Executives
John Jasek - Vice President of Onshore Gulf Coast
Lee Boothby - Chairman, Chief Executive Officer and President
George Dunn - Vice President of Mid-Continent
Terry Rathert - Chief Financial Officer, Principal Accounting Officer and Executive Vice President
Gary Packer - Chief Operating Officer and Executive Vice President
Analysts
Dan McSpirit - BMO Capital Markets U.S.
Cathy Milostan - Morningstar
Leo Mariani - RBC Capital Markets, LLC
Subash Chandra - Jefferies & Company, Inc.
David Tameron - Wells Fargo Securities, LLC
John Herrlin - Societe Generale Cross Asset Research
Pearce Hammond - Simmons & Company International
Gil Yang - BofA Merrill Lynch
William Butler - Stephens Inc.
Joseph Allman - JP Morgan Chase & Co
Anuj Sharma - Pritchard Capital Partners, LLC
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
Robert Morris
Newfield Exploration (NFX) Q1 2011 Earnings Call April 21, 2011 9:30 AM ET
Operator
Good day, everyone, and welcome to Newfield Exploration's First Quarter 2011 Conference Call [Operator Instructions]
And before we get started, one housekeeping matter. Our discussion with you today will contain forward-looking statements such as estimated production and timing, drilling and development plans, expected cost reductions and planned capital expenditures.
Although we believe that the expectations reflected in these statements are reasonable, they are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Please see Newfield's annual report on Form 10-K and quarterly reports on Form 10-Q for a discussion of factors that may cause actual results to vary. In addition, reconciliations of non-GAAP financial measures to GAAP financial measures, together with Newfield's earnings release and any other applicable disclosures, are available on the Investor Relations page of Newfield's website at www.newfield.com. At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman, President and Chief Executive Officer, Mr. Lee Boothby. Please go ahead, sir.
Lee Boothby
Thank you, Carla. Good morning, and thanks for joining us for our first quarter conference call. Due to some internal meetings we're having today, most of our management team is here in Houston today. Seated with me are Gary Packer, our Chief Operating Officer; Terry Rathert, our CFO; John Jasek, Vice President of Gulf Coast; George Dunn, Vice President, Mid-Continent; Bill Schneider, Vice President, Gulf of Mexico and International; Daryll Howard, Vice President at Rockies; Brian Rickmers, our Controller; and of course, Steve Campbell, VP of Investor Relations.
As always, we appreciate you dialing in for our call and we'll have plenty of time at the end to take your questions. Remarks today will be brief, and I will address three main points.
First, a quick summary of our first quarter financial performance, as well as our capital investment plans and production outlook for the remainder of 2011. Second, I'll outline our primary objectives for 2011. It's important that you understand where we are allocating both our people and capital. And finally, I'll update you on the progress in our largest development projects.
These are the programs that are driving our expected 50% increase in domestic oil volumes in 2011.
So let's start with the first quarter financial results. We reported the results last night, and if you had time to review the numbers, you will agree it was a pretty simple quarter. Our results were in line with expectations in both production and costs.
Our earnings before FAS 133 charges were $133 million or $0.98 per share, slightly above First Call estimates. Our production in the first quarter likely differed from your expectations with slightly lower natural gas volumes, offset by higher oil volumes. Like others, we experienced some weather-related issues during the first quarter. As a result, our natural gas production came in at the lower end of our guidance range at about 45 Bcf or about 500 million cubic feet per day. We made up for the shortfall in natural gas with higher-than-expected oil volumes, 4.4 million barrels or 49,000 barrels per day.
Replacing gas volumes with oil also helped improved our profitability. Revenues in the first quarter were $545 million. Net cash provided by operating activities before changes in operating assets and liabilities was $361 million or $2.67 per share, also best in First Call consensus for the quarter.
Our production for 2011 is expected to be up 8% to 12% over 2010. Late last week, we learned that a mechanical failure associated with our FPSO operations at our PM 318 Abu Field in Malaysia, which forced us to shut in the field for approximately 60-90 days. We estimate that the net impact for our second quarter volumes will be about 200,000 barrels.
Although we expect repairs will be completed timely, the field is non-operated and we do not fully control the timing of activities. We will keep you updated on the repair progress.
We've accounted for the loss production impact in our guidance for the second quarter as well as full year. Despite the deferral of this Malaysian production, our expectations in 2011 production today continue to roll up to the midpoint of our range of 312 to 323 Bcf equivalent.
In our release last night, we updated our 2011 capital investment program to an estimated $1.9 billion. This is $200 million higher than our beginning-of-year estimates, and the primary drivers behind the increase are as follows:
first, a large portion of the increase relates to new and ongoing leasing of acreage in an undisclosed resource play. Our expansion into this area actually began in 2010. Although we felt it was prudent to include in our planned expenditures, we are not yet ready to disclose our position in this area. We will provide additional details to you later this year.
Second, like others in the industry, we're seeing 5% to 10% increases in service and labor costs throughout our onshore U.S. operations. These increased costs relate to pressure pumping, steel price inflation, water handling trucking costs, mostly diesel-related, as well as overall increases in labor expenses. Although some of our service costs are fixed through contractual arrangements, we made the appropriate adjustments to full-year expectations on costs and our guidance ranges today.
The third driver relates to efficiency gains being seen in a few of our drilling areas. In today's report, you can see that we are drilling wells in record time in the Eagle Ford, the Uinta Basin and the Granite Wash. The resulting impact is more wells and more completions in a given calendar year.
And lastly, we're including some planned capital investments in the Uinta Basin associated with our recently-announced acquisition of assets from Harvest Natural Resources. This deal is expected to close in the second quarter and we intend to promptly go to work on the assets.
Our increasing Capital Investments will be significantly offset by the benefit of higher oil price realizations and resulting cash flow from operations. In addition, we have an ongoing program to divest nonstrategic domestic assets. These sales will allow us to direct proceeds to our core development projects, as well as refocus human capital to other programs. To date, we reached agreements to sell assets that comprise about ½ of our planned $200 million or more in divestitures. We will provide complete details on our asset sales once completed later this year.
Let's move now to a review of our major objectives for 2011. When we built our plan for 2011, it was a conscious combination of profitable growth and returns, and therefore, we picked the drilling programs with the highest margins. Due to continued disconnect between oil and natural gas prices, substantially all of the year's budget is ear-marked for oil or liquids-rich plays. Our 2011 plan was designed to grow oil volumes and we certainly intend to accomplish that objective. I'll update you on our largest oil developments in a moment.
Objective 1, accelerating all investments to create the best returns has followed our continued emphasis on the future. When you analyze the data in our recent 10-K, you should see that our forward plan assumes about 2/3 of our cash flow will be invested to develop our proved reserves, the remaining 1/3 is planned for allocation to our future. By this, I mean new opportunities, most likely in areas where we are already active but will benefit our future growth.
Most recently, we announced the addition of more than 80,000 net acres in the Uinta Basin, just north of our Monument Butte field. The expansions comes from 2 transactions. The first, our previously announced acquisition from Harvest Natural Resources expected to close next month. These assets lie immediately north and adjacent to the Monument Butte field. The second adds 11,000 net acres through a third exploration agreement on Ute Tribal lands. Once we close our Harvest transaction, we began -- we plan to provide an update on our plans in the region. These are great transactions for us and add acreage in our own backyard that we know and understand. And where we have demonstrated cost advantages. We will soon have about 250,000 net acres in the Uinta Basin.
To recap, we've captured nearly 800,000 net acres in resource plays since late 2009 and gained entry into perspective areas like the Eagle Ford, Pearsall Shales, Southern Alberta basin, and all are done at very attractive costs. We're actively assessing all of these plays today.
We certainly understand the importance of meeting short-term expectations, but rest assured, we are also focused on our long-term inventory of drilling ideas and our ability to grow in profit in the future.
Our third major objective revolves around people; ensuring that we have enough of the right people to execute our future growth plans and that they are focused on the right plays. I've given several industry speeches recently and some of you may have heard them. In these, I mentioned that our greatest future challenges in this business may be above ground. I categorized government regulations, taxation or loss of incentives; access to new domestic opportunities and the ability to attract, expand and train our workforce as tomorrow's key challenges facing industry today. Newfield is aggressively hiring today and I'm confident that we will have the workforce required to meet our future challenges.
Let's move now to updates on our oil projects. In the Gulf of Mexico, our Gladden field commenced production in mid-February. Although production was late due to the delayed issuance of a required federal permit, the field is now above the original plan at about 6,000 barrels of oil equivalent per day, and we have a 57.5% working interest in that field.
Our Pyrenees development is expected to commence production in the fourth quarter of 2011 at about 50 million cubic feet per day and 2,400 barrels of condensate per day. We operate Pyrenees with a 40% working interest. The development is progressing well and is on schedule.
Our Rocky Mountain production is the largest contributor to our oil growth story and is expected to grow about 25% in 2011. We're focused on growing our oil volumes in the Uinta and Williston Basins. During the first quarter, we reduced Monument Butte inventories to normal levels. You'll recall that inventories at year end were pushed higher due to upsets in the Salt Lake City refineries and interrupted service on the major supply pipeline.
We continue to see great execution in our drilling operations at Monument Butte. Our program this year calls for 5 operated rigs, drilling a mix of 40-acre development wells and 20-acre infill wells, and continued development and assessment on our Tribal acreage in the northern areas of the field.
We are drilling and casing wells in about 4 days today. Our net sales in the first quarter averaged about 18,200 barrels of oil equivalent per day, and we expect that annual volumes in this field will grow about 15% in 2011.
We'll optimize our drilling programs in the Uinta Basin this summer and integrate our growth plans on the new acreage we are acquiring to the north. As I said earlier, we'll have a detailed update for you later this summer once the transaction closes.
In the Williston Basin, we're running a 5-rig program. And as you're all aware, pressure pumping services in the Williston are extremely tight. We now have our dedicated services working to complete our wells. We also have a 10-well inventory awaiting completion. Nearly all of these wells are Super Extended Laterals or wells with average lateral length of about 8,600 feet. We expect to complete more than 15 wells in the second quarter of 2011, which will lead to a significant boost in our oil volumes later this year.
Our three most recent completions clearly show the benefit of the longer laterals. The wells had an average initial production rate of 3,900 barrels of oil equivalent per day, which includes a recent best-in-class gross IP of 4,468 barrels of oil equivalent per day. Super Extended Laterals will be our preferred development plan going forward.
In the Mid-Continent, our efforts are focused on drilling in the liquids-rich Granite Wash and the oily portion of the Woodford. We're running 4 operated rigs in the Granite Wash and our current net productions in the area is 110 million cubic feet per day.
To date, we have drilled 39 horizontal wells in the play and we continue to make efficiency gains. In last night's release, we highlighted a recent best-in-class drilling performance of 25 days for a 4,700-foot lateral. We expect to drill about 30 wells in this play in 2011 and should grow production at about 20% over 2010.
Our efforts today are confined to the liquids-rich Marmaton formation. We understand this integral very well and have drilled 21 of our wells in this target horizon. The average gross initial production from this zone, about 17 million cubic feet equivalent per day and our recent completions have all IP-ed over 20 million cubic feet per day.
We have about 50,000 net acres in the Granite Wash play including about 10,000 net acres in new perspective areas we plan to test later this year. In the oily Woodford, we are running 3 operated rigs. We have several wells today that are in various stages of completion and expect that we will drill 15-18 wells in the Arkoma in 2011.
To date, we have 5 wells with more than 30 days of production. These wells have averaged just under 1,000 barrels of oil equivalent per day over this period and we are encouraged with the results. We see the potential to drill about 100 wells in the play and intend to focus our Arkoma basin efforts here during periods of low gas prices. We continue to drill assessment wells on our 335,000 net acre position in the Maverick Basin, targeting the Eagle Ford Shale as acreage block is located principally in the Maverick and Belumut Counties in South Texas. Due to hunting season restrictions in the South Texas region, our drilling and completion operations were suspended last October due to hunting lease stipulations. Operations recommenced in February, and we have dedicated fracture stimulation services working today to complete an inventory of some 11 recently drilled wells. We expect production for most of these wells will commence in the second quarter.
Performance in our drilling program has been stellar. During the first quarter, our Eagle Ford Shale wells we're drilled and cased at an average of less than 10 days. This illustrates that our experience from other resource plays is transportable. Our initial drilling results in the Eagle Ford were encouraging, and our efforts today are focused on optimizing our completions to increase both oil production rates and EURs. Our primary goal is to move this play quickly toward development.
In the Southern Alberta Basin, we have about 280,000 net acres and we continue with our assessment program. We recently completed our second horizontal well and are preparing to drill our eighth vertical well. We continue to test multiple perspective horizons across our acreage. As we have said time and again, we're executing on our assessment plans, testing multiple formations and do not plan to discuss results until we have a better understanding of our acreage and its potential.
In Malaysia, we have a large oil development underway at East Piatu. The development is on schedule and we expect first production in the fourth quarter of 2011. The East Piatu development is expected to produce about 10,000 barrels of oil per day gross, and will lead to international oil growth for us in 2012.
So in closing, I've given you a brief overview of our largest current programs, Newfield is uniquely positioned today with a deep inventory of projects to select from and we are confident that this optionality will continue to allow for improved returns. Our people understand our key objectives today and they are focused on doing the right things right. #1, growing production; #2, adding proved and probable reserves at attractive costs; #3, selecting the best projects and matching our investment timings to the most effectively navigate the inevitable cycles in our business; and 4, building for our future through the assessment of current plays, identification of future trends and hiring and retaining the best technical workforce in the business. That wraps up my prepared remarks this morning, and we're happy to take your questions. Operator?
Question-and-Answer Session
Operator
[Operator Instructions] And our first question comes from Gil Yang with Bank of America Merrill Lynch.
Gil Yang - BofA Merrill Lynch
Lee, could you comment -- I'm a little unclear about your guidance, given the shortfall in the second quarter, the full year being unchanged. Is that -- you're anticipating that you can make up for the lost time over the rest of the year? Or is it because of the acceleration in other parts of the business that is above budget?
Lee Boothby
I'm not sure I understand all of your questions, Gil, so I'll take a shot at what I think you asked and you can fire back if I missed the mark. The discussion relative to production in the second quarter is specifically related to a current infrastructure issue in our Abu Field in Malaysia. That's a minus 200,000 barrels net or about 1.2 Bcf equivalent. Now we fully expect that the repairs will be completed in the 60-90 timeframe, which means it'll be a second quarter event. We expect to have the field back online. I would say that if in some unforeseen or unfortunate circumstances that, that doesn't occur, then we'll let you know at that point in time and we would revise the production impacts. But right now, we've assumed that's a second quarter event, and the field's back online in the third quarter.
Gil Yang - BofA Merrill Lynch
Right, okay. But you can't make up for those lost volumes. If they get tacked on the end of the project, you can't accelerate the next couple of quarters to make up for that, right?
Lee Boothby
We're not -- the field shut-in is unavoidable, Gil. We can discuss whether it's end of the life or distributed over the life. As far as the volume is in the calendar year, we're making up for the volumes that were associated with that field through performance in other areas of the portfolio. And I think the fact that we've reiterated our guidance and held firm on our guidance range, hopefully it gives you some level of comfort given the fact that we also navigated some weather issues in the first quarter and a number of other items. I feel real confident where we're at with our production forecast, and we plan to deliver in 2011.
Gil Yang - BofA Merrill Lynch
Okay, got you. That was really my question. The second 1 is, given the higher spending levels and the efficiency gains you're having at Granite Wash, Eagle Ford and Uinta, you'll need to complete more wells and so that'll cost you some extra capital, but do you expect your backlog to change or do you expect to be building up a backlog of uncompleted wells going forward?
Lee Boothby
Well, we actually expect the backlog of uncompleted wells to work down. We're working through that inventory at this point. We've got frac crews running in the Eagle Ford Shale. Post hunting season, John Jasek and his team are working hard to reduce that inventory. And Daryll Howard's team, up in the Williston Basin, likewise, has frac crews running to work down the inventory that we built up there. Beyond that, we would expect the normal inventory that occurs just in the normal drilling complete cycle. Williston Basin, we've got 5 rigs running, and John Jasek's team will likely have 2 to 3 rigs running during various parts of the year down in the Eagle Ford. Those are the 2 areas where we're carrying the inventory in that's going to be completed in the second quarter.
Gil Yang - BofA Merrill Lynch
Alright, and then just last question regarding the hunting that you mentioned, hunting stipulation. Is that -- that's going to be an ongoing issue and you just [indiscernible] the plan around it as you develop that field up going forward?
Lee Boothby
Well, I think that there will be some areas where it's more impactful than others. I guess I continue to maintain the hope that, as oil and gas revenues increase down in that area, that Oil and Gas business will become a little bit more important than hunting season. But hunting season in South Texas is a cultural thing and it's not going away anytime soon.
Gil Yang - BofA Merrill Lynch
Got you. Okay, thanks.
Lee Boothby
Thank you, Gil.
Operator
Moving on, we'll now hear from Pearce Hammond with Simmons.
Pearce Hammond - Simmons & Company International
At Monument Butte, I'm thinking about the recent acquisitions being in state lands rather than federal lands, can you comment on the permitting difference between the 2 and the relationship the industry has with the state?
Lee Boothby
Sure, I'll let Gary Packer take that question.
Gary Packer
Yes. Typically, Pearce, permitting on state lands is normally about a 60-day process. Historically, on federal lands, that could be anywhere between 6 months and 1 year and 6 months. So it just gives us just a little bit more flexibility to navigate changes in our inventory.
Pearce Hammond - Simmons & Company International
Great. And do you expect some acceleration on drilling because of being on state lands?
Gary Packer
Well, that's certainly an opportunity that's available to us and we look to in the future. I think first and foremost, the teams are working hard right now to optimize the allocation of capital that we've already put into the business in 2011. And as communicated in Lee's call that we are looking for some acceleration options this year, and we have notionally allocated some incremental monies there. But that remains to be seen once we get the deal closed. Look for us to be more transparent with the plans for the remainder of 2011 and into 2012.
Pearce Hammond - Simmons & Company International
Great. And then switching gears to the Marcellus, Lee, how is your joint exploration agreement with Hess progressing?
Lee Boothby
Since Gary did such a good job in the other question, I'll let him update you on that as well.
Gary Packer
It's really not advancing right now. As you're probably familiar with some of the regulatory situations up there are still in a bit of state of flux, and we filed some permits but they're essentially in suspended animation right now, as well as the leases. And we need to see some of those, the rule-making, both from the PA DEP and the local water boards get resolved before we can move that forward.
Pearce Hammond - Simmons & Company International
Great. And then final question is, we've heard a lot about additional service capacity come into market in tight areas like the Bakken and the Eagle Ford, what remains the tightest area of completion? Is it equipment, profit, labor?
Gary Packer
It's hard to break out any one of those things. We haven't necessarily seen the horsepower arrive yet. It's something that's been a bit elusive and keeps getting deferred a little bit. If you look beyond that, I'd say it's probably people and profit.
Pearce Hammond - Simmons & Company International
Thank you very much.
Lee Boothby
Thanks, Pearce.
Operator
Moving on, we'll go to Wells Fargo's David Tameron.
David Tameron - Wells Fargo Securities, LLC
Good morning. LOE, can you talk about -- you ramped it in the second quarter? I know it's a lot of workover stuff but it looks like you maintained 4 [ph] of your guidance, can you just talk about how that works?
Gary Packer
Yes, you bet. The increase that we had in the first quarter was primarily related to weather and most of it was in the Rocky Mountains. Both -- typically, when the weather is bad out there, we have increased chemical costs. And then as we come out of the winter into spring, we have seen increased workovers. As a result of that, we think we can get ahead of that, though, for the rest of the year.
David Tameron - Wells Fargo Securities, LLC
Okay. I mean, so simple math tells us you've got to be down in the third and fourth quarter in order to get the full-year average?
Lee Boothby
Yes, that's right.
David Tameron - Wells Fargo Securities, LLC
Okay. All right. And then going back -- let me go back to the Harvest acquisition. But just standing back and thinking about the issue with the Uintas has always been you can't ramp fast enough, can't get permits fast enough, et cetera. That's obviously in the permitting front improves it, but is this acreage going to take place of other acreage that you would have drilled? Is it an upgraded of acreage or should we think about it more like you finally get -- not finally, but you've talked about getting a refinery, another agreement out there, and maybe that what's you were talking about as far as solutions to accelerate. How do you get value out of Harvest, I guess, is the question?
Gary Packer
Well, first and foremost, Dave, and you're spot on. Our intention in this transaction was never to accumulate acreage and inventory of wells and put it at the end of the line. Our valuation clearly is, from the beginning, is that we can put incremental dollars to work out here and drive production north of what it would've been otherwise. And don't think of it any different than that. But it does give us a tremendous amount of flexibility in the near term and how we allocate capital. But the way we're going to create value out here is to continue to build with the business partners we have in the refining community in the Salt Lake City basin and others, in order to expand capacity, put more dollars, and more rigs to work on an ever-increasing footprint that we have in this resource. And now it's going to be about 0.25 million acres.
Lee Boothby
And David, internally, we've been clear and I think I haven't had the chance to visit with you since we announced the transaction, but -- and Gary mentioned it earlier, our first step is to optimize. That's optimizing within the context of the new portfolio so that the things that this acquisition will add incrementally, I think that's a prudent first step. And the second step will be acceleration. So look first to first optimize and second, accelerate.
David Tameron - Wells Fargo Securities, LLC
Okay. And then one more question in the Uinta. The Mancos Shale, I know, and Kenny yesterday was making noise about the liquids component in the [indiscernible]. Can you remind me, when you guys did go up to the Mancos a few years ago, was there any liquids component in there? I thought it was predominantly dry gas but...
Gary Packer
Yes, David. As I recall, that was pretty dry. I have heard the same rumblings you have of some liquids in the Mancos, but the test that we had of it I think was pretty definitive and it was dry.
David Tameron - Wells Fargo Securities, LLC
Okay. Very good. Thanks.
Lee Boothby
But we have a lot of it, David.
David Tameron - Wells Fargo Securities, LLC
Yes, you do. Thank you.
Lee Boothby
Alright, thank you.
Operator
Moving on, we'll now go to Brian Lively with Tudor, Pickering, Holt.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
As costs continue to creep up on you guys, what level of cost increase would you need to see before you actually cut rig in some of the oily plays?
Gary Packer
Well, I would say that that's a fine line. I think there are a number of things that happened to you, and I'll let Gary provide some color here when I finish talking as well. Obviously in the overheated areas, you've got the incessant fight for services and equipment and timing issues. And the first casualty is usually efficiency. The service costs are bid up, you certainly see margin erosion. I would tell you that what we do realtime is monitor, basin-by-basin, project-by-project what's going on, if we need to reset the deck within our portfolio and transfer activity out of an overheated area into an area where were more competitive. Certainly we have that option, and it's something that we consider each and everyday. So it's a balancing act and I guess, our view is, our focus diversity, as we like to call it, provides options. And we'll exercise those options going forward just as we have during the course of the last couple of years. Gary, you got any color you want to add?
Gary Packer
Yes, I think you used the right word, Lee. The discretionary aspects of the investments that we're making and that we have within the portfolio give us a lot of options. Certainly, the overheating of the market as you suggest is regional oftentimes, and we've been able to push back with efficiency gains and others. So the first thought is that there's sufficient margin for us to continue from an economic standpoint. We'd look to optimize that by moving capital out of the overheated markets into the areas that we've had the best efficiency gains. And if that wasn't sufficient, we also have discretionary investments that were alluded to in our release as well that you could look at in order to make sure that we balance the budget. But in no case are we looking to withdraw money that's going to affect the production growth that we've got baked into our forecast.
Lee Boothby
And Brian, I'd also want to make a point for all of you guys to consider. Adding activity into an overheated area just to prove that you can run more rigs is not always a smart decision. In fact, I'd say most days of the week, it's a dumb decision. So we're going to be very, very prudent and careful with regard to when and where we ramp, and we're going to make sure that we work hard to preserve our margins. That's our game plan and that's what you should expect to see out of us.
Gary Packer
I'd add one other thing, Brian. That is, the levels of some of the costs increases we've observed today, I would've predicted that we might have been thinking about doing just what you suggested, maybe we move some capital in different areas. But I'll throw some kudos away to our technical folks. They continue to deliver phenomenal performance in terms of understanding bit runs and changing the bit designs. I mean, the list goes on and on and on to significantly offset those cost increases and continue to prop up the return. So to answer the question in the vacuum in terms of cost increase, without having appreciation for what the people can do, that's really a tough call.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
Thanks. And I understand it's not an excel exercise. But if you were to just compare today the returns between the Bakken where you have a lot of cost inflation, with Monument Butte where it's a little bit lower, just can you give us an idea of what the relative returns are between those 2 plays, current cost?
Gary Packer
Yes, sure, Brian. I hate to capture anything at current cost, but we're typically looking and look at sensitivities between anywhere between $75 and $100. As far as the returns, we continue to preserve anywhere between 60% and the north of 100% returns on our Monument Butte investments, and that hasn't changed. We continue to see the margin contraction in the Williston Basin and the Bakken, as you suggest. It's the area that's probably the most overheated. And we've probably seen about a ¼ of our margin or road there here over the last six months or so. Still profitable. But I will tell you that the Bakken now is probably at a return equivalent to maybe what we're seeing in the Granite Wash and the oily Woodford. So we probably have, after you step out of Monument Butte, you have some very comparable investments. Even at low gas prices, the liquids and the efficiency and the margin expansion we've seen in the oily Woodford and the Granite Wash have kind of allowed them to more effectively compete with the Bakken.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
Okay. Last question for me is if you think about the kind of 2 areas you're testing big right now in Big Valley, in the Williston and also in Northern Maverick County and Eagle Ford, what science -- what are you guys looking for in terms of taking those projects into more of a full development, full commitment phase?
Gary Packer
First of all, I guess I'd correct you. In Big Valley, we've just drilled our second well there. The first 1 was a 3 forks well. We've just drilled a Bakken well and it's currently unloading as we speak. So we're not in the position to speak to that right now. So once we see the results of that well, we have some other wells permitted and we would follow that accordingly. We have a lot of options with our rigs there with the diverse position that we have in the Williston Basin that we could move considerable activity in that direction, so if we could get that indication. Northern Maverick County is an area that we really have not spent much time or effort focusing on in the Lower Eagle Ford. We have been spending much of our time up there being able to maintain our leases in the drilling in the Georgetown. Now as far as what are the things that we're doing to continue to understand that play as well as the Big Valley and the Bakken. We're looking at this year. We're examining the impacts of PAD locations and various spacing that we would have in the Lower Eagle Ford. We have spent considerable time looking at the completion designs in Eagle Ford. As you recall, last year we went out and we pumped basically 5 fracs that were identical to 1 another. This year, we're looking at hybrid fracs versus just strict slick water. Were looking at the different concentrations of propane and engaging in the debate that goes on so often whether you drill these things toe up, toe down and others. So we've got a lot of learning to do and a lot of knobs that we can turn as we look to optimize those developments.
Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.
Okay, still early but I appreciate the color again, guys.
Lee Boothby
Thanks, Brian.
Operator
And now we'll open the floor up to Subash Chandra with Jefferies.
Subash Chandra - Jefferies & Company, Inc.
Following up on the Northern Maverick. So the Georgetown, can you just talk about sort of the repeatability of it? Sounds like it's just mundane work to hold the leases or is there something reserve-accretive that can occur there that could move the needle?
Gary Packer
These are -- the Georgetown, as much as we've got an inventory there in excess of 75 wells, they're amplitude driven oil plays. They're mundane in the fact that they are extremely profitable, high rate of return wells. They just don't have the depth and breadth that the Eagle Ford and the Pearsall do. These wells cost less than $1.5 million, probably about $1.2 million. They produce about 50,000 barrels, come on at about 400 barrels a day. As far as mundane, they keep the lights on and they maintain our leases and they allow us to really focus our efforts in other areas while we look to understand the play and kind of build that learning curve out there.
Lee Boothby
And Subash, I'll remind you, that's 1 of the real attributes of the Maverick Basin acreage position that we have. Its multiple objective horizons. And that was part of the optionality that we really liked about that position before we acquired it, and we come to appreciate it more and more everyday.
Subash Chandra - Jefferies & Company, Inc.
Okay, got it. And so in the Eagle Ford, Northern Maverick, Eagle Ford, is it just too shallow to pursue there?
Gary Packer
It's not that it's too shallow. Again, we're focusing our efforts in some of the other areas because we have the optionality that the Georgetown provides us to maintain those leases. As you take the Georgetown horizon, which is in the north part and you slide it down into the south, it becomes a gas play. So it doesn't provide the optionality that the Georgetown provides to the north. And I guess the other point is, is that we have a more expanded infrastructure to the south because in many of these new plays, we don't have pipelines laid everywhere. And we elected to focus our drilling activity where we can drive the learning curve, drilling similar wells near infrastructure at this point in 2011.
Subash Chandra - Jefferies & Company, Inc.
And just from a perspective looking at whether it's Northern Maverick or Eagle Ford in general or Alberta Basin, Bakken. I think we've, sort of our first glance, is we want to make it all look like the Williston Basin. But do you think the perspective might be closer to Monument Butte? If you went into horizontal development in Monument Butte that those might be more of the metrics we should be looking at for these developing plays?
Gary Packer
I just think it's too early and I just would hate to speculate on such a thing at this point. All these plays are different, you see variability within the Williston Basin itself, play-to-play. So it's very difficult to start to compare basins that far apart, and think that they'll perform similarly or not after just drilling a few wells.
Subash Chandra - Jefferies & Company, Inc.
Okay, and just finishing up here. The oil wells, Granite Wash, Monument Butte and wet Woodford in Q1, were these PUD locations or were there some on booked locations? And how do you see that progressing through the course of the year?
Gary Packer
So what were the plays? The Granite Wash, where else?
Subash Chandra - Jefferies & Company, Inc.
The Monument Butte and the wet Woodford.
Lee Boothby
I suspect you probably have a decent mix of PUDs and probables or otherwise in the Granite Wash. Monument Butte is probably about, 3/4 of those wells are PUDs. And you probably on the wet Woodford, you probably have a more heavier weighting to the unbooked probables there, just because we're in its infancy of the development that's going on there.
Subash Chandra - Jefferies & Company, Inc.
Perfect. Thank you. And one final one if I could. Could you provide a breakdown between Georgetown wells this year and Eagle Ford wells this year?
Gary Packer
We probably will drill 30-some wells to the south in the net central area where we have about a 200,000 acre position in the Eagle Ford, and we'll drill 4 to 5 wells in the north, primarily in the Georgetown.
Subash Chandra - Jefferies & Company, Inc.
Perfect. Thanks a lot, everyone.
Lee Boothby
Thanks, Subash.
Operator
And now we'll move to Bob Morris with Citi.
Robert Morris
Thank you. On the $200 million increase in the budget, would you say about 3/4 of that is just the increase in service costs and labor costs?
Lee Boothby
Well, we haven't split the numbers out, Bob. I mean, for a reason -- I mean, clearly the biggest reason for that is we want to keep our stealth play stealth until we're ready to talk about it. But clearly, a significant portion of that total is related to the observed increases and we advised that we had made the adjustments to our guidance. So it's not an insignificant portion of it, but each of those elements is -- that was articulated as an important element in that $200 million increase.
Robert Morris
Okay. On the portion of that, that you said it was the efficiency gains in drilling versus what you planned before, how many more wells will you now drill as a result of that?
Lee Boothby
Well, I would say if you look at the Granite Wash as an example, we've got the potential of picking up about 5 incremental wells during the course of the year, assuming that the first 3 wells that George and his team had delivered here early in the year we're able to replicate that performance now through year-end, which we expect. So we'll probably pick up 5 wells there. And at Monument Butte, I would say the 4-day time horizon is in line with our expectations, so I wouldn't expect to see anything incremental there in our normal Green River program. Probably the thing to look for there is when we come out mid-summer with the plans relative to our Harvest acquisition. You'll be hearing about what we've done and what the program is going to look like in terms of optimizing the investment program. So we'll have more than just Green River wells to consider drilling out there, so the investment mix and well count may change. I'd say near term that you should probably expect those to change in the second half of the year.
Robert Morris
Okay. So really, the Granite Wash is the only play that, that efficiency gains will result in more wells being drilled, I guess?
Lee Boothby
Gary's got a comment there.
Gary Packer
Well, you probably have just a handful of wells in the Eagle Ford that we'll manage with how we deploy our rig fleet down there. We've got a couple of rigs under contract. But we could also -- we'll just manage through that. As Lee suggested, we'll have a few more wells at Monument Butte, but that's really going to get caught up in the optimization.
Lee Boothby
Bob, I would say that about 1 on the Eagle Ford commentary, I let that out because we're monitoring the investment environment down there, the pressure pumping services, cost aside are overheated in our judgment and we're working through all the aspects of getting our mind around that plan and what the right development plans are. But we made a point in the call to reference the performance of our team. Terry jumped in and stated that they continue to impress. And I'll just say that drilling and casing Eagle Ford wells, 5,000 foot laterals down there in less than 10 days is not something we were planning for just 6 months ago. So they're well ahead of where we expected to be in that regard, and I think that bodes very, very well as we move towards development in that Eagle Ford shale play, which is a hint to everybody. You need to look at more than just rig count. Because we can certainly deliver a lot more wells per rig year in the Eagle Ford sitting here today than we were expecting 6 months ago.
Robert Morris
You mentioned you continue to hire people, but overhead came in below your guidance range again in Q1. Is that reflective of not being able to hire people as quickly as you anticipated or is that slowing you down at all?
Gary Packer
No, I think that hiring talent is an ongoing process. I think that the statement of saying that we're hiring aggressively is just a statement that we're investing in our future. I think it's important. The crew change that we've all talked about for the last 15 or 20 years is upon us, and we've got to get the young people into the business and trained and developed. They've got to get a chance to learn from all the experienced folks before they decide to ride off into the sunset and enjoy their retirement years, which is just around the corner. Very...
Robert Morris
Those overhead costs in the quarter was below. Why is overhead, two quarters in a row come in a lot lower than your expectations.
Lee Boothby
I'm sorry, I didn't hear.
Gary Packer
The rig costs.
Lee Boothby
I'm sorry I didn't get that.
Gary Packer
Bob, part of its just timing of some things we had expected to happen in the first quarter that we now think will happen in the second quarter. So it's not related to our ability to hire people, it's related to other leases and things of that nature.
Robert Morris
Okay. I guess last question would be, everybody mentioned profit as a bottleneck, particularly in the Eagle Ford. Is that something you're struggling with that could be an issue? Or do you feel comfortable with securing profits for the wells you're drilling?
Lee Boothby
Well, I'll give that to John since he's living it realtime.
John Jasek
Well, we have had some issues just with the profit. And like every other E&P company down in that area, we've been able to manage through it and have profits available when our frac schedules and our frac dates come up. All right, it's just something we're just having to manage through like all the other E&P companies. And to-date, it hasn't been a limiting factor, but it's something we closely monitor everyday as we look at our frac schedules and when they're coming up and the availability to profit. So it's an issue of concern, but we're managing our way through it. And to-date, it hasn't been an issue for us in delaying our jobs or getting our completions on the way.
Robert Morris
Okay. Thank you, gentlemen.
Lee Boothby
Thanks, Bob..
Operator
And now we'll go to William Butler with Stephens Inc.
William Butler - Stephens Inc.
I have one question, just making sure I saw this number right. Production in the Bakken was about 7,000 barrels a day net. Last earnings is in 5,000 now.
Lee Boothby
Correct.
William Butler - Stephens Inc.
Okay. And is that attributable just to -- to what?
Lee Boothby
Well, that's attributed to decline. I mean, I think at the end of the day when you aren't able to complete and turn your wells on, then the wells that are producing decline. I've loved them if they -- if they traded sideways, but that's just not the way these things work. And our 10-well inventory that we're working through is going to give you a real good production surge second quarter through the end of the year. So we built inventory during the course of the quarter and we're working down that inventory now with the new frac services that are in place.
William Butler - Stephens Inc.
Okay. And so, were the delays in drilling more weather-related since then, or availability?
Lee Boothby
No, we've continued drilling. That's how we built the inventory of wells. The delay was in getting the new pressure-pumping equipment into the basin and working for us. We signed agreements late last year to acquire those services and they arrived early April. That was all part of the plan.
William Butler - Stephens Inc.
Okay. Thanks. On this undisclosed resource play, any better sense of the -- when you all might disclose that or is that just sort of later in the year and leave it at that?
Lee Boothby
I'd say, yes, maybe later in the year. That's the way I would couch it at this point.
William Butler - Stephens Inc.
Okay. Okay. And then on your production guidance, does that already reflect any potentially lost production associated with asset sales? Or is there much production associated with those?
Lee Boothby
I'll let Gary Packer update you on that.
Gary Packer
Any of the transactions that have been closed have been relatively modest and that has been reflected in the guidance. Prospectively, as we look at the projects that are still sitting out there, those haven't been baked into the guidance but we view that to be relatively small at the end of the day.
William Butler - Stephens Inc.
Okay. Okay. And then last thing, on the oily Woodford, I mean, have they been on long enough to where you all are seeing the gas-oil ratios, if they're sustaining or changing?
Lee Boothby
George.
George Dunn
Well, yes, we have several of them that have been on long enough to see the trends, and I guess you'd say that these are really just high-yield -- very high-yield gas wells, and so there is a decline in the oil trend that's projected. You're probably seeing some of the public data, but -- so it does decline.
William Butler - Stephens Inc.
Okay., And then lastly on the acquisitions in the Uinta that's between the Altamont and the Monument Butte field, I mean, I know you're all going to comment on it later in the year but how much of what Harvest had booked on the, say, approve basis would've been related to deeper potential zones such as the Wasatch or even the deeper gas Mesa Verde?
Lee Boothby
I would tell you that I think Harvest put out quite a bit of information on their position, some three or four weeks in advance of us announcing the deal. If you haven't read it, I would encourage you to read it, and that'll give you a real good view of what Harvest thought about those assets. I will tell you what we think after the deal is closed and we've got a plan in place that we can communicate.
William Butler - Stephens Inc.
Okay, understood. All right, that's all I had. Thank you.
Lee Boothby
All right, thank you.
Operator
And now we'll hear from Leo Mariani with RBC.
Leo Mariani - RBC Capital Markets, LLC
I wanted to follow-up on the Bakken. You guys identified that as an area where you saw the most cost inflation. I was just trying to get a sense of what your current well costs are out there on some of those Super Extended Laterals you're doing.
Gary Packer
When we entered the year, we had targeted in this as we have this in all of our basins. We have a targeted well cost that was standards of goal and then we have our base and then we've monitored that throughout the year. I'll tell you that when we entered the year, we were looking at low $8 million wells, maybe $8.5 million wells. We've seen and we've targeted something, we believe these wells ought to be drilled for about $1 million less than that. What we've seen thus far is, on occasion, those wells can actually start with a $9 million, and it's dependent upon areas. So I would say anywhere between $8.5 million and $9.3 million wells. I would caution you -- I see well costs printed all the time on Bakken wells, and I think it's important to really make sure that you've got -- you're looking at facility costs, and everything is baked into those costs because we -- our observations are that we sit right in there with the best of the group as far as costs. And I think we're all probably experiencing very similar inflation.
Leo Mariani - RBC Capital Markets, LLC
Okay. You guys talked a little about -- in your prepared comments about weather downtime in the first quarter that caused you primarily to have lower-than-expected gas volumes. Can you guys kind of quantify how much production you think you lost there in the first quarter?
George Dunn
It's probably in the vicinity of a B. It was in the combination of the Rocky Mountains as well as the Mid-Con. I think that, that accounts for the majority of any differences we had between guidance on our realized volumes in the first quarter.
William Butler - Stephens Inc.
Got you. Okay.
George Dunn
And remember, as you saw it in Lee's prepared remarks, were always looking to direct capital to oil in favor of gas these days. So there's always a little bit of noise that's created as we incrementally invest in those oil projects, and that to some degree, you see the results in that as well.
Leo Mariani - RBC Capital Markets, LLC
Okay. Jumping over to the Eagle Ford, can you just give us kind of an update on how things are unfolding from an infrastructure perspective? Are all the wells that you have -- is there any problems with production? Any bottlenecking you're seeing? And you're bringing a big slug of wells on here in the second quarter? Are you able to sort of fully realize all of the sales versus the production there? Is there any issues kind of around infrastructure that you may've been thinking about?
John Jasek
Yes, this is John Jasek. We do have -- as you've correctly alluded to, there's a ton of slug approaching, coming down from the Eagle Ford into South Texas creating some bottlenecks in terms of gas take-away as well as oil take-away from the area. For us, as we talked about earlier in the call, we focus on where we have infrastructure and where we can hook our wells up, drill them, hook them up and sell them pretty much into known outlets. So it is a concern for us, and we monitor it everyday and we manage our business appropriately. And we're able to navigate through the issues that are currently going on in South Texas in that way. So marketing, that had some issues but we're managing our ways. And our wells are located where we can have the right takeaway capacity today.
Leo Mariani - RBC Capital Markets, LLC
Last question for you guys. Just on the Southern Alberta Basin Bakken, sounds like you guys have a number of wells on production at this point in time. It sounds like you're kind of waiting to put out results later this year at some point. I guess just curious as to how many of those wells are actually flowing. Are you just sort of in test mode at this time? Are you actually putting oil in tanks? So just give us any kind of update you can there.
Lee Boothby
I've said this so many times, it probably sounds like a broken record to some of you guys. I'll say it again, we've got 2 wells, I had mentioned in the call that we've completed. Only 2. We have 7 wells down vertically. We've got 1 additional well planned in the balance of this year for that portion of the program. We've got core data, logged data that we collected, being analyzed. And we've got the plans to complete and tests some additional zones during the balance of the year. Expectation would be that if all of that comes together on that schedule. And later this year, we'll be in a position to have some information that we can share. Notionally, I'd say third quarter would probably be the time horizon to be thinking about something along those lines. But we don't have any additional information. We said that all the wells we drilled have encountered oil. I wish I could tell you more. But that's all I know, and I guess we see the same rumors and press releases that you guys chase around and I hope half of them are true, because if half of them are true that's going to become a pretty important producing basin. We're a long ways away from certifying that as Newfield.
Leo Mariani - RBC Capital Markets, LLC
Okay. Thank you very much.
Lee Boothby
Thank you.
Operator
And now we'll go to Anuj Sharma with Pritchard Capital.
Anuj Sharma - Pritchard Capital Partners, LLC
My question is on the marketing in Uinta Basin and Bakken. Looks like, domestically, during the WTI prices went up by around $9, you guys captured only $2.75 in unhedged realized oil prices. So it looks like on the upside, you guys are capturing that as 1/3 of the price increase, and my fear is that some of the transportation deduct [ph] which might have gone up might be -- there might be more secular shifting if the prices come down by $10. Those costs might not come down in the same fashion they have gone up. So can you give me a little bit of color on what's going on there?
Terry Rathert
I think there's a lot of moving parts that are very, very difficult to make a high-level summary of that nature. We have -- the underlying change in the mix in terms of what the relative contributions are is probably the bigger factor. I can tell you that, for example, in the Uinta, oil prices move up $10 a barrel. In that, I'd say, $80 to $100 range we're capturing more than 20% of that move in realizations that the well had. And that's true everywhere. So I think maybe if we need to get into more range varity, maybe Steve can follow up with you on a separate basis. And we can look at some of the components to help you understand why it appears that we don't participate in that much of the upside. But we do everywhere within the international arena where in the international arena, you're subject to supplemental taxes and the way the TFC terms work, you don't participate in that same large percentage of the upside in oil prices.
Lee Boothby
Yes, Anuj, I just may add. I'm just looking at the realized prices that we had there. We started the year at about $75 a barrel realized, and those have gone up to $85 in March. So we have seen a $10 increase in our realized prices out there.
Anuj Sharma - Pritchard Capital Partners, LLC
And domestically, you're saying?
Gary Packer
No, I'm just talking about in the Rockies, we have seen a $10 increase throughout this year in our realized prices.
Lee Boothby
I think I'd follow-up with Terry's comment. We'll get Steve to hook up with you and you guys can work through the details and get all of that sorted out.
Anuj Sharma - Pritchard Capital Partners, LLC
Fair enough. Can you give me a little more color on how the marketing progress on the marketing negotiation is going with the liquid refiners and how much of capacity...
Lee Boothby
Now we'll provide an update on our plans for the Uinta Basin asset in total this summer, after the Harvest transaction has closed.
Anuj Sharma - Pritchard Capital Partners, LLC
Fair enough. Thank you, guys. That's all I have.
Lee Boothby
Thank you.
Operator
And now we'll hear from Joseph Allman with JPMorgan.
Joseph Allman - JP Morgan Chase & Co
Thank you. So Lee, one of my questions was just something you said. So you're expecting that Harvest transaction to close this summer?
Lee Boothby
We're expecting the Harvest transaction to close in the second quarter. Initially, I would say next month. And then we have some time that needs to run after that, before we're able to say anything publicly. So what I would say is plan on us -- at the earliest possible time this summer in June-July timeframe, that we'll have an update and tell you what our plans are out there in this area. We made that commitment when we announced the deal, and we'll honor it when we're able to.
Joseph Allman - JP Morgan Chase & Co
And there was a separate transaction with a private seller as well, is that the same timetable or...
Lee Boothby
That's correct.
Joseph Allman - JP Morgan Chase & Co
Okay. That's helpful. And then earlier in the call you talked about the winter stipulations in the Eagle Ford. And maybe I just didn't listen carefully, but could you just talk abut how that affects your activity and development there? Do you need to just shut down a lot or can you still do stuff while folks are hunting?
Lee Boothby
Since I've said cultural deer hunting, and John Jasek almost all in the same sentence, he participates. I'll let him explain it to you. It's his project.
John Jasek
Yes. I mean, as Lee said, deer hunting is near and dear in South Texas and it's big ranches, they have long-term leases that are very high-valued to the landowners that have been there prior to the leases being taken by our predecessor at TXCO. So there are some leases that have significant stipulations and restrict your ability to drill and complete wells during the hunting season. Now, it's more of an efficiency thing, so there's a decision to be made about what's the right use of capital and how do you manage around those stipulations that are within those. And that's not applying to all the leases. There are just certainly leases that we have down there. So 1 of our issues are managing around those leases to until we get it to full field development, and we can obviously work with those landowners to minimize the stipulations and find a way to go forward on a win-win basis. Some of our leases don't have any stipulations at all. So again, it's a combination of issues out there and during the first program we are likely to stop activity during that season while we regroup and get ready for our 2011 campaign. So it's an issue and we'll work around it, there's a mix of opportunities and ways to solve this problem down there.
Joseph Allman - JP Morgan Chase & Co
So in summary, do you think it'll slow things somewhat but not too much? Or do you think you'll be able to keep it sort of the pace that you -- just as you'll be able to move activity to where there are no stipulations?
John Jasek
Exactly. We'll manage our way through it and we'll maintain the right development pace per the project warrants.
Joseph Allman - JP Morgan Chase & Co
Okay. That's helpful. And then in terms of -- going back to the cost issue and like in the various plays. So in the Bakken, it sounds as if your costs are higher than what you anticipated at the end of the year. On the well performance side, would you say that given more time and data, are the wells performing better than your tight curve? And can you give us the same kind of data for the other plays, so like the Bakken or the Eagle Ford and the oily Woodford?
Gary Packer
I guess I'd say we had pretty high expectations for the Super Extended Lateral wells that we were going to drill in the Williston Basin, and those have delivered the tight curve results. But the bar was set pretty high for them. So as you've seen, we've posted some wells north of 4,000 barrels a day, I think we've scored 2 of those thus far. So we're real pleased with the results of those wells. As far as the relative cost inflation in the other areas, it's a balance. We see cost inflation in all the plays. Everywhere, as Lee alluded to, on fuel and steel and people are all up. The question is, is how much are we able to push back from an efficiency gain? I'd say the Granite Wash team is ringing the bell right now as far as their ability to push back and drill best in class wells and offset those increases that we've been able to essentially hold those flat. As we look into some of the other areas, Monument Butte's probably been about 5% to 6% in inflation in those wells. So very, very modest as we've seen there. Oily Woodford has seen some, but again it's still very early and we're in our learning curve there and enjoying some of the benefits. So highest in the Williston, the lowest in the Granite Wash and everything else is kind of scoring out somewhere in between.
Joseph Allman - JP Morgan Chase & Co
Did I read the press release correctly that -- so your average well cost in the Eagle Ford is $6.5 million to $7 million drilling complete?
Gary Packer
That would be right. And we still stand firm on our thoughts that those ought to be about $5.5 million wells. It's just once we get the learning curve and some of the services in place down there, that's still our objective from a development standpoint.
Joseph Allman - JP Morgan Chase & Co
And how are those wells doing versus your tight curve?
John Jasek
Well, this is John again. We talked about the whole hunting lease pause in our discussion. In 2011, we've got our services in place from a fracture stimulation standpoint. We did our first 2 wells in March, late March. So those wells are first now clinging back up, and so its way too early to tell how those first additional 2 wells are performing from a tight curve standpoint. So we're fracing a little a day, we have another 8 wells planned for next month. So we're just getting into the data standpoint of how the Eagle Ford is going to perform in 2011 campaign versus what we put out last year. So it's kind of where we are. It's too early to tell in the Eagle Ford from a 2011 standpoint.
Joseph Allman - JP Morgan Chase & Co
Got you. Okay. Very helpful. Thank you.
John Jasek
Thank you.
Operator
And now we'll hear from John Herrlin with Societe Generale.
John Herrlin - Societe Generale Cross Asset Research
Just some quick ones. Could you address the number of frac stages you're now doing in the Bakken, the Granite Wash and the Eagle Ford and how much they're up over the not-too-recent-past?
Gary Packer
We're sitting -- I know in the Bakken, we're pumping 32-stage fracs. In the Granite Wash, were pumping typically about 16-stage or so, and that's a very similar number in the Eagle Ford. Typically these are all about 300-or-so stage lengths in each of those.
Lee Boothby
The Williston Basin, John, have been approaching 2x the lateral length.
John Herrlin - Societe Generale Cross Asset Research
Right, understood. What about costs? You gave the amount for the Eagle Ford, what about the Bakken and Granite Wash?
Gary Packer
Just as far as the completion costs?
John Herrlin - Societe Generale Cross Asset Research
Yes, the frac costs.
Gary Packer
Yes, I think they've all held pretty flat this year because many of these are contracted services. We haven't other than some of the fuel and the people costs that have been moved, we've seen some inflation. We haven't really seen any increases over the year. Now I would say that just typically, and all of these plays vary little bit. North of 50% of the well costs in the Eagle Ford is completion, well north of that as Lee just communicated. In the other plays, it's typically common to see about 50% of your costs or so be in the completion.
John Herrlin - Societe Generale Cross Asset Research
Okay, great. You can clearly now drill ahead of the fracs in terms of scheduling. Can you give us any sort of sense of how you're planning to manage those inventories? Or is it more a function of infrastructure or other events? I mean, how should we think about impact wells that need fracs and when you bring them on?
Lee Boothby
Well, I think I'll start and then I'll turn it over to Gary for additional detail, John. I think the statement I made earlier, and I don't know if you heard one of the earlier questions, is we're going to work down through the inventory in the lower Eagle Ford wells. John already mentioned that he's in the midst of working through that at present. Daryll and his team in the Rockies and the Williston Basin had a similar inventory, and they likewise have got the pressure pumping services in place now and are working through their inventory. So our expectation near-term is in each of those areas, we've got 10 or 11 wells that we carried, drilled and cased non-completed at the end of the quarter. We'll work through that inventory during the course of the second quarter and expect the run rate on the back end of that to just be the normal work-in-progress type well count, which would generally be a well or so ahead of the rig schedule.
John Herrlin - Societe Generale Cross Asset Research
Okay, thank you. That's it for me.
Lee Boothby
Thank you.
Operator
And now we'll go to BMO Capital Markets' Dan McSpirit.
Dan McSpirit - BMO Capital Markets U.S.
At Monument Butte in general, can you speak about development spacing? And has 10-acre density been tested?
Lee Boothby
I will tell you that the neat thing about Monument Butte, it's truly an oil resource. That's the way we talk about it and I think that we're really proud of what we've done in building the acreage position out there. You'll recall we started with 40 acres as the original plan in terms of full-field development, Daryll's team has not completed the 40-acre development across the field and, of course, we've added acreage into the mix that now is the time and half again the size of Monument Butte that most of which doesn't have a well on it. So the way to think about the field is 40-acre primary development, 20-acre infills at Monument Butte. We've proven both there and north of the line and approximately the field that that's working and working very handsomely. The 10-acre development would be the next logical step and Daryll's got a significant portion of his technical team in the Rockies working that issue right now. So we're not at a point where we're able to say that we're ready to go, but I will tell you that we see the potential. We believe it's real and we're pretty excited about that being another part of the story for Monument Butte.
Dan McSpirit - BMO Capital Markets U.S.
Got it. And then turning to Granite Wash, will you test additional horizons this year beyond the 10 already assessed? And then 2, can you speak to your statement about assessing new areas, second half 2011 that is targeted objective and location of that acreage?
Lee Boothby
Well, on the first one, we've been pretty clear since the latter part of last year, that were going to focus on the Marmaton section with our Granite Wash program this year. We tested the 10 horizons, build depth of inventory and certainly, we proved that case with the returns. And the 1,300 BTU gas and the condensate associated with the Marmaton, we're going to stay focused there. As far as the location of the incremental acreage, I'd prefer not to speak specifically to that at this time. But if you were thinking it might be just a little bit east of where we've been doing most of our drilling, you'd probably be right.
Dan McSpirit - BMO Capital Markets U.S.
Got it. Thank you very much.
Lee Boothby
Thank you.
Operator
And now we'll go to Cathy Milostan with Morningstar Inc.
Cathy Milostan - Morningstar
Yes, thanks for taking the call. I'm just going to switch gears a little bit and -- we haven't talked about the deepwater Gulf of Mexico, and I saw the start-up of your field there. And just wanted to get some color of what have you seen in the last few months as you're getting this underway that gives you an encouraging sign that progress is certainly being made there, and would certainly help in getting Pyrenees on track for the late 2011 start?
Lee Boothby
Well, I think that starting roughly a year or so ago, shortly after Macondo, we stated publicly that as long as we're able to keep our production online and keep our development projects in train and on schedule, that we thought we would be just fine with the optionality in our portfolio that we can navigate and shift capital around other projects until the business environment settled out. Late last year, we made a decision to reallocate notional exploratory capital out of the Gulf of Mexico for 2011. But hats off and kudos to our team, they have managed to keep all of our development projects online, on schedule. Gladden was a little bit late, as mentioned in the call on a permitting basis. But Pyrenees is the last operated project that we had in inventory. On top of that, our technical team is doing great work in the interim period, really working the prospect inventory. We like the prospect inventory we have in the deepwater Gulf of Mexico, and they're dotting the Is, crossing the Ts in terms of the technical picture there. And at the appropriate point in time when the business environment is truly clear and understandable, we'll make the decision as to what the future holds in terms of investing in the Gulf of Mexico for Nisku. That time is not today beyond the development projects. And we'll revisit it later this year with hopefully a little bit better clarity from the governmental side of the ledger than we have today.
Cathy Milostan - Morningstar
Yes, I was just wondering that if you had -- if you've seen any refreshing change or advancements on the regulatory side there...
Lee Boothby
I think I'd prefer to speak politely and say that we'll take the activity that's happened to date as positive and encouraging signs. But clearly, it's baby steps in what's going to be a long path, in my opinion.
Cathy Milostan - Morningstar
Okay, thank you very much.
Lee Boothby
Thank you.
Operator
And ladies and gentlemen, that is all the time that we have for today's question-and-answer session. At this time, it is my pleasure to turn the call back over to our speakers for any closing or additional remarks.
Lee Boothby
Operator, that's all we have today. I think that I'd like to just thank everybody for your time and participation. And we look forward to updating you on our progress at the end of the second quarter. Thank you.
Operator
Ladies and gentlemen, that does conclude our conference call for today. Thank you for your participation.
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