whiting is a high-margin oil company. We forecast to grow our production 17% to 22% in 2012. We estimate we have over 10 years of future drilling inventory in our Williston Basin plays alone. Outside of the Williston, we're experiencing encouraging results in high potential plays like the Niobrara and the Permian Wolfcamp. With the completion of our trust offering, we've recharged our balance sheet and increased our capital spending to accelerate activity in these areas.

Operator, please open up the conference call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of John Freeman from Raymond James.

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

First question I have had to do with the differentials on the guidance going forward. I'm trying to get a sense of a few things that are baked into that. First, does it assume that the NGLs are a similar percentage of the oil volumes that there were in the first quarter? And then does it assume that the price for NGL is around the same kind of, call it, 50%, 51% of the oil price?

Michael J. Stevens

Our NGL volumes are going to go up slightly. We're at 10.6% of oil volumes. The first quarter will go to around 12%, that's really due to the Trust sale, we didn't sell many NGLs off with the Trust. Secondly, we are on 51%. A little depressed. We've, in my differential guidance, I put it up at 55% in the second quarter.

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

Okay, great. And then shifting gears. Last year, there was -- we had some discussions about looking at Starbuck as a JV and in recent conversations, it sounds like wanting to sort of expand possibly a JV to have Starbuck, Hidden Bench, maybe Missouri Breaks. And so just trying to get a sense is, is the plan you -- sort of you drill some more wells in this newer areas, namely Missouri Breaks, Hidden Bench and then to include all of them but you still think, if that's the route, you could have a JV done by the end of the year?

James J. Volker

Well, the short answer there, John, is yes. All the things you said there are true. Along the way, the obvious thing that would keep us from wanting to do a joint venture there would be even better results than we're currently experiencing, which may make us want to keep it all. And as you may be aware, on the Western side of the [indiscernible], there has been some encouraging results out there and we're going to drill our first well there, again, between now and year end. And so we're probably going to postpone, at least for the next couple of months, that decision while we drill a few more wells and complete a few more wells, for example, at Starbuck, as well as Hidden Bench.

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

Great. And then just last question for me, could you give me what the completed well cost was on that most recent Niobrara well?

Michael J. Stevens

Yes, we're -- currently, just the drilling portion of those, we're drilling for about just right under $2 million on the drilling. The completion is also running; it's about $2 million. So that well, the total completed well cost on that was about $4.3 million.

Operator

Your next question comes from the line of Will Green from Stephens.

Will Green - Stephens Inc., Research Division

I wonder if we could shift over to Big Tex for a minute and maybe talk about the recipe you guys used on that first horizontal Wolfcamp, was it gel or slick water? And then are you guys looking to lengthen the lateral or tighten the spacing at all from here?

James T. Brown

The first one we did was a hybrid track that we ran some slick water. And then as we increased our sand concentration, we went -- moved over into a cross-linked gel or kind of hybrid-type track. Yes to all your questions. That was a rather short lateral cross to single section. We are looking at lengthening our lateral, which we're doing on some wells that we're drilling right now, and we're also doing some analysis to figure out what the proper spacing is, how tight we can drill these.

Will Green - Stephens Inc., Research Division

Great. And then what were the costs on that first well action, if there was a little bit of science involved? So that's probably not a great number to use, but anything that leads you to believe that costs are not running at the $5 million level, or is that still a good number to use?

James T. Brown

That's still a good number to use. We were probably a little over that on this first well, but that's still our target number.

Will Green - Stephens Inc., Research Division

Great. And then just one other one on that, on that Big Tex 301. What kind of choke was that initial rate on? And are you guys artificially lifting it at all at this point?

James T. Brown

No, that well is still flowing. I just don’t happen to know what choke that one was on.

Operator

Your next question comes from the line of Neal Dingmann from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Say, Jim, first question, just on -- overall question, just on your hedging strategy going forward. Do you -- will you consider adding a bit more on the out years? Or just kind of what your general thoughts are right now as we sit at current oil levels?

James J. Volker

Well we would see ourselves, first, with respect to 2012, being between 50% and 55% by the time we get to the end of this particular quarter. And the answer would be yes, by the time we get to the end of the year, we would expect that 2013 would be approximately 50% hedged well.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then looking at obviously, the great results you talked about on that first record Three Forks well, I was wondering during that Sanish field, kind of that quarterly for you, is that -- what's the plan as far as the number of more Three Forks versus just that Middle Bakken wells?

James T. Brown

Just in Sanish, we have almost completed all of the Middle Bakken wells. I don’t remember the exact breakout. I think we've got something like 14 additional Bakken wells to drill up there, and the remainder of them will be Three Forks.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And then on the Three Forks, it seems like you continue to have a bit better cost than most of your peers around there. Do you see that going to -- kind of continuing going forward?

James J. Volker

Yes, we're not seeing any really strong upward trend on our costs and round numbers, $6 million at Sanish, $7 million completed well costs outside of Sanish.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then as far as -- just last question on the Wolfcamp area. Is that the kind of positive results that you just talked about on that 24-hour production rate? I assume going forward now after that type of result, you'll just do almost exclusively now horizontal on most of that acreage you have there?

James T. Brown

Well, there are actually 2 different plays, 2 different play types we're chasing out here. And on the area that we call Big Tex and moving up into an area we call Three, we are thinking that is best accessed with horizontal wellbores. Out in the farther west in an area that we call as the transition zone, we are still going to be proceeding drilling from vertical wells out there, just to see how good a producer we can get out of a vertical well. So we still have 2 different plays going on.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

And then as verticals yield, will you test some of the lower zones as well and go after that, or how will you go after the verticals?

James T. Brown

The verticals, we're targeting the Wolfcamp and then the very bottom part of the Bone Springs. So they're going to be -- we're going to have at least a limited amount of Wolfbone-type completion out there.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Perfect. Great results guys.

James J. Volker

You're welcome, Neal. And round numbers, $5 million for the horizontals in the Wolfcamp and roughly $3 million to $4 million for the vertical wells in the Wolfbone.

Operator

Your next question comes from the line of David Tameron from Wells Fargo.

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

Can you guys talk about what the production profile looks like at your EOR projects over the next couple of quarters, if North Ward, assuming that's ramped, can you just give us some sense?

James J. Volker

Well, we've got a slide in here that shows you how we intend to ramp up, not only, I'm going say short term but long term, and in general, it's on a general rise between now and the year about 2017 as we go from approximately 9,000 barrels a day up to a little better than 20,000 barrels a day, net.

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

Okay. And are you guys saying -- I know your CO2 is down to a level you've [ph] injected, even injected more. Where are you at as far as the amount of CO2 you want to be injected and when does that respond to really kick in?

James J. Volker

The good news is that we're getting full deliveries on both of our contracts, both the one at Postle and the one at North Ward Estes. There's some minor, roughly between 15 days and 20 days of maintenance on some lines and some compressors by the people who sell us gas at Postle, but they gave us plenty of warnings for that, so we will just wet up our wag during this particular quarter, and they'll be back with a temporary amount of maintenance that they're doing and it will be over in roughly 15 days, we think. So no real problems with respect to our CO2 deliveries. The volumes have been there, the pressures have been good, the quality of gas is great and we don't see any changes in that. And in general, we have enough CO2 that we can fulfill really all of our proved reserve needs at this time. And we're adding contracts. We've documented that in the past as to what we've done as we have executed additional contracts with Kinder Morgan and this summit plant that is very nearby our project. And so we're in good shape on CO2 as we move forward and execute really across all of the phases of the remaining phases at North Ward Estes. And of course, we're fully covered at Postle.

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

Okay, good. And last question for me, just going back to the guidance, the differentials or what kind of deck did you guys assume in your guidance, particularly on the oil side?

Michael J. Stevens

The deck we use to average right around $103 in 2012.

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

Okay. That's the right -- so the different guidance off that $1.03?

Michael J. Stevens

Correct.

Operator

The next question comes from the line of Brian Velie from Capital One Southcoast.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

All right, a couple of quick questions really on the -- first on the Montana side of the Williston. The Missouri Breaks acreage that you're looking to acquire right now, I know you're not releasing results for the wells that are being drilled out there. But can you add some color to what kind of competition you're seeing out there with so many people looking at oil?

James J. Volker

Well, I can say that we've been successful and we continue to be successful at adding acreage out in that area, and we're happy with the results. Roughly the -- most of the 20,000 acres that we added in this particular quarter, roughly 17,500 of that was right there at Missouri Breaks. So we're having good success. We're slugging it out there with some of the people. But in general, I would say the work that we've done on title leads us to the people that we need to go east, and we do have somewhat of a competitive advantage out there as a result of all of the title work that we've done, and that's really been helping us in terms of adding that 20,247 net acres during the quarter.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. Also the Chitwood well, first, you tested the lower bench. If that's successful, will that kind of open up additional locations for you guys above and beyond the 10-year inventory that you spoke about? And if so, can you give us kind of an idea of what kind of other potential that opens up for you?

James T. Brown

Yes, I mean, obviously, if that's a successful test, we'll have another zone to go after. Right now, we think it's pretty much -- could possibly be Hidden Bench, also over Missouri Breaks. So just the acreage position we have there, you could add 1 or 2 wells, at least 2 more wells for spacing unit across that acreage position.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

That's very helpful. And then finally, a few quarters ago I think it was, again in the presentation today, that 350,000 to 600,000 EUR range for as kind of generalization across the whole basin in the Williston. Is that something -- clearly, your beating production numbers there. Do you feel like you're seeing a tighter range and can you add any kind of, I guess, guidance in terms of whether that's -- whether you might kind of again increase that range on the bottom end?

James J. Volker

I think you'll probably see us look at that again when we get down to the end of this year. What we tried to do specifically with respect to Slide 15 is show you that the Pronghorn area is every bit as good as Sanish.

Operator

Your next question comes from the line of Mike Scialla from Stifel, Nicolaus.

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

Following up on the Pronghorn results. Well, actually it looks like you lowered your rig count, did I get that right in the overall Lewis & Clark Pronghorn area from 9 to 6? Any read through on that?

James T. Brown

Yes, what we're implementing at Pronghorn is pretty much -- we're going to be drilling all of our wells off pads there. We're going to be drilling either 2 or 3 wells off of the pad, just depending how the pattern works out. So a couple of things, we think we're going to see a benefit on the cost side of there -- of utilizing this. And we also think we're going to be able to drill more wells with fewer rigs because we're going to be eliminating all those rig move days out of there. So our goal is to get to the same endpoint with fewer rigs.

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

Okay. And then I don't know if the state production is correct, but it looks like January and February your volumes went down from December in the Lewis & Clark Pronghorn area, is that right? And if so, any reason for that?

James T. Brown

Well, I can't -- I mean, I have not looked at those numbers, but I can't envision any reason why they should have gone down.

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

I think -- that didn't seem correct.

James J. Volker

Yes, it must just be a slow reporting thing going on there.

James T. Brown

I have looked at those numbers and they think they're up for both of those months, so we can focus on that later. One thing Mike, as Jim pointed out, our pace of activity slowed there towards the end of the quarter and that's one reason why we didn't have as many incremental like Pronghorn results during March and whatnot.

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

Right, okay. You showed your results in Pronghorn look pretty similar to Sanish. How much acreage would you say you de-risked in Pronghorn now?

James J. Volker

Well once again, what we're doing there is we're in development mode at this point, drilling out the area that, as you can tell, we've previously described as de-risk. By the time we get to the end of this year, we'll update that slide again because we, by that time, will have drilled more wells near the extremities of those de-risk areas. And in the interim, other operators are drilling adjoining what we called our de-risk area and expanding the limits of what we would then term the de-risked area. So all I can tell you is that yes it is growing, but we don't feel like it's something that we ought to update every quarter. It's something that we think is appropriately updated about every year.

James T. Brown

If I could add to what Jim said as well, Mike, Jim and I looked just the Pronghorn de-risking this quarter and it's up, I think, about 8,000 or 9,000 acres. And we just feel adding that increment slide every quarter, I mean, when you look at the size of the prospect, it's over 100,000 acres. Really, it just makes sense to update it annually.

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

That's fine. I guess point being that it's bigger than Sanish and you've got something that looks similar.

James J. Volker

That's right. That's the point.

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

Looks pretty positive. Switch over to Missouri Breaks. When I'd look at some of your competitors drilling in that area, frankly doesn't look very good. You sound very encouraged by that area. Are you doing anything differently than what has been done before?

James J. Volker

Well, the answer is that we're seeing relatively low rates of decline on wells that come in with lower IP. So we're encouraged by the fact that the wells up there, I'm going to say, may be more consistent once they're right after completion and experience less of a steep rate of decline. On the other hand, of course, we won't get the flashy IP and perhaps as high a 30-day rate, of course. On the other hand, we do think it leads us to believe that something in the 300,000 BOE range, perhaps the 340,000 BOE range, maybe even a little higher in some cases, is going to be fairly typical there. As I might say, we think something around that higher end of the range, 340,000 or so would be fairly typical for Lewis & Clark.

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

Can you remind me of well costs in Missouri Breaks?

James J. Volker

Yes, roughly $7 million and we hope to bring that down over time.

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

Okay. And then last for me, looking at North Ward Estes, you showed the production growth year-over-year but sequentially, it looked pretty flat from fourth quarter to first quarter. Is that CO2 volume-related or is there any concern there that you didn't see growth sequentially?

James J. Volker

No, it just happens to be where we were in the execution of the plan. And from this point on, all of our results lead us to believe that there'll be a general increase every year annually. Year-over-year, there might be some flat quarters but in general, as we execute on our plan here, we expect that thing to pop out at over 20,000 BOEs per day, net to Whiting.

Operator

The next question comes from the line of Scott Hanold from RBC CM.

Scott Hanold - RBC Capital Markets, LLC, Research Division

A couple of questions on the Williston Basin. So how many rigs are you running? When I look at your schedule, that 19 rigs in the Northern Rockies, are those all in the Williston Basin?

James T. Brown

Yes.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And so what is sort of the plan and inventory going forward? I mean, when you look at sort of the Sanish Field, how long do you think you're going to be able to keep 9 rigs there and keep them active? Is that, you got another year to or less than that, or do you think there's more opportunity there? And if not, would those rigs go elsewhere?

James T. Brown

Correct, yes.

James J. Volker

First of all, the plan keeps us drilling there for another 2 years, almost 2.5 years.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, and then...

James T. Brown

7 rigs there, Scott, not -- we've added 7 rigs to your end.

James J. Volker

It's 7 at Sanish, 5 at Pronghorn. This is like as of the 20th of this month. It would be 7 at Sanish, 5 at Pronghorn, 1 at Lewis & Clark, 2 at Hidden Bench, 2 at Missouri Breaks and 1 in Starbuck. I hope that's helpful to you. That totals 18.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. No, that's great. And then I guess the plan would be depending on what happens in Missouri Breaks and over time those rigs in the Sanish Field would eventually find a place elsewhere in the Williston, is that kind of what you're thinking?

James J. Volker

Absolutely.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, good. And then in terms of like your gas and, I guess, oil infrastructure up like in around the Sanish Field, where are the thoughts of monetization opportunities around there? Do you guys still content on sort of owning your interest? Or could you monetize from your structure as you continue to sort of build that out in the Sanish, as well as other places in the Williston?

James J. Volker

So thanks for asking. The answer is yes. We do think it's a hidden asset. We would guess that by the time we get to the end of this year, that our interest in the Robinson Lake Gas Plant, for example, would be netting us approximately $3 million a month. That's to our 50% interest there. And so we would see that as being worth somewhere in the range of $350 million to $400 million, should we want to monetize that in some sort of a combination, sort of a trust with respect to the liquids value there, as well as the properties underlying or -- I don't mean the oil and gas properties but the equipment that's there. And we would like -- we think we could do that in some sort of a term trust that would encompass our ownership of that plant, at least our half ownership. But the same thing is true, it won't happen quite as fast, but I think the same thing is true. In fact, we have several people who want to become a participant with us in our plant that we built over near Belfield in the Pronghorn area. So there is monetization opportunities there and I really feel like across Whiting, especially with respect to, say, an asset like Postle that's roughly twice the size of the recent Trust that we did, we have over $1 billion worth of monetization out there that is, in my opinion, not adequately valued within Whiting.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, appreciate that color. And then down in the Permian Basin, you looked like you added a little bit of acreage here and there. How big you think you could extend that, or is it getting way too competitive around those parts?

James J. Volker

I would say that it's competitive around the acreage position that you currently see. I think we could pick up another 10,000 or 20,000 there as we infill around acreage positions that we already have. However, we're using our geoscience down there to find other comparably sized areas. And in general, when I say comparably sized, I typically think of something that is a needle mover here at Whiting has to be in 100,000-acre range. So we're looking for new opportunities in the Permian and we're looking at them to be approximately the size of Big Tex or larger.

Gray Peckham - Susquehanna Financial Group, LLLP, Research Division

Oh really? Okay good to know. And finally on the, I guess, the Ross project you have going on, around the CO2 areas, what can we expect other than -- I mean, how -- if this works, how much of a production lift could that provide to you all?

James J. Volker

Well the first thing that we would do, of course, is we would take the results of the pilot, study it, make sure that it sort of produces the kind of economic results that we expect there, which we believe will be attractive to say the least. And we should have that answer, I believe, by the time we get to the end of this year. But I wouldn't expect to see significant production out of that area or something like around the middle of next year or beyond.

Michael J. Stevens

Scott, it's 145 million barrel potential reserves, so you can compare that to what we're already producing down at North Ward and kind of...

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So you can you do some sort of an extrapolation based on the potential. Is that a fair statement for production?

Michael J. Stevens

That's about as good as you can get at this point.

Operator

Your next question comes from the line of Pearce Hammond from Simmons & Company.

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

In the past, you've talked about in the Redtail Niobrara, EUR's potentially in the range of sort of 200,000 to 250,000 BOE. I was just curious if these 2 most recent wells you feel like are kind of within that range?

James J. Volker

I would say at the higher end of that range.

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

And then based on the drilling complete cost that Jim had outlined before sort of $4.3 million, what sort of rates of return do you think you see here with your Redtail play?

James J. Volker

Generally 3:1 on our money.

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

And then moving to the guidance, just if I can get a little more clarification on the G&A guidance and then DD&A, just a little change upwards for both of those for full year 2012 relative to where we were before?

Michael J. Stevens

D&A is most impacted by the production plan and the net revenues that flow into that plan so with the higher production forecast, that's causing more money to flow into that plan and therefore, a little higher rate. And then with DD&A, that one's always very hard to explain because it's so complicated, successful effort company. Of course, it's a function of costs and reserves. Our main plays, our developed plays, the EUR and the Bakken rates are well below the corporate rate that we show out there. While our new plays right now, such as Redtail and Big Tex, are quite a bit above that rate. So as we continue our drilling in those areas, we expect to add reserves and drive down our DD&A rate in those areas. In addition, the Trust sale helped out our rate probably to the tune of $0.25 to $0.50 per BOE, our DD&A rate.

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

Great. And then just one for Jim. The acquisition environment within the Bakken, how does it look? Are there opportunities to add to your working interest in wells? And what's the climate like right now?

James J. Volker

Well, I think it's typified by what we did in Q1, which was to add basically across the Williston there about 20,000 net acres. And I would guess as we move forward across Whiting, all of our plays during the year, we may be able to add somewhere in the range of 60,000 to 80,000 net acres.

Operator

Your next question comes from the line of David Tameron from Wells Fargo.

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

Just one follow-up. The non-op increased -- non-op portion of the CapEx increased at $91 million. Where is that going?

James J. Volker

Well, generally that's simply participating with others in the Williston Basin, and it's across all of the prospect areas that we map for you.

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

Okay. I mean is there one operator in particular that's ramping harder than other?

James J. Volker

No, there really isn't. It's a good smattering across all of the operators and across all of the prospects that we map for you there.

Operator

[Operator Instructions] Your next question comes from the line of Mike Scialla from Stifel, Nicolaus.

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

Just a follow-up on the Redtail project. You gave the IP rate for the Wildhorse 16-42. That was in January. Has that well been online? And if so, do you have any longer rate production that you could provide?

James T. Brown

Yes, it's been online since that time, and we haven't really turned anything lose since then. But I can tell you that those wells are continuing to perform very well, and we're very pleased with what they currently are. We're still looking at something in the 200, 250 barrel a day out of that well.

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

So pretty shallow decline?

James T. Brown

Yes.

James J. Volker

Right. And plus roughly 200 to 250 Mcf a day.

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

And I think you've completed everything up there so far in the B bench, so any thoughts on testing the C bench, or do you think you're already draining that with developing these in the B bench?

James T. Brown

Mike, we've tested other zones out there. We haven't -- everything we've got up there is not in the B bench, but we're not ready to talk about that.

Operator

There are no further questions at this time. I'd like to turn the call back over to Eric Kagan for closing remarks.

James J. Volker

Well, I'll pick that up, operator. This is Jim Volker. And just simply like to thank all of our Whiting employees for a job well done in 2012, and for the exciting plans we have for the remainder of the year. But also express my thanks to our directors for their continuing contribution to Whiting's success. And now Eric would like to make some comments about where we'll be appearing at conferences.

Eric Hagen

Thanks, Jim. We'll be participating in the RBC Global Energy Conference downtown Manhattan, Raymond James 101 Conference in Boston and the Bank of America Merrill Lynch Small and Mid-Cap Conference in Boston, all the week of June 4. And we look forward to seeing you all at these events.

James J. Volker

In closing, we thank all of you on the call for your new and your continuing interest in Whiting Petroleum Corp. We look forward to seeing and meeting with you soon. All the best.

Operator

Ladies and gentlemen, that concludes today's conference. You may now disconnect, and have a great day.

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