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Newfield Exploration (NYSE:NFX)

Q4 2011 Earnings Call

February 22, 2012 11:00 am ET

Executives

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

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

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

Analysts

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

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

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

Gil Yang - BofA Merrill Lynch, Research Division

Anne Cameron - BNP Paribas, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Operator

Good day, everyone, and welcome to Newfield Exploration's Fourth Quarter and Full Year 2011 Conference Call. Just a reminder, today's call is being recorded. Our discussion with you today will contain forward-looking statements, such as estimated production and timing, drilling and development plans and 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 statements.

In addition, reconciliations of non-GAAP financial measures to GAAP financial measures, together with Newfield's earnings release and 2012 capital investment program 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 very much. Good morning, everyone, and thanks for joining us today for our fourth quarter and year end 2011 conference call. I'm joined in Houston this morning, our Chief Operating Officer, Gary Packer; our CFO, Terry Rathert; and our VP of IR, Steve Campbell. Following today's brief prepared remarks, we'll be happy to address your questions.

Our call today will focus on 3 main topics: First, a summary of the fourth quarter financial and operating results and our 2011 highlights; second, I'll discuss our year end 2011 proved and probable reserves and how the shift to oil that we've been presenting since 2009 is evident in our results. And lastly, I will cover our simplified game plan for 2012. Our focus is clear and I'll summarize our planned activities and capital plans in our key oil and liquids-rich plays.

So let's go through our fourth quarter financial results.

Our net income, excluding the impact of the FAS 133, was $127 million, or $0.95 per share. Our results were below first call consensus primarily due to lower natural gas volumes and an increase in our DD&A rate, partially offset by higher oil volumes. Our increased DD&A reflects our ongoing shift to oil. Revenues in the fourth quarter were $677 million. For the quarter, oil and liquids comprised 40% of our total production and more than 70% of our total revenues. Our shift to oil began 3 years ago and we are well on our way to becoming an oil company in 2013. Our net cash provided by operating activities before changes in operating assets and liabilities was $387 million or $2.87 per share.

In the fourth quarter, our oil and liquids liftings averaged nearly 64,000 barrels a day. They increased about 9,000 barrels a day, or about 15% compared to the third quarter of 2011, and totaled 6 million barrels. When compared to our first quarter 2011 oil liftings, our fourth quarter oil sales were more than 30% higher. We are achieving strong growth from our oil plays and we will continue to focus both our people and capital on these plays in 2012. By design, our gas production is on natural decline. This the right economic decision with today's weak natural gas prices and we are making no investments in dry gas today. Our natural gas production in the fourth quarter was 44 Bcf, or 478 million cubic feet, per day. Our gas production declined about 20 million cubic feet over the course of the year.

We had some great highlights in 2011 that will set us up for outperformance in the future. Let me run through a quick list. Through several transactions in 2011, we captured approximately 75,000 net acres north of Monument Butte in Uinta Basin and expanded our dominant position in the region. We are the 800-pound gorilla, with more than 230,000 net acres in the basin and a potential to develop multiple new and exciting oil plays, both vertically and horizontally. We secured our future in the Uinta with signing of 2 agreements, a 7- and 10-year term, with 38,000 barrels of oil per day in refining capacity for our Uinta Basin oil growth. We assembled more than 125,000 net acres in the Cana Woodford play and Anadarko Basin of Oklahoma and then yesterday's release disclosed this as our stealth play. We invested approximately $100 million in leasing in 2011 to extend the Cana Woodford south and east of the known fairway and expanded our composite footprint in Oklahoma's Woodford Shale play to about 300,000 net acres. Our technical people did a great job of identifying an opportunity to extend this play to the Southeast and our land professionals moved quickly to capture it for us. Our acreage is not in the dry gas portion of the play. We've identified a liquids-rich and oil-prone extension to the Cana and we are expecting strongly competitive returns from our investments. We have a long and proven history in exploiting the Woodford formation in Oklahoma and have a very aggressive assessment program planned for 2012, which I'll discuss in a few minutes.

We commenced production from 3 new offshore developments, 2 in Malaysia and one in the Gulf of Mexico in late 2011 and early 2012. These new developments added about 17,000 barrels of oil equivalent per day net of new production. We refined our asset base and sold $710 million in nonstrategic assets in 2011 and early 2012, an additional $18 million in sales will close the coming weeks. This is a program that we will continue as we work to build the Newfield of the future, and focus our people on the best return projects in our portfolio.

Yesterday, we also disclosed year end proved and probable reserves for 2011. Our optional reporting of probable reserves makes us somewhat unique in the industry. Internally, we are managing our company on a 2P basis and believe that our disclosure provides greater transparency on the reserves over time. At year end 2011, our proved and probable reserves totaled 6.5 trillion cubic feet equivalent, a 5% increase over 2010. Our probable reserves showed the depth of our inventory for future growth. Of our 2.6 trillion cubic feet equivalent of probable reserves, about 42% meet the technical definition of proved but simply lie outside of the 5-year development window. Therefore, they're technically classified as probable per SEC guidelines. Our emphasis on oil is reflected in our reserve report. We've increased the oil and liquids component of our reserves to 40% of total proved reserves. Our 2011 proved oil reserves increased nearly 30% over 2010. Our natural gas reserves declined 6%, representing our continued slowing of natural gas investments in the coming years.

Proved reserves at year end 2011 were 3.9 trillion cubic feet equivalent, up about 5% from the prior year. In yesterday's release, we provided proved reserves for the last 3 years to help with your comparative analysis. For 2011, we organically added about 860 billion cubic feet equivalent of new proved reserves and acquired about 50 billion cubic feet equivalent. We sold more than 120 billion cubic feet equivalent with our ongoing nonstrategic asset sales program. These sales generated more than $400 million of proceeds in 2011.

We replaced more than 400% of our 2011 production with proved and probable additions and more than 300% of 2011 production with new proved reserve additions. About 45% of our proved reserves are undeveloped and about 55% are proved developed. With our continuing increase in oil reserves, the present value discounted at 10% of our proved reserves grew more than 20% to $6 billion after-tax. If you have any additional questions on our reserves, we'll be happy to address those at the end of today's call.

Before moving to or 2012 game plan, let me provide a quick update on our nonstrategic asset sales program. Each of our Domestic business units has contributed and there were more than 40 individual transactions that comprised the $728 million in total realizations. In early 2011, we set out on a path to refine our asset base. By selling nonstrategic assets, we were able to reallocate both people and capital to higher valued projects and assets that we see as an important part of our future. There are some detailed tables in last night's release that show the impact of asset sales on our production by division. The largest transaction was the $276 million sale of about 23,000 net acres in the Williston Basin, located West of the Nesson Anticline and our Catwalk area. We sold current net production of about 300 barrels of oil equivalent per day and 8 drilled and uncompleted wells. This sale allows us to focus our development drilling efforts on high-graded areas in the basin. I'll talk more about our increased Williston Basin activity levels in just a moment.

In early 2012, we announced that our Gulf of Mexico assets were now nonstrategic to our future and announced plans to explore options to capture the most value. I'd like to spend the remainder of today's call on our 2012 game plan. It will be an oil-focused program and our activity levels will only revolve around a few key assets. As I said in our last conference call and on the road recently, we're executing a simplified game plan in 2012 and we are confident that we can deliver on our key goals and expectations. From the macro perspective, our short-term view on natural gas is pretty negative. In recent years, our industry has discovered massive natural gas resources. Although most of the industry is shifting to oil and liquids-rich drilling programs, there's a tremendous amount of associated gas and, even with our weak economic backdrop, U.S. natural gas supply remains strong. 24 months’ strip price for natural gas is has fallen 25% since late October. Our shift to oil began in late 2009 and since that time, our oil and liquids growth has a CAGR of 20%. Our transition to oil has not been easy and we are accepting declines in our natural gas fields. We are executing this transition to oil with a careful eye on the balance sheet and we work diligently to sell nonstrategic assets and deploy the proceeds towards lucrative oil plays and necessary debt repayments.

In a given calendar year, a $100 million investment in our natural gas portfolio would provide twice the production growth from an equal oil investment, but with today's disparity in oil and gas prices, the cash generation from the oil investment is nearly 2.5x that of natural gas. We are focused on one overriding product, cash, and delivering sound returns for our investment decisions over the long term. I am confident that our 2012 game plan will further our transition to an oil company and lead to improved returns, higher revenues and strong cash flow production growth per share. Our 2012 capital budget will range from $1.5 million to $1.7 billion. This is down approximately $400 million from our investment levels in 2011. As we've done over the last 3 consecutive years, we plan to live within our internal resources. We've used a combination of cash flow and nonstrategic asset sales to maintain a strong capital structure. Our expectation is that natural gas prices will remain challenged in 2012. With that outlook, it is prudent to limit investments and accelerate our transition to an oil company, a target we fully expect to achieve in 2013. In the second half of 2012, we expect that more than 50% of our production will be from oil and liquids. Substantially all of our total budget will be allocated to oil and this program is expected to grow our oil and liquids production by more than 20% in 2012. Due to reduced investments in natural gas, our gas production is expected to decline up to 15% in 2012. Our production guidance is a product of making sound investment choices in 2012 and ensuring that we position ourselves for stronger oil growth levels in 2013 and beyond. Our goals in 2012 are to maximize our revenues, cash flow per share, improve upon our per-unit of production operating margins. For all the reasons referenced, absolute production growth is not an emphasis for us in 2012, and we expect that our production will range from 290 to 300 Bcf equivalent or flat to slightly higher than 2011 pro forma for asset sales. You will see in our first quarter guidance that we've deferred approximately 2 Bcf of gas production through curtailments and deferred well completions in the Mid-Continent. We may also elect to curtail, shut in or defer additional natural gas production should prices further deteriorate.

Our largest investment areas in 2012 will be the Uinta and Williston Basins, the Cana Woodford and Malaysia. I'll provide a brief overview of these programs before closing the call and taking your questions.

Our oil production in the Uinta Basin is expected to grow more than 20% in 2012. We will allocate over $500 million into the Uinta Basin of 2012. To date, we've drilled 9 horizontal wells in the Uteland Butte and 17 vertical wells in the deeper Wasatch. Our results to date are consistent with our expectations and we have an aggressive assessment and development campaign planned in the region in 2012. These new plays, along with our Green River development at Monument Butte, provide strong returns and will add significant value for us in the future. In 2012, we expect to drill up to 65 wells in the Central Basin. This includes up to 30 horizontal wells with an emphasis on our pressured Uteland Butte play, along with horizontal assessments of the Black Shale and Wasatch intervals. Our first pressured Uteland Butte well is drilling today and completion is planned in the coming weeks. Our first horizontal Wasatch well will spud in March with results expected late in the second quarter. These plays will accelerate our oil growth and drive our transformation to an oil company. We expect to run 7 to 8 rigs in the Uinta Basin in 2012, with 4 to 5 allocated to the Central Basin. We've reduced our historic 4 to 5 rig count in the Monument Butte Field, Green River targets to a planned 3-rig program in 2012. We are focused on driving outsized oil growth from this asset and our new refining agreements give us the visibility we need to double our production levels out of the Uinta Basin by 2015.

We will invest about $200 million in the Williston Basin in 2012. You'll recall that our activities in the basin slowed in late 2011 to ensure that we limited our budget overexpenditures. We deferred the completion of about 17 wells and dropped 3 rigs. Since then, we sold a package of the assets, which included 8 of the uncompleted wells. Our crews have completed 3 wells since January 1 with an average 24 hour IP of 2,900 barrels of oil equivalent per day. Plans are to have the remaining 6 wells completed before mid-year, and we expect to run 2 to 4 rigs in the Williston Basin during the course of the year. Our current production is about 7,500 barrels of oil equivalent per day, and is expected to grow about 35% in 2012 compared to 2011 levels.

In 2012, we expect to drill about 25 new wells in the Williston Basin. Our drilling is focused on identified locations in the Middle Bakken and Sanish/Three Forks across our acreage. We have about 60,000 net acres in core development regions along and southwest of the Nesson Anticline and an additional 40,000-acre position, all held by production in the Elm Coulee. We have more than 250 identified development drilling locations today and plan to increase our activity levels in the Williston Basin going into 2013.

Let's move on to our newest area, the Cana Woodford, where we plan to invest about $300 million to rapidly assess our new acreage in the Anadarko basin. We call this play stealth throughout 2011 as we assembled a 125,000-net-acre position.

From a pit perspective, this new area is great. From a proven operator in Oklahoma and in the Woodford where we have drilled more than 375 horizontal wells to date, our new acreage has scale of thousands of potential locations and running room. We have great relationships with service providers, and it can compete for the services we need in Oklahoma. Regulations in Oklahoma are favorable and we can get the necessary permits we need in a timely fashion. And lastly, this play has both oil and liquids rich gas, which will keep the economics competitive within the best of the Newfield portfolio. We are ramping to a 7 operated rig program in early 2012. Our rapid assessment, pending success, will put us in a position to further increase activity levels into 2013. This play has potential to drive material future oil and liquids growth for Newfield. We've drilled a few wells in our acreage to date and are encouraged with the early returns. In addition, we have interest in a few industry wells on and around our lease position that have also been very positive. Consistent with our previous disclosure in new drilling areas, we will wait until we have adequate production data from a sampling of wells before we discuss our results publicly.

It would likely be midyear before we are in a position to provide you with a meaningful update. In Malaysia, we are seeing record gross production today of about 70,000 barrels of oil per day. And today, we're the fourth largest producer in the country and the third largest producer in the Malay Basin. These are material oil developments to Newfield, and to our partner, Petronas. Our projects in Southeast Asia are all oil. For 2012, we will allocate about $235 million internationally, with approximately $135 million to Malaysia. The remaining $100 million will be for the development of our Pearl Oil Field in the Pearl River Mouth Basin offshore China. Our first production is expected in late 2013 or early 2014.

Our net production today in Malaysia is a record 30,000 barrels of oil per day, 1,000 barrels of oil per day higher than reported last night with early and good news this morning. Our people in Malaysia continue to outperform and we're really excited about the potential looking forward. Our Malaysian crude trades at a Brent price and we are seeing excellent returns from these oil developments. We will accelerate development of our Malaysian producing fields and test new oil and natural gas exploration prospects in 2012. Our East Piatu field came online in November and is today producing about 12,500 barrels per day, higher than our earlier expectation of 10,000 barrels per day.

We have recently accelerated Phase 2 development well campaign, which will allow us to keep production at maximum rates. The Puteri field commenced production in October and is today producing about 8,000 barrels per day. Our exploration efforts in Malaysia are ongoing with some exciting oil and gas exploration wells planned for 2012. Recent positive changes and deepwater PSE terms, deepwater natural gas PSE terms, provide compelling investment options in our portfolio today. In addition, we continue to seek new opportunities in Malaysia to ensure future oil growth.

In the Maverick Basin in Texas, we plan to invest about $100 million in 2012 and run a one-rig drilling program. We're drilling our second Super Extended Lateral in the Eagle Ford today, and our first well is now being completed. These wells are part of a planned 4-well pilot program of SXL wells in 2012 on our southern acreage block. In addition, we will be testing prospective targets during the course of the year in the Austin Chalk and drilling oil wells on our Georgetown play in northern Maverick County. In closing today, let me summarize our focus in 2012.

Our efforts will be laser focused on growing oil production and reserves. Our oil and liquids production in 2012 is expected to increase more than 20%. This growth will come from our ongoing success in the Uinta and Williston Basins, Malaysian oil developments and initial volumes from our new liquids-rich Cana play. Success in the Uinta Basin and Cana Woodford will lead to material reserve bookings at the end of 2012 and set us up for superior growth in high-value plays in 2013. We are taking the right steps today for our future. We will continue to improve our organizational focus. Focus was one of Joe Foster's sounding principles for Newfield and we will not stray. The success of our nonstrategic asset sales program is helping us allocate people and capital to the best projects. Focusing on fewer activities will help lead to superior results in our operations. We will continue to live within our means and align our investments with internal resources. We have ample resources to grow our oil projects and expect that our nonstrategic asset sales will continue. We will manage our balance sheet, and as always, maintain a strong capital structure. We will not lose sight of the future and will continue to build the people and prospects for the future. We've made significant investments in Team Newfield over the last 3 years and our recent expansions into exciting new areas like the Central Basin in Utah and the Cana Woodford in Oklahoma help to ensure that we have the plays in our portfolio today for our future growth. I'm excited about 2012 and confident that we are executing the right game plan to continue creating long-term value for our shareholders. Operator, we'll move to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And ladies and gentlemen, we'll go first today to William Butler with Stephens.

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

I was wondering if you could specify on the Woodford Cana, a little bit more on the counties that you all are in.

Gary D. Packer

Yes. The Canadian and Grady Counties, which would be specifically the areas east and southeast of the historic Cana field.

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

Okay. So would you be primarily east of there of where Continental has got a big acreage block? Does that sound about right?

Gary D. Packer

I think Continental has the lease position across the entire play. So I really couldn't speak to that. But I'd say, east and primarily southeast of the historic Cana field.

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

Okay. Great. And did you all – and I hope I didn't miss this, but did you all disclose, in terms of what you all are expecting oil and NGLs cut-wise on a percentage basis?

Lee K. Boothby

We did not.

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

Okay. Would you like to?

Gary D. Packer

We have no plans to talk about that until we feel we have fully assessed the position. We're drilling wells across the acreage and once we have our arms around that, we'll be able to bring it forward. Clearly, it's targeting both oil as was referenced in the call, as well as condensate gas and NGLs also play part of that, of course.

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

Okay. Thank you. As we start thinking about 2013 and the things you all are doing to position yourself for that, how should we think about the growth for the year?

Lee K. Boothby

We haven't put any growth numbers out. Obviously, for 2013 at this point, I would say that let us execute our plans during the course of 2012. I expect that sometime around midyear, we should have a basket of results that we can talk about in terms of how it sets up the back end of 2012 going into 2013. But ultimately, our objective is to navigate forward with an oil-driven growth profile and get back to where we can deliver double-digit growth driven by oil. I think that transition from a gas-dominated production mix and oil-dominated production mix will take a couple of years. And on the back end of that, we'll be back to the game plan that we've been talking about over the last couple or 3 years. Again, oil-dominated production, oil-dominated reserves.

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

Okay. And one last question. As you all think about gas curtailments, what other areas besides the Woodford and the Granite Wash would you all consider further curtailments if you did?

Gary D. Packer

That's really the area, William, that's where most of our natural gas is coming from and that's where we'd focus it.

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

Will this be further curtailments in those areas then, switch it?

Lee K. Boothby

That's correct. We have -- some of it's associated with capital programs and completions of wells that are natural gas focused that we're rolling out of 2011 into 2012 and some of it will just be relative-to-zone margin gas. The other part of it would be just deferred gas as we look to step into completions and we probably have broader shut-ins than we otherwise would have to do in order to ensure the effect of completion of offset wells.

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

Okay. And what gas price and for and sustained for how long would you all -- are you all considering further curtailments?

Lee K. Boothby

I would say at this point, we don't have a specific target price. I mean, clearly, we've said if gas prices deteriorate further, I would say that if gas prices fall below $2, you might see some dramatic adjustments at that point. Where we sit today, I think that the game plan is pretty well set. We'll accept the decline on our gas assets because clearly, they are cash flow positive, covering operating cost. We just won't be investing any new capital in gas projects.

Operator

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

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

Real quickly, looking at your potential divestiture plans. Can you talk a little bit about whether you'd consider selling additional Bakken? And then, on the opposite side of that, are you looking at any potential acquisitions to bolster oil production growth, whether they'd be corporate, asset specific, leasehold, i.e. more acreage at Cana Woodford, just kind of give us a sense of each side of that equation?

Lee K. Boothby

Okay. So on the first side, I would say we have no additional plans to divest Williston Basin assets. We've described those as bridge assets. We've got a strong development inventory and we're looking to ramp up activity there. So I'd say that's not on the short-term target list. The only thing that we've announced at this point, Dave, is that we're going to pursue options to maximize value of our Gulf of Mexico assets that could involve divestiture or a number of deal terms, trades, et cetera. We are going to be open to any and all of that, but in the end of the day, it's going to be about maximizing value on those assets and that could mean that we produce out the producing fields. The only thing we've stated there is we have no additional intention, no intention of drilling exploratory wells, prospectively, and no material capital allocated to the Gulf of Mexico in 2012. So I think that's the only thing that we've kind of flagged for consideration in 2012. Beyond that, we still have additional assets that are more appropriately, I would say, described as part of our past as opposed to part of the future, and we'll continue to consider opportunities to shed nonstrategic assets in lieu of repositioning our human assets in terms of higher priority projects. In terms of the leasing or acquisitions, clearly, we've said publicly that we think that the current environment and environment we'll likely will see over the next couple of years likely will favor some M&A-type activity. We intend to keep our toe on the water, if we find opportunities to strengthen the portfolio at attractive prices, we'll probably take advantage of those opportunities. But clearly, not going to target any of the areas that we're specifically focused on in that regard. Beyond that, in terms of leasing, I would say that we've got no outsized leasing plans afoot starting 2012. But obviously, we'll continue to add acreage where it makes sense as long as we can get the acreage at attractive prices and it fits with our overall strategy.

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

Great. Thank you. And then, just looking at your reserve revisions, you had some negative revisions associated with a number of different things: waterflood responses, higher gas production cuts in part of Monument Butte, some well failures on the Gulf Coast. Could you give us some additional color on those? Is this a onetime cut or is there potential that these have additional downside related to them?

Terry W. Rathert

Dave, I think you got the list right and most of those are onetime, I will say that we gave some geographic descriptions of where some of those were along the Gulf Coast. We've had some historic well bore fayers [ph] and some really old wells and wells that have been pretty active, I call it, geologic section. We think those are pretty much behind us as they've continued to diminish over time. The vertical wells we referenced in Mid-Continent in a couple of areas we had some old vertical production sections that were opened over very large sections and they saw the effects of horizontal completions offset. With the relatively low pressure in today's gas prices, it doesn't make sense to go back and try to bring them back online and do the workovers necessary to return to production. So they're almost an artifact of what you think of as a price revision, de facto that they saw some offset well interference. In the Greater Monument Butte, yes, there is waterflood timing issues in terms of recognition and in the other areas you mentioned, we tried to extend the field to the Northwest and we encountered an area that was, we believe, influenced by the Duchesne fault in the region and put a little more gas in the section than we would otherwise seen. That additional volume of gas basically made them more gassy and not as attractive to continue to drill in that area. So we've directed our activities away from that and maybe, I'd ask Gary to expand on the fact that we recognize that today and we've actually moved our activity in the Rockies away from that region and he can address our plans for drilling there.

Gary D. Packer

Yes, Dave. As we encountered more gas to the northwest to the field, this is really -- it's not in the Central Basin, but it's outside of Greater Monument Butte-Eunice. Made some gas wells and the fact of the matter is, is historically, you would have been able to blare some of this gas. Regulatory changes have prevented that. Therefore, we kind of flooded our infrastructure with the natural gas which caused some back pressure that cost us to not want to drill there anymore, or at least temporarily. So as we've redirected our activity, you'd see all of our Green River activity has been redirected into our 20-acre infill drilling within Monument Butte proper. We'll run about 3 rigs there this year, and we're having good success in that, and that's really where the Green River will be focused. Their rest of the drilling campaign up in the Central Basin, which is really where a lot of the growth is going to be in our future.

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

That's helpful. On the waterflood timing issue, is that something where once the response is achieved would you actually see a positive reserve revision from that?

Gary D. Packer

That would be my expectation, yes.

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

Okay. And then last question, just looking over at the service cost environment, up in the Bakken, I know you guys looked at some of the folks who, when you were in not -- in a non-operated position and the well cost there, can you give us kind of updates of your cost and the cost that you've experienced in non-operated positions as well?

Gary D. Packer

Yes, we -- I haven't updated that look that we made, Dave, of the non-op position. I can tell you what our view of it is. Right now, we're looking at somewhere in a kind of a low $10 million well cost for a 1,280-acre well. That's maybe upwards of about $1 million lower than what we previously had talked about. There's a couple of things. I think just improved execution is going to drive most of that versus service cost changes and in 640-acre wells, we’re going to be looking at somewhere around $7 million well or so, in that vicinity.

Operator

We'll go next to Subash Chandra with Jefferies.

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

Hypothetical here, but when do you think you would go after that Tcf-plus gas probable inventory, at what gas price would you renew activity?

Lee K. Boothby

Well, Subash, I'm going to guess probably not $2.50.

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

I hear that loud and clear. But do you think is it a 5 number or a 4 number. Any flavor?

Lee K. Boothby

Well, we're going to be consistent on our answer with what we said previously. We've got plenty of attractive oil investments in the portfolio and to pursue gas investments, the gas investments have to have competitive returns with our oily portfolio. So you either have to see oil come back dramatically on price or gas declines. So you close of the gap between the 2 product types. That'll really make the gas inventory attractive. Most of our gas assets are held by production, so the fact of the matter is, we can sleep good at night and we're not going to lose the leaseholds. The only issue you'll see is what you've seen the last 3 years, you'll see as we move oil into the 5-year window and push gas out, you'll see that repositioned into the probable reserves. The bigger issue, I think short-term, on the overall reserve issue is, what is the SEC price going to be at year end 2012, and what are the result and impacts there in terms of reserve classifications? I think that's something for you to keep your eye on.

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

Could you provide maybe a boundary of what type of PUDs, dry gas PUDs remain at risk in the 2011 reserve report if it was to get pushed out of the 5-year window?

Gary D. Packer

I think you for the most part, most of our gas PUDs have been pretty well been moved out of the 5-year with window as demonstrated by our capital plan. We have no plans to drill gas wells in 2012 and that pretty well holds true through that 5-year window, so almost all of our gas PUDs are already out there as a practical matter.

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

And in the Cana, just not on operational results, of course, but how much, how many rigs do you think you'd need to run to retain the acreage?

Lee K. Boothby

We've looked at that and based on the current acreage position we have right now, we could, as we entered this year, we had 2 rigs, we've got 5 rigs running now. As alluded in the call, we'll be -- we would anticipate 7 by year end. We could get to 10 rigs and that will allow us to hold the entire 125,000-acre position.

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

So 10 rigs. So you would hold that in the current year, or --

Lee K. Boothby

No, we would --

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

Over what time frame?

Gary D. Packer

Subash, I think that was about 3 or 4 years, that's a combination of drilling. It's not just drilling 5,000-foot laterals. This year, we'll be expanding our lateral lengths. So there certainly has to be an element of expanded lateral lengths in order to accomplish that.

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

Okay. And I guess, so the Super Extended Lateral, that has to be applied for on a case-by-case basis, and do you think that there just might be statewide approval of that at some point?

Gary D. Packer

I think some of the recent legislation opens the door for that. And I think we would anticipate broader application for the Super Extended Laterals.

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

Okay. And in terms of selling a material-producing asset like the Gulf, how do you think of that shrinking to grow, so to speak, versus the 10 Bs or so that you've sold in 2011?

Lee K. Boothby

I think we would think about it in terms that we've described. It's a value proposition. We can hold those assets and take the cash flow off of those assets and redeploy them over time, or we can find an attractive transaction or series of transactions that allows us to maximize value and then reposition to take the capital and redeploy it into other areas and the people and reposition on the higher priority projects. But I think it's just a more visible manifestation of what we've already done during the course of 2011 with our nonstrategic asset sales. I think that's the key with the Gulf, that we’re deeming it nonstrategic.

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

All right. And a final one for me, what are these Malaysian IRRs on a per well basis, perhaps or project basis?

Gary D. Packer

Yes, by the nature of the PSC terms, you're kind of capped out even at the higher oil prices. I'd say we're typically looking, we did a look back here recently and we were north of 30% returns on a project like East Piatu, but you probably struggled to get much over 35%, I would suspect.

Operator

We'll go next with Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

Can you talk about the natural gas exit rate versus 2011's exit rate? Is it going to be down 20%, 25%? Is that a reasonable assumption?

Lee K. Boothby

Well, natural gas, you’re talking about for '12?

Gil Yang - BofA Merrill Lynch, Research Division

Right. The exit rate.

Lee K. Boothby

In '11 versus exit '12?

Gil Yang - BofA Merrill Lynch, Research Division

Right.

Lee K. Boothby

Yes, we said that the natural gas volumes will likely decline up to 15%. So I think you'll be inside of a 15% decline rate. 60% of our production last year was natural gas on a 300 Bcf total, so you do the math on it. I'll let Gary give you some other color.

Gary D. Packer

Yes, I think our fourth quarter numbers were about 44 Bcf, Gil, and first quarter we're sitting at 39 so that's down about 10% or so. A lot of that's going to be driven by just the timing of completions. As you know and as we've talked about publicly, we made a considerable drop in operational activity in the fourth quarter. That lack of completions in drilling then follows through. That bow wave hits you in the first quarter. And as we put rigs back to work, and get back to a more normal state of operational activity, that number will grow generally. But its 10% quarter-on-quarter.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. But does the 15% reflects the volumes for the entire year versus the volumes in the entire year of 2011?

Lee K. Boothby

Year-over-year.

Gary D. Packer

That's correct.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Can you comment on the DD&A rate, took a sort of jump in the fourth quarter and understandably it's because the oil is more of the focus. But given that, Lee, you said that the transition's been going on since 2009, is there anything in particular that caused the jump in the fourth quarter? Is it because of the Asian production came online and that carries a heavier DD&A rate, which I see in your guidance it does. Is that part of it?

Lee K. Boothby

I'll let Terry take that one since he's in the middle of all that.

Terry W. Rathert

Yes, if you break it into the pieces, you have a international DD&A rate, which is clearly much higher than the domestic part of when you bring that production into the mix. It has a heavy influence on the domestic front. It shifts to continued investment in oil. At $2.50, that's still, if I did my math right, in the range around $15 a barrel. So when you think about the DD&A rate is going up, it’s a matter of fact that, that and the fact that if you go back 3 years, we had full cost ceiling test write-down when natural gas prices and oil were very really low. We had this big, deep reset of our cost pool at levels which absolutely were not sustainable because of the then current way the full-cost ceiling test rules worked. And you just expect that to continue to change as we go to oil, we'll continue to move up.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Great. Lee, you mentioned the idea of focus of the company and can you talk about your longer-term strategic view. You mentioned that you might do some other acquisitions again in new areas. Can you talk about how you think about the long-term focus of the company given that you got Uinta, you got Bakken, you got now the Cana, Eagle Ford, Asia, maybe a new asset. Where should we be thinking about the strategic long-term focus of the company going?

Lee K. Boothby

Well, Gil, we've said publicly over the course of the last few months that our objective, over the next 3 to 5 years, is to expand our foundational asset portfolio. So we've had 2 foundational assets that we've talked a lot about the last 4, 5 years, Monument Butte Field, which is a Green River story, Green River oil sands story, and the Woodford Shale. The Woodford Shale positions largely natural gas, we've expanded that position with the Cana, I'll come back to that here in a moment. Focused on wet gas, condensate and oil, which I think will improve our mix in the Mid-Continent Region. And then the Central Basin, we took steps in 2011 to materially expand our acreage north of Monument Butte, added north of 75,000 acres to go into the position that we already had there, to take our total position up north of 230,000 acres. The Central Basin expansion provides a whole new opportunity set to us relative to what we've had historically in the Uinta. And we're excited about that, and we're accelerating our horizontal testing in multiple horizons but we're going to attack in the first half of '12. So ideally, we've got the 2 foundational assets we've talked about. We believe the Central Basin could be a third piece of that puzzle and I would say that I hope that the Cana Woodford could be another piece of that puzzle in that regard. But ideally, 3 to 5 years out, we'd have somewhere between 4 and 6 foundational assets and that's what we spend all of our time talking about and focused on. We put out the logic that the balance of our development inventory, which hits on a number of the projects that you talked about, Williston Basin, historically, Gulf of Mexico, Southeast Asia, our developable portion of the Eagle Ford today, et cetera, et cetera. We look at them as kind of bridge development assets and it's kind of bridge to the future. They're attractive assets, good returns, but they've got less than a 10-year development inventory. So the key for us is to manage that activity within the context of our capital program. We'll look at the some of those areas for potential growth towards the foundational assets and in some of those areas, that may require taking advantage of acquisition opportunities at various points in time to expand the portfolio. So, I think it's going to be a mix of activities. But overall, I think about foundational assets and the bridge assets being a bridge to the future.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, great, Lee. Final question, going back to I think one of the previous questions. At what price gas would it be drillable? If you just kept oil the same, understanding it needs to be competitive with the rate of return, but could you just give us an idea of either what that rate of return is today that you would need to gas to get to be competitive or at least what the gas price is to get to that rate of return?

Terry W. Rathert

I would -- kind of shooting from the hip here a little bit. But I would think if we saw service costs in the area of the Woodford that are not heavily influenced by the oil price around them, where there's more normal pressure pumping cost, we observed in the past, we're in the $5 range then this things could be moving right back on top of the radar screen and be highly competitive. Because it's almost, it's just pure margin, right? I mean, in essence, you take at 250, you can't get compelled to do much of anything in natural gas almost anywhere. The reserves have a positive value to us at year end pricing, they're just beyond the 5-year window. You move the pricing up $1 and it becomes a pure dollar profit and cash flow. And any other thoughts?

Gary D. Packer

Well, I think the most -- my first thought there, Gil, was is if we saw improved gas prices, we'd just have higher discretionary cash flow and we would move to drill more oil, quite honestly.

Gil Yang - BofA Merrill Lynch, Research Division

Right, right. But at some point you'll say maybe I can drill more gas and it sounds like maybe $5 is a point where that happens if costs come down maybe 20% or something like that?

Lee K. Boothby

If you put it in return space, we've well documented the returns from our oily portion of our portfolio, Gil. You can do the calculation yourself. But you're going to need 35%, 40% plus returns to compete on a return basis on the back end of our oil assets. So it will just be a function of what can we generate out of the gas investment versus the back end of our oil portfolio.

Operator

We'll take our next question from Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

You've described your asset sale program as a desire to reinvest in your existing inventory. Where will, if you manage to sell the Gulf of Mexico this year, where will those cash proceeds go?

Lee K. Boothby

Well, I think, quoting Gary's response a moment ago, we'll look to utilize those assets to accelerate development in our oily portfolio. We hope that with success on our aggressive assessment programs in the Uinta and the Cana Woodford that our -- the oil development inventory is expanding. We know we've got the ability to expand activity in the Williston Basin today. So we've got places that we can take that. We're actually doing some tests in the Maverick Basin of Super Extended Laterals, pilot project success there. We can go and attack that project as well. So we've got multiple projects in the portfolio that we can attack and we've got development projects overseas in Southeast Asia that are oil as well. So we've got plenty of places to reallocate that capital that would be realized from any divestiture.

Anne Cameron - BNP Paribas, Research Division

I guess I was actually just asking where will the first dollar go, which play, between them?

Lee K. Boothby

Okay, well I, sorry. I guess I give you a really long answer. I'll let Gary give you a short answer since he directs where it goes.

Gary D. Packer

I guess I'd have to say today that the first dollar, we'd probably bring into the Bakken. It's not because it generates the highest returns, it's that, right now, we have some pretty material assessments going, and I'd like to see some were activity and more results from the Central Basin, the horizontal program, as well as the Cana program. But the Bakken and in the other area I'd put more immediately is our 20-acre infill play at Monument Butte. It generates superior returns, it's well understood and our, on our regulatory and our permitting environment is improved. So those 2 areas where we'd take incremental activity sooner than others, sooner than the others.

Anne Cameron - BNP Paribas, Research Division

Okay. Great. And are you still leasing in the Cana at this point?

Lee K. Boothby

I really couldn't comment on that right now.

p id="142743717" name="Anne Cameron" type="A" />

Okay, okay. So if 10 rigs are what you need to get to hold your position there, what do you think the max, like from a logistics perspective, what's the max rig count on 125,000 net acres you have that you could run?

Gary D. Packer

Yes, I mean, historically we've got up to 17 rigs running in the Woodford Shale. The team did a great job, but that's running pretty hard with the teams that we have in place. As I said earlier, 10 rigs running through 2016 allows us to hold our position, assuming it stays where it is right now. So somewhere in that 10 to 17 window is probably a feel good for us, a sweet spot, so to speak.

Anne Cameron - BNP Paribas, Research Division

Okay, got it. And then the 198 Bcfe negative performance revision on your reserves, would you be able to quantify how much of that is proved developed and how much of that is PUD?

Terry W. Rathert

The majority that would be proved developed is you had a wellbore failure as the majority of the wells were producing, obviously, if you had vertical wells were on production were adversely affected, that would be producing. We moved, I think, the note showed that we moved 87 Bcf of proved and undeveloped reserves beyond the 5-year window. That clearly is the largest piece of the proved and undeveloped.

Anne Cameron - BNP Paribas, Research Division

And that does the 5-year rule count towards the negative performance revision, or is that, just fall into a bucket of like other negative revision?

Terry W. Rathert

Well that's where the revisions go. So when you move them out, so that goes into that line because you don't have another -- you don't have the 5-year rule category line on the -- so we bump it into that revisions number.

Anne Cameron - BNP Paribas, Research Division

Is it part of the 198 that you outlined as the negative performance revision?

Terry W. Rathert

No, in the line item that you see in the description, it is not part of 198. It's part of the total revisions.

Operator

We'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Uinta Basin, can you talk to your capacity for growth on oil production until the downstream contracts that you've signed come online? And then when those contracts do come online, should we think about that incremental barrels a day as the upper limit for your capacity for growth or should we expect additional unlocking of downstream capacity?

Lee K. Boothby

I'll give you a high level and I'll let Gary fill in the details. First and foremost, I would look at the contracts that we have in place to give you comfort zone visibility of expected growth profiles out of the basin on the low end of the scale. So if you think about exiting 2014, it will be my expectation of a 40,000-barrel a day minimum, low end of the range. If you took the existing arrangements that we have in the basin with other refineries outside of the longer-term agreements, we've got another 10,000-odd barrels that we move today so you're looking at 40,000 to 50,000 barrel a day if you just utilize these agreements and keep existing arrangements in place. Getting to a 50,000-barrel a day type number in 2015 gives you a 2x growth rate over a 3-year time horizon out of the basin. And clearly, I would say that Gary and his teams probably won't be satisfied with stopping at that point, but I'll let Gary give you any additional color.

Gary D. Packer

Brian, I guess the only thing that I would add is that those contracts allow for the initiation of additional capacity as early as 2013 and there's a ramping of activity that comes along with that. So I would look for it as a pretty much a steady growth rate in a 20% to 25% this year. I would look for, in excess of that in 2013, which really sets the table for what Lee was referring to, is something of 40,000 to 50,000-barrel a day rate in '15 and beyond.

Brian Singer - Goldman Sachs Group Inc., Research Division

Thanks, that's helpful. And then looking at the Granite Wash, how much of the shift and the redirection of capital away from the Granite Wash would you say is gas price related or for CapEx constraints in the context of your portfolio versus is related to either inventory or resource visibility reasons and maybe you can touch on the commodity price environment you'd allocate back there as well?

Lee K. Boothby

Let me see if I got your question. If I didn't, try again. But I think the first part of that question is that obviously, we've tested multiple horizons in the Granite Wash. We've talked publicly that the shallow horizons are high Btu and high condensate yield and they've generated attractive returns. That still true today, and on a $2.50 gas, the returns have diminished over the 35%, 40% returns that we're talking through most of 2011. The way that I would look at it near-term is we're taking the rigs that we've had deployed in the Granite Wash, and were moving them to the Cana Woodford in the short-term. Gary has repositioned the rigs there for the assessment program that's going to be a pretty aggressive effort in the first half of 2012. And again, that's focused on wet gas condensate and oil targets that we believe will generate superior returns. So that's what we're pursuing and that's the most notable part of the shift in terms of rig count. And clearly, the deeper portfolio in the Granite Wash the doesn't have the condensate yield, I would put that on the to-be-deferred-in-the-future discussion, and we have no interest in pursuing at this time. We don't have to. Our position's held by production.

Operator

Ladies and gentlemen, that's all the time we have for our question-and-answer session today. I'll turn it back over to Mr. Boothby for closing remarks.

Lee K. Boothby

Operator, if there's anybody still there, well, we've got time for 2 more questions. If anybody's still out there that wants to ask a question.

Operator

And gentlemen, there are no questions at this time.

Lee K. Boothby

Okay, all right. Well then, I'll go ahead and say thank you for your time this morning and thank you for your interest in Newfield. We look forward to updating you as the year unfolds on our plans and progress towards becoming an oil company in 2013. Thank you.

Operator

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

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