Newfield Exploration Company. Q1 2009 Earnings Call Transcript

Newfield Exploration Company (NFX)

Q1 2009 Earnings Call

April 23, 2009, 9:30 am ET

Executives

David Trice – Chairman & Chief Executive Officer

Terry Rathert – Senior Vice President & Chief Financial Officer

George Dunn – Vice President of Mid-Continent

Gary Packer – Vice President of Rocky Mountains

Analysts

Subhash Chandra – Jefferies & Co

David Kistler – Simmons

David Heikkinen – Tudor Pickering, Holt & Co

Ben Dell – Bernstein

Brian Singer – Goldman Sachs

John Daniel Sullivan, Jr – Olstein Capital Management

Rowan Maren – Ruffer

Joel Allman – JP Morgan

Rehan Rashid – FBR Capital Markets & Co

Wei Romualdo – Stone Harbor.

Brian Kuzma – Weiss Multi Strategy

Presentation

Operator

Please standby. Good day everyone and welcome to the Newfield Exploration's First Quarter 2009 Conference Call. Just as 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 of plans, expected cost reductions and planned capital expenditures. Although we believe that the expectations reflected in these statements are reasonable, they are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Please see Newfield's most recent 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 President Mr. Lee Boothby Please go ahead, sir.

Lee Boothby

Good morning and welcome. Thanks for joining us today for our first quarter conference call. Our remarks today will be brief and is always we’ll happy to take your questions at the end.

I’m joined in Houston, this morning by the members of our Senior Leadership Team including our Chairman and CEO David Trice. Our CFO Terry Rathert, Bill Snyder, he runs our International and Gulf Coast Onshore business units or Steve Campbell we’re joined on the call by George Dunn, from our Mid Continent Office in Tulsa and by Gary Packer and Daryll Howard from Rockies Office in Denver.

Our message in 2009 is simple, clear and concise. We are living within cash flow, and we are allocating, our investment dollars to the place and projects that make the most sense in today’s economic environment. We have a diverse portfolio of assets and a strong hedge position. Both of which provide us with lots of options today. For a last few months we’ve been on the road every week. Split pretty evenly between investor meetings and visits to all of our business units, and we will on the road again next week. I can tell you that our teams are doing an excellent job of managing through this period of weak commodity pricing, and they are working diligently across the board to lower cost and maximize our returns.

Although we are hedged at strong commodity prices in 2009, and well into 2010 we are making weekly capital investment decisions on how to best allocate our dollars. Let me quickly reiterate our 2009 priorities. Number one, preserving liquidity and living within cash flow, our cash flow in 2009 is well insolated by our hedge position for ’09 to 2010 mark-to-market our hedges are worth nearly $1.2 billion this includes about $200 million that we realize in the first quarter of this year. This are detailed in our add in effects publication on our website.

Our capital budget of $1.45 billion incorporates very little for service cost reductions in 2009. And certainly not to the degree that we are seeing today, or that we expect to see later in the year. Although we are significantly hedged the continued erosion in gas prices is lowering in cash flow expectations from initial levels. So lower service cost are welcome offset.

We will maintain our strong balance sheet. As we clearly articulated at year end or spending is front end loaded in ’09, due to the timing of expiration projects and our development spending. We currently have $614 million outstanding on our facility and have remaining borrowing capacity today of about $700 million. We expect to generate free cash in the second half of the year and plan to use proceeds to pay down any further borrowings. We’ve elected ’09 with a stronger balance sheet, and we entered the year.

Number two our second priority, is to continue allocating our capital dollars the projects that make the most economic sense. We are meeting weekly as a leadership team to discuss capital allocation and are practicing realtime budgeting to make sure we are shifting resources and making the best choices.

The benefits of our diversed asset portfolio are definitely apparent today. We have moving the chess pieces around this year and here are a couple of the recent examples. In the first we took two rigs working under terms contracts in South Texas, and combined a contract into one rig, we then move that rig to the Mid-Continent business unit where it is operating today.

Our spending on the South Texas business unit is down more than 80% of our ’08 levels. A high pressure, high temperature exploration wells don't warrant investment with today’s relationship between commodity prices and service cost. And the second example, we recently dropped a rig in our Woodford Play, and added a rig in our Granite Wash play out in the Texas Panhandle.

We continue to run three rigs in our Monument Butte Field today. One rig in a Williston Basin, but demand for oil in both areas has increased in differentials have narrowed, with the Woodford and Granite Wash play is substantially held by production, we got the ability to consider shipping capital from gas projects back to oil projects later this year should the economic conditions warrant. That gives you an idea of how the changes are recurring over the span of one quarter. And the third priority is to deliver on our production growth target. We continue to believe that profitable growth is important, not just in ’09, but end of 2010 and 2011.

This is a challenging time in our industry and it differentiating factor in our performance will be our ability to grow. And our hedges and improving margins to lower service cost will help the profitability. Although we are intentionally slowing completions in the Woodford today and we were reduced our rig count there, our company guidance continues to call for 6% to 10% growth in 2009.

We’ve remain very confident that we have the ability to grow in 2010, while living within cash flow and we've underpinned our 2010 cash flow with solid hedges for both oil and gas. As I said our priorities this year is simple, clear and concise it’s up to us to execute.

Our financials for the first quarter were released last night. And production was nearly 63 Bcf an increase of 14% over the first quarter 2008 levels. Our cost and expenses were below our guidance ranges clearly showing how hard our field personnel are working to lower and maximize margins. We are seeing release in every flat asset of the cost structure and we’ll continue throw flow through the P&L as the year-end falls.

The continued slide natural gas prices down some 35% since year end 2008 force the large drilling test charge at the end of the first quarter about $854 million after tax. And our forecast accounting roles we are not allowed to use the value of our hedges to offset this charge as a result our domestic DD&A rate enters the second quarter at about a $1.80 for Mcf equivalent.

If you have questions on our financials, Terry Rathert our CFO will have to take them in just a moment. In our last conference call we detailed the progress in 2008, to lower cost and improved returns in the Woodford. We assure that those positive trends are continuing today. On today's call, I would like to use our remaining time to spotlight our operations in the Rockies. Specifically the Wilson Basin. It's important for you to understand that we are building a very sizable oil portfolio in the Rockies.

As we began preparations for upcoming May Board Meeting, really struck me that our two largest areas, the Rockies and the Mid-Continent a relatively recent additions to the Newfield story. In fact, five years ago we didn’t have the Monument Butte asset, and Woodford was in its infancy rarely discussed in public.

We certainly come a long way and now have two important foundational growth assets that will carry us through our third decade. It’s no action that they were focused on oil in the Rockies. We had a theory back in 2004 that might be more value in oil specifically out West. We thought at the time that the oil prices could be as high as $30 to $35 a barrel. As opposed to the mean reverting $18 to $20 per barrel period it seem to be prevalent at the time. While it pays to be lucky and our 2004 thesis in oil has certainly proven conservative.

Monument Butte is definitely a price resilient asset. When we bought the field in ’04, oil was selling for around $30 per barrel. Since that time, we’ve more than doubled the field production we booked additional proved reserves totaling about $55 million barrels of oil equivalent and lots more to come. And we’ve increased our rest of in our ultimate recoverable oil in place. Recently the demand for Black Wax has improved than we are today selling some 19,000 barrels of oil a day, up from about 17,000 barrels a day of sales at year-end 2008.

We have increased our sales from inventory to meet the recent demand, all three of the refiners in the South Lake City Area. Differentials have narrowed from about $18 a barrel at year-end 2008 to about $12 a barrel today. And remember that this includes about $4 to $5 a barrels of trucking related transportation expense borne by the refiners.

We are seeing some solid reductions in our industry leading cost structure in the Monument Butte field, this is a pretty efficient operation before with wells before with wells begin drilled and just four days to six days, but our teams have taken some additional cost out of the system.

Rig cost along with bits and motors are down more than 25% pressure pumping is down about 20% oil country tubular goods are down about 20% we expect additional 20% in very near future all of these numbers are off the peaks that we saw in 2008.

Together today a completed well at Monument Butte, shows showed the 20% reduction from the ’08 highs an $880,000 well then is costing us about $725,000 for well today. And we have additional yet to come out of the system.

We are still running the three-rig program at Monument Butte down from five rigs late 2008. This three-rig program provides modest production growth in 2009 and we always have the option of adding additional rigs with 100% of the acreage held by production, we have lots of options to slow accelerate activity based upon market demand oil prices and available cash flow. Should natural gas prices continue to weaken through the summer we’ve got the ability to accelerate our drilling for oil and decrease our focus on gas in other regions.

Lets move Northeast and talk about the Williston Basin. Another great oil plant. Newfield is quietly assembled the large position in the Williston Basin over the last several years. I was reading a report not long ago that detailed the top acreage holders in the area and we were omitted even though our net acreage holdings would have placed us strongly in the top 10. We are fairly new entrant and we’ve maybe still off the radar screen for some.

But today we hold nearly 500,000 net acres and we believe that significant new opportunities remain about a 190,000 net acres and what we considered core development regions on the Nesson Anticline and the region just West of the Nesson Anticline there is a map in our add-in effects publications if you'd like to see acreage distribution.

We've been drilled and operated 10 successful wells today aided these in the Bakken and two in the Sanish Three Forks. I attended a detailed meeting in our Denver office last week, and I thought I’d share of highlights with you.

Our last three wells in the region they all tested more than a 1000 barrels of oil equivalent per day in their first 24 hours online. Although IPs in isolation don’t mean a lot. It does allow you to see the progress that we’ve made on several fronts.

First maybe much better geologic understanding the entire basin today then we did a year ago. We have talented team of employees of with proven success may map the entire region the better understand the Petrophysics, the depositional history and the fraction network. Using integrated geologic and geophysical models we’ve define sweet spots in the Sanish Three Forks and Bakken and our first two Sanish Three Forks wells in ’08 were a result of that technical work.

In fact our first well in Bakken IP it is just 329 barrels of oil per day our technical team did a post-mortem for us and clearly explained why the well is drilled and completed in the less than optimal location.

Second we are drilling our wells much more effectively the old learning curve benefit gain, faster penetration rates fewer days to TD and reduced trouble time. Our Moberg well which will TD soon and a lateral with their total measure depth of 19,600 feet is an example. We reached 10,000 feet in that well, in just eight days a record for us and I expect we will push that South soon.

Third we’ve made some significant changes and how we are completing our wells. This is evident by our increasing production rates, but that’s about as much information as like here to share on that topic today.

We are still operating the one of rig program in the Williston, down from our initial plan to run three-rigs party capital spending reductions in May 2008. We planned to drill 9 wells in 2009, our rig is moving throughout our different prospect regions and testing new areas. The success of our drilling program this year is setting up a development drilling plans for 2010 and beyond.

Differentials in the Williston have narrowed dramatically in recent weeks, from about $15 a barrel in late December 2008, to less than $6 per barrels today. We are producing about 2,700 barrels of oil per day equivalent net with continued strength in oil prices or further erosion of gas prices, we’ve have got the ability to pick up additional rigs in the Williston Basin over the balance of this year.

And closing let me reiterate a couple of key themes that I hope you look away from my remarks today. 2009 is a challenging year for industry. Newfield has been around for 20 years and we demonstrated our ability to thrive in times such as these. In fact 15 of our 20 years have been in a down market. We’ll be successful the same reasons that we have always been success from the past. Great people, strong financials and a solid business plan.

We’re doing the smart things today while keeping eye on future growth and profitability. Our diversified portfolio is truly an asset today and we posses exceptional optionality. We are able to shift capital to ensure that we are funding the best opportunities and I can assure that Terry Rathert and Gary Packer and our teams are working harder than ever to do this on a virtually realtime basis.

And finally, we are very intention in meeting our 2009 targets that includes 6% to 10% production growth continued reduction and costs and expenses and doing what it takes today to be an outperformer in 2010 and beyond.

Thanks for your time today and our management teams available to answer any of the questions you might have. Operator?

Question – and – Answer Session

Operator

Thank you sir. (Operator Instructions). And we’ll take our first question from Michael Jacobs with Tudor, Pickering, Holt.

Michael Jacobs – Tudor, Pickering, Holt

Good morning everyone, great quarter.

Lee Boothby

Thanks Mike.

Michael Jacobs – Tudor, Pickering, Holt

I appreciate all the color on the Rockies, but I would like to go back to the Woodford for a sec not everyone has over $1 billion in hedge value spread through 2010. Can you put your financial position into operational context by updating us on what your non-op activity is and then how we should expect gross net activity to change this year into next?

Lee Boothby

You're asking about non-operated activity in the Woodford specifically?

Michael Jacobs – Tudor, Pickering, Holt

Yeah kind of what you’re seeing versus what your partners are doing and kind of how – in your press release you mentioned an increase in working interest in the Woodford kind of how you expect to continue to increase your interest overtime?

Lee Boothby

I'll let George provide some color, but one of the benefits of our operating Oklahoma and since I spend a fair amount of time there, I can appreciate it. If Europe an aggressive operator and in a position to drill wells, the pooling provisions in Oklahoma work to your benefits. So we've been able to because we've maintained our activity levels, put some other operators interest owners in a position where they have had opt out if you will. So in doing that George Dunn's team has been able to grow the working interest position on average by about 3%. And that’s at no incremental cost other than in picking your share of the working interest. So we look at that as a pretty efficient way to acquire acreage at a good cost but I'll turn the non-op activity over to George.

George Dunn

Yeah I mean essentially non-op activities has been falling off as compared to 2008. It’s still I guess you'd say guesstimate what everybody is going to do, but it looks like we're in the range of 60% of what we were last year, for full year 2009. And that’s I guess dominantly some of the smaller players that have backed off. But in general rig counts has gone down out there by most everyone.

Michael Jacobs – Tudor, Pickering, Holt

Great, thanks.

Lee Boothby

One of the side that Michael on the side benefits of that is that we can achieve the same number net wells an increases in production through less activity which allows us to continue to focus on capital efficiency and doing things smarter and more effectively. So, there is a kind of a double benefit there as a result of being able to drill when others can't and pick up interest in that context.

Opeartor

And we will take our next question from Subhash Chandra with Jefferies.

Subhash Chandra – Jefferies & Co

Hi, thanks. Good morning. Any commentary on the well cost in the Bakken?

Lee Boothby

Gary?

Gary Packer

Last year our well cost in the Bakken were typically I would say $4.5 million to $5.5 million. We’ve achieved through the cost saving that was already discussed by Lee about $4.5 million our target this year is about 4.1 and 4.2.

Subhash Chandra – Jefferies & Co

And how about that 8,000 foot lateral? Does that include, does that fall into that cost range as well?

Gary Packer

No that's – that's our typical well would be a 640. We probably be in the high side of $5 million on the 1280's typically. But this is a – it's rare typically we’ve elected to drill the 640's.

Subhash Chandra – Jefferies & Co

Okay and, spud to sales what do you saying the Bakken?

Gary Packer

Actually, I have a chart on that I can dig up right now. It typically takes us about if we’ve averaged about 15 days from a TD to initial production. And that's down from about 45 days last years, so we made, the teams has made some great strides in that. Wells it’s typically are about 30 to 35 days or so. So, we are typically looking about 45 days for the sales.

Subhash Chandra – Jefferies & Co

Okay, great thanks. And then Monument Butte, you talked about updating the recovery factor. What is the new number?

Gary Packer

Its something that varies area to area throughout the field. I mean, we still believe our target about 18 to 20% is still our target. We’ve seen some increases primarily in areas where we’ve drill the in field 28 acre wells. And you have talk to the investment community about the equity quite a bit. What we started to do, and we're starting to see the response lately, is this by converting all the offset wells, the original producers to injectors really we’re starting to see some improved response. So, I can tell you that that confidence level that we are going to be on the high side of that numbers definitely improving.

Subash Chandra – Jeffries & Co

Okay, and in the Monument Butte, the Ute acreage, has drilling continued there, any sort of operational update on that acreage and were - was that acreage included and improved reserves for last year.

Gary Packer

The only acreage that was included in improved reserves on the Ute side would have been the 45 or 50 wells that we have drilled. We had minimal, we elected the book minimal puds up there. So, majority of that acreage would be considered on a unevaluated at this point. Despite our confidence levels that it’s going to be yield a lot of additional reserves. As far as activity right now, you recall we’ve signed a two EDAs. The second EDA has 8 well commitments this year. And we are just waiting a permits to come in to initiate drilling activity there, on the original EDA. I’d say our activity is been down year-on-year primarily, a result of the first quarter when we ended the year. We were at very low commodity prices and those wells are little deeper. As commodity prices have strengthened, we’ll increase activity there.

Subash Chandra – Jeffries & Co

Fantastic, Thank you very much.

Operator

And we’ll move on to our next question from David Kistler with Simmons

David Kistler – Simmons

Good morning guys.

Gary Packer

Hi David

David Kistler – Simmons

A quick question on the drilled but delayed completed wells in the Woodford. What is the number of wells that you guys have done that with so far. How hard do you project that going, and at what kind of either service cost price deflation or commodity price acceleration do you think about bringing those back?

Gary Packer

George

George Dunn

I would say, I guess in terms of how many we deferred that’s really just starting. As we’ve describe many times. Our cycles are lumpy, because are drilling that. And so we had a lot of completions in January February I’ll slowing of and we’re picking up in terms of wells getting TD that will be deferred through the summer. We are seeing stimulation cost come off as we speak they have come off, well not too dissimilar from what you heard in Monument Butte percentage wise. And now as the pumping services are probably, about as low as they are going to get so, its all the other supplies sand et cetera, that we expect to see more reductions as we go forward. And the current plan is to continue monitor gas prices that the cost are in the right direction already. And we’ll determine what we need to do, based on gas prices in terms of coming back on with completing wells.

David Kistler – Simmons

Okay so, just to understand that little better. It's, is it more pad driven in that you have a series of wells that you are drilling of one pad and don’t bring them on until, all are stimulated and brought to sales. Or is it an economic decision to defer it until you have better commodity prices which makes sense I just trying to understand?

George Dunn

It's the economic decision all I was giving you the pad description for is that, there is not a monster bow wave of completions just setting there right now. Just because the wells are just now in the middle of drilling and or will be TD, it over the next month or so, and that's when the bow wave will really start, but it's an economic decision. The answer to on of your questions was how many that we have, we’ve got about 10. And we’re in the early stages. We are going to monitor the inventory something George and his team say on top of real time. And I think that's we are just going to have to monitor the economic conditions as year unfolds.

David Kistler – Simmons

Great and then, just thinking about the Woodford. 6 more rigs rolling of contract this year. You added rig in the Granite Wash. Can you walk me through the economics of the two players. And could we see more rigs traffic their way up to the Granite Wash. Is that how about production issue who knows.

George Dunn

Our Granite Wash that is that will both are dominantly HBPs. So, we have no demands to in essence to drill in either area. And so we’ll make decisions clearly on economics Granite Wash is looking promising right now. And as we continue to drill and assess what we have out there will determine whether or not we add rigs out there, but that's clearly an options that's looking promising.

David Kistler – Simmons

Okay so, just from the pure rate of returns standpoint. The economics are better in the Granite Wash than the Woodford or I don't want to jump to that conclusion but it’s seems like you’re directing us there?

George Dunn

I would say that, I wouldn’t jump to those conclusions. I mean our decisions in the Woodford are in part related to the fact that the mid-continent express systems is not up and fully functioning. That’s going to allows us to utilize our firm transportation. That we have got for the Woodford production, we expect that to be in place in functioning by this summer, which in point in time we’ll see a Gulf Coast type differentials for our Woodford production said differently we’ll see basis differentials was about half what they have been year to-date. So, clearly that’s going to be a very positive incremental step for the Woodford, and it’s part of our decision to differ completions and slow up activity there, it’s a just a timing issue relative to that system. George said it's promising in the Mountain Front wash. I’d say that the way to read that is the economics are competitive within our portfolio. And we’ll make the right decisions, because it’s HBP. As we’ve said on many occasions. We have got options. We are encouraged by the early results. That we don’t care to speak about them anymore at this time.

David Kistler – Simmons

Great. I appreciate that additional color. Last question with respect to CapEx. You highlight that clearly service costs compression gives you significant amount of wiggle room. Potentially at least it looks like to potentially move those numbers down, or to be use that cash for something else. Can you give us any color on whether that the choice to use that cash elsewhere or you would be looking towards reducing that the overall CapEx number?

George Dunn

Well clearly, we are at the end of the first quarter and a lot has changed in the last three months. We didn’t set our $1.45 billion budget by accident nor the assumptions that, we’re stud in. We are very encouraged by the service costs reductions that we are seeing and that’s a net positive relative to the structure of our budget, but we haven’t reset the budget at this point despite the observation on the service cost because there's still uncertainty related to cash flow realizations in the pricing environment. So, we are monitoring that real time. I would say all vectors are positive and you can count on us and make the right decisions and now through year end. We don’t have any plans to increase activity at this stage. We are really focused on executing the plan that we laid out for 2009. And that’s going to be our focus.

David Kistler – Simmons

Great thank you guys very much appreciate all that color.

George Dunn

Thank you.

Operator

We can go to our next question from David Heikkinen from Tudor, Pickering, Holt & Co.

Lee Boothby

Good morning David.

David Heikkinen – Tudor Pickering, Holt & Co

Hi, and thinking about the. [Multiple Speakers], I'll just put in the blanks of what you actually said kind of going through that continued growth and just thinking into horizontal Granite Wash and moving rigs from South Texas, trying to get an idea of inventory and how you think about pace can you add to the play and kind of overall thoughts around that?

Lee Boothby

Well I would say that, George mentioned earlier that our position out there is largely held by production. It’s a substantial position, it’s one that we’ve built over the last several years., you'll be well aware that we’ve been drilling wells out in the South Ranch it[‘s pretty high activity areas for us the last five years. Going horizontal is a relatively new effort on the part of George and his teams in the mid-continent. They started late in the fourth quarter of last year. I would say we’re encouraged by the results, not surprised. We’ve got a good acreage position. And lot of potential out there to exploit that going forward, because it’s held by production. We’ve also got the luxury of time. So, I would say that we’ve said or we are going to say at this point, yeah we are happy with the early results all the wells are drilling out there horizontal, you probably going to here more about in the near future. It's probably the best and I could say.

David Heikkinen – Tudor, Pickering, Holt & Co

Okay, that's all I have thanks.

Lee Boothby

Okay. Thank you.

Operator

And we’ll take our next question from Ben Dell with Bernstein.

Ben Dell – Bernstein

Good morning.

Lee Boothby

Good morning.

Ben Dell – Bernstein

I have a couple of specific questions around the Woodford. And really, around the type of frac and scales and fracs that you’re doing. Can you give us some indication if you compare the sort of fracing that you are doing today, versus three years ago. What’s the average half length is, and what the interval spacing is and how that's changed. And I guess my follow-up questions to that is obviously, pressure pumping cost are coming down. And average frac costs are coming down. How much of that is being offset by your average frac getting bigger. And more extensive in this space and closer together?

Lee Boothby

I’ll let George to answer those questions.

George Dunn

I’m not sure, how many questions that was there. Dominantly, what we’ve done is three time test are going to smaller and smaller volumes. And then relating that back to performance to insure that we are getting the, equivalent performance with smaller volumes. And we still continue to test that today, half lengths is a kind of, when we do our microseismic. We see noise a long way, away the question is how much if we cropped. And we clearly have seeing that there is some interference when we talked about that before on 40 acre spacing. And at this point, what we know is 40 acre spacing looks like to optimal development although we’ll see with time. And that depends on economic conditions whether or not goes smaller et cetera, so it's really a matter of driving down the costs more so then specifically I guess what the half length is driving down the cost and monitoring performance so that we don’t loose any recovery. I don’t and what was, do you had more questions there at the end maybe I didn’t catch them all.

Ben Dell - Bernstein

Yeah, I guess the follow-up was to your point about driving down costs. If you say pressure pumping costs were coming down 40 to 50%. How much of that is being offset by an increase in complexity in terms of the fracs you're doing and number of fracs per well?

George Dunn

Well, the only difference mostly if we are going to smaller volumes we continue to reduce costs so, as much as we can do that it will actually be a cost reduction the flip side is just we have not done any significant increase in numbers of stages other than just to match whatever lateral lengths we are drilling. So, we are still pumping in the range of 4 to 600 foot intervals.

Ben Dell – Bernstein

Okay

Lee Boothby

Ben, I would say that I'm thinking about 30,000 fee here that, one of the things to remember and we’ve talked about this over the last few years. And then if you just to want to encapsulate what George said. George and his team over the course of the last year have cut our average fracs stage roughly in half. So, we are actually pumping smaller fracs today then we did in the first two years of the play. And we’re seeing the same results that we had. So, the costs savings are an added to that. And say all factors are positive relative to what’s going on there in terms of frac design and the results.

Ben Dell – Bernstein

And then just one last question if I could. What percent of your CapEx captures IDCs?

Lee Boothby

I would say that probably this year because the majority of our capital is in drilling and we don’t have the same proportion is seismic and leasehold purchase that we have and years past as probably in the 50% maybe even greater range would fall into the IDC range the bucket.

Ben Dell – Bernstein

So, you think depending on obviously, the gas price that the change in tax rules actually went through you would see maybe a 15% drop in cash flow associated with that?

Lee Boothby

Yes they would clearly be a immediate impact of cash flow and that but this concerning about the propose this industry independence in particular historically it is been more than cash flow to grow volumes and provide production in when you change the tax structure and deductibility of IDCs. It’s an immediate reduction and the sources of cash available to industry to drill wells. And you’ll introduce a lot of volatility in pricing and we don’t need more volatility than we already have.

Ben Dell – Bernstein

Okay great that’s all I had Thank you.

Operator

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

Brian Singer – Goldman Sachs

Thank you, good morning.

Lee Boothby

Hi Brian.

Brian Singer – Goldman Sachs

Most of my question have been answered, but just a couple on Monument Butte, the pick up in production that you mentioned it was due to greater demand in the region. Was that met by additional drilling or do you have production behind pipes?

Lee Boothby

The increase and that was referred to in the call by Lee. I was reference to sales we had inventory quite a bit crude upwards 550,000 barrels or so, late in the year. We’ve seen very good demand for that crude. And therefore we been drawn of a little bit of inventory as you know, and as we mentioned we backed up from a five to three rig program so, sometime later this year. We’ll actually, see that run off in inventory across with our production numbers, which today with three rigs. We were obviously we are able to drilling volume cycle like we were under five, are probably going to be in the 16 to 17,000 barrels a day range.

Brian Singer – Goldman Sachs

What oil price are, I guess what oil price, are they any signs, or what you’re looking for from a demand perspective to potential an add rigs back in the region?

Gary Packer

Well, certainly we have enough economic incentive today to add more rigs back into the system. Our returns, we’re in oily business here in the Rockies between the Williston Basin and Monument Butte. We’ve got some very strong returns, when we’re – when we – we are beyond $35 of barrel or so NYMEX, we're incentivized to put more rigs to work. So it's just a matter of us to using our capital discipline that Lee and team spoke of to direct capital this way.

Brian Singer – Goldman Sachs

Okay

Gary Packer

Certainly, we are ready for it and we can add volumes if that money is available.

Lee Boothby

And Brian I would point out that, our strong hedge position really it does give us the luxury of not responding to market conditions and the flavor of the day in a knee jerk reaction basis I mean these programs, merits a methodical planned approach to scale up and scale down and I think that, you will see us move capital and directions that make sense during the course of the year and clearly, we highlighted that attractive oil economics will get our attention. And but it’s not something that you can start and stop literally in a course of days. It takes a little bit of time to everything lined up to do it right and make sure that you maintain the efficiencies and the profitability that we want out of these projects.

Brian Singer – Goldman Sachs

Thanks that’s helpful and then lastly in the mid-continent, any contemplation of – shut in our curtailment of existing production response to your natural gas prices and differentials?

Lee Boothby

We're certainly evaluating that. I know we've talk to many of you each of our regions, has provided leadership team with their assessment, in terms of current economics and we’ve got view in terms of regional market conditions. Again we’ve highlighted that we slowdown our completion activities in the Woodford that’s in part related to response there. We’ve not made any decisions to shut production in at this point, clearly if we get to the point that economic conditions warrant a shut in and we’ll advise it at that time. This point may remain – we’re maintaining our guidance 250 to 260 Bcf for ’09 and we think that we’ve got a good plan to deliver those results.

Brian Singer – Goldman Sachs

Great, thank you.

Operator

And we will move on to our next question from John Sullivan with Olstein Capital Management.

John Daniel Sullivan, Jr – Olstein Capital Management

Hi, guys. Just a quick question on the proven reserves. The write-down, was that, is the $400 billion cubic feet equivalent is that with the write-down was associated with or is that something, we should actually be kind of looking at taking off of what we’re looking at is proven reserves. Was there some sort of add to that, where it’s really not going to be something like 2.55 trillion cubic feet now down from 2.95.

Terry Rathert

Yeah, John this is Terry. The – that the write-down in the reserves are, in some respects related but there are not – there was not direct correlation between the two. The write-down is associated with the way we go as a full costs company testing the value of our assets on the balance sheet against, the carrying value of assets on balance sheet against a SEC prescribed methodology of, how you value proved reserves, you use the point in time pricing at the period in. If the March 31, has 363 per million BTU that triggered a reduction in the present value, which triggered the full cost setting that's write-down. We’ve been under the rules that are being proposed and expected to be implemented for the end of the year that would not have occurred. The volumes that were taken off are prices related revisions you recall at the end of the year we had relatively low prices, the cost threshold and the value of a – of our essentially our longer lived proven undeveloped reserves at year end, survive very well in the sub $6 environment. We took another $2 plus out of the system at March 31. A lot of reserves that we had on undeveloped basis with a bit, with the now current cost, that how it has to be done. We didn’t make it in the 363 environment. If you raise that 363 price to $4 about 25% of those reserves or 35% of those reserves comeback a third. If you rise to 450, you get about three quarters I mean back, you bring it back to five and anyhow we almost get – you get a 100% of them back. So, it’s just a function of what is the price that your if the measurement date under the prescribed SEC methodology today. Again if we were using the methodology that’s – has been proposed neither the write-down full cost saving test write-down would occurred nor would have the reserve related price performance revisions have been effected for the quarter. So if gas prices at the end of July our $4 of those reserves comeback and if it’s $5 and they will back. So, it’s a very volatile of moving thing.

John Daniel Sullivan, Jr – Olstein Capital Management

Okay great. And just one last question, I was happy to hear that you guys are getting good demand out of the black wax crude. Any updates there on, how much or how much you guys want to comment on your customer, any updates on the acceptance there of the crude?

Lee Boothby

We’ve been operating under a series of agreements since late last year. Basically, we paying advance for crude and I would say everything is working very well out there and we prefer not to comment on any further on that. We are happy with the markets and happy with the business relationships that are in place.

John Daniel Sullivan, Jr – Olstein Capital Management

Thank you.

Operator

And we move on to our next question from [Rowan Maren] with Ruffer.

Rowan Maren – Ruffer

Hi, I notice that your guidance for second quarter actually includes higher costs and safety in terms of the first quarter is that just you’re being conservative. Or do you have some reasons to believe that your costs will actually go up?

Lee Boothby

On a unit of production basis, the lease operating expense is a little bit higher and it’s a really a function of some planned activity and things that we don’t necessarily have in hand. One of the biggest changes in the costs structure and the aggregate is production taxes. And production taxes, we project those based upon what we expect the value of crude and the production to be. Historically, we have gotten in Texas we get severance tax credits or rebates. We don’t project those because we have no clue when we will get that money back from State either on the timing bases or in quantity buying individual well. So, that frequently comes in better than what we project in guidance because we received refund but we never know when they are coming so, we don’t project that those.

Rowan Maren – Ruffer

Okay thanks, and the costs for workers is and other things. Can you give us a little more color on actually what is included in that?

Lee Boothby

Expenses for work over would be major well rework. If we had well for example that hadn't anticipated having a tubing or packer failure and then mobilize a rig to pull the tubing and it be a major non-recurring type of expenditure would be into that bucket.

Rowan Maren – Ruffer

Okay, so you don't have a specific program of enhancing existing wells in any specific area?

Lee Boothby

Generally, we have put that in the recurring or we have regular programs to go out and improved performance on existing wells. It would be the – but we think, as there is things we can’t plan for, that fall into the major work over category, because they are effectively non-recurring.

Rowan Maren – Ruffer

Thanks

Lee Boothby

We know that, generally, they recurred. They are unpredictable as to where and when and the quantity and number of activities are fall in that bucket.

Rowan Maren – Ruffer

All right, thanks a lot.

Lee Boothby

Thank you.

Operator

We will take our next question from Joe Allman with JP Morgan.

Joel Allman - JP Morgan

Yeah, thank you, good morning everybody.

Lee Boothby

Hi, Joe.

Joel Allman - JP Morgan

In the Woodford shale before you decided to defer some of these completions. What were you seeing as the cost per well and what you are seeing in terms of results per well.

Lee Boothby

George.

George Dunn

See I had to do my mute. Costs are I think similar to what we stated before and it depends on the length of the lateral that I guess on the average $5.5 to $6 million as not unreasonable then what was your next question on deferrals.

Joel Allman - JP Morgan

Just before you decided to the deferrals over the on costs drilling complete and then what kind of results, have you been seeing with the most wells?

George Dunn

The results are similar, I guess. There's no major change in that with the number of, I don’t 275 wells now and we’ve pretty much have a statistical handle on those. So performance is similar other than as we extend lateral lengths, we pick up additional rate in reserves.

Joel Allman - JP Morgan

Okay, that's helpful. And then in terms of the – the spending in the Woodfords could you give us a number like what do yo plan on spending for 2009 on Woodford? And how much of that is to hold leases?

George Dunn

Oh, very little to hold leases. And probably less than the couple of wells, we don’t – we just don’t have much of HBP that's required, so most of everything we are doing in the development mode pad-type drilling and see Woodford all in the range of $350 million buck to $400 million.

Joel Allman - JP Morgan

Gotcha. I thought recently you folks said that you were going to spend about a third of the money in the Woodford to hold leases. Did I just misunderstand that?

George Dunn

Yeah I’m not aware of that, I am not aware who said that, I guess.

Joel Allman - JP Morgan

Okay. I got it, I'll follow-up. I appreciate it. Thank you.

Lee Boothby

Thanks Joe.

Operator

And we’ll take our next question from Rehan Rashid with FBR Capital Markets.

Rehan Rashid – FBR Capital Markets & Co

Good morning. Just a couple of quick clarifying questions on the Woodford the $5.5 to $6 million that's before taking into account the service cost deflation?

Lee Boothby

George, are you still there?

George Dunn

Yeah give me that question again, I am sorry.

Lee Boothby

He is asking you clarifying question on the cost, your reference cost $5.5 million to $6 million is that before.

George Dunn

That's includes obviously some cost reductions and so going forward. As we’ve stated all of our rigs running out there on term contracts and so we haven’t seen any cost reduction in that yet so as they come off term if we keep them, and there will be cost reductions in rig rates. We have realized some of the cost savings like intangible tubulars that we expect more of that going forward. We were working on our way through inventory. So, it hasn’t been significant in our area, in the mid continent yet. So there is more costs savings we driven out of there and as we said earlier stimulations have already come off significantly and that would be in those numbers already.

Rehan Rashid - FBR Capital Markets

Okay

Lee Boothby

I would remind you that I think we are essentially back unloaded if you want to think about the second half of the year as for most of the rig activity that George is speaking of, where we come off term contracts each one of those will be decision point. So, we had a half dozen decisions that we make there. If we were in the market today chasing rigs, we would see reductions of 35 to 40% on those day rates. Clearly, we’re not going to see that happen and so we get there and we are on a back end and working out from under the oil country tubular good costs that skyrocketed in ’08. We got to work through that inventories. So, we are seeing the costs come out of the system but the first quarter is not the right place to look for the costs adjustment. We think that we will have much more clarity in terms of where we will land there in second half of the year.

Rehan Rashid - FBR Capital Markets

Okay, okay, perfect. On the cash operating front I was looking at guidance in the fourth quarter for 1Q ’09. And this is just LOE it was around $3, $4 and you guys came in that $0.85 up any kind of major drivers of that, that I need to understand?

Lee Boothby

No, I don’t think so. It’s a just a little bit of timing issues that’s why our guidance for the second quarter is more inlined with, where we were before.

Rehan Rashid - FBR Capital Markets

Okay, okay. And then for the first quarter I understand that’s working interest has gone up a little for because people were non-consent. Did you see benefit of that in the first quarter at all in terms of production or is that going to be already later on in the year?

Lee Boothby

We’re not going to see benefit in production just because of the timing. George mentioned 275 wells that we’ve drilled – drilling and we’re completed. We’ve only got 215 or 20 of those wells production at any given times in various parts of the cycle. If you want to think about that, so I would say that you probably see better visibility going forward there and it’s certainly net win. We pay our shares working, interest cost and it’s a good acquisition in our mind.

Rehan Rashid - FBR Capital Markets

Got it, but that’s going to show up later. Okay, on the deep water side any update there when is that next well going to be drilled and I think we were looking into a subsalt potential also any update on that front please?

Lee Boothby

We don’t have any updates on our deep water activity at this point.

Rehan Rashid - FBR Capital Markets

Okay, thank you.

Lee Boothby

Thank you.

Operator

And we go next question from Wei Romualdo with Stone Harbor.

Wei Romualdo – Stone Harbor.

My question has been answered, thanks.

Lee Boothby

Thank you.

Operator

We’ll move on to our next question with Brian Kuzma with Weiss Multi Strategy.

Brian Kuzma – Weiss Multi Strategy

Hi, good morning guys.

Lee Boothby

Hi Brain.

Brian Kuzma – Weiss Multi Strategy

What was your net production, out of the Woodford?

Lee Boothby

It’s about 58% of the gross numbers. So, if you take a current rate of 240 about and that’s about a $140 million today, Brain.

Brian Kuzma – Weiss Multi Strategy

Perfect, and how do you see that changing then as a kind of non-op activity? That ratio of net to growth?

Lee Boothby

For the non-op activity, it is a small percentage of our total. I mean I think that are rich non-op interest is last time I looked at it. It was something less than 10% if you want to think about it, most of our activity in the Woodford is driven by Newfield operated activity where we got 65% to 70%. Working interest in many of those wells.

Brian Kuzma – Weiss Multi-Strategy Advisors LLC

Okay.

Lee Boothby

It's our activity drives our production.

Brian Kuzma – Weiss Multi-Strategy Advisors LLC

Got it. And then, out in the Williston as you look towards year end, one rig there. Do you guys thinking keep production flat, I was wondering?

Lee Boothby

Yeah, historically and our models, would tell us, we can essentially hold it flat, with one rig and then our current budget right now is to add a second rig in 2010 to drive those numbers up. There is an exploratory nature to the program we have in 2009. So, we have some, we have certain risk applied to that. But typically with the one rig study development program we can hold it.

Brian Kuzma – Weiss Multi-Strategy Advisors LLC

And then can you guys give us anymore color on what you guys found in Malaysia at the past discovery?

Lee Boothby

We drilled the well and found about a 100 meter gas column about 50% net to gross there.

Unidentified Company Representative

Basically what I would say is that we’ve, we drilled hoping to find oil we found gas. We’ve got a working hydrocarbon system. It's a very large structure, international projects, large structure, large potential. You’re in with a chance and we’re evaluating the discovery and we are evaluating our option and there are a number of other undrilled opportunities near the vicinity. We'll have more to say about that in the future, there is a relatively recent results.

Brian Kuzma – Weiss Multi-Strategy Advisors LLC

Okay. Thanks guys.

Lee Boothby

Thank you.

Operator

And we will take our final question from Subhash Chandra with Jefferies.

Subhash Chandra – Jefferies & Company

Yeah, thanks. I wanted to make sure I'm thinking about there is a right way but if I look at mid point of your production growth is here about 8% or so. And sort of look here what you’re talking about in the Woodford representing about a fifth of the pie more or less, so Woodford growth gets you about half way to that 8% annual growth rate. If I'm thinking about correctly what’s makes up what are the areas, we will make up the balance of the annual number.

Lee Boothby

Well, I would say that, we see growth in the Rockies obviously we have advertised that we talk about our foundational growth assets, I think the pull up one of our recent presentations, you will see that we featured to the top three assets with that you’ve got growth trajectory. It’s pretty easy to see that the mid-continents with the two plays, the Mountain Front Wash play and the Woodford being the gas side of that story. And Monument Butte and now the adder being the Williston Basin is the new kid on the block, they're providing the growth in the oil story. They are getting the largest share of the pie from the capital budget that’s the growth driver. We’ve got growth in our Gulf of Mexico baked in that’s a ‘10, ‘11, ‘12 type. Growth trajectory from projects that are under development elsewhere, we are holding our own and the Gulf Coast onshore, we focused on delivering production and generating cash there. I would say that foundational growth assets for the drivers and incremental projects are the adders.

Subash Chandra – Jeffries & Company

And then I guess your clarification because I guess it was a bit confused on, because in the Bakken, you referenced keep production flat with that one rig and then in Monument Butte I think you said that you would have fairly modest growth with the three rig program and as you sort of destock your inventories, maybe in the back half of this year. You will actually see some sequential declines. Did I, what am I missing there?

Lee Boothby

Well, first of all I didn’t mentioned international. We’ve got growth year-over-year with our Malaysian position that’s been discussed previously so that’s part of the growth story as well. I believe remembering the quote there relative to the statement of Monument Butte, it was nominal/modest growth for the three rig program and we’ve got the ability to add rigs there and that’s going to get consideration just year end falls and the Williston basin, if we can hold our own at one rig as Gary mentioned and we’ve got the option of adding rigs there as well. So, I would tell you that it’s driven by foundational growth assets. It’s not too hard to understand and probably if you give Steve a shout after the call he can give you the additional details that you might want to get you home.

Subash Chandra – Jeffries & Company

All right, thank you.

Lee Boothby

Okay.

Operator

And that concludes the question-and-answer session today. At this time, Mr. Boothby, I will turn the conference back over to you, for any additional or closing remarks.

Lee Boothby

Well, I guess, I just to close by thanking David for the opportunity to handle the call today. I appreciate his faith and conference in that regard. And as always, we thank you for your interest in Newfield. And we look forward to updating you on additional successes as the years unfold. Thank you.

Operator

And that does conclude today’s presentation. Ladies and gentlemen, thank you for attending.

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