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Executives

Lee Boothby – Chairman, President and CEO

Bill Schneider – Vice President, Gulf Coast and International

John Jasek – Vice President, Gulf of Mexico

Steve Campbell – Vice President, Investor Relations

Terry Rathert – Chief Financial Officer

Gary Packer – Chief Operating Officer

Daryll Howard – Vice President, Rockies

Jim Addison – General Manager

Analysts

Gil Yang – Bank of America/Merrill Lynch

Brian Lively – Tudor Pickering Holt

Brian Singer – Goldman Sachs

Subash Chandra – Jefferies and Company

David Cameron – Wells Fargo

Scott Wilmoth – Simmons and Company

Joe Allman – J.P. Morgan

Irene Haas – Canaccord

Dan Mcspirit – BMO Capital Markets

Bob Morris – Citi

Heather Hilliard – ODS-Petrodata

Newfield Exploration Co. (NFX) Q2 2010 Earnings Call July 23, 2010 9:30 AM ET

Operator

Please standby. Good day, everyone. And welcome to Newfield Exploration Second 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 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 Chairman, President and Chief Executive Officer, Mr. Lee Boothby. Please go ahead, sir.

Lee Boothby

Thank you. Good morning, everyone. And welcome to our second quarter and mid-year 2010 update call. Thanks for your interest in Newfield. With me today in Houston, I have Bill Schneider, our Vice President of Gulf Coast of Mexico -- Gulf Coast and International; John Jasek, Vice President of Gulf of Mexico; Steve Campbell, Vice President of Investor Relations; Terry Rathert, our Chief Financial Officer; and in Denver, we have Gary Packer, our Chief Operating Officer; and Daryll Howard, our Vice President of the Rockies; and we’re joined in Tulsa by General Manager, Jim Addison.

Earlier this week, we published a detailed operations report, with lots of information from our core operating regions. I will keep my remarks today relatively brief leaving plenty of time for your questions at the end. So let’s get started.

Our focus today at Newfield is very clear. First, continue to target our investments towards oil projects. We’re uniquely positioned in our peer group today with real oil projects in our portfolio. Our second quarter oil production was up 16% when compared to the first quarter of this year. We are on target for a 30% growth in our 2010 domestic oil volumes. The returns in oil plays today are superior to natural gas and we’re combining growth with returns.

Second, we are assessing some major new plays that could become a significant part of our future growth. We’re drilling our third well in the Southern Alberta Basin and we currently have four rigs running in the Eagle Ford Shale assessment program down in the Maverick Basin. Combined these oil high-yield liquid plays cover more than 0.5 million net acres and hold tremendous upside potential.

And third and finally, we’re positioning ourselves for future performance. We continue to strive for efficiencies in our natural gas developments and we’ll be in a position to again accelerate growth and gas assets when we see the appropriate return on investments. Through our diverse portfolio of assets we have multiple options to effectively manage the up and downs in our business, and navigate through the challenging elements in our business today.

Our hedge position is strong and provides for strong cash flow and profitability over the next two years. Due to our strong capital structure, we were recently upgraded to an investment grade rating by Standard & Poor’s.

These are certainly interesting times in our business. Just days prior to our last conference call with you the deepwater horizon incident occurred. Loss of life, the oil spill and its impact on the Gulf of Mexico and its shore lines are all tragedies, and forceful reminders of why environment, health and safety are critically important functions that can’t be overemphasized throughout our work force and industry.

Although, Newfield has a long history in the Gulf of Mexico, today it represents just 4% of our proved reserves and about 10% of our production. Our 2010 work program in the Gulf was front-end loaded and the moratorium does not have any impact on our planned drilling programs for 2010.

We have several active developments in deepwater and we fully expect we will be allowed to advance these projects. We’re confident in our Gulf of Mexico team’s ability to continue to execute at a superlative level.

Without a doubt, there will be new permitting in regulatory requirement that will impact future exploration. We are following closing all the new bills and amendments being debated in Washington, D.C. and we’ll carefully weigh their impact on project economics and our future drilling plans.

As you will hear, in today’s call, we have a deep portfolio and plenty of options. We’re confident that the options we possess and our ability to shift capital and human resources between business units will enable us to navigate in certain times ahead and continue to deliver profitable growth.

By now, I hope you’ve had a chance to review our second quarter financial results. Our pre-FAS 133 numbers were $1.06 per share. Our production volumes were at the upper end guidance and our costs and expenses were within our guidance ranges. Terry Rathert, our CFO will be happy to take any questions you may have regarding our quarterly results at the end of this call.

For 2010, our capital budget remains at $1.6 billion, unchanged. For the remainder of the call, I will use our time to update you on recent developments in our most significant plays, starting with our growing oil developments.

For sometime now, we’ve had a view that oil would be advantaged over natural gas. We back this belief by hedging a substantial portion of our future natural gas production. In fact, we hedged a greater percentage over a longer time period than has typically been our norm. I would encourage you to take a look at our hedge disclosure in our NFX publication.

For long weakness in natural gas prices has been further exacerbated by continually rising rig count. Apparently the need to hold acreage by production to precede economics and gas supply remains stubbornly high today. We hedged strong gas prices for 2010 and 2011, but because we have options we are focusing on oil projects today to deliver impressive growth.

Recently, there have been lots of questions on NGLs and their recent price erosion. This is a very minor issue for Newfield, since most of our liquid production is oil. In the second quarter, natural gas liquids, NGLs represented 2.5 Bcf or about 3% of our total production. This is up from about 1.5 Bcf when compared to the second quarter of 2009, primarily reflecting our growth in the Granite Wash play.

But in short, weaker NGL pricing is not a material issue for Newfield since our growth stands largely from real oil not NGLs. Our domestic oil growth today is coming from the Rocky Mountains from Monument Butte and Williston assets. I will talk a little about those at this time.

Starting with Monument Butte. This is our most significant growth asset today. It is a giant oil resource play capable of many years of double-digit production increases. We recently set a production record at Monument Butte at about 22,600 barrels per day that’s up 5,600 barrels of oil per day since year end 2009. We’re well on our way to reaching our year end 2010 target, of at least 25,000 barrels of oil per day. This field is the largest contributor to our estimated 30% growth in domestic oil production in 2010.

Our drilling team in Monument Butte continues to impress and set a recent drilling record of 2.8 days. That’s rig up to rig release and it was on a 20-acre directional well. Our improved drilling efficiencies are allowing us to drill an estimated 375 wells this year, with a five-rig program. It really puts it in perspective when you realize that we are turning a new oil well to sales every day now. This is the essence of a resource play and we are fortunate to have won this oil.

About 95% of our expected 2010 Monument Butte production is sold under term sales and 85% of our 2011 forward production is termed. Current differentials remain about $13 to $14 below NYMEX including about $6 per barrel of transportation expense. We’re working with area refiners to ensure their capacity keeps pace with our future supply growth.

Our results, on our northern expansion acreage or strong and three of our five operated rigs continue drilling on this 63,000 net acre area. We’ve drilled 90 wells in this acreage in 2010 and 220 wells since 2007 when we started drilling in that region.

To give you an idea of the success we’re having, a recent well here posted initial average production of 350 barrels per day over its first 30 days of production. In total, we estimate that there are currently about 4700 development drilling locations remaining in the Monument Butte area.

I’ll move on now to the Williston Basin. Our production in this region is the head of original plans and has nearly doubled since the beginning of the year. That production today is more than 4,000 barrels of oil equivalent. We added a fourth operating rig to our program last week and expect that our net production at year end 2010 will be about 6,500 barrels per day in this region.

We have about 160,000 net acres under active development along the Nissan and west of the Nissan, and year-to-date we expect to drill 25 or so wells in the full-year of 2010 cycle. Most of our producing wells to date have had lateral lengths around 4,000 feet, we expect in the second half that half of these wells we will drill, will have extended lateral lengths up to as long as 9,000 feet.

We continue to involve our completion designs to achieve the best results. In our operations release we detail recent well results and you can see several of the wells of initial production rates in excess of 3,000 barrels of oil equivalent per day and 30 day averages of a 1,000 barrels of oil equivalent per day or more.

In our Westberg development area on the Nesson Anticline, our recent Garvey Federal 1-29 well is our best to date and had an initial production rate of more than 3,800 barrels of oil equivalent per day from a 3,900-foot lateral.

We’re also seeing good results in our new assessment areas west of the Nesson in the Aquarium/Watford are a Bluefin well had an IP of about 2,500 barrels of oil equivalent per day and was our first Bakken well on this acreage area. More than half of remaining 120 wells this year will have lateral lengths of approximately 9,000 feet.

As a result of our improved drilling and completions we’re now seeing increased UR’s in the range of 500,000 to 750,000 barrels. Recent drilling complete cost for the Williston wells range from $6 to $8 million, gross.

I’ll move on now to Malaysia. Our international oil production was up nearly 10% in the second quarter of 2010, compared to the same period in 2009. The primary driver was Malaysia. Our East Belumut field on PM 323 has performed ahead of expectation in the first half of the year.

In the second quarter, our net production from Malaysia averaged about 15,000 barrels of oil per day. Unfortunately, as we reported last week, our export pipeline was damaged by an unidentified marine vessel, working nearly 20 miles from our East Belumut field.

Repairs to the damaged pipeline are expected to take six to eight weeks and last week we estimated that the deferred production related to the downtime will total about 0.5 million net barrels. Repairs are now underway and we will update you again when production resumes. We have several new developments underway in Malaysia that are expected to provide additional growth in 2011 and 2012.

I’ll move on now to talk a little bit about building for the future. Our oil production is at record levels. We continue to build for the future and are assessing some significant new oil resource plays. Some of which you are aware of, some that you are not. Maverick Basin will be where I’ll start. Without a doubt Eagle Ford Shale is one of the hottest plays underway today in the U.S.

Rig counts continue to rise and access to completion services remains tight. We have more than 300,000 net acres in the highly perspective Eagle Ford and Pearsall Shale plays and are investing about a $100 million this year thoroughly assess our acreage.

As of this morning, we are now running five operated rigs in the Maverick Basin and expect to drill about 15 wells in the second half of this year. Nine of these wells will be targeted at the Eagle Ford Shale and remaining wells will be drill to the deepwater Pearsall Shale.

We’ve drilled two wells to date, about to TD a third. First well was a 5,000-foot lateral in the lower Eagle Ford oil window in the northern portion of our acreage. Second was also a 5,000-foot lateral in the west gas window in the southern portion of our acreage.

We have a frac crew scheduled to arrive next week and we’ll have our first flow rates very soon. Our completions will be arranged back-to-back, and we will utilize the completion crew that will work exclusively for Newfield.

This ensures that we get the best possible quality and control, the timing of our jobs. It’s important to understand that this is a true assessment program. Simply stated this means we are sampling our acreage from north to south and intend to be in a position to understand its potential later this year, early next. We will not be making individual well results public and plan to update you with a package of oil results in an appropriate time later this year or early next year.

I’ll move on now to the Southern Alberta Basin. We have a similar assessment program underway on our 230,000 net acres in the Southern Alberta Basin of Northern Montana. Respected formations here are the Lodgepole, Middle Bakken, Spanish and the deeper Nisku. We’re preparing to start our third well now and plan to drill as many as eight wells before year end. We will test both vertical and horizontal wells in multiple formations.

Again, we will not be discussing individual oil results and plan to update you on package of wells when we have a comprehensive understanding of our acreage and it’s potential. Although, we’re not in a position to identify them yet, we’re applying our geological lessons learned to new oil plays. These are home grown plays that have significant potential.

Our geoscientists have done a great job of identifying these plays and positioning us early, as opposed to being a follower and paying a premium entry price. Acreage costs really do impact economics. I look forward to sharing results here in the future as we gain additional information.

I’ll move on and talk a little bit about our held by production gas plays. Plays that are capable of providing growth at the right time. Our operations release, we provided updates on our Mid-Continent resource plays the Granite Wash and the Woodford Shale.

Our Mid-Continent division recent production record of 360 million cubic feet per day net, we’ve been able to grow production over the last several quarters, despite a falling rig count in the region and the second quarter, we set a Woodford production record of more than 370 million cubic feet a day gross, and we expect that with the decreased rig count the Woodford production will still grow more than 20% this year.

The reallocation of capital, our gas directed rigged count has been slowed [result] acceleration in our oil plays. When stronger natural gas prices improve economics, we will be in a position to quickly grow our held-by-production gas assets with proven and predictable results.

Our rig count on the Woodford has decreased from nine rigs at the beginning of the year to four rigs operating today. But we continue to post efficiency gains. An example of this would be our lateral penetration rates, which have improved more than 20% year-to-date versus our average historical numbers. This significant gain in penetration rate allows us to do more with fewer rigs, for drilling longer laterals and we’re drilling them faster.

Our assessment of multiple perspective horizons in the Granite Wash play continues and by year end we expect to test at least 10 different horizons. We’re electing to conduct this comprehensive assessment this year to fully understand the [stake] potential on our acreage. It’s important to remember that we are not simply drilling in one sweet spot.

To date, we have drilled 26 horizontal wells across our 46,000 net acreage position. We recently drilled our longest lateral to date in the Granite Wash at nearly 360,000 feet, about half of our planned wells in the second half of 2010 will be drilled to the Monument formation where we have seen high liquid yield helping to improve economic. The Granite Wash is our highest return gas play and we currently plan to run four operated rigs through the balance of 2010. Our current net production in the region is around 80 million cubic feet per day.

Before I conclude our prepared remarks and moved to take your questions. Let me offer a few insights on what we believe, makes Newfield a preferred investment today. Number one, we have options. We have attractive oil and gas assets, and we’re pulling right levers to combine growth and returns. We’re confident that our diverse portfolio provides an advantage, as we navigate effectively through the challenges in our business environment today.

Number two, we’re making investment decisions around returns. We realize that growth is important, but it’s imperative that drilling decisions are based on economics. Our hedge position is very strong but we are not using our natural gas hedge position as rational for gas drilling. We’re slowing our gas developments because we can and channeling our dollars to oil to capitalize on our returns. We will be on a short list of companies that can grow domestic production in excess of 20% or more in 2010.

Number three, we’re building for our future. Although our budget in 2010 is driven by our expectations for cash flow and our commitment to live within cash flow. Keep in mind that there is more than $150 million allocated to assessing new oil and gas plays.

It would be easy to simply allocate these dollars for our current development plays but we must continue to build for the future. Our new assessments have the potential to rise to the top of our investment pyramid and if successful could be a significant part of our future growth and production, and reserves.

Thanks for your continued support to Newfield Exploration. That concludes our prepared remarks this morning, we’re happy to take your questions at this time.

Question-and-Answer Session

Operator

(Operator instructions) We’ll hear first from Gil Yang of Bank of America/Merrill Lynch.

Gil Yang – Bank of America/Merrill Lynch

Good morning Lee. In the Woodford, are -- is your ability to continue grow due completion of uncompleted wells or conversely are you choosing to not complete some of the wells that you’re drilling today in the area?

Lee Boothby

Good morning to you as well, Gil. A couple of quick answers and I will let Gary jump in if I happen to leave anything out. I would say that our activity is relative to deferred completions from 2009. Most of that activity played out late first quarter, early second quarter. I would say that accessing those completions is now behind us. The record production that we recorded in May, out of the Woodford shale and gross production, I referenced of 370 million a day, was related to the ongoing drilling efforts as well as that surge from those deferred completions.

We do have the option as the second half unfolds to defer some completions into 2011. And since we have done that before, we will monitor the market conditions as things play out and certainly that’s one of the tools in our tool kit and we will use it as we think it is appropriate. But at this time, all of the deferred completions from 2009 are behind us.

Gil Yang – Bank of America/Merrill Lynch

Okay. Great. And will you -- your comments about oil versus gas, what I noted, would you have any interest or ability to further shift your capital spending towards oil and less gas and sort -- along those lines sounds like the four rigs you’re running in Woodford. Are those two hold acreage and so you can’t slow down beyond the four rigs?

Lee Boothby

Well, I will remind you that in the Woodford, let me start there and I will work my way backwards to your questions. In the Woodford, we’re substantially held by production, up until this quarter, we reported a net acreage number of around 166,000 net acres. You’ll note in our release, it is up over 172,000 net acres. So, we have added to our position in the Woodford but of that, 155ish, somewhere in that zip code of those acres are held by production.

So we have very little requirements for HBP drilling in the Woodford. The same story is true in the Granite Wash. We have four rigs running in the Granite Wash as well. And I was careful to point out that our current plans relate to continue to have those rigs running now through the end of the year but as with the completions, we will continue to monitor the situation and we do have options in the portfolio. We’ve been shifting towards oil all year and something we will continue to consider on an on going basis in the second half of this year. The biggest variables there really are assessment programs in the Maverick Basin and Southern Alberta Basin but we really think those will be mostly a 2011-2012 type of event.

Gil Yang – Bank of America/Merrill Lynch

Okay. Thank you very much.

Lee Boothby

Thank you, Gil.

Operator

We will move next to Brian Lively of Tudor Pickering Holt.

Brian Lively – Tudor Pickering Holt

Good morning, guys.

Lee Boothby

Good morning, Brian.

Brian Lively – Tudor Pickering Holt

Just kind of thinking about Monument Butte for a second, you reiterated the 25,000 barrels a day exit rate. Just trying to get a sense of what the upside to that rate could be from an exit standpoint since the wells seem to be performing better and you’re continuing to drive down drilling times?

Lee Boothby

I will put that to Mr. Packer in Denver and let them answer that question.

Gary Packer

Yeah. Typically, the 25,000 barrels a day was derived by some of our early drill rates that we had in drill pace, that we had entering 2010 with some of the increases and improvements that we’ve seen year-to-date, you know, I would say, you know, 25 is still a good number. We could probably see as high as 265. That would probably capture the high side of what we could exit 2010 with it.

Brian Lively – Tudor Pickering Holt

And there are no immediate processing or takeaway constraints on that, even that higher 26,000-barrel a day rate?

Gary Packer

No, we’ve seen a very good appetite for the black wax that we produce from Monument Butte. That is not a contracted volume. We have essentially all of our volumes in 2010 and the majority of our volumes in 2011, all contracted. There is always the uncertainty, with spot volumes but the appetite has been such that we think we have got it covered.

Brian Lively – Tudor Pickering Holt

Okay. Moving over to the Bakken, just reading through the ops update the 500 to 750,000 barrels per well. Is that your average estimate for the long laterals or the existing short laterals?

Gary Packer

Yeah. As far as the EURs that we have there, that probably -- that range captures not only the 640s or 4,000 laterals through the 1280s but it is also is meant to capture the on Nesson Anticline off of Nesson Anticline volumes. To date, our historical type curve that that we have been using in the -- for the short laterals has evolved into about 450 to 500 MBO. As is in the update, we plan to drill a majority of our wells throughout the remainder of this year, the -- on 1280s or 9,000 to 10,000 foot and we think that 5 to 750 captures the range of EURs, we will see there. While we haven’t actually drilled wells like that to date, we have an abundance of information on and immediately adjacent to our acreage position and feel real comfortable with that.

Brian Lively – Tudor Pickering Holt

And as you move to drilling more than, I guess, half of your wells for the rest of 2010 is long laterals in the Bakken. Are there any areas that you’re limited to where you have to drill the short laterals? Are there any regional differences where you would choose to drill the short and I’m thinking kind of the Nesson versus the big valley area?

Gary Packer

The only area that we would preferentially drill the shorter laterals, historically, has been up on the Nesson Anticline. And it has been more driven by the acreage blocks that we currently hold in the offset operators as we would drill longer laterals, we would need to put larger spacing units together which typically get into operator ship issues. As we move off the Nesson and move into areas such as Catwalk, Watford, Aquarium in the like. We have larger contiguous positions even where we’re free to drill the longer laterals. It wouldn’t be a geologic reason.

Brian Lively – Tudor Pickering Holt

Okay. And as I look at the 30 day rates on the short laterals, they just seem pretty strong to I guess what my expectations were at least. What are you guys doing from the completion side? I understand that it is 10 to 12 frac stages but in terms of ceramic -- how much ceramic are you putting away and just kind of any general thoughts on the well quality so far.

Gary Packer

Well, I don’t know that as far as the stages go, we’re probably pushing 14 to 16 stages, versus the 11 and 12. So, we’ve certainly evolved in that regard. I would say that we’re probably opening these wells up in a little more controlled manner than maybe some of the numbers you’re used to seeing and therefore you have more of a -- maybe a little lower decline than what you may have anticipated.

We’re tailing with ceramics. So, you know, we’re pumping sand for a bulk of the job and tailing with ceramics, so that is kind of how we’re involved in that. Other than that I just think we’re in some good areas and therefore if you look at -- if you’re comparing our results versus an average across the basin, you may just be seeing that rocks makes a difference.

Brian Lively – Tudor Pickering Holt

Okay. And then last question just on the Woodford, what is your estimate of rigs that you need to run to keep production flat there?

Gary Packer

Typically, we’re anticipating four rigs and that’s kind of the -- where we have -- where we’re currently bringing the fleet down to. So, we ought to be able to essentially be an equilibrium as we look forward in that level. As Lee referenced earlier that’s far in excess of what we need to and that gives us some flexibility as we look into the future and look to allocate our capital between oil and the gas place.

Brian Lively – Tudor Pickering Holt

So if I understand longer term, if you ran a four-rig program, that would be the estimate to keep production flat out of the Woodford or would you still be growing?

Gary Packer

I would say our look into next year, it’s about equilibrium. We could see some marginal growth next year but that’s a little premature at this point. I would think of it as being flat.

Brian Lively – Tudor Pickering Holt

Okay. Thanks. Thanks again.

Gary Packer

Thanks Brian.

Operator

We will move next to Brian Singer of Goldman Sachs.

Brian Singer – Goldman Sachs

Good morning.

Lee Boothby

Good morning, Brian.

Brian Singer – Goldman Sachs

In the Granite Wash, can you talk a little bit about what you are seeing in terms of, kind of, CEOs and pricing and as well I know you did highlight the less relevance of NGLs overall but maybe talk a little bit about what you are seeing in terms of the ability to get yields for your NGL products.

Lee Boothby

Gary, you want to take that?

Gary Packer

We sell into northwest right now and therefore, we’re not taking specific ownership of the NGLs and we’re getting it priced on a BTU basis at the well head essentially.

Brian Singer – Goldman Sachs

Got it. And is that, I mean, what are you saying on the [kind of takes] side as well?

Gary Packer

Boy, I tell you what, I will have to get back to you Brian on that. I couldn’t tell you what our condensate pricing is at this point.

Brian Singer – Goldman Sachs

Okay. And separately taking a step back, on capital spending can you just refresh us on what you are thinking about this year and next year, in terms of capital spending and when you think about your hedging gains and spending within cash flow. I mean, you obviously have significant hedging into this year and looks like depending on the price deck on track to have hedging gains next year. When you think about your CapEx, do you think about spending within cash flow before hedging gains or using hedging gains as an opportunity to do some of the exploration work that you were talking about earlier?

Lee Boothby

Well, you know, Brian we’ve been consistent always. So we’ve been a hedger for a long time. And we have always hedged for the same reasons to underpin our operating programs. And we’re not planning our business on the fluctuations of day-to-day or week-to-week and we need a longer term view. Given the nature of the large scale operations, it’s not an efficient thing to do, to speed up, slow down, put your foot on the brake one day and the accelerator the next. So it really gives us the operating flexibility to look a little bit further into the future and plan and allow our operating teams to continue to execute.

As far as commitments on capital programs, we’ve set out on the road. That it is our intent to maintain our commitment to live within cash flow until such point in time that we consider the economic conditions such that it makes sense to do something else. I don’t know when that time is going to be. We doubt it’s going to be this year. Our hedge position tells you that we doubt, it is going to be next year but clearly, it is our policy not to comment on budgets next year because we’re halfway through 2010. We’re focused on ‘10 but I would say the assumption, until we tell you otherwise that we’re committed to a little different cash flow that is going to remain in place and that excludes acquisitions. Obviously, we’re looking at kind of a rolling two-year average in that regard. Maverick Basin TXCO acquisition would be one of those items. We have got nothing else on the horizon in that area and we have got plenty of work to do between now and the end of their to assess our new programs.

Brian Singer – Goldman Sachs

Great. Thanks. And then very quickly, any update on extending black wax into new markets?

Lee Boothby

Flip that to the Rockies.

Gary Packer

We’re looking at all options there. You know, as -- as we look forward right now, Brian, you know, through 2010 and 11, we’re very comfortable. With the kind of success that the team is enjoying up here as you look into 2012, our first preference would be to continue to work with our partner refiners up there, which we already have and expand the capacity there. But as you continue to enjoy success, we have to look at all options and there probably are some out there -- but, right now we’re feel pretty comfortable where we’re at.

Brian Singer – Goldman Sachs

Thank you.

Operator

Our next question comes from Subash Chandra of Jefferies and Company.

Subash Chandra – Jefferies and Company

Yeah. Good morning. I just wanted to, I guess, make sure that in Malaysia, it sounds like any remediation costs or clean up costs from the oil spill was going to be either covered by insurance or immaterial to Newfield?

Gary Packer

I think that is a good summary, yeah basically covered by insurance.

Subash Chandra – Jefferies and Company

Okay. Great. And in the maverick basin the two wells drilled to date so any commentary on, you know, I guess, it is supposedly it is in the normally fresher part of the play or is that the case and the completion design, you going to go through the gel frac and sort of the big prop and is that -- does that make sense?

Lee Boothby

I appreciate the effort. I was pretty clear on the call that we’re not going to comment on individual well results and plans and we will put together package of wells and talk to you later this year or early next. Once we feel that we have got enough information to talk intelligently relative to the play.

Subash Chandra – Jefferies and Company

Got it. Sorry, Lee. I missed that part. Anyway…

Lee Boothby

I just wanted to reiterate it. I know some of your buddies are listening out there. So I can’t say it enough.

Subash Chandra – Jefferies and Company

I hear it loud and clear. Okay. Thanks guys.

Lee Boothby

And in advance before you ask me the question about the Southern Alberta basin, I said the same thing about that, too.

Operator

And Wells Fargo’s David Cameron has our next question.

David Cameron – Wells Fargo

I guess, I know what not to ask. First, question for you…

Lee Boothby

We like you asking but, you know, we’re just not going to tell you anything until we get data, guys.

David Cameron – Wells Fargo

I know, I know. In the…

Lee Boothby

Keep asking, I enjoy it.

David Cameron – Wells Fargo

Okay. Let’s go to Uinta basin. Monument Butte, I noticed back, a few months back, you guys committed to wells in some horizontal, some horizontal wells at Monument Butte. Any update on those particular wells. Have you drilled those? And a future potential, we are growing horizontal in the base there?

Lee Boothby

Yeah. We have been looking at horizontal well plans at Monument Butte for years. And as we built the competency internals of the company, we’ve expanded that here into the Rockies. We have permitted a numbered of wells I believe horizontally targeting various horizons. We’ve drilled one to date and it is not completed at this time.

David Cameron – Wells Fargo

Okay. So that is something to stay tuned for?

Gary Packer

Yeah. That’s right. You know, David, I mean, it is a -- the sands are very variable in the field. So you have had to be very careful in how you target these, but with the amount of work that has been done geologically, we feel like we’ve identified areas in the field where there is sufficient continuity to drill a horizontal. And in those areas, we’ve mapped it out and I think it is just one of those things as we continue to apply more and more technology to the play. We have the opportunity here to see some good results, so we’re excited about it. But it’s -- we just don’t have any results at this time.

David Cameron – Wells Fargo

Okay. Fair enough. Let me ask you another question along the same -- along the same lines as it relates to the Uinta basin. The Ute tribe has reportedly got a little upset at Questar. Can you talk about any impact there to you guys and how it affects your relationship, your current relationship with the tribe?

Lee Boothby

It has no relationship with us. We have a -- what I would describe as an outstanding relationship with the Ute tribe as good as we have with any partner throughout the organization. And we look to continue to build on that relationship and from what I am aware of and I have nothing more than that what you have read. That appeared to be more of a one-off situation between Questar and themselves.

David Cameron – Wells Fargo

Okay. Very good. Thanks.

Operator

We will hear next from Scott Wilmoth of Simmons and Company.

Scott Wilmoth – Simmons and Company

Hey, guys, just wondering in the Williston, what the current AFE is running for at 9,000-foot lateral.

Gary Packer

It’s somewhere, we’ve provided in our cost update, you know, $6 million to $8 million. We anticipate that well to be somewhere with current rig rates and current stimulation costs in a $7.5 million to $8 million zip code but -- you know, we will be, in fact, we’re drilling our first 10,000-foot lateral as we speak and we will be able to provide you more color on that, a little bit in our next quarterly call.

Scott Wilmoth – Simmons and Company

Okay. Given the tight service market up there, you guys anticipating any increasing low costs in the Williston in the second half of 2010?

Gary Packer

We hope that we’ve captured much of the increases in our current AFEs. We have seen increases as you would expect. But, hopefully, we have most of those already baked in and we feel that the 7.5 to 8 would capture that.

Scott Wilmoth – Simmons and Company

Okay. And then, with the additional rig going into the basin, what part of the play is that going to work and then also, when do you guys anticipate, drilling a well in big valley?

Gary Packer

Of the four rigs, that we just put our fourth rig to work out there. Two of them are working on the Nesson and two of them are working off the Nesson in some of our other areas. I would -- I wouldn’t anticipate activities in the big valley area until September or fourth quarter.

Scott Wilmoth – Simmons and Company

Okay. And then just more on a macro gas level, you guys mentioned the ability to ramp up gas production, when it makes economic sense. What do you guys looking at to make that decision? Is it the one-year strip, two-year strip, how do you guys think about that?

Gary Packer

Well, I guess, being the keeper of the margin calculations, I would say when we think we have margins with that activity to compete with other investment opportunities, we have around the company then we will go back to really putting it to drilling in those areas. It is always going to be about margin. And, it is not price, it is margin. And, you have to look at the cost that underlie that and operating costs and the value of the product so -- we will keep in tune with what the margins and in each of these areas are as we go forward and make the decisions on capital allocations based upon returns.

Scott Wilmoth – Simmons and Company

Okay. Thanks guys.

Lee Boothby

Thank you.

Operator

We will hear next from Joe Allman of J.P. Morgan.

Joe Allman – J.P. Morgan

Thank you and good morning, everybody.

Lee Boothby

Good morning, Joe.

Joe Allman – J.P. Morgan

In terms of the Granite Wash, have any of the 26 wells that you drilled been a second well under the same acreage and do you plan on doing that, whether or not you have done that?

Lee Boothby

Joe, if you go back to our original release and I’m trying to remember, I think it was July of last year. I think there were a half a dozen wells, maybe six or seven wells. And read the names of the wells very carefully, there were three wells with the name McCoy on it. They were all drilled into the same horizon in the Monument, one on the east side of the section and one on the west side of the section and I guess you can guess where the third one was, right in the middle.

We did that as an initial test early in the program to go ahead and ascertain two things. Number one, variability and deliverability, relative to petrophysics within individual target horizons. These two west side, while we had better petrophysics from the drilling program in the center, so, somewhat did Gary read in section and what we found is where we had good rocks on the east and west, they performed much better than the rock in the central portion of the section but all three wells were good wells and they continued to perform very well. So that’s – To my knowledge, the only three wells, single zone section. So you could say a couple of hundreds acres for well type volume allocations relative to the section that we found, but we did it early and we got that in our back pot in terms of performances, as we planned the future developments.

Our focus has been on assessing the individual horizons. We talked about there being as many as 30 individual horizons. And I think we’re about seven horizons in now to our testing. So if you think about 26 wells and take the three that I just told you, they were in the same zone out, you can get an appreciation that we got relatively sparse drilling, within individual target horizons. The point there is we want understand what the inventory looks like on our acreage, so that we can get it planned appropriately within our portfolio model and future plans. We will have about 10 of those sections and 10 of those horizons tested by year end, which is right in line with our pre 2010 expectations.

Joe Allman – J.P. Morgan

Okay. That’s helpful. And then on the different topic, could you – And you referred to this a little bit, but just go across your different key operating areas and just talk about what you’re seeing with service costs and where you are really seeing a lot of pressure?

Lee Boothby

I will let our Chief Operating Officer take that one. Mr. Packer?

Gary Packer

Yeah. I would say that a bulk of the cost inflation, we have seen is certainly on the pumping services. Oil country tubular goods has been up as much as 20% throughout the organization. Rig rates as you’re probably aware, depending on where you want to start from the ultimate low, could have seen somewhere between 30% to 50%. However, we have had – Much of that has been either baked into our numbers, as we entered the year or under rig contracts so, we haven’t seen that translate into the well cost, as much. But just as an industry number that’s probably pretty appropriate.

On the pumping services side that number could probably be and if it’s regionally variable, in areas like the Bakken and Eagle Ford, this has already been addressed, is extremely competitive. So you could have seen, certainly, 30, 35% annual increases in pumping services there. In some cases maybe hair more.

In other areas like the Monument Butte, the number would be less than that. So, on a completion basis you could probably that about half of those figures and say that’s where our completion costs were up, so that, if you know, on average I would say about 15%. On the drilling side, we have seen cost increases anywhere between 5% and 20% depending on where you’re at.

Joe Allman – J.P. Morgan

Okay. That’s very helpful. Thank you.

Gary Packer

Yeah.

Operator

Canaccord’s, Irene Haas has a next question.

Irene Haas – Canaccord

Hello, guys. Just want to get a feel as to how you guys think about the gas market as you mentioned earlier, rig counts are still high, nobody is blinking. How do you see this whole thing played out and what do you think needs to happen to tighten supply?

And along the same thought process are you guys a little cooling down on the Marcellus trend, since you -- even if you are more established trend such as the Woodford, you’re pulling back rig count. How do you feel about the Marcellus at this point?

Lee Boothby

Let’s see, jammed a number of things in and I’ll try to get them all, if I haven’t miss any Irene you can go ahead and remind me, and I’ll come back to it. So let’s start with the Marcellus.

Our plan in the Marcellus we’ve been very clear. We built a team. It’s a quality team. We see the Marcellus as a substantially significant long-term source of supply in North America. We believe we need to be represented there but we’re going to be very judicious and diligent in terms our efforts and we expect it to be a multi-year effort to build the business in Appalachia.

So we haven’t changed our position relative to our thoughts on the Marcellus and the team continues to evaluate opportunities each and every day. Relative to natural gas and the decrease in the rig count in the Woodford, clearly, I go back to Terry’s comments on margin. I mean, our – We have got oil in the portfolio and we have options to accelerate and we have been exercising those options for most of the last year now. And you’re seeing the results come through in terms of growing domestic oil volumes. I think that is significant. It is driven by attractive margins so we’re going to do everything we can to make sure that we get the best investments at the front of the line and that we keep them there.

So, we monitor that on a real time basis and we will shift accordingly. And I think we have learned a lot over the last year and half or so in terms of our ability to shift, not just capital but human resources, around, within the organization and I think it is a real competitive advantage in the type of market that we’re in today. As far as the natural gas market, which I think was your other questions and the leadoff, we have been bearish as you will recall, since exiting 2008, or ‘9, ‘10 and ‘11. And I think that we have not been surprised by how things have played out. I think as long as the rig count continues to run up and we’re being driven by HBP efforts. And natural gas plays it is almost inevitable that you will continue to be oversupplied and obviously in a commodity market that is bearish and we tend to lead to low price outcomes in that regard.

Having said that, I think once the HBP flurry is behind the industry and we can get some folks through the flood of money coming in internationally, promoted dollars. Then maybe we can get back to a more normal situation where the balance industry is making economic decisions and making investments on the merits, as opposed to making investments for other reasons, which I think is a lot of what is driving the buoyant rig count that we see today. It’s not going to turnover until rig count turns over and if we get back to a more appropriate supply demand situation.

Irene Haas – Canaccord

So it will be after 2011. That’s first, probably, chance that we might have some more positive view on this?

So it will be after 2011, problem first probably chance that we might have some more positive due on this.

Lee Boothby

We certainly hope so. I will leave it at that. I don’t have the magic wand to tell you which date, which month, which year, which quarter that is going to occur but I slept pretty good at night thinking about 2010 and ‘11. That’s our focus right now.

Irene Haas – Canaccord

Okay. Great. Thanks.

Lee Boothby

Thank you.

Operator

Dan Mcspirit of BMO Capital Markets has our next question.

Dan Mcspirit – BMO Capital Markets

Gentlemen, good morning.

Lee Boothby

Good morning.

Dan Mcspirit – BMO Capital Markets

Thanks for taking my questions. Thank you. Turning to the Bakken, can you speak of the choke size and the Garvey and Bluefin wells? And then what are you modeling, I guess generally here for the first year decline rate and then lastly at what point in the life of the well do you bring it on pump?

Lee Boothby

Well, we have actually kind of cut back on our flow-back program a little bit to be able to kind of manage those near-term rates a little bit. I think in general, we’re, our first choke size is in the 30s, low 30s, from that standpoint. We have seen some bit of a reduced decline in that first year and seeing that, when we reported our IP rates and our 30 day averages so, we think it is real early, we’re collecting that data but we do believe that we’re seeing some expanded or decreased first year rates. When it goes on…

Gary Packer

First year rates have decline.

Lee Boothby

It could climb up. Rate goes on pump. It is pretty well specific. It’s pretty area specific. It really depends on kind of the flow back where we’re at. That can be anywhere from three months to six months.

Dan Mcspirit – BMO Capital Markets

Got it. Thank you. And then turning to Uinta basin, you continue to squeeze out days on the drill time with – I guess your year to date average, now, being four and half days. What does that mean in terms of cost savings? Can you give us a reference on that and I guess maybe, why the somewhat ride range in the cost estimate of 700k to 900k per location and then lastly can you speak about spacing in the play?

Lee Boothby

Okay. Let’s see, as we move to more reduced days, it actually ultimately requires increased cost in our overall capital budget because we’re drilling more wells. As a result of the efficiency gains this year off the top of my head when we went from five and half days down to four and half days we’re going to consume an extra $80 million this year in CapEx as a result of that.

Now the reason we have such a wide range in capital cost is the play actually gets deeper as you move south to north and then, not only that our infill wells are all directionally drilled and more specifically, remembering those costs also we have our infrastructure cost or tank batteries. So there’s a wide variety of factors that could affect a specific well outcome, size of the battery, depth, directional versus straight hole.

As far as spacing goes, on the tribal side we’re drilling many of these wells are on 40s or even as we step out, these wells could be the first well in a 640, okay? So the infrastructure cost could be higher as a result of that.

As we step back into Monument Butte, that is primarily a combination of 40-acre vertical wells as we continue to extend the play. But in addition to that we’re also drilling directional wells from existing paths which are 20 acres and that makes up the balance of the Monument Butte proper play.

Dan Mcspirit – BMO Capital Markets

Okay. And then, thank you, and then, one last one, if I could. What is your lowest ranking asset, maybe in terms of economic breakeven or return on investment and maybe what’s the future for that asset?

Lee Boothby

We don’t have lowest ranking assets that I’m going to disclose, I mean, I would say that if you look at behaviors. The lowest ranking asset in terms of capital investment was our deep high pressure, high temperature drilling program in conventional deep target along the Texas Gulf Coast and we advent in that effort, over year ago and today our Gulf Coast onshore is managing the production associated with those producing assets, which generate really attractive cash flow is going into our resource plays today, but all of our drilling investments are directed towards assessment programs relative to the Maverick Basin. So we reshaped that team and that’s kind of a normal cycle.

I think the IQ test is not what you’ve done historically but that production provides cash flow. It’s the incremental investments that you make, perspective -- on a perspective basis, do they make economic sense? Do they have attractive margins? Do they generate the required returns, so that you can be a healthy self sustaining business and I think that’s a question frankly that more people should ask themselves.

Dan Mcspirit – BMO Capital Markets

Got it. Thank you and gentlemen, thanks again.

Lee Boothby

Thank you.

Operator

Citi, Bob Morris has our next question.

Bob Morris – Citi

Good morning, Lee.

Lee Boothby

Good morning, Bob.

Bob Morris – Citi

As you continue to run four rigs and drill in the Woodford you mentioned later in the year you have the option to postpone the completion of those wells that you’re drilling. What gas price would prompt you to stop the completions and postpone those?

Lee Boothby

I’ll let our Chief Financial Officer, actually of all things market related answer that one Bob.

Terry Rathert

Bob, I think one of the key questions there in terms of complete or not complete, it’s really a timing decision and, if we were to hit really low gas prices and had better use for the capital on an immediate basis we’d move it somewhere else. As a practical matter that’s a timing decision not an investment decision per se.

So, we continue to have pretty good gas prices. We’re still getting good returns on our drilling there. I can tell you the returns aren’t as high as drilling Monument Butte, 20 and 40-acre oil wells, so it’s really more function of looking at the total return and timing.

Bob Morris – Citi

And in that regard you mentioned that the Granite Wash was your highest return gas play. Just ignoring capital allocation issues and what other alternatives you might have. What gas price does that give you an acceptable rate of return, is it $3 and I know you’re testing a lot of horizons, but having mentioned that was your highest return gas play, again, ignoring the capital allocation issues, that’s something that’s economic in your mind at $4, $3, $2? What is the level there?

Terry Rathert

Well, I think maybe the best way of thinking about that, look at the large quantity of proven and probable reserves they put on the books at year end 2009, sub $4 gas price environment.

Bob Morris – Citi

Right.

Terry Rathert

Some of those were carrying in costs that we had had rigs under contract for some period of time. So, clearly, all those are very, they are working, it’s sub $4. Go back to one of my earlier comments. If we remain in the sub $4 gas price environment and we don’t have competitive and other pressures pushing service costs and cost corrected to a $4 environment so like roll it back to 2003. We have that kind of cost environment these things are tremendously exciting in terms of returns, $4 with gas price -- gas price with day rates that you have to pay if you were drilling in the Haynesville, it doesn’t get very exciting.

So it really gets back to that margin question and when you have a dislocation in the service cost side because of abnormal forces driving pumping service, costs or drilling rig rate costs, things of that nature, kind of distorts the return and you get this little dislocation for a period of time. In a normal environment, $4, those things would be very attractive.

Bob Morris – Citi

And when you mention the market environment, you talked about the increases in cost both completion and drilling, at a constant gas price when you -- it doesn’t matter what you pay, if you pay $4 or $5, have the drilling efficiencies, the longer laterals, the shorter drilling times overall, offset those cost increases over the past year, so fixed price margins have held steady or they more than offsetting those cost inflation pressures, so that your margins are actually improving over the past year at a constant gas price?

Terry Rathert

Well, clearly, we have seen significant increases or improvements in terms of drilling efficiency. And what that has done is drive the cost per completed lateral put down. I think there are some charts in our -- different historic materials on our website that show how dramatically we decreased those costs per foot of well completed. So if you just think of a constant gas price that’s the -- translates directly into a huge pickup in terms of rate of return.

Bob Morris – Citi

Right. Okay. So…

Terry Rathert

And that was in light of, right, a service cost environment that was relatively static at the time.

Bob Morris – Citi

Right.

Terry Rathert

Putting over pin on that, and say okay so, you could stand that kind of an increase, in cost and have a fixed return. You can’t go through the mental gymnastics, what you could tolerate in the context of what’s happening in the service costs as we have continued improvement and efficiency.

Bob Morris – Citi

Right. So the bottom line is despite the service cost increases your breakeven price has moved down over the past year?

Terry Rathert

I would say that all things being equal, it’s probably been more or less flat. Maybe down a little bit but we’ve had some great improvements in efficiency and some point that is very much a function, particularly in the Woodford of our, extended laterals, super extended laterals, pad drying, all the efficiencies that come with that kind of a development.

Bob Morris – Citi

Okay. Great. That’s helpful. Thank you very much.

Lee Boothby

Thank you, Bob.

Operator

Our final question will come from Heather Hilliard of ODS-Petrodata.

Heather Hilliard – ODS-Petrodata

Hi. Good morning.

Lee Boothby

Good morning, Heather.

Heather Hilliard – ODS-Petrodata

Hi. I had a question regarding the Gulf of Mexico in particular. And I was looking for some guidance on the Gladden development in the Mississippi Canyon area. I haven’t seen anything in any of the recent updates but earlier this year I think in February, Newfield was estimating a late 2010 first production. Obviously the environment has kind of changed, but can you’ll comment on that at all?

Lee Boothby

I’ll let Mr. Jasek comment.

John Jasek

Yeah. We still anticipate Gladden to be coming on in late 2010. The project is on schedule and on budget.

Heather Hilliard – ODS-Petrodata

Okay. Excellent. Thank you very much.

Lee Boothby

Thank you.

Heather Hilliard – ODS-Petrodata

Bye-bye.

Operator

With no further questions, I’ll turn the conference back over to our speakers for any closing or additional remarks.

Lee Boothby

Well, we just like to thank you, again, for your continued interest in Newfield. I know that we’re getting into the fall Investor Conference cycle and we’ll be seeing many of you on the road here in the weeks and months ahead. We look forward to visiting with you and continuing to update you on the progress of Newfield. I hope that you take-way, as we are excited about not only where we’re at but where we’re going. And I look forward to visiting with you and updating you as the year continues to unfold. Thank you.

Operator

And, again, that does conclude our conference. Thank you all for your participation.

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Source: Newfield Exploration Co. Q2 2010 Earnings Call Transcript
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