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Newfield Exploration (NYSE:NFX)

Q3 2011 Earnings Call

October 20, 2011 9:00 am ET

Executives

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

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

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

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

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

Operator

Good day, everyone. Welcome to the Newfield Exploration's Third Quarter 2011 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 2010 Annual Report on Form 10-K and subsequent quarterly reports on Form 10-Q for a 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 statement.

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.

And 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, and thanks for joining us today for our third quarter conference call. I'm joined in Houston today by other members of our leadership team, and together we'll be happy to address your questions at the end of today's call. Today I will provide a brief summary of our third quarter financial and operating results, provide some color on where we are today and brief updates on our most significant oil developments.

Our oil production year-to-date is up nearly 30% over last year, and we have some large development projects that will provide a boost as we enter 2012. I also will provide thoughts on how we are scenario planning today to execute the right game plan in 2012. We will stick with our tradition and not providing full year guidance until we have final board approval in early February.

Let's quickly address our third quarter financial results.

Our net income before FAS 133 gains was $140 million or $1.04 per share. Revenues in the third quarter were $628 million or 40% higher than the same period last year. Net cash provided by operating activities before changes in operating assets and liabilities was $409 million or $3.02 per share. Our natural gas production was 45 Bcf or about 494 million cubic feet per day. This was down from the second quarter and reflects our continued emphasis on liquids production with our capital investments. Our oil liftings increased 16% quarter-over-quarter to 5.1 million barrels or about 55,000 barrels per day equivalent.

Results of our oil focused programs are evident with crude and liquid volumes up nearly 30% over last year's third quarter. Our domestic recurring LOE expense on a unit of production basis was higher than guidance and reflected increased service cost. With the exception of international production taxes, the remainder of our costs and expenses were in line with guidance. International production taxes reflected higher oil price realizations as we continue to enjoy the wide Brent and WTI differentials.

Although I'm not happy about our operational results of late, I can assure you that we are taking the appropriate actions and have a simplified and focused game plan to deliver superlative execution in 2012. Year-to-date, we have sold a greater number of non-strategic assets than we originally anticipated, and we have other sales in process. We also have made some tough cost-cutting decisions as a result of challenges in this environment, particularly in the Williston Basin. A combination of these events negatively impacted our production and as a result, we've adjusted our full year guidance. We have high confidence in our asset base. It's a great portfolio of assets, and we believe it provides us with multiple options to grow our cash flow from operations.

Our portfolio is a competitive advantage, and we will use it to make the best long-term decisions for our shareholders. It's important that you understand that our recent challenges are not related to well performance in our core focus areas.

I said in our midyear update that we were more likely to cut activity than raise our $1.9 billion capital budget for the year. As we entered the fourth quarter, it became apparent to us that we would need to curtail some activities to ensure we do not overspend our budget. Keep in mind that our budget year-to-date have some large development projects to midyear front-end loaded, Pyrenees, Piatu, leasing in our stealth play, et cetera. We will spend significantly less in the fourth quarter to meet our $1.9 billion capital budget.

In today's news release, we're adjusting our 2011 production guidance to 300 billion to 304 billion cubic feet equivalent. I would like to summarize where we are compared to our beginning of year guidance of 312 billion to 323 billion cubic feet equivalent.

First, non-strategic asset sales. We expect proceeds from asset sales this year could amount to as much as $400 million to $500 million, far in excess of our $200 million to $300 million goal. The 2011 production associated with these sales is about 5 Bcf. These non-strategic asset sales allow us to improve our focus of both capital and human resources on assets important to our future.

Two the Williston Basin. We've been behind in our Williston Basin program all year and have taken proactive steps to adjust course. Simply stated, we had expected to exit 2011 with net production of about 15,000 barrels of oil per day. And today, we're about half that rate. Our issues relate to weather, delays in the arrival of necessary services in the field and the result in inability to complete wells timely. Compared to our original guidance, the Williston Basin is down 6 Bcf. We've reduced our operated rig count, and we'll defer completions on more than a dozen horizontal wells into 2012. This is an obvious area for us to institute strict capital discipline and preserve our budget.

Our Williston issues are not related to the subsurface. We have great assets in the Williston that can provide some of the highest returns we have in the company. Our wells have performed extremely well once online, and we've demonstrated our ability to drill wells efficiently. There's a table in @NFX that shows our recent well results. The recent tightness in the service market and the subsequent cost increases have forced us to better manage our investments in late 2011.

Number three, decreased activity, capital expenditures and deferred production. We've recently reduced expenditures in multiple areas to ensure that we live within our $1.9 billion capital budget for 2011. We've dropped rigs in the Granite Wash and the Williston and have shuffled timing of drilling in the Uinta. These proactive decisions equate to about 3 Bcf equivalent of deferred production in the second half of 2011.

And fourth, weather. Weather-related issues this year have cost us about 3 Bcf. Our midyear update accounted for about half of this deferral. The remainder is related to the recent Tropical Storm Lee.

Now let's talk about our path forward, where we are headed. Our efforts today are focused on 2012. Let me share some thoughts with you on how we are approaching next year. We will simplify the game plan in 2012 and ensure that our best people and projects are aligned, and that we are driving oil growth from fewer projects. I'm confident in our ability to deliver and excited about the opportunities ahead of us. Oil will remain the favorite commodity in our 2012 plan. The Uinta Basin will be the centerpiece of our story. We anticipate that margins and oil production will continue to be better than those in natural gas. Our emphasis will continue to be on oil and liquids growth, leading to continued margin expansion and cash flow growth as priorities over absolute production growth.

We're already shifting additional resources from the Williston to the Uinta Basin, and this push will continue into 2012. Our recent strong well results help reinforce the potential of this basin to drive our corporate oil growth. More on that in a moment.

In addition to the Uinta, we have a portfolio of great oil and liquids-rich assets. Our large oil fields in Southeast Asia are benefiting from $110 grant today. And domestically, we have the oily Woodford, Granite Wash and Eagle Ford plays that are all contributing high margin barrels to the bottom line.

Our game plan in 2012 will be to optimize all these assets to create the best possible outcome. We will continue to streamline our asset portfolio and improve our organizational focus.

Over the last several years, we've sold non-strategic assets, and you should expect this will continue in 2012. It's important that we constantly high grade our assets and allocate both our people and capital to the best projects in the portfolio.

We will continue to build for the future. We've accumulated in our value winnings some exciting new plays. Any of these could turn into another play of scale for us in the near future. We will manage our options, balancing production growth and a focus on improving margins, maintaining our strong capital structure. We're looking at a number of different scenarios for 2012. Our internal view is not one of a strong economy as a backdrop. Our hedge position provides clarity on our cash flow resources, which we will continue to use as a guide for our capital program.

As customary, we will have our 2012 plan approved by our board in early 2012 and be in a position to share many more details with you at that time.

Moving on now to operational updates.

First, we'll start with the oil plays in the Uinta Basin where we have about 250,000 net acres in multiple exciting oil developments underway. We're the largest operator in the region and have been able to capture superior returns. We recently attained a production high in the Uinta Basin of 24,500 barrels per day, supported by continued strong well results in the Central Basin area in the Wasatch formation.

Recent notable Wasatch completions include the Lamb well, which had an IP of nearly 1,200 barrels of oil equivalent per day in the 30-day average over 600 barrels per day. Our Padilla well recently commenced production at more than 1,100 barrels of oil equivalent per day. And just this week, our Miles well initiated flow. And as of this morning, it is flowing at over 1,000 barrels of oil equivalent per day and continues to clean up, following fracture stimulation this past weekend.

These are game changers for us, especially in a basin where the average well has historically come online at 85 barrels of oil per day. As we've said time and again, we're a proven operator in the Uinta Basin. Our most recent deep Wasatch well was drilled in just 13 days from spud to rig release. This compares to our acquisition case of about 18 days and a historic industry comparable wells of 40 days or more. We do have a competitive advantage in our operations. We will be testing some exciting new play types in 2012 in multiple perspective horizons throughout our acreage block. We plan to aggressively pursue the application of horizontal drilling, and wells are planned for early in the new year. And for vertical wells today are exceeding 1,000 barrels of oil per day. Just imagine the potential of the horizontal wells have to drive economics and generate cash flow with significantly less capital investment. We're drilling 2 wells in the Uteland Butte today and plan to test the pressured section in early 2012, where recent regional results from the industry look exciting. Today, we are high grading our rig fleet and bringing in larger rigs that are better suited for our new development plans. We expect to operate 8 rigs in the Uinta Basin in 2012, and we'll be looking for every positive signal to accelerate our activities in the region. We believe that our Uinta Basin assets have net undeveloped resource potential of more than 700 million barrels of oil equivalent in the proven productive horizons of the Green River, Wasatch and Uteland Butte.

And don't forget that our acreage has multiple additional stacked oil and gas plays ranging from 4,500 feet to more than 16,000 feet true vertical depth.

In the Eagle Ford, we have about 40,000 acres where we will concentrate our development operations primarily located in the southern portion of our acreage block. We're also testing additional perspective horizons, including the Austin Chalk, Georgetown, Glen Rose, Pearsall Shale and others. Development drilling today centers on the Southern acreage. And we've seen recent success in our West Asherton field, a 20,000-acre block. We have some exciting drilling programs underway today in core development areas, with a high service cost prevalent in Eagle Ford today. This is not a basin that warrant acceleration in activity wells.

In the Southern Alberta Basin, we are nearing the end of our comprehensive vertical testing program. In our operations report, we provided an update on our results today. All of our wells have encountered oil. We remain encouraged about the ultimate prospectivity of the basin. Although to date, we have not experienced indications of high production rates. Our horizontal wells to date tested secondary targets. One of the wells is unstimulated, and the other had about 225 barrel initial production rate from just 30% of the stimulated portion of the lateral.

Fully stimulated, this could have been a pretty good flow rate. History tells us that we have a demonstrated track record of improving results over time, and I'm sure this will take place in this basin as well. There a number of operators conducting assessments in the basin today, and this will ultimately benefit us. Our activity levels to date satisfy the majority of our drilling obligations for our 5-year exploration period. We will limit our expenditures in this play in the near term and preserve our option for its ultimate development as work continues. We have approximately 340,000 net acres in the play.

In Malaysia, our team has done an excellent job this year as nearing the finish line on our large developments with East Piatu expected to flow oil this weekend. Despite the repair issues we had to deal with this year at Abu, our oil production has exceeded beginning of year expectations. And recent gross volumes are nearly 50,000 barrels per day, and we expect them to exceed 60,000 barrels of oil per day by year end 2011.

These are great assets and add significantly to our bottom line.

If you have additional questions on any of our operating areas, I'd be happy to address them during Q&A.

In closing, let me quickly reiterate where we are focused today. First, we are working hard to get our large offshore developments online. This will provide a nice boost in liquids production in 2012, adding additional high margin oil and gas liquids production. Second, we have a simplified game plan for 2012. We will allocate our capital to the projects with the best margins. This will likely mean a continued de-emphasis on gas plays and a concentrated focus on oil. Our Uinta Basin projects will be our largest growth driver in 2012. Third, our investments in 2012 will be underpinned with internally generated cash resources, and we will maintain a healthy capital structure. Fourth and last, we will continue to manage for the long term benefit of our shareholders. I'm confident we are doing the right things today and for the right reasons.

That concludes our prepared remarks today, and we're delighted to take your questions at this time. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question this morning comes from David Kistler with Simmons & Company.

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

Quick question. I know you're not going to go deep into CapEx for 2012, but can you give us what you think maintenance CapEx would need to be to keep production flat on a quarter-over-quarter basis?

Lee K. Boothby

Let's hear Rathert take that question.

Terry W. Rathert

Dave, I think, we're not going to give you any good indication where we are in 2012, as you suggested, because we're working through that right now. I would guess that maybe one of the best ways to think about that is we have a lot of areas that are in different phases of life cycle. And so picking any one and trying to pin it down to a business unit or a basin is particularly problematic. But generally, I would say that the maintenance level is probably in the range of $1.1 billion to $1.2 billion to just be flat year-over-year. And that again is very much dependent upon how we see some things develop by basin prospectively as we shift capital around. That number is moving.

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

I appreciate that color, and I don't mean to dig too much deeper into but just one more on the CapEx side. $1.1 billion to $1.2 billion keeps production flat on a year-over-year basis. You've got a decent ramp in production throughout this year. If I just think about keeping flat with fourth quarter rates, I would imagine it would need to be -- I don't want to say significantly higher than that but slightly higher than that. Am I thinking about that the right way?

Lee K. Boothby

I think, David, when you work through it -- Terry is trying to get some color in terms of how the pieces fit together. I mean, clearly, if you take the fourth quarter exit rate and maintain that number, you'll be looking at a number in the 320-ish, 325 Bcf range, somewhere in that zip code. But remember the flush production that is coming on of this field, and they've got declined. So you've got to balance that out. So I would say that the answer in the end of the day and Terry's funding levels is somewhere between those 2 endpoints in my judgment.

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

Okay, I appreciate that. And then maybe switching to your Alberta Bakken well that you put out the initial results on. Can you talk a little bit about what kind of completion issues you had and why only 1/3 of it got off?

Lee K. Boothby

I'll let Gary Packer take that question.

Gary D. Packer

Yes, Dave, as you initiate these horizontal wells and any of these new plays, there's a certain portion of the wellbore that's going to be out of [indiscernible] as you're steering into something you haven't drilled before. It's very typical. It's something you almost can factor in early on. Rather than spend the incremental money and sidetrack these wells, you go ahead and you complete the intervals that you have. And in the case that we've referenced, we had about 30%. The other thing I would say, and again this is very typical of these early plays, is trying to understand what the appropriate completion technique is, and the first well in the basin is always going to be a bit of a challenge. You learn from that, you move on. We just haven't had the chance to apply that to a second well yet.

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

Okay, appreciate that color and completely understand in the early stages that, that can happen. Following up on one other thing that you mentioned on the call. You talked about doing additional divestitures in 2012 above and beyond your target for this year. Can you talk a little bit about what levels you might be targeting or any of the specific assets? Can we get any granularity on that?

Terry W. Rathert

David, this Terry again. I think it's a little too early to tell. As we go into the budgeting process here for 2012, what we're going to be looking to do is determine how well we allocate capital and human resource to the basin with the highest return, look at what our capacity is to make investments there without marginalizing those returns, and that will match it up with our cash flows. And if there's a deficit, then we can spend more to generate better returns in what we're getting from non-strategic assets that are generating cash flow, and think about converting those to cash and funding those activities very similar the way we did this year. But going into next year, we're going to start out with the cash flow from operations as the first building block in that process, and then we'll see where things stack up from there.

Operator

Our next question comes from Brian Lively with Tudor, Pickering, Holt.

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

On the Q3 CapEx rate of $679 million, how much of that was E&D CapEx versus leasing?

Lee K. Boothby

I would say a bulk of that was due to operations, Brian. We are finishing up some leasing on a play, so I would suggest to you that it was probably $25 million or so off of the top of my head, a minor amount of it.

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

But could you guys maybe talk about how the run rate goes down in Q4 then?

Terry W. Rathert

Sure, Brian. This is Terry. I think the easiest way to do that is if you grab your statement of cash flows and look at the year-to-date investment in oil and gas properties, it's not $1.75 billion. Close to $150 million of that is capitalized internal cost, so that puts us at $1.6 billion against our announced capital budget of $1.9 billion. And it's actually probably a little bit on the high side of $1.9 billion, but it's not $2 billion. So what we've done is recognize that we need to change the pace and, as Lee mentioned on the call, a lot of our capital budget was front-end loaded with these major developments. When you take those out, because they're not happening in the fourth quarter, when you take the change in pace in the activities and deferral completions, then you end up with capital budget that we need to adhere to in the fourth quarter being around $350 million. And we're going to do that. We have the plans in place to accomplish that, and everybody knows that we're not going to give up that target.

Lee K. Boothby

I guess I would add to Terry's comment, Brian. Operationally, the way we're able to influence that most directly is the dropping of rigs and completions. This was referred to in our announcement if you refer to the various programs for executing this year. In the Granite Wash, we've historically went about 5 rigs. We've already got that down to 3, and that's likely to see about 2 rigs by year end, so that's pretty material adjustment on wells, as you well know are pretty expensive wells in the order of $10 million or so. When you look at the Williston Basin, we've historically been running about 5 rigs there. We'll probably average 2 to 3 rigs for the remainder of the year, so that's about half of what we would have otherwise been running. We do have a new build coming out at year end that will be added to the fleet, but we've been able to manage our contracts such that we've got some flexibility there. The other thing I'd ask you to look at is these completions. As we all know, these horizontal stage completions are quite expensive and typically 50% or 60% of our well cost. We've made a decision once we elected to cut back in the Williston Basin on the rigs, we're going to allow ourself to build a bit of an inventory on the completion side as well. So we'll likely exit this year with about 13 unstimulated wells in the Williston Basin. That's a pretty, pretty big number that will allow us to get some flush production back in 2012. And also we'll -- as the year unfolds, we'll back off in some of the completion operations in the Granite Wash. All of these should take a pretty material reduction in our fourth quarter run rate.

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

A question on the Bakken and on spending kind of aligned with that. The $11 million well cost, that seems high relative to even some of the other operators in that play now. Why are the costs so much higher?

Lee K. Boothby

Well, I think, first of all, I guess I would take issue with your comment on the well cost. We've put ourself out and compared our drilling curves and our costs against all the operators in the area. In each of the areas that we're active, I can tell you that we're very competitive as far as the wells that we're drilling. I will tell you that all our wells this year are proportionally much higher as a result of drilling the 1,000 foot laterals. Last year and even today, we can back off and drill a 4,000 to 5,000 foot lateral in the neighborhood of $7 million. Earlier this year, we were in an 8 5 to 9 3 environment. And we've seen that number go up to 11. Now the lateral lengths that we have today are between 9,000 and 10,000 feet. And I can tell you in the $11 million, there is some element of trouble cost that are built into that, that are a reflection of what we've seen in 2011. Now many of the costs that you historically see don't have trouble cost built into them. And in the environment that we're currently drilling today, you are far more likely to see increasing costs associated with that area than you are in areas where the rig count is much low. So that is a fully-loaded facilities, trouble cost, as well as drilling complete. Now as we look forward and you see some of the contracts that you have in place for stimulation services roll-off, and you see the basin moderate or more services come in, I fully expect that number will back off. But I'd be naive in thinking that if we would be seeing a $9 million well cost anytime soon.

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

Okay, that was really helpful. Last question, and I'll get off. Lee, in the prepared remarks, you said basically in 2012 oil growth from fewer projects. Can you guys maybe talk about which assets are sort of untouchable? Obviously Uinta is, but which other assets are untouchable? And then would you consider in -- like you said high grading some of the more resource-oriented plays in the U.S.?

Lee K. Boothby

Let me start with the takeback in the comments. Certainly, the Uinta is the centerpiece, and I stated in the call that we're excited about the well results that are starting to roll off now in the back of the Central Basin land acquisitions that we've undertaken this year, excited about the potential application of horizontal drilling completions in the basin in multiple horizons. So I think that's the thing to think about in terms of future for 2012. The Williston, we like the returns on the Williston. I'm confident that buying some time here to get lined up and oriented, hit the ground running in 2012 with the completion inventory, I think that will be a net positive there as well. Internationally, we've got our large oil projects that we've been working on. East Piatu will be online this weekend, so we'll have that activity behind us, so we'll maybe enjoin flush production, cash flow from those assets as well as the Pyrenees development, which is going to come online in December of this year. So when you put all of those pieces together, I think it's a pretty strong story in terms of the oil-producing assets.

Now on the gas side, I will remind you that we are largely held by production. We've been accepting decline on the base assets there, and that's going to likely continue to be the case if we trade sideways in this type of market -- market condition. Beyond that, as far as the additional assets, a lot of the activity we've undertaken this year has to do with some of the legacy historical conventional Gulf Coast, natural gas assets. That's part of the refocusing in terms of personnel. I think that's a positive step, and that's where part of the focus comes from in terms of the organization. Beyond that, I don't think that, as Terry indicated, we're really in a position to talk about specific assets or specific opportunities that we might use to either accelerate or further streamline. The statement was made as a continued commitment to ask ourselves to grow, hold, divest, question each and every day, and it's a challenge that we've placed with all of our management teams around the different regions. So we'll continue to ask ourselves which assets are part of the future, and we'll ask ourselves likewise which assets more appropriately are part of the past, and we'll continue to make those decisions to strengthen the portfolio through time.

Operator

Our next question comes from Joe Allman with JP Morgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Lee, in terms of the lower guidance, it seems to me that a lot of the lower guidance is self-imposed, and I saw your table in your release and the numbers you cited today. Do you agree with that, that most of the lower guidance is self-imposed? Or is most of it just disappointment on the operations?

Lee K. Boothby

I think your assessment is absolutely correct. I mean, it's not our style to go ahead and make excuses. I mean, we've been communicating all year that the inflation and the market conditions were deteriorating execution and margin erosion in the service cost environment. You also see deterioration in the quality accrues that you get out on a location. So all of those factors kind of come together. So the first commitment is control what you can control. And as Terry indicated, we're going to hit the $1.9 billion budget. That was a commitment we made. That was something we can control, and that required curtailing activity. Clearly, we could have continued to drive forward and roll through year end and tell you that we spent $2.1 billion or whatever the number would have been. And our production numbers would have looked in line with what we said that we can deliver. But we thought a more prudent decision at this point is to adjust our program, start repositioning assets within the corporation to the 2012 game plan, and we're doing that as we speak. So why not buy some time there to get things right, so that you can execute the program in 2012. So I would agree with you, most of it is self-imposed. But I don't think that's a bad thing. I think it's something that frankly more companies should do. There was comment in there that we're going to chase margin expansion, and then we're going to continue to drive oil in doing that. We're going to chase cash flow growth, again driven by oil. And we'll do both of those in preference to absolute production growth. And I think that's a strong statement, and it's a position that we believe as a leadership team is the right thing for Newfield, and we think it's going to position us well in 2012 forward.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That makes a lot of sense. And then at the beginning of the call, Lee, you mentioned that you weren't particularly happy with some of the operations, and you've talk about some of the, I guess, quality issues in the Williston Basin. Any other issues in the Williston or elsewhere that are particularly concerning?

Lee K. Boothby

Well, I have to say that any of the basins, Eagle Ford would be another one that we talked about that you've seen a lot of activity, explosion in the activity, difficulty in services, all the things that come with overheated basins as a general rule, I think, in how many times we have to obviously to prove this in our course of our careers. But every time a basin overheats like that, you see a deterioration in quality, and it does impact execution. So clearly, we're reducing activities where we can, mostly on the basis that the margins don't compete and other options that we have in the portfolio, and then the improved focus in terms of repositioning the human capital into the areas is critical as well. And one of the other considerations that we use as a regular part of our business, the core value of the corporation, if you will, has to do with H.S. & E. performance. So overheated basins generally puts you in a position that you've got to worry a little bit more about your people and the operations. So balancing out organizational capacity and all of these factors is a critical thing to do, I think. And we're trying to balance that in the context of generating the results that we strive to achieve.

Gary D. Packer

Let me add a little something to that, Joe. There are regional fluctuations in this. But across the board, I mean, you can see, and I think everybody's numbers reflect this, you're seeing anywhere between 10% and 25% increases in completion costs across the nation in many of these major plays. I've complimented our Mid-Continent team and some of the more mature areas of the Rockies. We've been able to push back and basically offset virtually all of the increasing costs that we've seen due to their various performance, moderating techniques and technology. I think when we talked about the Williston Basin, not only do we see the costs up. And quite frankly, it still generates returns that still do compete. The biggest issue we have is the reliability of when that production is brought to market. That's the thing that has become less and less certain to us, and that's caused us to really back off preferentially there. We'll make these investments, but we need to have assurance of production. We exited the Gulf of Mexico Shelf for a reason. This was big part of that. We just needed to make sure that once as we get the resources in place to ensure the timely execution of these projects in addition to the capital investments that we're making.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's very helpful, Gary. And then just lastly, Lee, when do you expect to make an announcement about the Uinta Basin marketing plan?

Lee K. Boothby

Well, we've made a commitment, Joe, that we'll have more to say on that before year end, and we're going to honor that commitment. So we'll have more -- I guess, more information on that issue before year end.

Operator

We'll take the next question from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

A couple of different questions. For the Southern Alberta lateral that was partially stimulated, how long is the total lateral, did you say?

Lee K. Boothby

I believe it was somewhere in the order of 3,500 feet, maybe 4,000 feet, Gil.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, and basically you only stimulated about 1/3 because only 1/3 was in zone. Gary, was that the understanding?

Gary D. Packer

It was a combination of areas in which we could initiate fracture as well as of those that were in zone, correct.

Lee K. Boothby

I think you'll remember early in these play areas that you've got to gather data in terms of stress fields and wellbore orientations. So I would say that a portion of the issue in that well is that we would drill in a different orientation today, knowing what we know today.

Gil Yang - BofA Merrill Lynch, Research Division

Got you. Okay. With respect to the production taxes in Asia, it sounded like they were quite a bit higher than you expected. And obviously, the oil price was probably higher than you expected. But was there any PSC sort of effect where you're getting less of the incremental dollar because of those -- because of any contracts of that nature?

Gary D. Packer

Gil, every one of our PSCs is in just a little bit different position relative to cost recovery and things of that nature. So we generally can do a good job of estimating where the liftings come from and the allocations between them. The swing factor is what is the oil price realization, and there is a supplemental tax. So as you experience higher and higher oil prices, a large portion of that turns out to be taxed. So we can mail the mix because we've scheduled liftings pretty far in advanced. And if the liftings occur in time, and occasionally if we miss it by a week or two or whatever, we can get that right. The unknown, really, at the end of the day is when we start out the day making projections for the end of the year is, was the oil price between now and then.

Gil Yang - BofA Merrill Lynch, Research Division

Right, okay. So in other words, the higher oil price in the quarter that you had expected in a disproportionate amount was taken out as part of that PSCs, and so that's why the production taxes are higher than you had anticipated.

Gary D. Packer

A higher -- on the incremental revenues, a higher percentage of those is taxed in the underlying production. For example, at $85 a barrel, we estimate the tax. And if we get $100 a barrel, a disproportionate share of that $15 goes to tax in the underlying $85.

Gil Yang - BofA Merrill Lynch, Research Division

Got you, okay. So when I look at your fourth quarter guidance, given that the Brent-WTI differential is pretty high today and given that WTI is not -- has sort of bounced up a little bit, it sounds to me like your production tax forecast seemed a little conservative versus what you actually reported in the third quarter. Is there something in there that I'm missing?

Terry W. Rathert

If we use the strip price on $9.22, so that's an $80 oil price. And we use the $3.84 gas price, and then you adjust that for its premium to Tapas or Brent. So we're realizing today close to $115 a barrel for that crude.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And $115 Brent in that sort of range, your production tax will be in order of $5 and $6 as you forecast?

Lee K. Boothby

And we'll also have cost recovery from our new production at Piatu.

Gil Yang - BofA Merrill Lynch, Research Division

Got you. Okay, so the cost recovery would appear in that production tax number?

Terry W. Rathert

Cost recovery barrels are not subject to production tax. And so what Bill says there is because they're not subject to production tax, the volume weighted average production tax will be lower. So the $5 to $6 guidance that we provided is based upon the forward strip at $9.22, which stays at $8.62, and the observed differential between WTI and Brent at that time which was around $10 a barrel.

Gil Yang - BofA Merrill Lynch, Research Division

Got you. Okay. And the cost recovery barrels are on East Piatu?

Terry W. Rathert

East Piatu, and we'll be drilling in East Belumut, so there'll be cost recovery barrels there as well.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. But the 7,000 barrels, so you will actually be booking more than 7,000 barrels for East Piatu because you'll get 7,000 barrels net and then plus the cost recovery barrels. Is that right?

Lee K. Boothby

Yes. Once we ramp up to the full 10,000 barrels a day.

Gil Yang - BofA Merrill Lynch, Research Division

Got you. Okay. And then the last question is, given you're slowing down pretty dramatically in the fourth quarter, essentially taking your foot off the accelerator, what's the momentum going to be in volume growth going into 2012. It sounds like it will be negative. And as you step on the accelerator again with your new capital budget for 2012, how quickly is it going to take to ramp up? And will we, on a quarter -- I know you don't have guidance for 2012, but just in terms of trajectory, should we expect there to be sort of flattish through the year? Or is it dip down and then begin accelerating in the back half of the year?

Lee K. Boothby

Well, Gil, as we've said, we're not going to put out any numbers right now until we have thoroughly worked through what our guidance is going to be for 2012. From an operational standpoint, clearly, we're trying to manage all our rig contracts such that we have ultimate flexibility in our ability to go ahead and move rigs around the organization to make sure we can accelerate in the areas in which we desire to do so. Now the good thing we're working for us is, as we've already said, we're going to have a [indiscernible] of unstimulated wells that we'll be able to address in the first quarter of the year. So that will help us in the first quarter and then we would be able to accelerate in the areas that we elected by putting other rigs back to work. In some cases, we're farming rigs out, but we still have access to that. And we've also got 2 new rigs coming to work for Newfield, one in the Williston Basin and one in the Uinta Basin.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Are you paying any stack and laydown charges?

Lee K. Boothby

No.

Operator

We'll now hear from Leo Mariani with RBC.

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

Can you talk a little bit about well cost in the Uinta, particularly in the Wasatch and the Uteland Butte in terms of what you're seeing?

Lee K. Boothby

Sure. I think the numbers that we've put out a few months ago, when we unveiled the whole Central Basin play, are still pretty good go-buys for us to look at. I think if you looked at, at the time we announced that, we've talked about $2.6 million well cost, that's an average of a number of different well types that we will drill, some that's shallow, something is basically the deepening of the Green River well, some of them is as deep as the deepest section that we can drill within the Wasatch. So the range of well cost that we can see in that play is probably as low as $1.3 million for a deepening of a well. But it could be as high as $3.5 million or so. So it's very difficult to focus on an average that we try to provide a simplified type curve for the market to understand the play versus any specific well. So the wells that we're drilling today have typically been deep Wasatch wells, a little over $3 million. So it's an area in which in the Uinta Basin, we've had our best cost advantages in the organization, and we continue to get the lid on those costs. The other issue there is I know there's been some discussion that we've been asked about, and that is how do this compare with some of the other regional operators. I can tell you that when you compare a well, Wasatch well at Monument Butte impaired or with the Central Basin relative to Altamont Bluebell, our wells are considerably shallower. And therefore, our well cost will be considerably cheaper. And it's also very difficult to compare these plays when you reach to the West and you look in the areas where that geopressured section is being drilled. But they're just not drilling as many wells as we've got, those well cost would expect to be a little higher as well. So I do think we have a cost advantage. But in the numbers that we've put out there historically are still accurate. Now the Uteland Butte formation, that's still something that I believe we've put out $2.8 million well cost. We've seen that well. And remember, we've only drilled a handful of these. We've drilled the 5th or 6th time that you put out those numbers. We've drilled about 5 or so more of those wells, but we're just bringing 2 to production right now. But they're somewhere in the $2 million to 3 million range of very early well cost. So I'd say were still within the target that we proposed for that as well.

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

Okay. And how does the -- Obviously, you guys are adding a bunch of activity as we get into '12. How does that affect your traditional, shallow vertical Green River program? Do you think you're going to potentially pull back in that activity in favor of the Wasatch and Uteland Butte, can you just discuss some of the dynamics there

Lee K. Boothby

Sure. I think that's entirely accurate, what you said. Historically, we've built an organization out there that can handle and has historically run somewhere between a 5 and 6 rig program. We've historically talked about permitting constraints that existed out there. By doing exactly as you suggest and shifting away from wells, that as Lee suggested, make 85 barrels a day to 1,000 barrels a day. We can kind of take the pressure off the system from a permitting standpoint and manpower standpoint and really drive our growth through these Wasatch and/or Uteland Butte wells. Uteland Butte, as we've historically talked about, has all been drilled in the normally pressured section. I think there's been some great results in the region where we're drilling in the geopressured section. So we're really looking forward to that opportunity, and I believe it's the next -- we got the second well up in our program right now is a pressured well. So we ought to see late 2011, early 2012 to start accumulating results in the geopressured Uteland Butte.

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

Okay. I guess with respect to the Granite Wash, you guys did talk about pulling back some activity there. If I'm kind of looking at some of the numbers correctly, I think you guys talked about 57 wells programmed to date. I kind of looked at your last update, it was 47, So if I kind of looking at incremental 10 wells. Am I correct in that you're seeing a bit of a degradation there in the IP, as I kind of calculated a rough number of around $12 million a day on the IP for the last 10 wells? Can you guys kind of comment on what you've been seeing in the Granite Wash?

Terry W. Rathert

I think the number you threw out there is accurate. All I would ask you to consider when you think about the wells on average IP as we've continued to move from a well of 2010 that had a higher proportion of gas wells associated with it. If you look at 2011 results, you're going to higher proportion of Marmaton, what we would call an FG well, and that's going to bring that number down a little bit just due to that switch to oil.

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

Got you. Okay. I guess, I mean, the decision there, is the pullback -- is that more just one focused on sticking within the $1.9 billion for this year as opposed to any concerns on the economics there?

Lee K. Boothby

No. The pullback is to live within the $1.9 billion capital budget. As Gary indicated, we've got rigs that are going to be showing up in multiple regions, and we've got a portfolio there. It will be part of our 2012 game plan. But right now, it's a pullback related to managing to the $1.9 billion budget.

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

Okay. And I guess with respect to the Eagle Ford, you guys talked about cost inflation there. If I was kind of reading it correctly, I mean, it looks like your well cost for the last several months, well, we talked about in Q2 versus 3Q or -- were pretty similar. It looks like your results were also pretty similar in terms of the wells. So I guess, obviously, you've talked about in the developed 20,000 acres and then in your prepared comments mentioned an area of 40,000 acres that could be open for development. Is that something we should still expect reasonable activity on as we get into 2012?

Lee K. Boothby

It will be part of the mix for sure, and your analysis is accurate.

Operator

We'll now hear from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

As you shifted activity and capital to the Uinta from your other areas, can you just talk about how much of the additional resources and your 8-rig program for 2012 would be focused on exploratory opportunity, new zones relative to development? And when you talked about the recent Uinta production rate of 24.5 barrels per day at an 8-rig program with the permitting or any downstream constraints that exist, how should we think about where that 24.5 can go 12 months up?

Lee K. Boothby

I'll let Gary go and give you the color on that.

Gary D. Packer

As far as the 8-rig program out there, we've challenged the team up there to do as much of the exploration so to speak, i.e. targeting horizontal drilling activity to some of the new zones that we've uncovered, and we've discussed publicly, plus a few that we haven't talked a lot about as much of that in the first quarter as we possibly can. There's significant upside potential to anything we have previously contemplated in those zones. So I think we'll assess the results at the end of the first quarter and deploy our capital accordingly. So we have multiple scenarios what we're modeling right now, Brian, regarding that output. What I would consider a very conservative case would be continuing to do what we're doing, and that was basically our acquisition scenario where we're drilling 1,000 barrel a day, Wasatch wells, which is nothing to sneeze at. The upside is that we have some proportional step change that becomes a bit of a game changer for us in 2012, and you would look at that at the tail end of the year. So I guess, before I -- I'd like the ability to kind of finish some of the modeling work we're doing there before I address about 24.5% and where it can go. I think historically, we've talked about growth rates out there well north of 15% doing what we were doing. And I believe in the call that we projected last time, we were well north of 20%, 25% is what the capability to grow that basin is. So if we have some of these new opportunity center, I think there's a possibility that it could be greater than that. But we really need to see some more results before we can nail that down.

Lee K. Boothby

And you'll get additional color, Brian, when we update you on the marketing plan out there towards the end of the year.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. Thanks. It sounds like based on your comments there that the real step change in horizontal or in more of the Uteland activity and the Wasatch activity would probably start from a drilling perspective more in the second quarter, and then maybe you can start to see the impact on production in the third quarter and fourth quarter?

Lee K. Boothby

Yes, very accurate.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then going over to the Williston, a couple questions there. First, are you just waiting for January 1 to come around to be in a recommence completion activity? Or are there other milestones you're looking for?

Gary D. Packer

I think there's other milestones. As Lee suggested, the Granite Wash is an example of where we back off to manage to a $1.9 billion budget. As I look at the Williston, I'm looking to have a higher confidence that the service sector can deliver on some of the costs and the commitments that we've made out there, and it's only then will we look to accelerate activities.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. Do you feel that you need any more scale in the Williston? Obviously, your well results in that perspective look okay. It looks very good. But do you think you can do more scale? Or the other way to ask it would be, has the Williston become or is it becoming less strategic for you especially as the Uinta is improving in stature?

Terry W. Rathert

The strategic question is a good one. I would say that the economics display, especially if we can get the well cost down a little bit, will certainly compete with anything that we've got in the organization. I think for anything to be truly strategic, it has to be something that we can grow and build upon far into the future. So I would say this is a fabulous bridge asset that has considerable value both in driving oil volumes and margins and our NAV. But as far as an area that -- and if we could grow our 140,000 acres today, I'd certainly be interested in doing that. But that said, when you're sitting at kind of a locked position as far as your acreage goes, I'll stick with my comment that it's a bridge to other major core foundational assets that will develop over time.

Operator

Ladies and gentlemen, that's all the time we have today for questions. I'll turn the call back over to management for any additional or closing comments.

Lee K. Boothby

Well, thank you for your time. Thank you for your interest in Newfield, and we look forward to updating you on our progress in our next call. Have a good day.

Operator

Ladies and gentlemen, that does conclude today's conference call. We thank you for your participation.

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