Operator: Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Whiting Petroleum Corp Earnings Conference Call. My name is Lassie, and I'll be your operator for today. At this time all participants are in listen-only mode. We will facilitate a question-and-answer session towards the end of the presentation. As a reminder, this call is being recorded for replay purposes.
I would like to turn the presentation over to your host for today's call, Mr. Eric Hagen, Vice President of Investor Relations. Please proceed.
Eric K. Hagen - VP, IR: Thanks, Lassie. 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. This conference call is being recorded and will also be available on our website at www.whiting. To access the call and the webcast, please click on the Investor Relations box and then click on the Webcast link.
Please note the forward-looking statements disclaimer and discussion of non-GAAP measures and reserve and resource information on Slide 2. Also take note that our Form 10-Q 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.
James J. Volker - CEO: 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 4% increase over the third quarter of 2012. Production for 2012 averaged 82, 540 BOEs per day. This represents another 22% increase over 2011 total production.
Adding back the 4,500 BOEs per day that was conveyed to the Whiting USA Trust II in March of 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 higher growth rate through monetization of some assets. We see only an approximate 400 million 2013 out-spend which we can easily over 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 to 1.3 billion remains. Further the monetizations that we expect will cover in our opinion at least two times the outspend.
Moving to Slide 4 the largest contributor to our production growth has been our North Dakota operation. 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 a number one 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 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 7009 BOEs per day.
Further, our Redtail prospect in the DJ 02-0214H in the Niobrara 'B' 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 formation in the Williston Basin.
Moving to Slide 6, you will see a summary of our year-end 2012 proved reserves. 80% of our proved reserves are crude oil, 10% are NGLs and 10% and natural gas. 97% of our proved reserves are located in our Rocky Mountain, Permian Basin and Mid-Continent region.
Adding back the 10,000 or the 10 million 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 the corresponding PV10 value.
On Slide 8, we show our 2013 capital budget. As in 2012, the lion share of our CapEx is expected to be directed to the Northern Rockies specifically for drilling in 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 consists 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 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 location.
Slide 10 provides the 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 three core areas; 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 Partial field.
Slide 12 shows 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 grey well locations and new objectives as white. Of note, there is a new prospective formation the Lower Bakken Silt which is primarily present at our hidden bench prospect. The Lower Bakken Silt is situation between the Middle Bakken and upper Three Forks. We plan to bracket this formation with as many as eight wells above and seven wells below the Lower Bakken Silt.
Moving to Slide 13, you will 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 six Pronghorn Sand wells for 1,280 acre spacing unit, which is up from our initial plan of three wells per spacing unit.
Slide 14 shows our Western Williston Basin Prospect area. At Tarpon, we've implemented pad drilling with plans to drill three 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 are Sanish field and the Parshall field area. Highlighting recent results of 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 wells 7,217 foot lateral was fraced in the 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 three Middle Bakken wells per spacing unit or 176 net wells. We also plan to refract several wells at Sanish in 2013.
Slide 16 refers to our Red River Plays. At Big Island we've identified more than 50 vertical Red River prospects using 3-D seismic. Out most recent completion at Big Island the Katherine 33-23 flowed 593 BOE per days from the Upper Red River D zone. We plan a horizontal Red River D well in mid-2013. Our Red River Play is the Starbuck prospect. We'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 the 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 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 in the 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 the All-State capacity are largely due to additional rail. We are currently moving about 30% of our oil production in the basin by a rail. The excess capacity has led to much narrow differentials in the Williston Basin. In the fourth quarter, our Bakken crude sold at a $4.70 per barrel differential to NYMEX oil prices.
On Slide number 22 and 23, we provide some facilities updates. Robinson Lake Plant inlet gas rate increased to 67 million cubic feet of gas per day in the fourth quarter. Of 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 two EUR projects.
James T. Brown - President and COO: 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 a plan to the Colorado Oil and Gas Commission to drill up to eight wells in the Niobrara B and four wells in the A zone for 640 acre and 960 acre spacing unit. We currently have one drilling rig running at Redtail. We plan to add a second rig around mid-year that will begin 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 plants planned inlet capacity is 50 million cubic feet of gas per day.
Slide 26, shows our Big Text project located on the eastern side of the Delaware Basin. We have established production from the Wolfcamp on the three-corners of our acreage block and recently have experienced some encouraging results. The May 2502H was completed late December as the horizontal Upper Wolfcamp well flowing 674 barrels of oil per day. The wells 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-in performance completion.
Now I will turn to our EOR projects, Pecos and North Ward Estes Field, combined they represent 39% of Whiting's total proved reserves and 19% of our current production. Fourth quarter production form Postle and North Ward Estes, totaled 16,360 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 injection since late 2011 is being 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.
Michael J. Stevens - VP and CFO: On Slide number 30, you 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 11% increase over the third quarter of 2012.
On Slides number 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 number 31. We set our oil differential guidance lower than 2012 levels to reflect the recent narrowing of differentials in the Northern Rockies.
On Slide number 32; our fourth quarter EBITDA margin remained consistent at 66% of our blended realized price per BOE.
Slide number 33 shows that we continue to maintain a strong balance sheet with total long-term debt of $1.8 billion and a total debt to total capitalization ratio of 34%.
Slide number 34 shows that our 2 senior sub notes are trading above par. It also shows that we're well within all of the covenants in our credit agreement and bond indentures.
Slide number 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 number 36, you will 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.
James J. Volker - CEO: In summary, in December 2012 Whiting was a number one 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 are 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 locations.
Operator, please open up the conference call for questions.
Operator: John Freeman, Raymond James.
John Freeman - Raymond James: The first question I had, Jim, you alluded to the fact that any projected outspend you have that the asset monetizations would well more than offset that. Along those lines, if you could get maybe some update on where we stand on Postle?
James T. Brown - President and COO: Well, what I can say now today, John, is that, we are fielding strong interest in that both from, I would say, people who would like to buy and 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 on 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 would 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 a great value 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 if it's not owned by is it's owned by somebody else who truly understands it and will do very well with it. If it continues to be owned by us in part after some sort of monetization I can assure that we'll continue to do the great job that we have with it so far having more than double the production from when we acquired it.
John Freeman - Raymond James: 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?
James J. Volker - CEO: 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 in Middle Bakken with three wells per spacing units. We have four 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 following year. What's really interesting at Tarpon is that we have identified both 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 area and we are seeing good saturations from core data that we've collected there at Tarpon and so we think we 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 three wells per spacing unit in there. The thing to recognize about Tarpon is that it is heavily fractured, that explains the high rates that we got and so that's the – the well density there is somewhat less in some of the other areas that we are drilling.
Operator: Jack Aydin, KeyBanc Capital Markets.
Jack Aydin - KeyBanc Capital Markets: I am just looking at your inventory in the way that primary and prospective location is more than double what you had before. Then I am 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 or almost doubled in a way. Could somebody explain it to me?
Eric K. Hagen - VP, IR: I can explain it to you, Jack, it is Eric Hagen. I think you are comparing apples and oranges. I mean, our 3P numbers were fairly constant year-over-year and typically within the 3P we are just promoting reserves from possible into probable to proved and then we are 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.
James J. Volker - CEO: Jack, to help clarify that I would say that we don't have in our current reserve base the locations that you see they are under the identified prospective locations. So, we haven't added those in yet. It's basically something that's occurred over the last six months of 2012, as we have seen the potential for everything on them there, meaning three additional wells in the upper Three Forks/1280, four Bakken Silk Wells and four Middle Bakken Wells/1280, four lower Three Forks/1280, three lower Three Forks/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 have done and the core that we have taken. So, those are basically new objectives then we go into the higher density locations, Pronghorn Sand higher density that's three more additional Pronghorn Sand. The higher density at Sanish, that's three additional Middle Bakken I was pleased to 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 to 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 a resource base here in the first half of 2013.
Jack Aydin - KeyBanc Capital Markets: One more question for me. Could you update us on the new venture area that you involved in anything, when we might hear something about what you all are doing?
James J. Volker - CEO: Well, we do have a couple of self-plays where 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 two areas. I'd 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.
Operator: David Tameron, Wells Fargo.
David Tameron - Wells Fargo: Can you talk about well cost of Basin and kind of what's and I know it varies from region to region, but as far as Bakken what you had in '12 and what your targeting or budgeting for '13?
James J. Volker - CEO: Well, I guess I'll let Jim Brown answer that. I'll begin by saying that we typically have a well costs 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 this is outside of Sanish where we have lower well cost, but outside of Sanish it's running in the $8 million to $8.5 million range. 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. The frac is basically, we save that as a result of being able to do our fracs in one day using the sliding sleeve approach and of course the efficient drilling operation that we have where we work 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 a hole between surface and our 20,000 foot PD; 10,000 feet deep, 10,000 feet horizontally you know that. So that drilling operation never stops, never slows down supplies, parts, chemicals, repairs everything is delivered in a timely manner and that we are drilling with the right weight on the bed, and the right mud system in order to get that well to PD. As you know we've drilled 100s of wells in the basin now. We think we have an excellent idea about what needs to be done in each one of prospect areas. Frankly, we believe that there is 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 service is improving we are going to continue to bring our cost down and some even more efficient. Jim, would you please supplement the outset?
James T. Brown - President and COO: Jim, you did a pretty good job of covering most of what we are 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. Doug Walton, Rick Ross our operations and drilling guys are working on this. They are same team that worked on our (indiscernible) program to decrease our actual drilling time. We are 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 are about half way through this project right now and we pulled about 23 days out of that cycle time. So, we are going to continue to push this project forward this summer into the well throughout the rest of the year. But what we're seeing is we're pulling about another $175,000 out of the cost of the Sanish well, which already Sanish is on the low-end. We think we're getting about $1.5 million out of the cost of a Pronghorn well and we're just going to expand this program across all our operations. So, not only are we saving costs, but we're getting these wells on production much quicker than we have in the past.
Michael J. Stevens - VP and CFO: I'll just note, Dave, just for you models that we give a breakdown by area of well cost, which as Jim Volker indicated is – on the low-end is about $6.5 million at Sanish and on the high-end is about $8.5 million in our Hidden Bench areas, whether it's deeper and harder and we have to use ceramics and stronger materials. So, in this year our budget is for – it's around $7.7 million, it's about $8 million a well. If you divide our CapEx divide by net wells, we're just pretty consistent with where we've been running the past few quarters.
David Tameron - Wells Fargo: All that color is very helpful. Jim Volker, since you went there. Let me ask that question to you. You said AFEs that others are submitting look like they are higher than yours. Is that – I would say in the time of rising price environment AFEs go up et cetera, when you go and experiment or exploration AFEs come in higher. But in a development area, are you seeing cost overruns on AFEs or are you just seeing that the initial AFEs submitted at '10 versus '08?
James J. Volker - CEO: My comment, Dave, was primarily directed to the fact that when the AFE comes in, it's higher.
David Tameron - Wells Fargo: Rail or just takeaway capacity and back last, I guess, maybe third quarter there was talk of potentially trying to or maybe agreements that we're going to take oil through the coast – East Coast in particular, now the differential has changed, but the takeaway, seems like the bargaining power obviously has gone up on your end, but can you talk a little about how you think about that today and if you're still getting the same type of inquiries?
James J. Volker - CEO: Yes, we are. I'll simply just point to the fact here and that is that we've recently executed another fixed differential at around $5 to move crude over to the Philadelphia refining complex. So, we've done that with the people who own it and financial intermediary there who helped them with their financing. So, it's worked out well for us and I see continued strong interest there essentially as the Bakken crude replaces the imported Brent quality crude that came in there and that continues narrow our pricing differential.
James T. Brown - President and COO: One thing I'd add Dave is 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. (Doug) if you could help me what are the two rail facilities that are…
J. Douglas Lang - VP, Reservoir Engineering/Acquisitions: Bakken Oil Express and BakkenLink.
James T. Brown - President and COO: 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.
James J. Volker - CEO: We're moving about 30% by rail.
David Tameron - Wells Fargo: I've got three or four more questions but let me just ask one. The PV10 up 3% after-tax year-over-year, could you guys comment on that a little bit as we rolled over, I would have expected something but a little higher than that?
James J. Volker - CEO: Dave oil prices were down a few bucks and also we had OE-equivalent and I think that was accounted for the main reason why it didn't go up as much. Doug any thoughts on that?
J. Douglas Lang - VP, Reservoir Engineering/Acquisitions: No, I would just – I guess just to remind everybody I'm sure from -- other words the David and other callers or other listeners on the call today is that SPE's (indiscernible) engineers has published PR amass the guidelines per reserve estimates in book (indiscernible)
James J. Volker - CEO: (indiscernible) will be more likely to increase than decrease. So, obviously you have evaluate that as you book reserves. Some are new, in particular are new pud reserves we book, they are 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 changing mix have been cautious and I guess conservative in our booking. So, we are really cautious of that and I know we are criticized for being conservative sometimes, but that's the way we run our business. That maybe had some affect which you are talking about there.
Operator: Michael Scialla, Stifel Nicolaus & Company, Inc.
Michael Scialla - Stifel Nicolaus & Company, Inc.: Look to me like in the third quarter we might have been seeing some signs that Sanish field the production there look like it was maybe starting to plateau. So, I was little surprised to see it growing again in fourth quarter. I know you don't want to give guidance on a field by field basis, but that's obviously your biggest field so I am just wondering what you expect from Sanish this year. Do you think it is getting closer to (indiscernible)?
James J. Volker - CEO: We don’t want to give guidance field by field, Mike. We are a big company. We are running 6 or so rigs out of 20 in Sanish. We want people to focus on the overall results in the basin and our field company-wide Williston Basin production. This has been going on for over a year now. People have been saying Sanish is going to peak or decline, in every quarter it hasn't. So, I just don't think, we want to get into that micro-forecasting every field.
James J. Volker - CEO: But I will try to help you there, Mike, by saying, look you didn't see on Page 6, we think there is another 190 wells to drill there. So, we'd say, we're pretty proud of Sanish, and it's the field that keeps on giving. It's the highest OOPI of any field in the Williston Basin. So, we have without I guess in say answering your question directly, we do have high hopes for Sanish in 2013 and 2014. I think it will 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.
Michael Scialla - Stifel Nicolaus & Company, Inc.: 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 talk about what's giving you the confidence in making those assumptions that you'll have 1,200 locations?
James J. Volker - CEO: Mark Williams has been running in his engine in preparation for answering that question. So, if you don't mind I'd turn it over to him.
Mark R. Williams - SVP, Exploration and Development: So, the Niobrara as we look at right now is lighting being in the transaction from an exploration program and to a development program. What we've really seen, this has driven by a lot by the rockwork that we have done there. The oil in place in that reservoir is tremendous and it's up over 35 million barrels per section and the…
James J. Volker - CEO: It was about twice the Bakken.
Mark R. Williams - SVP, Exploration and Development: Correct. So, the challenge for us and all the operators in Niobrara is the Niobrara (B) is on a particular and the A for that matter is a chalk, what that means is its got lot of porosity, 12% 13% porosity but the posh spaces are extremely small. So, the challenge is to figure out how to get all of that oil out of relatively tight rock. What we've done is we 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 that we can by single wells alone and we get the effect of what we call synergistic fracking there. So prong one is to essentially drill that well on eight wells per spacing unit rather than the four with the idea that we can get the effect of fracking this kind of simply shatters the reservoir throughout of our spacing unit. The second one is we've seen a very strong correlation between higher frac sizes or higher frac volumes I should say and better performance, so that's the other thing. We started to see very good consistency in our results with that. We got four 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 learns that Jim Brown just talked about from our Bakken program and applying them right from the get-go in our Redtail development program. So, what we're going to be doing focusing on four pads starting in April and May this year, where the second rig will probably add on a third rig towards the end of August, and we're just very encouraged by the results. You can also look at Noble's results immediately to the south they're addressing 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.
James J. Volker - CEO: Since Mark has already mentioned I will expand on it little bit. One of the great things that's happening here is that we are learning from watching outside operators the one that Mark mentioned is announced an over 90 well drilling program there, but essentially is interfingered with our acreage position and they are 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 is potential as well. Another operator has actually filed a permit that will allow them to drill an even greater number of wells within drilling spacing unit as long as they meet the normal state setbacks. So, it maybe that in some cases people will end up drilling perhaps 10, perhaps 12 maybe even 14 or so wells for drilling spacing unit. Again as Mark says, it is because it is such a rich that is high OOIP formation with relatively tight permeability. So, key seems to be getting in there and drilling it on close spacing, keeping your cost down, hitting it with big fracs and really getting in there and perhaps drilling two or three wells and then fracking them all at the same time. All of those things are things that our friendly competitors are doing and that we are planning as well. But we have very high hopes for that sweet spot of the Niobrara out there. We got in with the large and a moderate priced acreage position and what I would like to call easy A, 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.
Michael Scialla - Stifel Nicolaus & Company, Inc.: It's just the A and the B zone at this point. The Cordell is not really a prospective out there. Is it?
James J. Volker - CEO: We drilled one Cordell well very early in our program. We got okay results, but didn't look like it was worth developing at that point. But we've seen across the basin, not in our area in particular. But other areas is that the Cordell is very prolific. We see some or a lot properties where we are, what we recognize now that, if we are going to make the Cordell work we're going to have to put very large fracs on it. Some of the other operators out there who put fracs that are three and four times as large as the one that we did, this is 2.5 years ago. 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 will see us drill a couple of Cordell wells later this year and see what we can do with it.
Michael Scialla - Stifel Nicolaus & Company, Inc.: Then just one last one from me on the Niobrara. The well cost, I think, Jim Brown mentioned 4 million to 5.5 million a pretty wide range. What are the differences on those book-ins in terms of the assumption for the well costs?
James J. Volker - CEO: The differences are 640 spacing unit versus 960 spacing unit, so that's the difference right there.
Operator: Biju Perincheril, Jefferies.
Biju Perincheril - Jefferies: Jim, I appreciate how you laid out the drilling inventory and the 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 stills and then bench some of those concepts?
James J. Volker - CEO: Well, we have a number of people here that would like to answer that in addition to me. So, I guess I'll let Mark take off then Jim will follow-up.
Mark R. Williams - SVP, Exploration and Development: So there are two things and going back to that Slide 12, the potential high density infill it wasn't a great wells on there. What that really is all about is a recognition that when you go through and do the oil in place calculations through most of the properties and looking at the most 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 these wells based on essentially no interference. But the question in our minds over the last several months and last year or so and jut ourselves but other operators is what happens, how do we increase that recovery efficiency? 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 it on higher density essentially doubling the density in 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 at Pronghorn, four of them in our Sanish Field that you saw all them labeled on the maps that we showed here in the Investor Presentation that we're going to be doing that here over the next several months, especially Hidden Bench and Pronghorn, we'll get those things done probably by midyear. If those are successful as we expect them to be, we will 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.
Biju Perincheril - Jefferies: So, it will be towards the end of the year this year that we will get some production data from these pilots?
Michael J. Stevens - VP and CFO: I'd say third quarter we will start to see the results of all this and it is going to take a little bit of planning to go ahead and respace a lot of this. We are actually looking at the possibility of respacing Sanish right now. There is no reason not to do that. So, we are trying to make that all that happens as efficiently as possible. But I think in terms of actually getting into development mode we are going to be talking about the latter part of this year, early next year before we can actually drill in that higher density.
James J. Volker - CEO: Just to highlight something for you. When you look at Pages 13 through 15 there you will see a little red squares. Those are the actual locations where we are going to be doing these higher density pilot programs and we go into some detail there as to exactly what we are doing within each spacing unit in order to do these pilots. And as Mark say, yes, we will have I think good results from those that I talked to you about by the time we get to the third quarter.
Biju Perincheril - Jefferies: And then in the Niobrara have you completed any well from the zone and any results you can share there?
Mark R. Williams - SVP, Exploration and Development: I'd say just about Niobrara A. The reservoir properties are everybody is good as they 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 base and we believe that we have the best Niobrara A across the basin. The main challenge there is simply that the thickness is a little less than it is in the B. Actually we are about half the thickness, but we think as we go in into development mode there is a good chance that we will be able to develop the A as well. We have drilled two Niobrara A test, the results of those are encouraging. It's not as good as the Niobrara B yet, but we're still working on it, what I'd say there and we think there was a good chance that we will be able to add a significant amount of the A in. We're not counting into 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 are going to develop on right now, that's essentially all Niobrara B, but we think there is a good chance we'll be adding same A into that as we get further into the year.
James T. Brown - President and COO: Just to extend on what Mark said, one of those A wells, it came out of the lower IP than our typically B well, but when you get out 60 to 80, it was actually producing at as good as, if not at a slightly better rate, so we've seen a pretty encouraging results rate wise on that well, as well.
Biju Perincheril - Jefferies: 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 I guess some of the works 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?
James T. Brown - President and COO: So, there is really two things that we have done, one is – Jim Brown could chime on this as well, but we have done micro seismic surveys there, both surface micro seismic, which gives us a feel for the area that we're affecting by the frac jobs. We've also done vertical value micro seismic which tells us what our frac height is, and so we've spent quite a bit of money on science, I'm not 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 two things really tells us that the area that we're affecting by our stimulations around our Niobrara B well is very small. On the Bakken wells we have sort of 700 foot (frack-wing). In the Niobrara, we're probably talking about 200 to 300 foot frack-wing and that's probably a maximum and the other thing is as that 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 fracking the wells we drilled so far to-date. So the plan by drilling higher density is really just to breakup more of the rock, that's the whole idea there.
James J. Volker - CEO: Just to kind of summarize for you there Biju. If you think about is as when we do a frac, the frack-wing coming out in an arrowhead shaped manner with the fatter part of the arrowhead obviously back close to the wellbore after studying that through the microseismic what we can tell now is the proper spacing is 8 wells per spacing unit are 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.
James T. Brown - President and COO: I'd like to add just one more thing in there if I could the other thing is recovery efficiency when you start – when you focused a lot on that here recently, when you look at the EURs of even our best wells in Redtail right now and you compare it to the oil in place, we're looking at about 3.5% or 4% recovery efficiency which is very low number and tells us what our challenges is, to really breakup more of that reservoir rock see if we can get it up to 10% or 15% and that's what whole idea behind drilling these on a very high density. We're hoping to get some synergistic effect by drilling these well on very high density and simply breakup more of the rock and if you look at our competitors Noble has probably got – Noble and Anadarko has got the most experienced further over in Wattenberg and they are drilling on extremely high density. Jim, could you…?
James T. Brown - President and COO: We drilled two pilots. We drilled one pilot on 80 acre spacing with 2B wells. We drilled another one on an 80 acre spacing with an A and the 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.
Operator: Brian Corales, Howard Weil.
Brian Corales - Howard Weil: Just one more follow-up on the Niobrara. I know 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 more confidence on the northern side?
Mark R. Williams - SVP, Exploration and Development: There is really two things to consider there. If you look at all of our acreage at Redtail we have it what we call a Phase 1 area and a Phase 2 area. The Phase 1 area is where we have been drilling and why is that. The reason really is because that's where we have 3-D seismic data. We shot at 3-D survey little over a year ago and in this play unlike a lot of resource plays 3-D seismic is absolutely critical for (indiscernible) you got to have that mainly as because there is a lot of small faults that you 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, while we get that survey back sometime this summer but this is up where we drilled our 2 mile well. It has been a very good well. We haven't had this 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 till we get the 3-D shot.
Michael J. Stevens - VP and CFO: And the Phase 1 is I think about 70% of our acreage, Mark, is in that 60%, 70% roughly. So, that's kind of give you an idea.
Brian Corales - Howard Weil: And then going to the Sanish. You talk about potentially refracking some of these wells. Have you all done this before or maybe some of your neighbors and what you are all expecting the wells to kind of back to original rates or what's the kind of thought that?
James J. Volker - CEO: I think for refracking these wells, we're hoping to get a bump over what we have done right now. I don't think, we're going to see the original rates at all, but it doesn't cause us to have much to refrac.
Michael J. Stevens - VP and CFO: You have to remember way back in the early days of Sanish, the first, I don't know, year or so the wells we fear fraced up there, we only fraced with 10 stages, because that was the technology for sliding (fleet). So, we've got a lot of potential up 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, and that's what we're trying to tackle right now.
Brian Corales - Howard Weil: Then final one. You talked about the Bakken realizations just being I think it was around $4 off of TI, what you are seeing thus far in 2013?
Michael J. Stevens - VP and CFO: About the same. Down to a low, our companywide differential in January was around $5, Bakken slighted better now.
Operator: Hsulin Peng, Robert Baird.
Hsulin Peng - Robert Baird: Regarding your monetization effort, I know you updated us on the Postle field. Can you tell us if the joint venture or industrial monetizations are still on the table and if so, can you give us an update?
James J. Volker - CEO: Well, again, we have strong interest in some of our prospect areas. I guess they are all liked by the people who are looking at potential joint venture with this. I chuckle from time-to-time simply because some people like one area or two or three areas and not others in that and then somebody else comes in and they like the ones that the prior party didn't like. So, a lot of frankly has to do with who is looking and what they are 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 monetization so that they could get some perhaps some proved developed producing reserves, as well as do some drilling with us. I'm sorry I can’t tell you exactly what the metric we're going to get to 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 receiving and I believe that it will be excellent in the event that when we do monetize one of those assets or bring in a joint venture partner. It will help us in the sense that it will help to drive out through the promote, it will drive our S&D per BOE down and of course and -- 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% that 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 relatively low percentage when we see our discretionary cash flow for the year at 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 happen to the people who were strong on natural gas and pursued the growth at any cost and now they are caught with debt that they have termed out and the value of the debt is 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 am going to say monetizing some assets that we – that unlock value that are not being in our opinion correctly valued within Whiting like our EOR, and like our – and I have to say I think the EOR would come a little sooner than with 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 the big overspend and leaving ourselves subject to risk in the event of 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 bode well for oil prices. But nevertheless, we haven't taken – we haven't subjected the Company for 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 are 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 an 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 and those tend to be lumpy monetizations, but they really then can drive your growth for the next two to three years.
Hsulin Peng - Robert Baird: I agree what's that. The monetization could unlock value for you guys hence the question. Though I do want you to get a better feel for, so in your current '13 guidance are you assuming like $400 million – given the $400 million – roughly $400 million of offsets 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 two times – potentially two times outspend I mean you would have room to accelerate?
James J. Volker - CEO: The acceleration is not coming from the monetization. It's not in our guidance at this time, not in guidance.
Hsulin Peng - Robert Baird: Not in guidance, okay got it. I guess a follow-up question, just in previous quarters the CapEx dollar amount was that – was essentially suggested it was a bit lower than the 2.2 and I know your balance sheet is strong for you guys there is no extra funding in it. 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 whether its oil price whatnot and also where is the incremental CapEx dollar going to work to?
James J. Volker - CEO: There was lot of questions in there I'll try to answer them. One thing I would like to point out to you is that if you look at our CapEx there is 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 EUR which is more of a plateau type situation than the 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– I call them stealth plays that we haven’t discussed yet, but where we've drilled the couple of test wells and we are encouraged with the results. So, we are adding there to our acreage position and those adds I am going to say would be something that we will enjoy drilling on in late 2013 and essentially looking for growth in 2014 and beyond. In terms of getting you to think about our capital just I think what we are doing here is we are being very honest with the market and we are saying wait a minute look at the spend rate in the fourth quarter, it is really a continuation of that rate. I noticed some other companies are out there saying that they are going to cut back on their CapEx and yet grow. I think that's a challenge. I think what we are doing here is saying look we are spending it about that rate and frankly as 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 are on the conservative side, just like we were last year you may remember we came out at around 16%, 17% midpoint of guidance and we did over 22% year-over-year. So, this year we are out with about 14% midpoint, we hope to do same thing again.
Michael J. Stevens - VP and CFO: Just to be clear. When initially mentioned 1.8 billion we were running about 20 rigs and we had talked about dropping two or three rigs out of the program to cut back to 1.8 and now that we have seen strong interest in these assets now have visibility on a 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 million to be conservative. And then, if you do get a big monetization and as Jim has addressed it could be as much as twice our or more $400 million outspend. Obviously, we would have sufficient capital, if we wanted to, for example, drill a few more test wells, a big tax 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.
Operator: Jason Wangler, Wunderlich Securities.
Jason Wangler - Wunderlich Securities: Just had one question on big tax, how long do you think you're going to sit and evaluate before you look and bring in the rig back in and would it be a second quarter or even second half event or may be even is it even in the fourth quarter?
James J. Volker - CEO: Second half.
Jason Wangler - Wunderlich Securities: Second half. Would it be again just a program in which one or two rigs come in and get a few more test wells and see what you have before maybe developing, starting maybe '14?
James J. Volker - CEO: Yes, and Mark will elaborate.
Mark R. Williams - SVP, Exploration and Development: So, the well that Jim alluded to are May 2502, we've made several changes in our approach to completing these wells as well as our drilling objective. We've moved our drilling objective up there in the Wolf Camp and we're directly targeting the source rock in the upper part of the Wolf Camp right now. The combination of that is going to cemented liners and plug and curve sort of completions has made a pretty significant difference in that well. We believe that we can take that and apply that to other areas. The flow back results on that well has been very positive. It look it might potentially be a game changer, frankly, and so we have identified two 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 you in the say second quarter rather than the second half on that. But I tend to get ahead of those things sometimes. But at any rate, we do think we got a lot more running room on big tax rate. I think we've seen some good positive results as well as some of the outside operator both to the south of us and immediately to the Northwest. So, I think, we are starting to unlock the Wolfcamp there.
Operator: Michael Kelly, Global Hunter Securities.
Michael Kelly - Global Hunter Securities: Just a quick one on Missouri Breaks. First well there came on strong, hit over 1,300 BOE a day. What's the read through here to the whole 66,000 acre position, but just a go 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 a more Eastern Bakken acreage or it's just too early to tell?
James J. Volker - CEO: I'd say just about Missouri Breaks, our focus there 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 we have 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 we've 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 as to switch once we get our position (HBP'd) out there and we've got still some more work to do drilling one well per spacing unit in a better part of that whole thing which is I'd say somewhere around three quarters of our acreage position then you'll see us going into development mode and I think as you see on the slide that we have here the development slide I feel very confident that we're going to be able to drill four wells per spacing unit in the Middle Bakken there and the results we've seen from core in the upper parts 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 a 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 two zone, but breaking up more rock is better and so anyway we're still sort of early in that play and we got a lot of acreage there and you'll see us just essentially (HBPing) our acreage position through most of the year. We think it's really going to come on for us in terms of a big development play in 2014.
Operator: At this time I'd like to turn the call back over to Mr. Jim Volker for closing comments.
James J. Volker - CEO: Thank you Operator. I'd like to thank all of the Whiting employees and directors for 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?
Eric K. Hagen - VP, IR: Mark Williams and I will be presenting at the Raymond James Investor Conference in Orlando, March 4 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 into the call.
James J. Volker - CEO: So, 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 and all the best.
Operator: Thank you for your participation in today's conference. This concludes your presentation. You may all disconnect. Good day, everyone.