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Newfield Exploration (NYSE:NFX)

Q2 2012 Earnings Call

July 25, 2012 8:30 am ET

Executives

Lee K. Boothby - Chairman, Chief Executive Officer and President

Terry W. Rathert - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Gary D. Packer - Chief Operating Officer and Executive Vice President

Stephen C. Campbell - Vice President of Investor Relations

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Subash Chandra - Jefferies & Company, Inc., Research Division

Joseph Patrick Magner - Macquarie Research

Anne Cameron - BNP Paribas, Research Division

William B. D. Butler - Stephens Inc., Research Division

Kenneth A. Carroll - Johnson Rice & Company, L.L.C., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Dan McSpirit - BMO Capital Markets U.S.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Operator

Good day, everyone and welcome to Newfield Exploration's Second Quarter 2012 Conference Call. Just a reminder, today's call is being recorded. 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.

Actual results may vary significantly from those anticipated due to many factors and risks, some of which may be unknown. Please see Newfield's 2011 Annual Report on Form 10-K and subsequent quarterly reports on Form 10-Q for discussion of factors that may cause actual results to vary.

Forward-looking statements made during this call speak only as of today's date, and unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements.

In addition, reconciliations of non-GAAP financial measures to GAAP financial measures, together with Newfield's earning 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 K. Boothby

Thank you, operator. Good morning, everyone and thanks for dialing in today. Happy to report that the sun is shining and the sky is blue here in Houston this morning. And I know it's an hour earlier than we usually start, so just enjoy your coffee and we'll run through some of our mid-year highlights as quickly as we can. I'm joined this morning in Houston by Terry Rathert, our CFO; Gary Packer, our Chief Operating Officer; and Steve Campbell, our Vice President Investor Relations.

As you saw in last week's operations release, we are creating value through our oil investments in 2012. We improved upon our execution, we're meeting and beating production estimates, seeing solid results in all of our assessment areas and demonstrated that our asset portfolio has a deep inventory of solid, high return plays to invest in, both now and well into the future.

We believe that our diversified portfolio model provides us with a competitive advantage. In the slide packet we posted last week there is an interesting graph I would encourage you to review, shows the very deliberate steps we've taken over time to capture oil opportunities, accelerate their investment and carefully hedge both natural gas and oil to ensure the balance sheet strength to allow us the ability to execute our drilling plans. We didn't get here today by happenstance, and we appreciate the support of our investor base over that time.

What I see today is a very positive inflection point. Our transition to an oil company is real and more than half of our production will now be derived from high-value oil and liquids production. This is great news and we're excited about what this means for our future.

As you know, Newfield has certainly changed and evolved over time. We've transitioned from a Gulf of Mexico start-up nearly 25 years ago to a company today with core, onshore North American resource plays, lucrative assets in Southeast Asia, and a deep inventory in both oil and natural gas drilling opportunities. We've more than doubled our oil production over the last 4 years, we've transitioned from a company driving growth from natural gas to a company that is driving growth from oil, and we've done it largely organically. We have thousands of low-risk oil development locations that are ready to drill today in our core development areas and our recent assessment results show very exciting early returns in the Cana Woodford, Eagle Ford Shale and in 2 in new plays in the Central Basin region of the Uinta Basin.

More on our assessments later in the call. Our Chief Operating Officer, Gary Packer, will give you a good project-level overview.

I'm excited about our results here today and confident we will ultimately achieve our main goal, readying a development inventory of opportunities that will again propel us to double-digit production growth, driven by oil and financed through our internal resources.

I can assure you that our management team is united in delivering strong results for our shareholders and focusing on maximizing our primary product, cash. I'll turn it over to our CFO, Terry Rathert, to quickly cover our financial results from the quarter. Terry?

Terry W. Rathert

Thanks Lee. Our net income in the second quarter, excluding FAS 133 income, was $82 million or $0.61 per share. Revenues for the second quarter were $627 million. Value creation in or transition oil is evident. 86% of our revenues in the quarter came from our oil and liquids production. Cash flow for the period was $330 million. Our oil and liquids liftings in the second quarter of 2012 were up 40% over the comparable period in 2011 to 6.1 million barrels, or an average of more than 67,000 barrels of oil per day. Our NGL volumes in the quarter were about 530,000 barrels, only 4% of our total production had its realized price of $28 per barrel. Our oil and liquids production comprised 49% of our total production in the second quarter and we expect that more than half of our production will come from liquids in the back half of the year. I look forward to soon reporting our results in BOEs as compared to Bcfs.

I applaud our teams today for delivering outsized oil growth. We entered 2012 producing about 55,000 barrels and we expect to exit this year producing about 75,000 barrels. That's our daily rate. With no investments today being allocated to our natural gas assets, they're on natural decline.

Our natural gas production in the quarter was 39.8 Bcf, an average of about 440 million cubic feet per day.

Natural gas volumes year-over-year have fallen about 14%, which is about exactly in line with the decline we estimated in our full year guidance. We realized $3.48 per MCF on our natural gas sales during the second quarter. Allowing our gas production to decline is, again, the right economic choice. Too often, I hear people focus simply on absolute production growth. With natural gas around $3 and NGLs at just a third the oil price, our obligation to the shareholder must be to create value and we're electing to continue to invest all that we can in oil projects with higher returns as it is. We realized just over $94 on our oil liftings in the quarter. I'll be happy to address any specific questions related to the financials at the end of today's prepared remarks. But for now, I'll turn it over to Gary Packer to update you on a few of our recent operational financial highlights.

Gary D. Packer

Thank you, Terry. Last week, we issued a very comprehensive update on our year-to-date accomplishments. In the interest of time today, I will not rehash all the information, but I will share some insights on each of these areas.

Let's start with an overview of the 2 areas that have been in our portfolio for quite a while and are now seeing much better returns due to longer laterals, optimized completions and improved flow back techniques. Those areas are the Williston Basin and Eagle Ford Shale.

In the Williston Basin, our results are benefiting from steps we took to improve execution and get a handle on costs. Recall that we voluntarily slowed our operations here in late 2011, dropping rigs, deferring well completions and improving our field-level oversight to better navigate the challenges of a classic oilfield boom. These proactive steps are certainly paying off today. We are setting records on days to drill and case, averaging just 25 days year-to-date. This compares with 45 days 2 years ago, 35 days last year. We recently drilled and cased a 10,000-foot lateral in just 20 days.

Our development in the Williston Basin today is largely being conducted from common pad locations, these 2 and 3 well pad sites offer synergies in both drilling and completion timing and service costs are certainly moving in a favorable direction for us to date. We are taking full benefit of cost reductions and certainly anticipate realizing better benefits from these in 2013.

Today, we have an inventory of about 300 ready-to-drill locations in our core development areas on and off the Nesson Anticline.

The geology in the Williston is very favorable for development with stack pays, multiple benches to explore and in addition to the more than 50 Bakken Wells we have drilled to date, we have also drilled several Three Forks wells with good results. We are continuing our field studies to quantify the potential in the Three Forks, as well as the deeper ventures on our acreage. Ultimately, the Williston Basin will have tighter spacing and more development locations producing from varying depths than previously thought.

We have some pilot programs underway today to get us a handle on this, and there'll be more to report on this later. Our Williston Basin production recently hit 10,000 barrels equivalent per day, and our wells continue to perform very well. Our full year production in the basin will increase about 35% year-over-year. We recently added a rig and the economics of our investments in the area today warrant additional activity. We anticipate adding additional rigs in early 2013.

Let's move on to the Eagle Ford. Our recent Super Extended Laterals in the Eagle Ford have performed extremely well. The program's highlights can be summarized pretty succinctly.

First, we are seeing higher sustained rates over 90 days. This breakthrough is a result of changes made not only in the lateral length, but in how we are completing these wells, our controlled -- and our controlled flow back techniques. Our wells are producing about 1,000 barrels of oil equivalent per day and we have as much as 1,500-PSI flowing tubing pressure after 30 days. Again, we are intentionally managing the rates to limit pressure drawdown and maximize our anticipated ultimate recoveries over time.

Second, we are seeing higher EURs. Our production data is indicating significant increases in our recoveries and the wells are performing well above our type curves. We estimate that the EURs are in excess of 500,000 barrels equivalent. We need more wells and more time to confirm, but we are very encouraged to date.

And lastly, all of our improvements are translating into better economics. We are drilling these SXLs in about 12 days now and our drilling case cost are less than $3 million. Our drilling team has done an outstanding job lowering drilling cost. Completion costs remain high, but we are seeing signs of encouragement, our lower pressure pumping costs as we enter 2013 and be assured, we'll take advantage of these. Our completed well costs from pads should average about $8 million gross. At these costs, our Eagle Ford SXLs have a IRR of more than 35% and are confident that they will improve as we progress.

These recent breakthroughs have made our Eagle Ford investments competitive with other choices we have in the Newford -- Newfield portfolio today, and as a result, we are increasing our planned activity in the play and have allocated capital to drill at least 6 additional SX wells -- SXL wells in the second half of 2012.

Let's look at the West Asherton area as an example. At 120-acre spacing, on 18,000 acres, we have over 100 ready-to-drill locations. This equates to 35 million barrels or more, net to our interest. Industry wells just across the leased line are now being spaced at less than 80 acres. With continued strong results in the second-half SXL program, we will be in a position to allocate additional rigs to our Eagle Ford program in 2013.

I realize it's been a while since we've talked about the Eagle Ford play. You recall that we acquired the acreage for less than $500 an acre through an acquisition 2.5 years ago. And our recent success leaves us encouraged about the potential commerciality of the Eagle Ford across more of our acreage. Be assured, our teams are focused on expanding the economic footprint beyond just 40,000 acres.

Let's talk about our new assessment programs now in the Cana Woodford, the Uteland Butte and the Wasatch of the Uinta basin.

In late 2010, we started leasing east and south of the known Cana Woodford trend in the Anadarko basin. We have now been able to assemble rapidly over 135,000 acres for approximately $1,000 an acre. Our geologic concept indicated higher yields and the ability to produce from the oil phase.

Our 2012 program called for the rapid assessment of this acreage with the hopes to being able to push the play into development mode by 2013. Many of you likely questioned our decision to dedicate $300 million to a play we seemingly knew little about. But I would argue that's not the case at all. Recall that we have drilled nearly 400 cores horizontal Woodford wells just a few counties to the east in the Arkoma basin. We're a proven operator in Oklahoma and we have quickly transferred our learning curve to the Anadarko Woodford.

Since January, we have been running 5 rigs in the Cana. We are highly encouraged with our results and they are included in our recent well test in last week's operational release. In addition to these wells, we have also participated in roughly 40 industry wells operated by others. This success also provides us with increased confidence about the quality of our acreage. Our activity to date has focused on our southern acreage, which covers about 80,000 net acres.

We have initial flow rates of nearly 2,000 barrels of oil equivalent per day in black oil content that ranges 25% to 65%, depending on where you are in the liquids phase. Our wells are exhibiting strong pressure and our controlled flow back techniques here as well, are helping us sustain strong flow rates over an extended period of time.

And our mid-continent team has done a great job of quickly applying our learning curves to drill cost-effective wells. Our first wells in this play took about 100 days. Pretty much anticipated in the early phases of these types of assessments. We recently drilled and cased a well in less than 45 days, an industry regional record. These efficiency gains translate into higher returns and will help us increase our annual growth. Although it's early, we estimate that these south Cana Wells have gross EURs of 1.1 million to 1.7 million barrels equivalent and will deliver 35% to 50% internal returns at today's commodity prices. I'm confident we will be able to continue to improve on our drilling performance and further optimize our completions.

Our activity in the second half of this year will be weighted towards the southern acreage, however, we are planning to continue our assessment of the northern acreage and an SXL will be drilled later this year. The area encompasses about 55,000 net acres and has potential for wells with a very high black oil content.

My last topic, before we open the call to questions, is the Uinta Basin. We are developing multiple oil plays on more than 230,000 net acres in the Uinta. Since 2004, we have been exploiting oil plays in the region and have grown to become Utah's largest oil producer. We clearly have a competitive advantage in this basin. Our 2012 program is largely focused on the Central Basin an area north and adjacent to Monument Butte. We methodically grew our acreage position in this area. Beginning in late 2009, we identified and captured new oil plays, 2 of which we are now entering on development, the Uteland Butte and the Wasatch. Our new plays have tremendous resource potential and their development has the ability to drive our domestic oil production growth for many years to come into the future.

Let's talk about the Uteland Butte first. Our early wells in this play were drilled under Monument Butte field. They IP-ed at around 500 barrels a day, but we were confident that the play was even more prospective as we moved to the north, deeper and into the higher-pressured regime. The data we gathered from these early wells was instrumental in our ability to capture additional acreage in the Central Basin during 2011. We have recently migrated our drilling campaign to the pressured regime in the Uteland Butte play. And our most recent well commenced production at nearly 1,500 barrels of oil equivalent per day, of which, nearly 90% was oil. The well averaged nearly 1,300 barrels equivalent a day over the first 7 days of production. We have 2 wells to date in the pressured formation at the Uteland Butte and their average production is at least 3x that of a normally-pressured Uteland Butte.

Our first wells have now been online more than 30 days, and it's average production over this period is nearly 1,000 barrels equivalent per day. That means the well cumed about 28,000 barrels in its first month. This well has a lateral of less than 4,000 feet. So let me put these numbers in perspective for you. After drilling about 30 wells in the Bakken, we know that are 5,000 foot laterals cumed just under 20,000 barrels in their first 30 days. Our estimated EUR in the Bakken for a 5000-foot lateral is about 500,000 barrels and cost about $8 million. So our recent Uteland Butte pressured wells cumed normally -- nearly 30% more than the lateral and is 1,000 foot shorter and the well cost nearly $3 million less than its sister well in the Williston Basin. These early wells are indicating EURs of over 400,000 barrels. That's significant when you consider we have more than 70,000 net acres in this play. We are highly encouraged with the results to date. We plan to drill about 15-or-so additional pressured wells in the play later this year.

Our other exciting play in the Central Basin is the Wasatch. We've drilled more than 30 wells to date and the play has very strong economics.

Year-to-date, we have completed 18 vertical wells with an average initial gross production of nearly 900 barrels equivalent per day and 30-day average of more than 400 barrels a day. We recently completed our first 2 horizontal pressured Wasatch wells. The early flow rates on these wells are encouraging and we are looking forward to seeing what the near-term max rate will be, as well as the 30 and 60 day performance data.

Before we open the call to questions, let me mention our Malaysian operations where we recently set a record production of more than 30,000 barrels a day, net, and our gross production today is more than 75,000 barrels a day and our production here sells at Brent pricing. Like the rest of the organization, our team here has done a great job of bringing new developments online, drilling field development wells from platforms to maximize production and finding expiration projects to meet our future growth needs.

In the second half of this year, we have 3 high potential exploration wells planned. The first known is Paus North, a deepwater Block 2C and an appraisal of a 2008 discovery and that well is drilling currently.

With that, I'll flip the call back to you, Lee.

Lee K. Boothby

Thanks, Gary. And thanks to all of you for your interest and support of Newfield. We're very pleased with our performance at mid-year and are certain that our performance year-to-date and our positive trajectory are building momentum for what will be a superior 2013 and 2014 as we complete our transition to oil.

With that, I'll open the call for your questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Brian Lively of Tudor, Pickering, Holt & Co.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Lee, given the success that you've had now in the Cana Woodford and then, I guess, the incremental success from the Eagle Ford, can you provide an update on just overall portfolio and then any incremental rationalization plans?

Lee K. Boothby

Well, I would say that the success, as Gary indicated, in both of those areas is very positive. We're still early days in the Cana Woodford, we continue to plan an aggressive assessment, shifting to development campaign in the second half of 2012. So as the year unfolds, we'll have a lot more data at year-end to fully and properly assess the potential and the game plan relative to Cana Woodford. In the Eagle Ford, I would say the transition to the Super Extended Laterals opens up an inventory of opportunities. If you think about the 40,000-acre position we've described historically as developable, the 7,500-foot laterals and the results we're seeing there make that a pretty exciting piece of business as well. Gary gave an example on a fraction of that acreage where we've got more than 100 ready-to-go development wells. You translate that across the broader package, you're looking at 250, 300 wells that we can pound down there in the Eagle Ford. So I think that, thinking about those assets, they provide a really nice opportunity to accelerate oil development activity and our further hope would be, particularly in the Eagle Ford, that with additional success, that we will be able to expand the economic footprint there as well. As far as rationalization, additional asset opportunities, I would tell you we have nothing on the radar screen at this point. We've done a lot of that work over the last couple of years, in terms of shedding nonstrategic assets. We have a lot of that activity in 2011. But truth be told, we've got a grow-hold-divest mentality within our management team and we're going to regularly look for opportunities to shed assets that we deem noncore, nonstrategic and really double down on the areas where we're getting the best returns and the best results to drive future production and cash flow growth.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And Lee, I apologize if I missed this, but what's the status of the Gulf of Mexico divestiture?

Lee K. Boothby

I don't know that you missed it, we're not at a point where we're prepared to discuss it. We've still got ongoing discussions and activities related to that. And my hope would be that we'll have resolution of that issue here within the month.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, and then last question for me. Gary, you gave some good cost details in some of the plays. But in the Cana Woodford itself, what have you guys seen in terms of pro well costs and then what do you guys think, pro forma, those costs would look like?

Gary D. Packer

Yes, I mean, it's really difficult early on in these plays, as I described, as you're still investigating casing programs and ways to optimize the wells at 100 wells -- at 100 days, clearly, that's not a description of what we ultimately anticipate these wells to take to drill. We're also investing a lot of science in the early wells. So I don't think any of that really is germane in this early -- really early phase. I would tell you, we -- the progression that we're going right now, our investment thesis originally, that we were going to drill these wells for about $8 million or so, and I think we're well on our way to get there. But we're still learning. But we keep the momentum that we have today and recently posting wells in the order of 45 to 50 days, we're well on our way to get there.

Lee K. Boothby

Yes. And I think, one last thing and then we'll move on to the next question. But on that point, is I'll refer you back to the history we've had, Gary referenced in the Arkoma Woodford as we moved in to development. We published a few years ago the second, third, fourth well on the section. We've demonstrated, time and again, the ability to drive those costs down. So I think we're in a really good place and a great trajectory and I think we're getting the pay off for the accelerated program that we kicked off in early 2012.

Operator

We'll go next to Leo Mariani of RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Yes, there was an earlier comment, I think terry made it in his prepared remarks, about getting to a 75,000 barrel a day liquids exit rate. I just wanted to confirm that, that was the number you guys are expecting for the end of the year, because it certainly looks like it's above your guidance for 2012. Just wanted to get some color around that.

Terry W. Rathert

That's where we're headed toward the end of the year.

Lee K. Boothby

Now remember the guidance allows for potential planned shut-ins in Malaysia, for operations that Petronas has planned and some things that are outside of our control. But we've got great growth momentum in the oil and we expect that to continue through year end.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. Can you give us a little bit more color on the potential size of the 3 exploration wells you guys talked about in Malaysia here that you guys are going to drill in the second half?

Lee K. Boothby

Well, I think, the only color that we'll give is the one that's drilling. We've talked about a lot over the last -- the course of the last years, is the Paus well. It's on deepwater Block 2C, it's an appraisal well, drilling an up-structure fault block from a 2008 discovery. We've advertised that, that up-structure fault block could have 200 million to 400 million barrels of oil potential. It also has the potential of being gas condensate, which is largely what we saw in the original discovery well. Either of those outcomes, success case, we hope to put over an economic threshold in that project and allow us to continue to build our business offshore Sarawak, that's the game plan. The other 2, we haven't advertised and there'll be probably more color on those as the year unfolds. We expect to do those spud. The second of those will be a follow-up well on the SK 310, where we drilled the pinnacle reef gas discovery a little over a year ago. So we're drilling an adjacent pinnacle reef within about 3 miles of that discovery well. And in the interest of trying to not turn anybody away from questions, let's try to keep the questions to one, and possibly a short follow-up, and then we'll move down the list. I don't want to turn people away that are waiting in the queue.

Operator

We'll take our next question from Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, in the Cana, with the 6 wells that you guys drilled and various oil cuts and initial IPs, you mentioned that, that was really locationally driven. Was there anything to do with different completion techniques on any of those 6 wells? Or are you noticing anything different about how you're competing wells going forward?

Lee K. Boothby

I'll let Gary take that question.

Gary D. Packer

We continue to modify our completion techniques there. I would tell you that the control flow back is probably the biggest driver in what we're doing there. We continue to experiment with our stage spacing, number of clusters per stage and profit types and the like. But I would tell you that the -- I'd say the game changer for us year-to-date, and this applies broadly over many of the new plays that we announced last week, is the controlled flow back techniques, where we're just not opening the wells up haphazardly, we're actually bringing in rather slow. We're really taking great pains to minimize the draw down that we placed on the completion. We're seeing higher condensate yields as a result of that, we're seeing higher flowing tubing pressures sustain much longer and we think, we're maintaining better conductivity to the formation. We're seeing that in all 3 of our plays, and I think that's probably the biggest change that we've seen. But we continue to tweak it. Clearly, 6 wells is not enough to figure out what special sauce is and we'll just keep trying.

David W. Kistler - Simmons & Company International, Research Division

Great, I appreciate that. And then one question quickly on the Williston. You mentioned that you might be looking at a downspacing program. Can you talk a little bit more about that and where specifically you're looking at downspacing?

Gary D. Packer

Sure. We actually have 3 downspacing or spacing pilots underway right now. The spacing on those projects would be anywhere between 750 and 1,060 feet. That's much tighter than what industry has done. But we're doing that as a means to really accelerate our understanding of what the proper spacing ultimately is. So we're not much different in the industry as far as how we have things booked currently, but I can tell you that some of the tests that we'll do may be pretty revealing. I would've anticipated industry to be further along with this. But we're not, and therefore, we're going to -- we're probably pretty aggressive this year in the 3 tests that we're undertaking right now.

Operator

We'll go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

First, on the Eagle Ford SXLs. When you talk about drilling an additional 6 wells this year, can you characterize those? Are they more development wells based on the success you've seen, or more step out of assessment wells of other parts of your 40,000 acres? And then, I think you mentioned that you may be seeing more potential on your Eagle Ford or Maverick position beyond the 40,000 acres. Can you add a little bit more color on that and the timing of that assessment?

Lee K. Boothby

Sure, Brian. I'd characterize the wells that we'll drill the remainder this year as development. They will largely be 7,500-foot laterals, but we're actually going to attempt a 10,000 foot test as well. The reference to expanding the acreage block as we continue to move to the north, we get shallower in the section and we think some of the completion techniques that we've utilized that we think -- that we attribute some of the success that we've had in the SXLs, again, I don't think it's all about the length. From a completion standpoint we've changed our technique up quite a bit and we have not applied those to some of the shallower depths. So that's really what the objective there is. We ought to have one well tested in a shallower section later this year. And pending the results of that, that's something we'll be able to expand upon in 2013.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, that's helpful. And as a follow-up going to the Uinta. When you think about the better performance that you're seeing in the pressured parts of the Uinta and mirror that in the context of getting Black Wax oil to market. Are you able to drill the same number of wells, get more oil out than you thought and get that oil to market? Or do you end up drilling fewer but better wells due to midstream constraints? Or is everything you're seeing basically just in line with your expectations?

Lee K. Boothby

Let's see here, I'll take that one and Gary can fill in any of the details that I blur. I would tell you that when you look at the uplift, and we talked about this, Brian, for most of the last year in terms of our plans and visions for the Uinta, particularly in the Central Basin acreage, we started aggressively assessing that vertically so we can understand the section that we were drilling through and we started talking about a transition to horizontal testing. We've been really excited about getting that program kicked off and the fact that these well results are coming back so strong provides plenty of options. First thing I would say is that we have the long-term agreements in place to be able to move our crude. So when you think about our game plan, it's doubling production out of the Uinta Basin between now and 2015. That will allow us to fully utilize the capacity that we've signed up for. And I think in that context, the sooner we get there, the better. So all things considered, if we were running full capacity on the basin as things were opening up, it would allow us to shift capital into other project areas, because we will be able to generate higher yield -- production yield per effort, utilizing the horizontal drilling. But again, remember we're relatively early. I mean, we're very, very encouraged with results. I think we've got good strong results and sustained production on the pressured Uteland Butte wells that we've announced. And then our 30 wells that we've completed in the deep pressured Wasatch gives us high confidence in that overall section. But we're still very early there. We've just turned on our first few wells and we haven't yet released that information. So we'll continue to work the marketing and export side, but there's not anybody out there that should be losing sleep over Newfield's ability to move barrels in the Uinta Basin. I think we're in real good shape there. Gary, you got anything you want to add?

Gary D. Packer

Well, I think, you're familiar, Brian, that everything we drill in the Central Basin is going to be yellow wax. We have no issues on the Black Wax side, as Lee referenced. We're currently moving about 7,500 barrels a day or so equivalent out of the Central Basin, most of that is all oil. With an aggressive campaign that we believe that we could yield from this, I mean, you can do the arithmetic as well as I can, with the kind of wells we're posting there, we could be looking, end of next year, 20,000 barrels a day or more and in that situation, we are going to continue to look to capture ever-increasing yellow wax markets. But that's a really good story for us, that kind of growth. So we continue to work it. We see a lot of opportunities both in the basin and out of the basin for marketing.

Operator

We'll go next to David Tameron with Wells Fargo.

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

Just staying on the Uinta. There's been a perception out there that, just given the pullback in crude prices, some were speculating the Uinta is not as economic as other plays. Can you just talk about -- and you covered in the well cost a little bit, but can you talk about your IRRs coming out of Uinta and where that kind of rates in your program relative to other basins? Where you have development, like the Bakken?

Lee K. Boothby

Sure, David. When you look at the results that we posted last week, I would say each of these plays compare very favorably. As I referenced, and I only have 30 days to go on as we already described, but if you just look at the early results, it would indicate that a Uteland Butte well ought to compete very favorably with a Bakken well. Now that's only after 30, 60 -- and we have to watch this, as you well know, well longer than that. The trajectories of these wells are relatively unknown at this point because we're really blazing new territories, a new formation, drilling wells that have not been drilled before. But we're very optimistic. I don't know about the perception that's out there, but after 2 wells, these wells are over-delivering what some of our early modeling would suggest. And I would tell you I think they'll compete very favorably. But we have drilled far more wells in the Uinta Basin, and even more recently, in the Eagle Ford. So we have our minds clearly around where those compete, and they compete very favorably. But I would say, based on the early results, and that's all I could speak to at this point, that a horizontal program in the pressured Uteland Butte will not have any difficulty in any -- in a commodity price anywhere close to where we're at right now.

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

Okay. And then let me just, as a follow-up. Some of your competitors talked about potentially adding rail coming out of the Uinta to ease up some of the capacity or take care of some longer-term capacity requirements. Can you -- have you heard that? And I know from Newfield's perspective, you're talking about you guys are fine as far as takeaway, but have you heard that? And if so, any comment on that?

Gary D. Packer

I think, yes. I have heard that. It remains a legitimate option to take to market and we're exploring opportunities to at least test some of those markets out. So, I'll confirm that for you.

Lee K. Boothby

David, I'll just jump in and add a couple of reminders. Remember, we've been operating out in the Uinta Basin since 2004. We've drilled more wells than anybody else out there. We're the biggest oil producer in Utah, we dominate the Uinta Basin particularly on the oil side, we've got all kinds of synergies that work through the system that are related to that, that frankly our peers don't have. So I think we're in a wonderful position in that regard. And I would count on you and your peers to start changing the game, if you will, and erasing the urban myth. There's been a lot of bad things written about crude in the Uinta Basin. Fact of the matter is, it's a high-quality, high-value crude. Just ask the refiners. And I think that the wax issue is way overblown. I think people just don't understand it, but it's a high-quality crude and the economics on these wells, if you got the kind of results that we've been generating out over the last 12 months out of the Uinta Basin, the vertical well program in the Wasatch, early return from the horizontal, our experience in multiple basins, you got to be excited about where we're going to take this thing from here. So I like where we're at and I think we'll just let the results speak for themselves as we move forward.

Operator

We'll go next to Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc., Research Division

I was curious in the Cana, Stevens County, Garvin County. Has there been results there before? Is this sort of a frontier program, if you will? And of the 6 wells, were any drilled -- of wells drilled to date in the Cana were any drilled in that area? And how much further south you think the play might extend for these million-barrel-type results?

Lee K. Boothby

Well, I'll start talking while Gary is looking at a reference map. This is Lee. I'm going to remind you, Subash, that our odyssey in the Woodford actually started in this area in Southern Oklahoma, literally 10 years ago. And it started by studying the vertical wells and what's historically been called the big 4 play. And I think that Golden Trend area, if you want to go ahead and look for reference. And I would tell you that, not knowing anything about shale in 2002 or looking to redefining our strategy in the Mid-Con, we decided to go the unconventional route, relatively early on. One of the key pieces of data was some production logs that we ran in some wells that we had drilled, vertical wells, in 2001 in the Golden Trend and imagine my shock having grown up in the Gulf of Mexico to see that the primary producer in the big 4 in those wells that we ran those production logs in was the Woodford Shale and it was producing oil. Okay? Back in that timeframe, gas was the preferred commodity, so we went to the Arkoma Basin to chase gas. The fact of the matter is the Woodford in Southern Oklahoma has been producing oil for 30 or 40 years, it's just been co-mingled and therefore I think a lot of people missed the fact that it's been a real key part of the overall production down there.

Gary D. Packer

Yes, the only thing I'd add to that is I believe, Subash, that the majority of our wells have all been drilled in Grady County. We are intentionally not posting the well locations out there, but we've drilled a mix of wet gas wells and what we would consider classic oil phase. And some of those may get into Garvin, but we've not posted those to date. It'd be really speculative on my part to tell you, until we've actually drilled the wells, how far that will extend. But clearly, as we push the play to the east, we'll be getting in more of an elect [ph] window and you'll just have to stay tuned for our results as we do that.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And the follow-up in the Bakken. Could you just spell out the rig count, I think you added a rig, what number of that is,, if you got up to 4, plan to get up to 4 or not this year? And then on the locations, I think you said 300, does that include Three Forks? And what sort of spacing in Three Forks that might include?

Gary D. Packer

Yes, the -- as far as the rig count, as I said late last year, we backed off to 2 rigs. We are -- we currently have 3 rigs. One of those is a new build that we've been swapping out for one of our existing in the rig fleet. And then we would look at adding another rig, a fourth rig, probably in 2013, as early as possible, pending capital budgets and so forth. As far as the Three Forks, I believe that has 2 wells per section, but I would have to confirm that for you. We've looked at anywhere between 2 and 4, but in that well count, I don't think we utilized the full 4 count in there.

Operator

We'll go next to Joe Magner with MacQuarrie.

Joseph Patrick Magner - Macquarie Research

I'm wondering if you could provide a breakdown in terms of price differentials, oil price differentials between your various domestic oil plays, primarily the Uinta, the Williston and the Cana Woodford?

Stephen C. Campbell

Joe, this is Steve, I'm happy to do that. I don't have it with me, but I will pull it up and send you a range of differentials for each of those areas, but we didn't see anything in the quarter that was out of the ordinary.

Joseph Patrick Magner - Macquarie Research

Okay, I guess I could follow-up with you off-line. There was a comment made about the yellow wax growth and there's been a lot of focus on takeaway capacity and locking up long-term contracts on Black Wax. Just curious, you talked about running 7,500. Now, what kind of limitations are there and what kind of capacity exists on the yellow wax side now and what will be required to expand or capitalize on some of those market opportunities you referred to, Gary?

Gary D. Packer

Yes, for some obvious reasons, I'm not going to be too transparent with you on some of the options that we're exploring out there. I would tell you that we see 4 to 5 different avenues to expand our existing marketing of yellow wax. I think no different than black, it is something that we need to continue to work. As we have on the black, to enter into long-term agreements to expand the capacity. But it is certainly not something that we could sit back and do nothing about, or we will run into a cap. So I would anticipate through the balance of 2012, seeing us enter into some commitments that would allow us to make some immediate enhancements to the refining capacity. That is something that ought to happen by the end of the year to get us into and well into 2013. But I would tell you that we're going to have to pursue some additional areas of marketing as we look to 2014 and beyond. It's something that we got a lot of effort at -- in right now, Joe, and we'll just have to visit with you later on the specifics.

Joseph Patrick Magner - Macquarie Research

Can you address at all the current capacity?

Gary D. Packer

I don't have the information in front of me right now. I'd hate to speculate, but it's probably on the order -- somewhere in the order of 15,000 barrels a day or so, which would be out there available. So we're going to have to go get a little bit more as far as to live up to the growth, the capacity that we have by the end of '13. But I'd say 15 is pretty close.

Lee K. Boothby

And Joe, our arrangements with the -- the 2 long-term arrangements have allowances in there for yellow wax as well. So we've covered ourselves in the short term.

Joseph Patrick Magner - Macquarie Research

Okay. One last quick one, in terms of outstanding or ongoing assessment work. Any update on the Southern Alberta Basin at this point?

Lee K. Boothby

Well the update on the Southern Alberta basin is that we have no activity up there at the moment. I think that we've been monitoring industry activity. We transferred responsibility for that play to our exploration adventures team here in Houston. They continue to monitor activity, both on the U.S. side as well as on the Canadian side of the border. We've got term left there, some 3.5, 4 years remaining on our exploration phase and no need to aggressively pursue any activity in the short term. So monitor the results of some of the competitors in the area and we'll revisit that going into 2013 as far as the forward plan.

Operator

We'll go next to Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just a question on the Cana, given that you're ramping up activity as fast as you are. Could you comment a little bit on the midstream arrangement that you have in place? What stage are you with securing gathering systems and have you sought any partnerships with any midstream companies for processing?

Gary D. Packer

We're very far along in that and I would look for something -- we'll probably have something contracted in the third quarter.

Anne Cameron - BNP Paribas, Research Division

Okay, no more details on that or...

Gary D. Packer

No.

Lee K. Boothby

Not at this time.

Anne Cameron - BNP Paribas, Research Division

Okay, and can we have an update on your drilling program at the Pearl Development, offshore China?

Lee K. Boothby

Go ahead, Gary.

Gary D. Packer

Pearl's progressing nicely. We have our topsides rig and jacket all under construction in 3 different yards in China. Everything is progressing as scheduled, and we anticipate being in a position to be out and on production. Late 2013 would be aggressive, early 2014 is very likely. I actually visited the yards and visited our offices out there in April and was really pleased with how things are progressing.

Lee K. Boothby

I'll be making a trip this fall in August as well. So we're real pleased with the progress the team made in China.

Operator

We'll go next to William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

In terms of Malaysia, you all had previously talked about expected downtime in the second half of the year and you all may have tried to address it with an earlier question. But can you be any more specific on the timing of that downtime and whether it should impact 3Q versus 4Q more?

Gary D. Packer

Yes. There is downtime. We were a bit oversold in the second quarter in some of those from a lifting standpoint. And that's the thing we have to keep track of, is some of those lifting impacts are going to be felt in the third quarter. So ultimately, I think the number's going to be somewhere around 300,000 barrels, we'll be impacted in the third quarter just due to timings or liftings. There will be an incremental shutdown that's associated with our Tapas [ph] facilities downstream of our PM 323 project just doing some platform modifications, which will impact our production. But that's all factored into the guidance that we have out there right now.

William B. D. Butler - Stephens Inc., Research Division

Is that Tapas, is that going to be third quarter also?

Gary D. Packer

Yes, that's going to be a third quarter impact at about 300,000 barrels or so.

William B. D. Butler - Stephens Inc., Research Division

Okay, great. And then one other question, there's been some increased discussion about the Pearsall, in the Eagle Ford area, and you all previously discussed that, particularly in Maverick County. How would your geology there differ necessarily from sort of the [indiscernible] that guys like Cabot have pursued recently? Is that something that we could expect you all to have some potential for and have some oil there? Is that mostly going to be gas where you all are?

Gary D. Packer

It's our expectation that Pearsall in our area is primarily dry gas and then some of the JVs were announced, they were more of the wet gas liquid phase.

Operator

We'll go next to Kenneth Miller with JC Capital Management.

Unknown Analyst

I had a question on your return on investment capital criteria. What do you use for the allocation of capital to your projects? And how are these major areas that you discussed tracking these objective returns for the corporation?

Terry W. Rathert

Well, I would tell you, Kenneth, that we look at a variety of return criteria, it's not just one single thing such as rate of return or profit to investment ratio. And it depends in part on the nature of the project or the prospect and the level of uncertainty. But generally I would say that we look to our projects on a project-level basis to have in excess of a 25% pre-tax internal rate of return. In the international arena, we certainly look at things on an after-tax basis, because the nature of our activities in Malaysia, we're a taxpayer. When you look through our P&L, those current taxes are from Malaysia, because we've been extremely successful and highly profitable there. In domestic arena, due to the nature of high component IBCs, most of our current taxes are deferred, and so you'll see very little current tax. So generally I'd say that it's in excess of the 25% internal rate of return would be kind of a guiding type of value and the major projects that we invest in to deliver that in development phase. Clearly in the early stages in these assessments, we don't expect that to be the case. And I would ask you to go back and look at the history of our activity in the Woodford as an example. Where we started out -- I think, when Lee was in Tulsa and drilling those early wells, I kept telling you, we got to get through this first, 20, 30, 50 or whatever it is to make some better returns, and he kept telling me, we're getting there, we're getting there. Because we're driving the returns to experience and the activity and continuity of activities in these resource plays, you develop synergies and development cost efficiencies. And everybody that's in a major position in these plays can show you their track record of success in terms of driving costs down, improving returns through time. That's one of the benefits of large resource plays, and one of the reasons why you need to have a substantial acreage footprint for them to really generate the returns, because you have to get on that learning curve and drive the cost down. And that's exactly what we've done. So I would say, is that I think, we're on track in all of our resource plays. Where we're headed in that direction. Clearly, the first dozen wells are not going to be 25% returns. Those are more about identifying and assessing the opportunity and understanding where it fits in relative space in the portfolio, as compared to investing for that return to date.

Kenneth A. Carroll - Johnson Rice & Company, L.L.C., Research Division

But when you look at your entire investment properties, have you seen any long-term relationship between achieving your rate of return, rate of return on invested capital objectives, and either your stock price performance or enterprise value?

Lee K. Boothby

Well, I think it's a very interesting, try to factor in and figure out what's at play when. If you go back to the early part of 2000, we're a gas-focused company, and we're driving those results in the Woodford and we had the synergies coming and then gas prices went down. We've converted and invested in oil. And so I think that conversion investing in oil, because it generates more cash and more cash flow will translate into share price performance. But it has to be recognized and has to have visibility and that's what 2012 is all about. It's showing the capability, the capacity of these resource plays, the new ones we've entered into in terms of the Central Basin and multiple play sites in the Central Basin, the Cana, Gary mentioned earlier, the game changing types of performance we're seeing in the lower Eagle Ford now with the extended -- the SXLs. Those, when there's clear visibility, will transfer into share price performance. And we have a deep portfolio of those and have done that. If you look through time, we've done that transition from gas to oil organically, not unlike we went from being a Gulf Coast player, where our reserve life was 5 to 6 years to having a reserve life of 13 organically. And so, those are -- they take time to go through those transitions but they will translate.

Kenneth A. Carroll - Johnson Rice & Company, L.L.C., Research Division

Well it's been an excellent performance so far. One other quick question. With the 12 month, I guess, natural gas price drip now at $3.45. What would it take for you, I guess, either financially or maybe even emotionally to reallocate capital to your gassy Woodford properties?

Lee K. Boothby

I don't have any emotion attached to returns. It's all financial. So all it would take would be for the returns in those investments to compete with the returns we have in our oil portfolio. And I can tell you, it depends on the cost structure. If you had a unique cost structure in a gas basin at $3.45 where the cash generation for the dollar invested was equal to or greater than what it would be if I'm invested in oil at $90 a barrel, it would get allocated capital. Today, I don't know of a gas basin in North America where you can invest as much and get as high a return cash-on-cash as places like our Uinta Basin, the Williston, our lower Eagle Ford with 7,500-foot horizontals.

Kenneth A. Carroll - Johnson Rice & Company, L.L.C., Research Division

Understood. What about at $3.85 to $4 gas? I notice your latest hedging position, you sold gas at about $3.85, unless I'm incorrect. So at $3.85 to $4, would that become competitive with the others or would it take even more?

Gary D. Packer

I'll answer that question with -- and then I'm going to move on to one more. And so if you look at our year-end reserves, our year-end reserves were down to just about $4, in the ZIP code of current oil price, and we have moved all of our proven -- substantially all of our proven undeveloped oil reserves into probable because we don't intend to drill in the next 5 years. So that's a $4 number. We still have gas production coming from the legacy properties we're not drilling and developing, but it's producing. And so we're, in essence, improving the certainly around cash flow from those operations with those hedges.

Operator

We'll go next to John Herrlin with Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Just some quick ones. With respect to controlled flowbacks, what kind of an EUR uplift do you think you're getting by that approach?

Gary D. Packer

Well, John, it's a good question and it's something that we just don't have enough history yet to confirm it for us one way or the other. So I'd really would have say stay tuned in order to determine exactly what that's going to be. It's not -- if I think about like the Eagle Ford, to where it was and where it is today, on a similar well, I may be able to get to somewhere around a 40% increase. If you think about a well today, if it's 500,000 barrels or more, if we were in a $3.50 ZIP code before, that may be a hair aggressive, but we'll be keeping an eye on it.

Lee K. Boothby

John, I was just going to make it real, a real short technical answer, material. It's very material.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Uteland Butte in the high-pressure section, how much do you think the wells are draining?

Gary D. Packer

We'll have to spend some...

Lee K. Boothby

.

We only have 2, so we have 70,000 net acres. So they're each draining half right now.

Gary D. Packer

I can tell you our initial work. We're making the assumption that they're on 160s. But we're going to have to drill some spacing wells to really figure out how tight we can get that. But that's -- the work we've done thus far would indicate 160-acre space.

Lee K. Boothby

And John, when you put all of this together, the controlled flowback, the optimization of the completion recipe, getting a lot of data in multiple plays today in the wet gas condensating oil windows, and intuition would say that you would be moving towards a tighter spacing to optimize value and recoveries. So I think you'll see that progression over time. We're just early days. Excited. All signs are positive, and as I said earlier in the call, the sun's shining, and the sky is blue here.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, one last one for me, Lee, is on the Three Forks. You didn't give any kind of performance information, can you say anything?

Lee K. Boothby

Yes, I'll let Gary give you some color. He was involved with the early wells there. We've primarily focused on the Bakken, but we've been following what industry has done. We've drilled a few wells and we've had good performance. Gary is up to the minute with the specifics.

Gary D. Packer

Yes, in regard to the Three Forks, we've drilled a total of 8 wells. We'll anticipate drilling about 4 wells in 2012. Just recently, we brought in a well, our Ingle [ph] well, and it was on the order of 1,400 barrels a day. So I mean, it's -- I would tell you right now it's -- at this point, from an IP standpoint, they're checking in a little shy of the Bakken wells. We had some early concerns that the Three Forks would be a little tougher drilling and we've overcome that quickly. And they seem to be drilling at about the same rate. We've just cut 2 full conventional course in an area that we would call Watford and Aquaria to better study the Three Forks, not only in the main bench, but...

Operator

We'll take our next question from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Turning to the balance sheet and specifically the credits stats of net debt to cap and long-term debt to EBITDA. Based on your own internal estimates, where do you see the range on those 2 ratios, say at the end of this year, whether pro forma for the asset divestitures or not?

Terry W. Rathert

Well, net debt to cap, we should end the year with about $3 billion of long-term debt, and that's if we run a balanced budget. So far, we're pretty much in that ZIP code. What's a little confusing is the fact that over the quarter end date, we had done one notes issuance and hadn't completely taken out debt that was on the balance sheet. So you do the net debt calculation and run a balanced budget, we'll have about $3 billion. So the net debt to cap ought to be in that 40%, low 40% range. And I think, that's probably a good range with or without any material acquisitions or dispositions.

Dan McSpirit - BMO Capital Markets U.S.

Great. As a follow-up, if I could. In reviewing the Thorn [ph] and Grayson [ph] wells, the 2 wells drilled in the pressured area of the Uinta Basin, looks like they're about 6 miles apart -- located about 6 miles apart, you can correct me if I'm wrong. But what's the plan for additional wells drilled in the pressured area of the basin in terms of location distances here over the balance of this year? And could you remind us again, also of the pressure gradient of those wells versus others?

Gary D. Packer

Yes. Dan, the remaining program will be distributed across that area. You will not find it to be confined to any 1 or 2. We're not just going to snugging up against those wells. We're going to make sure we continue our assessment across the broader area. And the second question, what was your second question?

Lee K. Boothby

How many wells in the back half of the year?

Dan McSpirit - BMO Capital Markets U.S.

Well, it's just the pressure gradients of those wells drilled in the pressured area versus others.

Gary D. Packer

About 0.73 PSI per foot.

Dan McSpirit - BMO Capital Markets U.S.

Okay, and the vertical depth on the Grayson and Thorn wells?

Gary D. Packer

I believe they were, from a vertical depth standpoint, somewhere around 9,000 or 10,000 feet, and then the lateral lengths were somewhere between 4,000 and 5,000 in lateral.

Operator

We'll go next to Richard Tullis with Capital One South Coast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Just a couple of quick questions. Jumping over to the Williston. I noticed in the ops update last week, you had one well drilled there at about $10 million for extended lateral. What are you averaging, I guess, across the up play right now for the extended laterals there?

Gary D. Packer

As far as an average this year, that $10 million is an awfully good number for us. If I rigorously calculated the average, it would probably be a hair more than that. But Cana is, I think, a representation of where we're at today. And certainly, with some of the benefits that I anticipate realizing from some completion cost reductions, we ought to be inside of that number as we look into 2013. Something that we're always -- I think it's important to recognize, we consistently are hitting it out of the park with our ability to drop days and cost out of the system on the drill side. The completion is an area that we don't want to take too much money out too soon. Because as we look there to continue to space tighter and tighter, as you well know, we've gone from 12 to 24. This year, we've gone to 32 to 38. And we're going to be looking at going to 42-stage completions. And that's an element of how we've been able to drive the EURs up to 600,000 to 700,000 barrels a well. So I don't think that's stopped and I hesitate trying to drive the cost out of the completion too quick. But I think that's a good ZIP code and just remember, that when we talked about it 1.5 years ago, we talked about reducing activity, we talked about a well that was north of $11 million, and I think folks were shocked at that, and then quickly, everybody realized that was kind of the standard cost, it was out there in the industry. So I'm very optimistic of where we've taken it and where we will take it.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay, that's helpful. And then lastly, going back to the potential asset sale in the Gulf of Mexico, do you envision that selling as one entire package or do you think you might have to break it up a bit to multiple buyers?

Lee K. Boothby

I've said all I'm going to say on the Gulf of Mexico today. Hopefully we'll have more information in terms of where we're at on that within the month.

Gary D. Packer

We have time for one question. We're already over time for the call. So operator, one more call?

Operator

We'll take our last question from Rudy Hokanson with Barrington research.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Real quick and easy. On your general and administrative guidance, it's gone up a bit. And I know that you mentioned in the note regarding costs on the international side or with some planned production facility upgrades. And I was wondering if you could explain maybe what's happening with G&A for the whole year?

Lee K. Boothby

Rudy, it's really simple. The G&A cost, if you take the sum of what is shown is net G&A, presented by GAAP and those internal costs are capitalized, the numbers haven't changed. So the total of those 2 is the same, it's accounting landscape. And so the cost are right where we think they're going to be, have been and expected to be there all year. It's just accounting landscape in terms of what portion gets capitalized.

Lee K. Boothby

Thanks, Rudy. Well, I'd like to thank everybody for tuning in this morning. I certainly enjoyed the Q&A session. I hope the take away for all of you is that the management team and the organization is very excited about where we're at midyear 2012. I'm excited about the second half and I look forward to keeping you up to speed as we continue to have the good results rolling in for multiple plays. So have a good day, and thank you very much.

Operator

This does conclude today's conference. We thank you for your participation.

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