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Newfield Exploration Company (NYSE:NFX)

Q3 2010 Earnings Conference Call

October 21, 2010 9:30 AM EST

Executives

Lee Boothby – Chairman, President and CEO

Gary Packer – COO

George Dunn – VP, Mid-Continent

John Jasek – VP, Gulf of Mexico

Analysts

Scott Wilmoth – Simmons and Company

Gil Yang – Bank of America

Joe Allman – JPMorgan

Bob Morris – Citi

Joe Magner – Macquarie Capital

Ankit Ram [ph] – Global Data [ph]

Brian Singer – Goldman Sachs

Rehan Rashid – FBR Capital Markets

Dan McSpirit – BMO Capital Markets

Brian Lively – Tudor, Pickering, Holt

Gordon Steuart [ph] – Wells Fargo

Jack Aydin – KeyBanc Capital Markets

TJ Schultz – RBC Capital

Richard Tullis – Capital One Southcoast

Operator

Good day, everyone, and welcome to Newfield Exploration Third Quarter 2010 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 the expectations reflected in these statements are reasonable, they’re based up on assumptions and anticipated results that are subject to numerous uncertainties and risks. Please see Newfield’s annual report on Form 10-K and quarterly reports on Form 10-Q for a discussion of factors that may cause actual results to vary.

In addition, reconciliations of non-GAAP financial measures to GAAP financial measures together with Newfield’s earnings release and any other applicable disclosures are available on the Investor Relations page of Newfield’s website at www.newfield.com.

At this time, for opening remarks and introductions, I would like to turn the call over to the Chairman, President and Chief Executive Officer, Mr. Lee Boothby. Please go ahead, sir.

Lee Boothby

Thank you. Good morning, everyone. I appreciate you hanging with us through what appeared to be some technical difficulties. And those of you who had to call back in, I appreciate you calling back in. So I apologize for the delay, but we’ll get moving with the call.

Welcome to the third quarter conference call. I’d like to thank all of you for your continued interest in Newfield. Very quickly, by a way of introduction, I’ll announce that Gary Packer, our Chief Operating Officer; Terry Rathert, our Chief Financial Officer; Brian Rickmers, our Controller; Steve Campbell, VP of Investor Relations; and John Jasek, VP of Gulf of Mexico are with me here in Houston. And, remotely, we have George Dunn, who runs our Mid-Continent Business on the line as well.

Along with our earnings release, we issued a separate operations release yesterday, updating you on our core focus areas. We don’t address your questions in our prepared remarks this morning. We’ll have plenty of time at the end of the call.

If you’ve seen us recently on the road, you know that our focus is clear. We are delivering on our promises and have our sights fixed on meeting our 2010 year-end objectives. From our guidance, you will see that our production growth will not be less than 11% year-over-year, the upper end of our original guidance range entering 2010.

We’re investing in our oil projects and soaring our activities in natural gas plays. Our most recent tally shows that more than 50% of this year’s $1.6 billion capital budget is now oil directed. And I’m proud to report that the $1.6 billion remains unchanged since our beginning of year announcement.

Our domestic oil volumes are expected to increase nearly 25% in 2010 over 2009. We’ve improved our portfolio management and our margins have increased. Better margins are a result of higher returns in the oil plays, they’re constant efforts of lower costs and improved efficiencies, and a strong oil and gas hedge position. Through the optionality of our diversified portfolio of assets, we’re able to make improved capital allocation choices while continuing to live within cash flow.

And, finally, we are committed to building for our future. We have several significant assessments underway that could provide additional options and have a material positive impact on our future. We continue to look for attractive deals or bolt-ons in our current focus areas and we are steadfast in our focus to build a portfolio which can outperform through the inevitable cycles.

2011, well it’s now just around the corner. So for the remainder of today’s call, I would like to focus on 2011 and our assets that will continue to drive our evaluation and performance.

Our entire management team spent three days together in an offsite meeting last week working on our initial game plan for 2011. Our collective work product will go to the Board of Directors in early November. So here is a brief summary of our current thoughts.

First, the macro environment will remain challenged. In our view, 2011 will be a challenging environment in E&P. Natural gas supply continues to exceed demand, the domestic rig count particularly the horizontal gas directed rig count remains higher than warranted by pure economics. We recognized this climate [ph] early enough to build a strong hedge position. We’re very well insulated by these hedges and have oil opportunities and our portfolio today that is delivering both growth and excellent returns.

Next, we will continue to stay focused on oil over gas. It’s oil over gas once again. We will remain far more constructive on oil than we do natural gas going into 2011. We will continue to defer significant new investments in our natural gas development which were substantially held by production today and require limited drilling to retain primary term acreage. The Rocky Mountains will remain a centerpiece of our domestic oil story. And we are confident that we can continue deliver strong oil growth in 2011.

We are fortunate that our acceleration of oil investments began back in 2009. Because of this, we are guiding toward a 25% increase in our 2010 domestic oil volumes and a 12% increase from our total company oil volumes. With this, we will have great momentum on the oil growth as we move into 2011.

Our domestic oil growth stems largely from the Monument Butte Field in the Williston Basin. A continuing acceleration of our drilling programs here creates strong incremental net present value by shortening our full fuel development cycle. At Monument Butte, we have optimized our drilling programs to drill more well more efficiently and previously thought possible. We will drill about 375 wells this year at Monument Butte and grow production more than 20%.

Our pace today provides us with operational momentum as we enter 2011. Our development drilling continues in the Williston Basin with four operated rigs running today. Three of these rigs are working on our off Anticline acreage. We have successfully assessed our Catwalk, Aquarium and Watford areas, west of the Nesson and have moved these project areas into the development drilling phase.

Our assessment phase is focused on 4,000 foot laterals year-to-date. Our IPs for the 17 wells drilled and completed so far in 2010 average about 2,400 barrels of oil equivalent per day. As we transition into development we’ve planned to drill primarily 9,000 foot long laterals. We are currently drilling or completing five long laterals in our off Anticline acreage and expect to complete our first 32-stage frac job later this month in the Watford area.

We have lots of new information from our Williston program late this year. We continue to be excited about the potential of our acreage and expect that our 2011 Williston Basin net production will exceed 10,000 barrels oil equivalent per day in late 2011.

Our Granite Wash play in the Mid-Continent range continues to be an active focus area for us as well. The Granite Wash play generates superior economics through a combination of high early flow rates, quick payout, and the rich gas condensate that makes up the flow stream. In the third quarter, just 3.5% of our total company production came in the form of NGLs.

Internationally, our production is 100% oil. We average nearly 14,000 barrels of oil per day net in the third quarter and are guiding to 20,000 barrels of oil per day net in the fourth quarter. In Malaysia, our oil projects are very profitable. Keep in mind that our PSEs provide for surety of returns in low-priced environments, as well as a healthy participation in times like today. We break out our international cost structure separately in our release, so that you can better understand our profitability.

Today, we are also developing a new field in Malaysia on PM 329 called East Piatu. This oil development will add about 15,000 barrels of oil per day gross, late in 2011. We have a 70% operator interest in this field which will allow us to grow our Malaysian production in 2012.

Improving margins, growing cash flow per share will be differencing aiding factors ahead. We are in a 60% of our current revenues in 2010 will be derived from our oil volumes. Our B tax rate of returns today in the Williston Basin and Monument Butte range from 50% to 90%. Our Granite Wash play is delivering returns of 20% to 60% depending on the NGO count as a contribution.

There is a charge in our recent handouts that shows our margin improvement over the last two years. This is data pooled from public financials for 18 of our peer companies including ourselves. We moved from 12th place in 2008 to 4th place today. And today there is only 2% margin difference in the top four names. If you haven’t seen the slide, I will encourage you to take a look at it.

We are quite proud of this accomplishment. Margins matter and our results can be attributed to aggressive portfolio management, quality oil assets, a diligent focus on cost reduction, optimization of our drilling completion programs, and a strong hedge position that has added more than $300 million in additional revenues year-to-date.

Natural gas is a great commodity but not today. Long term, we remain gas bulls. Natural gas will have a vital role in our domestic energy policy and our energy future. And we will look for ways to improve margins within our gas directed portfolio. It’s clean, it’s abundant and it’s the only logical source of domestic energy that we have to meet our growing future power generation needs.

Short-term, we have an oversupply condition. We will continue to slow our investment levels in natural gas plays until fundamentals provide reason for acceleration. Let me be clear, we have a substantial Woodford Shale portfolio that is profitable at current low gas prices. And I suspect, and most operators in our peer group companies have a sweet spot or two in their gas plays as well that will provide them with the same option.

But with oil assets delivering superior economics, our investment choice is obvious today. We are focused on oil over gas and delivering profitable growth from oil. We produced our gas drilling activities dramatically. In fact, we are only running four dry gas rigs across the company today. As gas prices continue to remain at low levels, we will allocate even less capital to natural gas in 2011.

As a result of lower levels in investment in natural gas plays, you can see in our financials that our gas production is now declining as expected. We anticipate this will continue into 2011. It’s the right choice economically. More than 70% of our gas production is hedged for 2011 at about $6, but we will not subsidize less economic drilling with hedges when we have better alternatives in our portfolio, and our focus will continue to be profitable growth through oil. I am confident that we can deliver healthy production growth from our domestic oil plays and defer our ramp-up in natural gas developments into the future.

Service costs align with today’s demand, but not tomorrow’s. We have seen significant service cost increases in many of our focus areas, mainly the Williston Basin in Eagle Ford Shale. Cost increases have come in the form of pressure pumping, day rate increases, oil country tubular goods price increases, we’ve seen increases of 15% to 45% in these areas and economic margins has contracted.

We will continue to rely on the size of our operations, the steady nature of our drilling programs, and our quality relationships with key service providers to ensure that we get the most competitive price available in our oil plays. We also rely on our staff, a team of professionals that continue to impress with an ability to maximize margins through their diligent and creative efforts and the application of technology.

For 2011, our game plan will be very simple. Number one, focus on oil growth; number two, maximize our cash margins; three, provide consistent and predictable results for our shareholders; and four, continue to build for the future. We are confident that we have the portfolio of assets in place to deliver on our game plan and our proven team Newfield will continue delivering operational excellence.

Let me briefly cover our financial results for the quarter. For the third quarter, our earnings before our FAS 133 were $1.10 per share. Our production for the third quarter was 71 Bcf equivalent and includes the impact of approximately 3 million – and 300,000 barrels of defer production in Malaysia related to a damage export pipeline. Our Malaysian team worked hard and fast and the line was repaired and returned to service in four weeks.

Our 2010 capital budget, as I said earlier, remains unchanged at $1.6 billion. Terry Rathert, our CFO will be happy to take any questions you may have regarding our quarterly results at the end of this call.

Now, I will move on and give you a brief highlights in our assessment programs. In addition to our ongoing operations as I highlighted earlier in the call, we have active assessments underway today in several new areas. I will comment today on two of them, Eagle Ford Shale and the Southern Alberta Basin.

These oil plays have the potential to be game-changers in the future for Newfield. The Eagle Ford Shale is one of the hottest plays underway in the US today. We have more than 300,000 net acres in the highly prospective Eagle Ford Shale. And this acreage is has added less than one year ago, and a very attractive entry costs were approximately $400 per acre. We are investing about a $120 million this year to totally assess our acreage. Our operated rig count has ranged from three to five rigs in recent months, and our plans call for 15 wells to be drilled and completed by yearend 2010.

To date, four of these wells have been completed and turned to sales, and eight of these wells are growing or in various stages of completion today. As we have consistently stated, we do not plan to make any public announcements about our results until we have comprehensive assessment program completed. We expect to have results to share with you very soon, most likely in early 2011. What I can say is that our results to date have been consistent with our pre-drill planning, and we remain encouraged about the potential of this new area.

We have a similar assessment program underway on our more than 260,000 net acres in the Southern Alberta Basin. We recently TD’d our fifth well in this reason and has completed our first horizontal well. We will drill as many as eight wells in our assessment campaign, to test multiple formations across our Southern Alberta acreage block. We are executing our original plans and I am pleased with our team’s operational performance. Again we will not be discussing individual well results and we will update you when we have a comprehensive understanding of our acreage and its potential.

I will move on now to talk about the Gulf of Mexico. As you’re aware, last week, the moratorium in the Gulf of Mexico was lifted. This was a great first step to return our industry back to work in the Gulf. We had a great track of safety and environmental stewardship that spans decades, and I am confident that the horrific tragedy at Macondo, was an isolated event, and not indicative of our industry, and more specifically how Newfield operates.

Although, the moratorium is lifted, lots of uncertainty remains. We will carefully review the new rules and regulations. We will carefully assess the implied economic changes and use this information to help determine our passport in the deepwater Gulf of Mexico exploration arena.

In the meantime, our development programs are all on track. Initial gross production from Gladden project is scheduled for December 2010 at about 4,750 barrels of oil per day. We have a 57.5% working interest at Gladden. Our Pyrenees project is slated for first production in the fourth quarter of next year, and our Dalmatian and Axe projects are currently scheduled to come on line in 2013.

So in closing, as we enter the homestretch in 2010, I want to reflect on a slide that we provided in our IR presentations at the beginning of the year. We listed our vision for 2010 as follows.

Number one, continue to focus on domestic resource plays to scale. We are clearly doing so and are simultaneously assessing two significant plays that cover more than a 0.5 million net acres. We are also continuing to expand our footprint at the Monument Butte field. We wanted to focus on oil over gas and the proof is on our oil growth numbers for both 2010 and in our expected 2011 oil production volumes.

The second item was harvest assets and optimizing portfolio. We have refueled our conventional South Texas team to focus on unconventional basins. The cash flow from our conventional assets is helping to fund this transformation.

Thirdly, deploy people and capital to the best growth opportunities. From our improvement in margins, the results of capital discipline and more effective capital allocation are readily apparent. Our people are focused on the right assets and on doing the right things right.

And lastly, maintain financial strength. Early this year we added some term debt and our first maturity is – we retired some debt and our first maturity is now not until 2014. We were recently upgraded to investment grade by S&P. Our balance sheet is strong, our revolver is undrawn, and we have one of the most valuable hedge position in oil and gas in our peer group.

I like where we sit today and I am purely looking forward to 2011. Thanks for your continued support of Newfield Exploration. Concludes our prepared remarks, and we re happy to take your questions at this time.

Question-and-Answer Session

Operator

(Operator Instructions). And we will take our first question from Scott Wilmoth with Simmons and Company.

Scott Wilmoth – Simmons and Company

Hi guys. Just on Monument Butte for a minute you guys mentioned 2011 production growth 20%. Has there been an improvement in the permitting process there or do you guys plan to add a rig there in 2011 to maybe take advantage of an inventory permits you guys have or can you just talk about continued efficiency gains in the 2011?

Lee Boothby

I will let Gary Packer answer that question.

Gary Packer

We have not seen any material change in the permitting status out of Monument Butte. As far as the efficiency gains, I think we communicated earlier this year we're going to produce about or drill about 20% more wells than we historically have as a result of the gains that we’ve realized year-to-date.

We anticipate those gains will be consistent into – into 2011 and really I don’t see any change there. As far as add an additional rig, six rig is something we have in our pocket, I don’t anticipate that it will be funded in the first part of our program, but it’s something that we will look at as we move through 2011.

Scott Wilmoth – Simmons and Company

So the 20% growth does not imply a six rig?

Gary Packer

That’s correct.

Scott Wilmoth – Simmons and Company

Okay.

Gary Packer

Yes, I’m going to guess – I mean, we’re going to drill about 375 this year. I would suspect we will be pushing 400 as we look into – into next year once we get a full year of those efficiency gains.

Scott Wilmoth – Simmons and Company

Okay. And then can you just mention maybe improving well results or well results recently versus in the past, how those are trending?

Gary Packer

I think we saw a pretty good increase in well results as we stepped up to the north and got into some of the areas that hadn’t historically been drilled and developed as we moved on some of the tribal acreage. Those trends still continue. And we still continue to see good results in our 20-acre infill program, so no degradation in results in either of those areas.

Scott Wilmoth – Simmons and Company

Okay, great. And then just in the Williston, it seems like kind of takeaway capacity is nearing constraints, out of the Basin we've seen increased rail usage. Can you guys talk about your takeaway agreements or things you have in place to handle the ramp you guys plan in 2011?

Gary Packer

Sure. Specifically, we’ve looked at a couple of different projects. There are opportunities that continue to commit to projects, the Enbridge expansion, there is a [inaudible] line that’s out there. We also have some refinery commitments that are going to carry us through 2011. But – and then also as you already suggested, rail is certainly an option that we are looking at in all areas, more favorably than maybe historically.

Scott Wilmoth – Simmons and Company

Okay, but all 2011 volumes you say are committed to refineries at this point.

Gary Packer

They’re not – they’re not all committed at this point. Pretty close to them.

Scott Wilmoth – Simmons and Company

And then, you guys talked about in the Bakken Well costs obviously pretty heavy inflation there. Can you talk about the Eagle Ford, the general service environment there and kind of well costs, how those are trended?

Gary Packer

I’d rather not talk anything about the Eagle Ford at this point until we can put out all of our numbers down there. I guess suffice it to say that completion costs certainly are up relative to the time period that we’ve entered the play there, we’ve seen a material increase in drilling activity.

And, quite honestly, much of this was expected any time you enter a new basin whether it’s the Southern Alberta Basin or the Maverick Basin where infrastructure and the services don’t expect, you can almost anticipate this kind of early increase.

I anticipate 2011 as those services comeback into the areas, there will be a lot more readily available and we will see some softening in some of those areas, and as we lock into certain preferred service providers. But you hit the two where we’re seeing the most pressure, both in the Williston Basin and Mav Basin. 30%, 40% certainly would not be out of the question.

Scott Wilmoth – Simmons and Company

Okay. And then, just lastly, it looks like third quarter domestic oil production came in a little bit guidance. Can you just talk about what might have – would have led that?

Gary Packer

Sure. Probably it’s best described as three things. As we head into winter market, the Salt Lake City refineries typically enter in a turnaround period, where they're converting to their winter diesels which have a different cost point.

Two of our refineries encountered that and will be encountering that as we move into the fourth quarter, so that’s interrupted some of the volumes that will result in the build of inventory that we would anticipate taking out in the first quarter.

And then, also related to your prior question on the completions in the Williston Basin, I would say through the bulk of 2010, we were sitting at about 25 days or so when we took a well from TD to being placed on production. We’ve seen that slide as activities increased.

Today, we’re probably sitting about 45 days or 50 days and we’ve anticipated in the fourth quarter that that number could expand a little bit due to winter conditions as well as some of the pressure and services.

Again, we will see that improved as we move into the first quarter. And it maybe finally anytime we step into these assessment programs early on, takeaway capacity is a little less predictable.

As a result of that infrastructure has to keep up with your completions. And that’s probably been a minor amount of the difference. But at the end of the day, I think we’re only talking about 200,000 barrels or so.

Scott Wilmoth – Simmons and Company

Okay, great. Thanks guys.

Lee Boothby

Thank you, Scott.

Operator

And we’ll move on to our next question from Gil Yang with Bank of America.

Gil Yang – Bank of America

Hi, good morning, thank you. Could you comment on the international sequential expected pickup in the oil volumes? It sounds like it’s about 50%. Obviously, the pipeline coming back on is part of that. But what are the other components of that growth?

Gary Packer

Yes, a lot of that Gil is just the timing of liftings. We've built some capacity in the tanks as we were down there for a while and we’ve just scheduled our liftings here recently for the fourth quarter and we’re going to take two material liftings in November, December.

And, with that I guess operationally, the debottlenecking that we did at PM 323 has been very successful. The team has done a great job not only in returning that pipeline to production but also maximizing the production out of our East Belumut Field.

Gil Yang – Bank of America

Okay. So in a way we can think of the fourth quarter is being a makeup for this shortfall in the third quarter?

Gary Packer

To a minor degree. Part of that’s going to be the carryover. But we also have an increase in sustainable production out of East Belumut and PM 323. So I’m optimistic there. And as Lee referenced this in his call, as we look into the 2011, the East Piatu Field will be coming on I believe in October of next year. This should give us another little bump in the production as we look year-on-year internationally.

Gil Yang – Bank of America

Okay. So sales then roughly 6,000 barrels per day increase sequentially, how much of that is the sustainable growth portion and how is the makeup portion from the third quarter shortfall?

Gary Packer

Yes, I’d say off the top of my mind Gil, we’re probably looking at about 2,000 barrels or 3,000 barrels a day is what we’ve seen as an increase at – out of PM 323, and the balance will be just be lifting schedules.

Gil Yang – Bank of America

Okay. And that – is that 2,000 barrel, 3,000 barrel increase versus the third quarter sustainable until the October Piatu ramp-up?

Gary Packer

It’s going to be well dependent. We’ve got a drilling campaign and a rig committed in 2011. So notionally I would say yes. And we also – I mean the other, I guess the other one I did leave out, West Belumut is now on line. We have a couple of wells there. They’re performing well. But as you know, that also is into the same pipeline system which ultimately defines how much our takeaway is from PM 323.

Gil Yang – Bank of America

And could you comment on the costs of your wells in the Bakken, they’re running – they seemed to be very higher than – materially higher than what some of your competitors to the north would say their wells are costing. Could you comment on – do you think that that’s the case or are you talking about apples and oranges in the way you’ve talked about costs or do you think your cost can come down?

Gary Packer

Well, I mean, I can’t really comment on what the competitors of north are saying. I’m not specific, I’m not sure what companies and what type of well designs that we’re talking about. I’d historically, our well cost out there has been very competitive with industry activity.

Historically, we’ve been out there drilling these 4,000-foot laterals and the results that you – and we’ve posted on our website are all consistent with those shorter laterals. And I think those well cost at $5.5 million or so are very reasonable.

Now, as we head into the longer laterals and I think in the call we referenced about an $8 million well cost, to be clear, we have not drilled and completed a 9,000-foot lateral yet. So some of that is an estimation of what we will spend at this point in time with the higher completion costs factored in.

Absolutely as I look into the next year, I would anticipate our team as we drill the 9,000-foot laterals starting 2-stage completions, we will be able to pushback on that – those costs. But while I have a whole lot of information on the shorter laterals that we can talk about. The higher end costs there of $7.5 million to $8 million is an estimate in the current property market that we see in the wells.

Gil Yang – Bank of America

Okay. And then, finally, if I look at the results that you got on your operational press release, you have got some really good wells and where there is sort of okay. But they tend to be sort of seemingly clustered in the Aquarium, Watford area. I know it's a small sample. But do you think that or are you’re seeing any trends that with those IP results or is it just more the randomness of the sampling?

Gary Packer

Well, I think it’s a randomness of the sampling to a great degree. If you actually go back and look at the well results that we saw in the Westberg and Lost Bear area, we saw steady increase and improvement in well results overtime due to the tweaking of our completion practices. Kind of the average wells that you referenced are still 1,800, 2,000 barrels a day IP.

The area that we don’t and have not posted a lot of well results personally is in the Catwalk area. And I know we identified it as a development phase. We’ve now drilled off-late two or three wells in Catwalk, we’re just completing them at this time.

But there’s been eight wells drilled by industry across the acreage position that kind of has given us a lot confidence in what those well results will be. So I wouldn’t read too much into some of those IPs at this point, kind of let us drill few more wells and then we’ll report them what we think.

Lee Boothby

Gil, I would add to that, if you go back and look at the earlier results that we announced, say in our first year, year and a half of assessment, when we went towards some of those early wells and drilled offsets, we were 2x on the results.

So you can clearly see the learnings captured by our Williston Basin team being applied to the wells, and those are immediate offsets. So I think that’s a – that’s what I would look to you to go ahead and get you to feel good and kind of help understand, and we can’t change the sample set size at this point. We’ve got four rigs running and we’re drilling as fast as we can.

Gil Yang – Bank of America

Well, so, in that context though, do you think that are there significant differences in what you see geologically in Aquarium and Watford that would allow you to – I mean these are the first two – [inaudible] there's really a small sample set there. Do you think that maybe the wells will get better as you will learn more about that area? Is it different enough from Westberg that there's things you need to learn about?

Gary Packer

Absolutely.

Gil Yang – Bank of America

Okay.

Gary Packer

And we’ve seen this in every one of the resource plays that we enter. You establish that early EUR and IP well cost, and we have consistently been able to prove on each of those as we drill more wells. And I fully expect that that will be the case here as well. And, again, I am not apologizing for the well results that you see right now, because they’re quite profitable and we have a three rigs dedicated to drilling wells.

Gil Yang – Bank of America

And so there’s enough variability, it’s about 20 miles down the road, so – but there’s enough variability there that you need to do think – you may need to do think differently there?

Gary Packer

Yes.

Gil Yang – Bank of America

Okay. All right, thank you.

Lee Boothby

Thank you.

Operator

And we’ll take our next question from Joe Allman with JPMorgan.

Joe Allman – JPMorgan

Thank you. Good morning, everybody.

Lee Boothby

Good morning, Joe.

Joe Allman – JPMorgan

Recently we heard an industry comment about the Eagle Ford Shale and in particular the Maverick – in Maverick County that the oil out there is heavy. Could you guys comment on sort of the quality of oil and any other issues you need to deal without there in the Eagle Ford?

Lee Boothby

Well, Joe, I appreciate the question. I didn’t know who was going to ask this morning, but I figured somebody would. So I guess why not you. There is heavy oil in the Maverick Basin. People read their research players a little closely they’ll find that it’s bitumen and it's shallow and has nothing to do whatsoever with the targeted Eagle Ford section that we’re testing.

I would simply say that we’ve got a policy of not talking about what other people are doing and offering our thoughts. And I would appreciate frankly if some of our peers that want to pontificate about things that they know nothing about, might stick to their plays and you wait for Newfield to tell you about what’s going on in the Maverick Basin. I said we’re encouraged, I said that we’re continuing with our program. And frankly, I’m excited about what we’re seeing and I look forward to talking to you guys early in the New Year.

Joe Allman – JPMorgan

All right, good stuff, Lee. And then just moving on to a different topic, in the Arkoma- Woodford, so do I hear you correctly that assuming gas prices stay where they are – if gas prices stay where they are, you would expect to drop some rigs there in the Arkoma-Woodford?

Lee Boothby

Well Gary has been managing that all through the year and I’ll let him speak to it here in a moment. But we started the year in the Woodford at nine rigs. And we’ve had added some acreage over the course of the last year in the Woodford. Our total acreage counts up from a 172,000, so we do have a small component of non-HBP acreage.

We can handle the non-HBP acreage with about one rig. We’ve been trying to balance out. We feel it responsibility on our main operating areas to work with their service providers and the other people that are all part of a development activities, we’ll try to balance the needs of a healthy service environment with our desire to shift towards oil. And we’re rapidly accelerating in that regard. But we’ve gone from nine rigs to four rigs today.

The statement was made that if gas prices continue to stay very soft or deteriorate further, we’ll continue to rotate rigs out of the dry gas portion of our portfolio into the oil components.

The four rigs, the four dry gas rigs that we have running are drilling super extended lateral wells in the Woodford. And we’ve told you guys we’ve got a good strong core position there in those SXL wells work. And we’ve got a portfolio, but we prefer the margins that we see in oil and we’re going to continue to monitor that situation and be nimble with regard to our responses. But I’ll let Gary add any other color he might have.

Gary Packer

Yes, Joe, I guess the only thing I’d add is, I think the Mid-Continent team has done a great job of high grading the Woodford. And we could continue to maintain a reasonable level of activity out there and still drill returns of we’re proud of in the Woodford Shale. It’s just a matter of the fact that we’ve got these incremental opportunities and it’s our commitment that we live within cash flow that is only the restrictor on our capital investments out there.

I think it’s important that we maintain a relatively consistent level of activity in each of our areas not only for the benefit of the key service providers that we’ve aligned ourselves with, but also to maintain this trajectory and efficiency gains that we’ve referred to a few times this morning. You can’t take a program back to nothing and expect to capture those when you ramp back up again.

So, yes, I would anticipate a slowdown in the Woodford capital allocation, but will stay have a material presence there, and we will be in a position when gas prices do rally and they will, then we’ll be able to drive a very profitable growth out there long into the future.

Joe Allman – JPMorgan

Okay. That's helpful. And then lastly, just a different topic, on – back to the service cost issue. So going into 2011, what are your assumptions on your well costs? Do you expect them to be higher in 2011 from where they are now or flat or down because of efficiencies?

Gary Packer

I think we’ve done a great job of pushing back as much of the increases this year as a result of the efficiencies that we had.

I think it’ll be fair to say that if I look across the tour we made of each of our business units two weeks ago that we’re probably looking at somewhere around 10% or 15% depending on the area that have already been kind of build into our capital projections for 2011 on the drilling side.

Some areas have been able it actually hold the line and we’re looking at flat into next year. And as you know, much of this will be dependent upon the role of the rigs and how much new horsepower is coming out in the completion side.

Joe Allman – JPMorgan

And when you say 10% to 15% up in 2011 in some areas, is that from right now, or is that from the average of 2010?

Gary Packer

I would say that’s probably from early year this year maybe an average of 2010, so much of that’s already been baked in. So as you look into 2011, as a proxy, it would probably be flat to where we sit here in the third and fourth quarter.

Joe Allman – JPMorgan

Okay, all right, great. Very helpful, thank you.

Lee Boothby

Thank you, Joe.

Operator

And we’ll move on to our next question from Bob Morris with Citi.

Bob Morris – Citi

Good morning.

Lee Boothby

Good morning, Bob.

Bob Morris – Citi

A clarification on the production growth out of Monument Butte. I thought that 20% was this year and when we look at the 20,000 barrels a day you'll exit this year out, that's already up 20% over the average for this year. So I guess by the end of next year what would you expect that 20,000 barrels a day in the Monument Butte to grow to?

Gary Packer

When we look out and it depends on what our capital allocation is of course. But I would like to see and would expect to see somewhere in the order of 28,000 barrels to 30,000 barrels a day gross would be appropriate expectation, depending on capital investment out there for year at the end of 2011.

Bob Morris – Citi

Okay, that's more in line with what I was thinking. In the Woodford, you had stated earlier this year that the typical well required 450 gas to get a 10% full cycle rate of return. And, in fact, a year ago when natural gas prices were actually slightly better than what they are today, you curtailed about 3 Bcf of production out of the Woodford. So has that breakeven cost come down, and what is it now? And are cost at a level that today even with gas prices close to what they were a year ago you would not or would you now be looking at perhaps again shutting in production?

Lee Boothby

Well, we shut the production in last year in response to market conditions, so you’re exactly right. The decision was made last year when gas hit a two handle is when we made the decision. So we took the 3 Bcf net out and it was a decision we made that was signaled in market and all of the above.

I would tell you that the issues in terms of performance relative to the core, we’ve seen exceptional performance in terms of continued efficiency gains out of our team in the Mid-Con, so we’ve actually been able to improve the metrics on our super extended laterals and that’s all that we’re drilling today. So we get super extended laterals and the core of the Woodford Shale are the wells that are being drilled.

And, in that regard, year-over-year there is an improvement all up in those well cost and F&D costs improvement, and therefore, a slightly lower threshold. But I would say the 400 to 450 is not a bad range to be thinking about Woodford Shale 10% plus B tax.

Bob Morris – Citi

At today's price of 350, you're not considering shutting in any production, or where would you consider that again?

Lee Boothby

We haven’t got a specific target price, Joe. It’s something that we monitor and talk about on an ongoing basis and we’ll just monitor the situation and make the decision as we fit at the time. But 350 with our hedge position, we see no need to curtail production at this point.

Bob Morris – Citi

Okay. Right. That's helpful. Thanks.

Lee Boothby

Thank you.

Operator

And we’ll take our next question from Joe Magner with Macquarie Capital.

Joe Magner – Macquarie Capital

Good morning, thank you. Just wanted to touch base on the horizontal Granite Wash, apologize if I missed it in the comments. As more of a hybrid or liquids-rich gas opportunity, how do the economics of that project stack up relative to some of your other peer play oil projects?

Gary Packer

It’s a good question, Joe. And I’d say, if we were just going to look at a portfolio of wells in each of our areas, I would say that we’re sitting there at Monument Butte being earning the best returns, Williston Basin earning the second, and then as we move the next – and I’m not talking about our assessment plays at this point, I’m just focus on development plays – it would be the Granite Wash, specifically the Marmaton.

I would say that the Marmaton drilling in the Granite Wash competes favorably and probably right behind our Williston program. And as is referenced earlier, as it continues to see cost pressures, it may, depending on the well that we’d select could actually maybe rise above that. And then this would be followed by the Atoka drilling. So I’d say generically, B tax today you can probably see as much as a 50%, 60% if we drill Britt-like wells targeting the proven Marmaton section.

Joe Magner – Macquarie Capital

Okay. So I guess with all that being said, do you anticipate 2011 activity levels to be changed materially from where they were for this year, up or down or – some of that's gas price dependent, but how should we think about that?

Gary Packer

Yes I wouldn’t say materially. We have four rigs running in the Wash right now. I'd say that George would tell you that that probably feels pretty good. And then if any reduction there would only be because we have the superior investment opportunity somewhere else, but I just – I couldn’t see him getting below three rigs.

Joe Magner – Macquarie Capital

Okay, great. In the Woodford Shale, you've talked about SXLs are the only wells you're drilling now. It looks like the average length came down for the wells that have been drilled to date this year from where it was in the second quarter. Is there anything in particular that's driving that change?

Lee Boothby

I don’t know what you’re looking at in terms of the accounting. The – I’ll let George jump in here in just a second. But the last tally that we saw we just came through on our quarterly review tour and we were up year-over-year in terms of the total delivered length in accordance with our plan.

I would say that 7,000 feet is a number that you all probably be thinking about in terms of delivered length on those wells versus whatever the comparison is that you’re looking at. That’s fair George?

George Dunn

That’s accurate. I would say obviously anywhere we can we try to get north of 9,000 feet. And generally what would shorten the lateral length would be faulting geological condition, and so they’d range from 5,000 to 9,000, but generally, almost everything. Some of the average, I’m not sure where he’s getting the number, either maybe wells earlier in the year, almost happening has been in the 8,000 plus recently.

Lee Boothby

Joe, I’d follow-up with Steve, and we can get you tied out, so you’ve got the accurate up to date numbers there.

Joe Magner – Macquarie Capital

Okay. It looked like – I'll follow up. It looked like it was 8,800 in the second quarter ops update and 8,400 in the third quarter. I can follow up, that's fine.

Lee Boothby

Okay.

Joe Magner – Macquarie Capital

And then 2010 you've been committed to living within cash flow and it sounds like you're going to be maintaining that sort of philosophy. With the cost inflation you've experienced or that you have factored in for next year, do you think you'll be able to absorb those with efficiencies and other offsets to be able to maintain that same sort of a strategy going into the next year?

Gary Packer

Yes, Joe, we do. Our plan – it’s two-fold. We bake in a little bit of the cost increases that we’ve already talked about year-to-date. It is our full expectation that we will live within cash flow and will still deliver good growth numbers into next year. So it’s combination to the efficiency gains, but it’s also a comment on the quality of the assets that we plan to allocate capital to next year.

Joe Magner – Macquarie Capital

Okay. And then it looks like a couple of pieces you provided some 2011 growth expectations for out of the Williston and Monument Butte. When do you think you'll have a comprehensive plan put together?

Lee Boothby

Well, I’m going to hope that I don’t get too much trouble with the Board. We said we met last week and we’re giving you guys colors and our thoughts for 2011, we haven’t even talked to the Board, so they’re hearing it some of these for the same time – at the same time you guys are. We’re going to stick with our normal cycle. You’ll hear our thoughts and opinions early in the New Year and we’ll lay a mountain of detail for you at that time.

Joe Magner – Macquarie Capital

All right. Thanks for the answers.

Lee Boothby

Thanks Joe.

Operator

And we’ll take our next question from Ankit Ram with Global Data.

Ankit Ram – Global Data

Yes, hi, excuse me. Hello.

Lee Boothby

Hello.

Gary Packer

Yes.

Ankit Ram – Global Data

Hello.

Lee Boothby

Hello.

Ankit Ram – Global Data

Yes, actually we just wanted to know like as the natural gas prices – it’s like very weak in future, so how do you perceive as in – as in what strategies you’re forming in future plus like are you planning shutdown some natural gas productions to invest more in oil assets?

Lee Boothby

Short answer is yes.

Ankit Ram – Global Data

Right. So as in could you just tell us like what presence is in – which assets you’re like – and how you are shifting your focus as in – as in which assets you are not focusing more on and where are you addressing [ph] your focus now?

Lee Boothby

I think if you read the operational release that we put out it will be a pretty good guide for you in terms of what we’re focused on. The Rockies is the dominant piece for our oil story today as we’ve shifted capital all year to the Rockies. And the Mid-Continent regions is the dominant portion of gas portfolio today. So it’s been giving up capital in preference to investments in the Rockies. So that’s probably the best guide I could give you and I wouldn’t want to go in any more detail in individual assets.

Ankit Ram – Global Data

All right, thank you.

Lee Boothby

Thank you.

Operator

And we’ll move on to our next question from Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thanks, good morning.

Lee Boothby

Good morning, Brian.

Brian Singer – Goldman Sachs

In the Granite Wash, can you give us an update on well costs and how you're thinking about the total number of well locations you have to drill on the 46,000 acres when you consider spacing and the multiple horizons?

Lee Boothby

George?

George Dunn

Well costs are well I guess to use like Gary said earlier we expect 10% to 15% increase into next year of total well cost, but otherwise, they’ve remained pretty flat through this year, so that’s just a projection.

Total number of wells if we include both the liquids and the gas portion, it’s a lot and it depends on gas prices, et cetera where we will get to, what we’ve stated typically is 250 plus wells for sure, and you can probably double or triple that as we go forward and prove up all the horizons.

Brian Singer – Goldman Sachs

And is it the multiple horizons that are the sticky point here in terms of getting to a much higher number than 250 or is it more of the aerial extent and what percent of your acreage is perspective?

George Dunn

Yes, it’s assessing the rest of the acreage along with – I guess that our 250 numbers fix in a range of ensuring excellent returns at kind of current gas prices $4 to $5. As you go north of that as more and more stuff will prove up.

Lee Boothby

And probably the way I would think about it is we set out at the beginning of this year to increase the number of individual horizons that we’ve tested. At this time, George has successfully tested nine of nine where we’ve drilled horizontal wells out there. We expect that we’ll have the 10th horizon tested before yearend.

I think it is that assess program that drives the absolute well count in terms of thinking about the inventory. Clearly the Marmaton, the shallower zones are the liquids-rich zones and we've told you at many occasions previously the Atoka’s dry gas it’s about 1,100 Btu gas and the Marmaton is 1,300 plus with condensate NGLs. So I think we’re executing our plan as we told you and I agree with George’s assessment in terms of the likely well count.

Brian Singer – Goldman Sachs

Great, thanks. And to delicately go toward the Eagle Ford here, you mentioned in your comments that everything you're seeing is consistent with your pre-drill planning. Can you give us some color on what your pre-drill planning was in terms of the split between oil, gas, and NGLs and the quality of the oil?

Lee Boothby

Brian, I just probably like to defer to early next year when we lay all of the details out for that play, so if you’ll forgive me.

Brian Singer – Goldman Sachs

No problem. And, then lastly, if you maintain your current natural gas rig count, is the quarter-on-quarter decline that you're guiding to for 4Q versus 3Q representative of what we'd continue to see over the course of 2011?

Gary Packer

Yes, Brian, I think it is. I mean we’re – we’ve identified the decline. But it’s very shallow as you’ve already seen when we look. Companywide as we look quarter-on-quarter, I think we finished – we finished the third quarter. But 50.5 Bs or so we’ve guided you somewhere maybe a B down on the quarter. I think that’s representative as we look into next year.

Brian Singer – Goldman Sachs

Great, thank you.

Lee Boothby

Thanks Brian.

Operator

And our next question comes from Rehan Rashid from FBR Capital Markets.

Rehan Rashid – FBR Capital Markets

Good morning, guys.

Lee Boothby

Good morning.

Rehan Rashid – FBR Capital Markets

Going back to the Monument Butte for a quick sec, two questions; one, refinery capacity, I know you guys say you've got 85% kind of spoken for. As you go through 2011, should we be comfortable that further growth will be there in terms of refinery capacity?

Gary Packer

As we look into 2011, Rehan, we know that the Holly hydrocracker is fully operational. I think it came back on line in July earlier this year. Tesoro was actually seen in pushing the limits of the systems that they have in place which should gain us a little bit more capacity. The other thing that we’re looking out there is rail that is certainly an option for us.

Historically, we can all go back several years and it was kind of at a last minute and we saw that those differentials attributed to rail were relatively high. But we’re looking at it from a longer range planning view and I think it presents an opportunity that’s more cost effective than maybe what it historically was thought to be and that’s another option for us right now.

When you start looking out into 2012 and 2013, certainly we’re going to be working with our joint venture partners and our refiner partners up in Salt Late City to make more material commitments in expansions. But we’re confident that there’s another 10% or 15% out there to come.

Rehan Rashid – FBR Capital Markets

Okay. That's good. And on the Monument Butte, the second question. Where were some thoughts of trying a horizontal well there? And if so, any results? If not, the plans?

Gary Packer

Yes, we’re constantly looking at the horizontal wells. I hate to get into the discussions of specific wells that we drill when the field is broad as this, but the answer is yes, that we do see that as an option for us, we see its applicability. But as you well know just due to the distribution of the formation out there

I wouldn’t describe it as having broad application. But in a certain areas and in the certain parts of the field I think it does have application and it’s something that we’re certainly investigating.

Rehan Rashid – FBR Capital Markets

Okay, thank you.

Lee Boothby

Thank you, Rehan.

Operator

And we have another question this time from Dan McSpirit with BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning, and thank you for taking my questions.

Lee Boothby

Good morning, Dan.

Dan McSpirit – BMO Capital Markets

Looking at your Bakken producers, when will you need to bring these wells on pump if you haven't already for the earliest wells drilled? And what choke size are you flowing these wells at, at least generally?

Gary Packer

Every time I bring choke size up, everybody says 32-64, so I’m going to play the 32-64 card. I think each one of these wells varies a little different.

Lee Boothby

Gary isn't touching chokes regularly these days.

Gary Packer

It depends on the area. Many of these wells we’ve already snubbed in tubing and our current is flowing up tubing. But it’s area specific, it has to do with GORs. And so there isn't a preset time that we go ahead and place these wells on pump, some sooner than others.

Dan McSpirit – BMO Capital Markets

Okay. Got it, got it. And forgive me if this question was already asked and answered. But looking at the Granite Wash and the Marmaton specifically as a targeted horizon, what's been tested in terms of spacing and what will be tested maybe in 2011 here going forward?

Lee Boothby

George you want to take that?

George Dunn

Well, generally we’re looking at 200 acre to 300 acre spacing basically is what’s been tested. And, at this point, probably the 200 acre to 250 acre looks like it’s probably adequate.

Dan McSpirit – BMO Capital Markets

Okay.

George Dunn

And that it could depend, it’s a big area, and rock properties change some throughout the area, so there could be variances in how we space north to south, east, west.

Dan McSpirit – BMO Capital Markets

Okay, great, great. And then one more if I could, just turning to the Southern Alberta Basin, recognizing that any question here would likely not get answered. But you do list the four prospective formations or horizons in the press release. Are you targeting all four with the eight wells planned or is there a single bench or a single target that that's the focused?

Gary Packer

Yes, every one of the – we just TD’d our fourth well specifically on the vertical side and they do test and see the entire prospective section. As Steve referenced in the operational report, we have drilled one horizontal in that and we just selected on of those zones for initial test and we’re evaluating the results of that before we make any other commitments on horizontal and I prefer no to discuss the specific target of that well.

Dan McSpirit – BMO Capital Markets

Got it, okay. And one more if I could. Appreciating your emphasis, your focus on oil versus gas, but does the outlook ever get so negative in 2011 maybe where we have a repeat of 2010 where you become a buyer of assets, that is natural gas assets in a way to create more option value, the option value I see maybe in the Woodford?

Lee Boothby

Well, that’s a very good question. We’ve talked a lot over the course of the last question of portfolio model that we have built and how we’re using it to help manage the day-to-day. I think if you go back and look at Newfield’s history, we’ve made a number of strategic moves and off-cycle periods when the market is not frothy.

Frankly, we like the look of gas and frothy oil market in terms of adding into portfolio. But our mission is going to be the same. Nothing will be added to Newfield’s portfolio that can’t compete at the front of the line. And I think that’s a healthy perspective for us to have and that’s the guidance that we give our hunters that are out there chasing opportunities every day of the week.

We entered this year saying that we were going to continue to build for the future and I’ve already told you we’re going to continue to keep that focus for 2011, so I would say that, yes we’re going to be pretty opportunistic looking at the light types of gas opportunities in the soft market.

Dan McSpirit – BMO Capital Markets

Very good, thank you again, gentlemen.

Lee Boothby

Thank you.

Operator

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

Brian Lively – Tudor, Pickering, Holt

Lee, just to follow-up on the I guess potential for acquisitions. And you had mentioned in the prepared remarks still looking at attractive deals and bolt-ons, et cetera. Could you give some more color on that especially in lieu of your just prior comments on what you guys are or would be looking for in terms of acreage adds around your core assets today or maybe even looking at new areas?

Lee Boothby

Well, I think the earlier comments were simply to remind everybody that those things that make sense running around the areas where we exist we’re going to be in the market and chasing the right types of opportunities. Beyond that in terms of specific targeting or activities, I prefer not to speak to that until the right time and place, and that’s not today.

Brian Lively – Tudor, Pickering, Holt

Okay, fair enough. On the Williston, do you guys have a frac crew that's dedicated today?

Gary Packer

We do not have a frac crew dedicated today. As is very common out there many conversations are taken place with different service providers. But as we sit here today, that’s not the case.

Brian Lively – Tudor, Pickering, Holt

And then how do you – or how should we think about the number of net completions maybe on a monthly basis as you go forward with your ability to contracts and services?

Gary Packer

Well, I think what we’re doing Brian, we have some great relationships that we’ve established with some key service providers across the organization, whether it be in the Mav, the Gulf Coast, the Mid-Continent as well as the Rockies.

And I think we’ve been working with those parties to date effectively. But, nevertheless, as you – as I alluded to earlier, we have seen a doubling of the time that it takes us to get from TD to place in that well on production. And also from the very first question, we have seen some of those volumes interrupted because of that.

So we’ve got two service providers specifically that we’re aligned with that we’ve been able to make to get our wells completed to date. As I look into 2011 with the robust oil prices that we have in the activity up there, I would suggest you that we probably will end up aligned with one key provider up there to ensure that we can execute our plans.

Brian Lively – Tudor, Pickering, Holt

Okay, great, thanks guys.

Lee Boothby

Thank you.

Operator

And we’ll move on to Gordon Steuart [ph] with Wells Fargo.

Gordon Steuart – Wells Fargo

Good morning, guys.

Lee Boothby

Hi Gordon.

Gordon Steuart – Wells Fargo

A quick question, I know you talked about efficiencies today, but as you shift your focus more towards oil drilling, I’m just wondering what your thoughts are excluding any pressures, cost pressures and pressure pumping, service cost inflation, et cetera. But how should we look at your cost structure as you ship more towards oil, given that is more expensive than gas?

Gary Packer

Well our focus is all about our margin, right? And as certainly as we ship more towards – if you look on a gas equivalent basis, you would see it as a relatively increasing cost structure.

But, again, our focus is on margins, and when we can – when we can move into and focus on our oil projects, we’re earning $5 an equivalent Mcf, equivalent or so cash margin. That’s the right place for us to invest and that’s really what our focus is.

So we tend to stay away from just looking at it on a historic dollar per Mcf equivalent basis and really focus there. We believe we’re getting somewhere in the oil of twice the margin, twice the cash margin.

Gordon Steuart – Wells Fargo

All right, thank you very much.

Lee Boothby

Thanks Gordon.

Operator

And we’ll take our next question from Jack Aydin with KeyBanc Capital Markets.

Jack Aydin – KeyBanc Capital Markets

Hi, guys, thanks. Most of my question was answered, but I do have a follow up on the Alberta Bakken. Of the eight wells that you're planning to drill there, how far apart you drilling these wells from each other?

Gary Packer

The – first of all let me – when we refer to it is as this SAB, it’s the Southern Alberta Basin and not the Southern Alberta Bakken. We see the horizon is much broader than just any one specific horizon.

As far as the spacing goes, our first three wells were all within about six miles or so I believe as we sequentially stepped down dip in the formation as our fourth well is considerably – I don’t have a map in front of me, but it probably approaches 20 miles when we stepped – stepped into our last location.

Jack Aydin – KeyBanc Capital Markets

At this early stage, what kind of costs or what are you looking at? I mean I understand those are science wells, but initially what kind of costs are you looking at?

Lee Boothby

Well, it just doesn’t make any sense to really talk about the wells that we’re drilling today, because as you mentioned they are science wells and vertical wells, we've got exotic log suites, we're cutting cores, it's not reflective of the type of well that we would even be thinking about drilling in a development mode. So it just doesn’t add to the discussion in my opinion today.

Jack Aydin – KeyBanc Capital Markets

Okay, thank you.

Lee Boothby

You’re welcome.

Operator

And our final question comes from TJ Schultz with RBC Capital.

TJ Schultz – RBC Capital

Good morning, guys. Just on the Monument Butte, I know you said well performance is looking good as you move north and it looks like you've tested about 25% of the northern extension. Just wondering if you've seen any variance in performance as you kind of move away from the border with the greater Monument Butte Field, and at this point with that 25%, if you've tested yet the kind of four corners of the northern extension?

Gary Packer

The answer as we step north of Monument Butte, we step out of the historic area that’s been drilled and water flooded and we continue to enjoy great success. But as we do that, we get a little deeper in the geologic section. We have a little bit more pressure behind it and we’re probably stepping into a little bit more of a fractioning system. So, yes, we do see improved characteristics.

As far as the 25% reference is probably one where we can say that we have assessed that acreage position and it’s statistical. And we can have high quality or high confidence in our predictions in recoveries on a mean – from a mean standpoint. We have stepped out and drilled some step-out wells with success.

But I certainly wouldn’t describe the other 75% of the acreage position is being that we can statistically step out there and with high confidence. That’s going to be – I would anticipate in 2011 we would see more of those types of wells as we get more and more comfortable with what that acreage holds for us. But we’re just not quite there yet.

TJ Schultz – RBC Capital

Okay. Just one more thing on LOE for third quarter, it looks like it came in just about at the high end of guidance. Can you touch on what outside of the higher liquids content may have biased that towards the high end?

Gary Packer

As far as the recurring LOE if that’s what you’re looking at, it was a kind of a couple of things.

As you recall, we – the liftings certainly did impact that to some degree and the fact that it – we had anticipated going into the quarter that we would be down more substantially in our international volumes due to the pipeline interruption when the guys got to field back on line quicker.

With only four weeks delayed we had increased oil volumes and some of that ended up rolling in as far as the cost in the fourth quarter. That was a very just a marginal change certainly within guidance on the domestic piece of that.

TJ Schultz – RBC Capital Markets

Okay, great. Thanks, guys.

Lee Boothby

Okay, thank you. Operator?

Operator

And yes sir.

Lee Boothby

That’s all we got.

Operator

And there would be – just one moment – looks like we may have one other question that’s queued up, just one moment please. And we do have a final question sir from Richard Tullis with Capital One Southcoast

Richard Tullis – Capital One Southcoast

Hi, thank you. This will be quick. Looking at the Gulf of Mexico for next year, what are you expecting for development cost in some of the projects you have queued up to come on line in the next few years, Dalmatian, Pyrenees, Axe?

Lee Boothby

Well, John Jasek can answer that question.

John Jasek

Developing costs are – at currently we are expecting to stay within the guidance that we provided and we don’t see any significant increase in development costs going forward, and it’s due to obviously to the moratorium and the cost of goods and services and the supply that's out there. So it’s pretty much as normal and no significant changes one way or the other going forward.

Richard Tullis – Capital One Southcoast

And what are you looking at for new drilling next year, any thoughts there yet?

John Jasek

I think it’s too early for us to discuss drilling for 2011. As we discussed earlier, we are in the process of understanding the wealth of regulations and new requirements coming forth from the BOEMR and that we will evaluate and read and react and proceed appropriately going forward.

Richard Tullis – Capital One Southcoast

All right, well, thanks very much. Appreciate it.

Lee Boothby

Thank you very much, Rich. I guess assuming there are no further questions, we’d like to thank all of you for your time and interest at Newfield. We look forward to visiting with you on our next call and full-year results for 2010 and a little bit more color for our final game plan on 2011. Well, thank you, and let’s have a good quarter.

Operator

That does conclude today’s conference. And we do thank you for your participation.

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Source: Newfield Exploration CEO Discusses Q3 2010 Results - Earnings Call Transcript
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