Newfield Exploration Company Q2 2009 Earnings Call Transcript

Newfield Exploration Company (NFX)

Q2 2009 Earnings Call Transcript

July 23, 2009 9:30 am ET

Executives

Lee Boothby – President and CEO

Gary Packer – EVP and COO

Terry Rathert – EVP and CFO

Jim Addison [ph]

Analysts

Ben Dell – Bernstein

Amir Arif – Stifel Nicolaus

Brian Singer – Goldman Sachs

Dave Heikkinen – Tudor Pickering & Co

Subash Chandra – Jefferies & Company

Joe Allman – J.P. Morgan

David Kistler – Simmons & Company International

Joseph Magner – Tristone Capital Inc

Rehan Rashid – FBR Capital Markets

David Tameron – Wells Fargo Securities

Shannon Nome – Macquarie Capital

Presentation

Operator

Good day everyone and welcome to the Newfield Exploration's Second 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 and Chief Executive Officer Mr. Lee Boothby Please go ahead, sir.

Lee Boothby

Good morning and welcome to our second quarter conference call. Thanks for joining us today. These are certainly interesting times. But what I'm certain you will hear in our brief remarks today is that we are excelling in this environment and we get multiple options as we prepare to enter 2010, and very importantly we are financially strong, strategically well positioned and growing.

I’m joined in Houston, this morning by the members of our Leadership Team including Gary Packer, Chief Operating Officer, Terry Rathert, our Chief Financial Officer, Bill Snyder, who leads our International and Texas – Gulf Coast business units; John Jasek who runs our Gulf of Mexico business; of course Steve Campbell, Investor Relations, and Brian Rickmers. We also have our Tulsa and Denver offices connected.

Like most of her recent calls, we’ll keep today's call short focusing most of our time on the Granite Wash, most recent in a series of successes for Newfield in 2009. Our three main objectives for today's call is follows. First I’ll will discuss how we are approaching the back half of 2009 and offer a few insights into 2010. You will see that our diverse portfolio of assets and our strong hedge positions provide us with multiple options going forward.

Second, we will provide some brief operational updates from the deep water Gulf of Mexico and the Woodford. And the third as I said earlier, we will spend the balance of our time discussing our recent successes in the Granite Wash and what this Newfield development plan means to us going forward.

As always we have plenty of time to answer any off your questions at the end of the call. So let's get started with the 2009/2010 forward planning.

When you look at 2009 to date and think about our plans for the second half of the year, at the start of the fact we produced 127 Bcf in the first half in line with our beginning of year guidance. For the year, we fully expect to be in the upper half of our 2009 target range and for reference 2009 guidance was 250 Bcf to 260 Bcf equivalent.

All of this while continuing to defer completions in the Woodford as well as on the reminder of our planned wells in the Granite Wash in the second half of this year. We certainly understand the importance of producing our targeted volumes, but we want to be smart in how we do it.

We will be a prudent operator. We’ll continue to look forward to our cash returns and I feel great about where we are headed in the second half of ‘09 and for that matter 2010 and 2011. Teams are doing an excellent job of lowering operating cost around the Company and maximizing our returns.

Capital budget remains $1.45 billion for 2009 and we fully expect to live within our cash flow. Through June 30, we had invested $669 million. To cut the material cost reductions and changes in allocation by business units, we have been able to add in some new projects in this year's budget while still living within it.

Improvements in our leased operating expenses goes straight to the bottom line, improve our margins and our discretionary cash flow. Cost reductions are apparent throughout our business units and coupled with our hedges allowing us to maintain solid profit margins in today's environment.

Gary, Terry and I are spending a great deal of our time today on capital and resource allocation really scrutinizing to how and to where we are allocating our capital and more importantly our people. This analysis is driving our plans for the second half of this year and for 2010.

Let me share some examples and we’ll start with Woodford. In the Woodford, we continue to improve our operating performance. We have a detailed update for you in today's NFX Publication. To quickly summarize, we are still moving to longer laterals. We have predominantly pad drilling game plan for 2009 while continue to benefit from fallen service cost, a secured recipe for continued deficiency gains and improved returns.

Importantly, since our acreage is now almost entirely held by production, we have got lots of options because we control the pace and timing of development. Since beginning of the year, we have got three rigs in the Woodford, that's term contracts have expired. Today we are running 10 operated rigs and four of those 10 rigs have term contracts expiring in the second half of 2009.

Despite a slower pace of activity in the Woodford, year to date, our production from the Mid-Continent is ahead of plan primarily due to the strength of the Granite Wash combined with the our ability to maintain Woodford production year to date with pure operated rigs.

These high rig Granite Wash will also be referenced to allowing us to exceed beginning of the year forecast in the Mid-Con while drilling at completer – completing fewer wells. We are also looking for ways to emphasize the oily side of our portfolio and we have got a number of options here as well.

Our oil growth will come from offshore in Malaysia, Monument Butte in the Uinta Basin. Our Malaysian production in the second quarter was up 75% over last year and we have attractive options available to add additional barrels in 2010.

You will notice in our third quarter guidance, we are taking our Malaysian oil production rate higher yet again reflecting our continued projection for stronger than budgeted performance and barrels that where not lifted in the second quarter. Second quarter production in Malaysia was up 80% over the prior period in 2008, and for the year we expect it will be more than 30% over last year.

In the South China Sea, we found a rig in the second quarter and initiated appraisal drilling follow-up on our 2008 Pearl River Mouth Basin oil discovery. The well is [Inaudible] and we are in the process of testing it now. Drilling oil appraisal wells is another example of the project that was not in our original 2009 budget but we made it there. Prior to end of ‘08 and the pullback in oil prices, you'll recall that we are running five-rig program in Monument Butte. We have maintained production year-to-date for a 3-rig program and the strength of the crude markets has allowed us to sell additional barrels from field inventory.

We will be picking up a fourth rig in the third quarter which will once again – Monument Butte in the second half of the year. An example of refinery demand you take this crude today and differentials are currently running about $12 a barrel, and please remember that that includes transportation.

The addition of fourth rig in Monument Butte is another example of a project that was not included in our original 2009 budget. Another oil asset for us is the Williston Basin and we continue to enjoy success there. Our most recent Bakken and Sanish/Three Forks wells have come online at about 1200 barrels equivalent per day, as the complete list of these wells both the IPs and 30-well production averages in our NFX Publication.

Current plan is to add one rig in the Williston Basin early in 2010, plus we have inventories of about 70 development drilling locations in the Williston Basin and our inventory continues to grow with each new drilling success. What I hope is apparent today is that Newfield has lots of options, a rich and diversed asset portfolio is a huge positive for us today. We are diligently focusing on making the right decisions that will allow us not only to survive these challenging times but to thrive moving into 2010 and beyond.

We are consciously making daily tweaks to ensure the capital continues to flow to the best possible projects. We expect to be in a very solid position as we exit 2009 and enter 2010 because we have 70% of our national gas production in 2010 at an average price of more than $6.50 per million and 40% of our oil and more than $100 per barrel. We have good visibility on our cash flow forecast. Even with a lower capital budget in 2010, we are confident that our portfolio will be able to deliver 5% to 10% production growth within cash flow, highlights the position that we are in today.

Quickly on financials, I'll make a couple of comments regarding the second quarter. Earnings before FAS 133, adjustments where $1.28 per share. Our production in the quarter was about 65 Bcf equivalent, an increase of 12% over the first quarter 2008 levels. It is important to note that our Malaysian production does not include about 170,000 net barrels of inventory that will be lifted in the third quarter.

Due in large measure to superlative performance of our operating personnel, our costs and expenses were well below our guidance ranges in most categories. Our recurring LOE came in under budget and it continues to fall throughout our operations. It's about $15 million lower than guidance or about $0.25 per Mcf equivalent. To reference, that's a 30% reduction in LOE per Mcf equivalent since the fourth quarter of 2008. Again hats off to our team really working hard to lower the cost and improve our returns.

If you have questions on the financials, Terry Rathert, our CFO will be happy to take them at the end of the call.

Let's move on to some quick operational updates before focusing on Granite Wash. Our recent Pyrenees discovery in the deep water Gulf of Mexico was a significant second quarter highlight for Newfield. We agreed with our partners that this discovery warranted investment to delineate. Early July, we contracted a deep water rig that became available and are now drilling a side track to better delineate both the proven reservoirs and to test steeper potential that we were unable to see in our original well.

We hope to have results before Labor Day. This is another example of a significant project that we where able to include in this year's budget without raising total CapEx. We have an 11-block continuous area around our Pyrenees discovery. This complex also includes our 2008 discovery in Sargent and two significant prospects ticked up in the most recent lease, Mastiff and Saluki. These prospects each have 200 billion to 400 billion cubic feet equivalent reserve potential. We get an 85% interest in one and 100% interest in the other.

It’s our intention to sell down our interest on a promoter basis much like we did in Pyrenees where we had a 5% interest in exploration well and maintained a 40% working interest in the development. It's important that we assess this complex quickly as it will determine if we have a sub-sea development to existing infrastructure or multiple wells that will support a standalone development. We look forward to reporting our progress in this regard over the coming months.

In the Woodford, we are well underway with full field development. We drilled more than 280 horizontal wells to date and have held more than 90% of acreage by production. We continue to optimize how we are drilling and completing wells. Nearly all of our wells will be drilled from common tabs (ph) and we have observed nearly 50% reduction in drilling case cost per lateral foot from the first well drilled on our section to the eighth.

Due to the favorable regulatory environment, Oklahoma we continue to push lateral lines longer. Although we expect lateral lines to average about 5000 feet this year, we have two wells drilling today with 10,000 foot lateral lines and we have a number of other wells planned with laterals of 6500 feet to 8000 feet.

So far our data shows improved recoveries and efficiencies through longer laterals. As you know our drilling depths in the Woodford varied from north to south by more than 3000 feet. With efficiency improvements today and lower completion costs, we are able to drill and complete a 5000 foot lateral well from a pad in our core development areas of the North within $5.56 million. When you compare this to last September, we’ve added 1000 feet of additional lateral, two flat stages and nearly 1Bcf equivalent of incremental reserves for the same total cost.

Keep in mind that all of our rigs are under termed contract. If we read drilling these wells at spot rate today, they would be about $300,000 plus per well. To further show efficiency improvements, we are now able to drill in case of 5000 foot lateral in about 30 days. This is the same amount of time that it took us to drill in case of a 2500 foot lateral back in 2006. We are also stepping into these far southern portion of our acreage. Wells there can cost up to $2 million to $4 million more, the first wells in a section. But they are offset by significantly higher EORs likewise 30% to 40% higher.

Presently looking at about $2 FOD before rig rate adjustment in that region. Many of the wells this year bring the first well in the section don't allow us to recognize full development mode savings down in the south. But I'm confident that these estimates will come down with more experience just as they have done in the northern core development area.

In spite a lesser rig count, in the Woodford, we’ve maintained production at about 240 million cubic feet a day gross here to-date. And we have significant future production associated with our deferred completions inventory.

Last week, we commenced production in the Mid-Continent Express pipeline. This is a very significant milestone for our Woodford development. For 2009, we now have 350,000,000 million cubic feet equivalent per day. Our firm transportation capacity from the Arkoma Basin and we have the greenness in place to move that number to 650,000,000 million cubic feet staged annually through 2012 to match our future growth. This helps ensure that we will get best possible pricing for our Woodford gas resource.

Now let's move to the Granite Wash. We issued a separate news release last night detailing our seventh recent drilling successes in the Granite Wash. We have being active in the area since 2002 when we gained our initial interest through the acquisition of EEX Corporation. We have to admit we assumed a little value to this asset in the EEX transaction. Our knowledge in unconventional resources and pipe gas has certainly come a long way over the last seven years.

Granite Wash is a material play covering an area some 20 miles wide and nearly a 100 miles long, expansion of Texas Panhandle to the south southeast into Oklahoma. Our efforts have been focused primarily in the Stiles Ranch areas, which is just west of the Texas Oklahoma border in Wheeler County.

Our early efforts in this field are focused entirely on vertical drilling. In fact, we drilled nearly 150 vertical wells across the Stiles Ranch area and the vertical drilling took production from 3 million cubic feet a day back in 2002 to up over 90 million cubic feet a day midyear 2008. The Granite Wash has stacked sand deposits comprising of gas charged sediment column more than 3000 feet thick. They have four main geologic horizons and we divide our targets into more than 30 distinct productive zones occurring from above 12,000 feet to below 15,000 feet, all of which produce gas in our vertical drilling program.

Some of these zones are more than 100 feet thick. Both Newfield and the industry have come a long way in the application of horizontal drilling and completion technology in the last few years. Our experience in the Woodford got us to try horizontal drilling Stiles late in the year of 2008. One of the key challenges evolved around the ability to drill and complete cost effective horizontals at these depths.

You can see from last night's news release, where we have some pretty impressive results to date. Our first seven wells reached initial production rates of 22 million cubic feet equivalent per day. We are very encouraged by the way these wells are producing and the implications that the product data have on our unit cost, project returns, reserve recoveries and production growth profiles looking forward.

It is important to note that several of our wells also have very strong production which is providing a further uplift to our economics. We have a good understanding of which specific targets are likely to contain liquids and we are designing our drilling program accordingly. Our production from the Granite Wash has seen raise as high as 147 million cubic feet per day earlier this year. The largest contributor in this division is Stiles Ranch Field. Stiles is currently producing 112 million cubic feet equivalent per day.

As I mentioned earlier we have been shifting capital around to ensure that we are funding the best opportunities. With the results we have achieved in the first half of 2009, the Granite Wash is moving toward the top of the list. There are three operating rigs running in the field today. We moved at a rig from our South Texas drilling program up to the Granite Wash. To simply state it, the play has lower risk, has superior economics and we have significant running room. Expect to run a three rig program for the remainder of 2009 and drill about 14 wells this year.

Post-drilling completion cost in the Granite Wash to date with the horizontal wells have averaged about $10 million per well. The well that we just completed and returned to sales this week is drilled and completed for $7.5 million. So, we are already making some progress. I'm confident that our costs will continue to decrease with more experience. To date, the longest lateral we drilled in about 4000 feet. We will be experimenting with the longer laterals in the second half of this year, again applying a learning curve derived from Woodford.

Our technical teams in the Mid-Continent are working hard now to determine our optimal path forward. We have a drilling inventory in the field today that should allow us to run 3 to 5 operated rigs for the next several years. Technical challenges that accurately determine how many commercial horizontal locations we have in the field’s interior. Remember, we have already drilled 150 vertical wells. This work is ongoing but for now we have a deep inventory to drill and complete wells over the next several years and the inventory is growing. This inventory will allow us great development results and will help us grow production in 2010, 2011 and beyond.

As in the Woodford and Monument Butte, we control the timing of product development and its resources. We have about 35,000 prospective acres for horizontal at Granite Wash and about 80% of that is held by production.

In closing, I hope you sign off today's quote with a greater appreciation for options that our portfolio and assets provide us today. Our production growth is strong. But more important and just focusing on the quarter is understanding that our assets will allow for future growth as well. All of our people are focused and doing the right things today that will improve efficiencies while positioning us for success in the future. It is imperative that we find the right projects at the right time and we staff them with the best people.

I can assure you that Garry, Terry and I and the rest of the leadership team are spending a lot of time on this each and every day. Thanks for your time today and your investments in our Company. The entire management team is now happy to entertain any question that you might have. Operator?

Question-and-Answer Session

Operator

Thank you. (Operator instructions). We will turn first to Ben Dell with Bernstein.

Ben Dell – Bernstein

Hi, guys.

Lee Boothby

Good morning

Ben Dell – Bernstein

I have two quick questions. The first is around your Malaysian assets. Obviously, the economics in those are fairly good right now as production ramps up. Have you given any consideration to selling down those assets and taking that cap through and redeploying in the US where arguably you have a better long-term growth potential?

Lee Boothby

Well, I think if you study Newfield’s history over the last five years, you'll see that we made some very significant steps to reposition the Company in terms of the portfolio, most notably 2007 sale of our Shelf Gulf of Mexico assets, sale of our UK business, and sale of our Mid-Con CBM business. That capital was repositioned into our core foundational growth assets in the Mid-Continent and the Rockies. I would tell you our Malaysian assets, we’ve got a great team there in Malaysia. I was there back in May. We have got 110 people on the ground in KL. We've got a growing development inventory there. It's oil. It’s Southeast Asia. We've got a great team. It's been on the ground there for five years. We had exploration success out on Block 2C which we talked about the last call. We like the business. Again it's about oil in Southeast Asia. It's an important part of the portfolio and it’s growing. And we have no plans to market those assets. Having said that, our history says that if times are right and for the right price, it’s all about value and we continue to be about value. And I think that history of the decisions we made give you some indication of the size of things that we will consider prospectively.

Ben Dell – Bernstein

Okay. And just secondly, obviously your drilling costs are coming down and your average well performance seems to be improving. Do you have a feel for what your year end level will be and associated with that what sort of changes you will see in your reserve business associated with the new reserve rule changes?

Lee Boothby

I think it is too early for us to comment on either of those items but probably the SEC reserve will change. It's going to be significant for the industry. Investors [Inaudible] heading that effort for us internally. It's got its team deployed and are well positioned to be able to implement those plans but it's too early to speak to either of those items at this point in 2009.

Ben Dell – Bernstein

Okay. Great. Thank you.

Operator

Next we will turn to Amir Arif with Stifel Nicolaus

Amir Arif – Stifel Nicolaus

Hi, good morning guys. Congratulations on a great quarter. Few questions, first of all, on the Granite Wash, the two wells that you did provide 60-day rates, one was higher in one was lower. Is that just a well streaming up or are you just completing this – is there a bottleneck out there?

Lee Boothby

I would tell you that, clearly each of those have slightly different production rates. We had 22 million a day average. But first of all, average is well north of 30 million cubic feet a day in terms of IPs and so 60-day average is about 27 million cubic feet per day. That's an outstanding well. You know, we have been in the Mid-Continent since 2001. And that’s far innovative best well that we drilled out there in all those years. I would tell you that we have tested – but I didn't make a point out in the call. We do have 30 individual zones that we think are perspective underneath the Stiles Ranch Field. We drilled seven, drilled and completed seven wells to date. They are producing from three different intervals. So they are not all drilled and completed same section in the Granite Wash. and each one of those reservoir sections have slightly different reservoir characteristics. But we would expect to see variation between individual wells, but I would tell you that we are very, very excited about early returns there and our experience 150 vertical wells and all the technical data that comes with that logging, production log etcetera really put us in a super position to exploit that field successfully in the years ahead. Very excited.

Amir Arif – Stifel Nicolaus

Okay. And then is there a reason we don't have 60 days production data for some of the other wells?

Lee Boothby

We have operational considerations when we are drilling and completing horizontal wells. There are methodologies that are well established led initially by the Barnett Shale. We use them in the Woodford. We shut in, offset wells during completion mode with wells in the near. That's a portion of the production variance that we’ve had with regard to month-to-month type comparisons. And I would just caution everybody to be careful looking at monthly totals. It's related operational completions decisions within the field. There is plenty of up tick capacity in the region. We have been building that over the last several years.

Amir Arif – Stifel Nicolaus

okay. That sounds good. And the second question in terms of the 25 wells you’ve drilled but haven't completed. Behind the cash returns or what kind of gas prices do you need before you decide to start bringing these wells back on?

Lee Boothby

We talked about in the last call – I want to go back to some of the statements that we made. We made a decision to defer the completions and I will remind you that when we entered 2009, most of our rigs was under term contracts. We had to carry inventory fast in from 2008 service cost and equipment specifically [Inaudible] it's a good example. We got to work through those costs as the year unfolds and we are not going to get the full benefits of those cost savings until we get out from those contracts and get fully positioned with the current and prospective service cost environment. As far as the pricing environments, each one of our areas has different issues with regard to differentials and prevailing product prices. We’ve actually seen an increase if you will quarter over quarter and quarter end natural gas prices substantially hedged. We’ve got plenty of flexibility there. Most of our decisions are related to operational consideration and our commitment to position our capital investment on the best projects and deliver cash 2009/2010.

Amir Arif – Stifel Nicolaus

Okay. Sounds good. Just one final question if I might. Outside of efficiency gains that you're seeing which seems to be terrific, are you still looking for service cost that decrease further from current levels outside of –?

Lee Boothby

I’ll let Gary Packer talk about this.

Gary Packer

We have seen approximately 20% reduction in our cost. It varies area to area from the peak that we saw back in September. Naturally it's going to depend on what the commodity price environment is. Looking forward and how much more is going come out of the system. I suspect there is probably 10% left to be removed from the system, looking forward.

Amir Arif – Stifel Nicolaus

Sounds great. Thanks guys.

Gary Packer

Thank you.

Operator

We will turn now to Brian Singer with Goldman Sachs

Brian Singer – Goldman Sachs

Thank you. Good morning.

Lee Boothby

God morning, Brain

Brian Singer – Goldman Sachs

Back to Granite Wash. What you are – as the decline rates you are expecting their overall. And I guess can you provide a little more color, within your acreage whether you expect the results that you're seeing so far can be representative of future wells or whether you think you packed into more unique sweet spots within your acreage?

Lee Boothby

I would tell you that given the early nature of the production, it is too early to comment and – you can take it as a general statement but when you got 30 day and 60 day averages that give you 10 million, 15 million, 20 million a day type pipe rate. Those are strong wells in these resources plays. You know as well as I do how to translate that to EOR estimates. I would tell you that all I would say about EOR estimates in the first seven wells that our EOR estimate exceed 8 Bcf average.

Brian Singer – Goldman Sachs

Okay. Thanks. That's helpful. What about the represented, whether you think these wells are representative of future wells or I guess the variability has been within the year?

Lee Boothby

I said I expect to see variability within the individual zones. I think that the thing we are very excited about is that we drilled on east side of the field. We drilled on the west side of the field. We drilled on the north side of the field, and we drilled in three of 30 individual zones. So you're already getting a statistical sample of the acreage block. Clearly, as with any resource play, irrespective or any play for that matter, – that's what people tell you. There are going to be variabilities. There will be edges. But I would remind you – and I say it I think for the third time today, we have 150 vertical producing wells, and the production rate including an inventory of production wells could have been the envy of any reservoir engineers dream if you're going to try to evaluate field like this. So, we got all the data we need to be able to choose wisely with regard to individual zones and we have been absolutely amazed at the results achieved today. That's probably the best way to put it. Amazed, excited and super excited about the future there.

Brian Singer – Goldman Sachs

Okay. Thanks. And I guess last question on the Granite Wash specifically. How prevalent do you see liquids you mentioned you feel like you are on top of where you had high liquid wealth could be. What is driving that variability and how dominant do you think you will see liquid across acreage?

Lee Boothby

I’ll let Gary talk about it.

Gary Packer

Yes, the liquids are pretty much confined at the geologic inner well that we are currently completing in. As we referenced, we are completing thus far in two different instruments within the sections. We see those to be rather rich in driving some of the high equivalent rates. It's been reported there’s another inner well, the Atoka much as we have anticipated from a vertical production is quite a bit –.

Brian Singer – Goldman Sachs

Okay.

Lee Boothby

And with that information you can look through the release and probably figure out where the wells are.

Brian Singer – Goldman Sachs

Yes. Thank you very much.

Lee Boothby

Sure. Thank you.

Operator

Next is Dave Heikkinen [ph] with Tudor Pickering & Co.

Dave Heikkinen – Tudor Pickering & Co

Good morning guys. Taking through longer-term as rig roll off contract and how do you think about the ability to contract at half the day rate, do you double rig count – or you just locked in a lower day rate in each of these plays as you define them over time?

Lee Boothby

All right. I'll make sure I understand your question before we answer it.

Dave Heikkinen – Tudor Pickering & Co

Day rates are declining, when do you think about terming out contracts and as the lower-term contract mean you increased activity levels and drill more wells for the same dollars?

Lee Boothby

First on the term contract, obviously as a term contract won the term and we get four of the 10 wells in the Woodford that are going to come off-term contracts, we are now at the end of the year. We'll have an opportunity with each of those rigs to re-contract which is that the market price. I haven't seen or heard anything that looks like 50%. At this point, I would tell you that we have been expecting based on following the stock market, you might see 30, 35 ish percent reductions that are out there today. It's all going to depend on the market conditions at the time. With regard to activity, I would simply restate that we are committed as a leadership team to live within cash flow. So we will be shifting capital around the portfolio and we’ll be living within cash flow. So, to the extent that any of those decisions fit that criteria they would be considered.

Dave Heikkinen – Tudor Pickering & Co

Okay. And then on the bigger picture 30% or so oil as a direct more activity towards the oil, does the move up 5%. Can you – how much can you shift the overall portfolio to towards oil over 12 months, 18 months timeframe?

Gary Packer

Yes, that a – this is Gary speaking. That's a pretty big needle for us to move, to move at 5% to 10% near term. I would tell you, it’s alluded to – we have been doing – really walking the capital allocations quite a bit. And much of the money that we’ve moved around the last few weeks as it affects 2010 and the balance of 2009, I would say those investment decisions are probably bringing on incremental 50% to 70% oil versus gas. But still it is hard to move the number much. 35% would probably be on the high side.

Dave Heikkinen – Tudor Pickering & Co

Okay. That’s good. Thanks. And as you kind of get into the Granite Wash and you are doing field studies, I think that's pretty important to understand and that's in your defined fields, your acreage isn't drilled. I mean do you separate those as far as how you think about development, you include some exploration I guess wells as well. How does that play into the overall appraisal process?

Lee Boothby

I think I was careful to state. Obviously I meant to you in the course of the call that our team is working in the team in Mid-Continent is working hard to optimize in terms of the forward plan. Fairly the sections that don't have wells would be riskier than sections that we've got oil control. But having said that, we know for well that all of the acreage that we are talking about is within the productive Granite Wash. So, we are not confident with that. We’ll work a plan up. We like the options that we got right now in development, but clearly at some point in time we'll be testing the non-producing acreage as well.

Dave Heikkinen – Tudor Pickering & Co

And at the end of the year, just make sure that what you right, really I think you'll drill [Inaudible] wells but probably don't complete those until gas prices improve. Maybe compete a little bit – I guess if you have more liquid contents – but don't expect a big growth of completions between now and year end, gas price?

Lee Boothby

We are managing in the budget criteria that the referenced. I think the decisions on when to complete those wells would be left to Gary Packer, our business unit leaders and operating teams. There are a lot of issues to consider. We want to have and maintain healthy service sector, so we are going to maintain activities in our core areas and work with our service providers and partners that keep the crews and equipment working. That's good for everybody to the fullest extent possible. Likewise we are going to choose the time we believe is optimal to complete those wells where we got service cost and that the production is meaningful relative to our game plan.

Dave Heikkinen – Tudor Pickering & Co

All right. Thanks.

Operator

We’ll turn now to Subash Chandra with Jefferies.

Subash Chandra – Jefferies

Yes. Good morning. First question in the – have you tried – what sort of the average track stages and have you tried some of the [Inaudible] multi stage, 20 stage, 25 stages and do you think might –?

Lee Boothby

Yes. To this point typical track stages have been in the neighborhood of 500. Therefore, we are typically drilling 4000 foot to 5000 foot laterals which put us at 10 stages or so. So we have drilled more extended laterals and those are more of the exception in the rule. We are looking at and have experienced – experimented with many of the small stages – small as 300 feet with success and we have not to date but looking at it some of the more [Inaudible].

Subash Chandra – Jefferies

Okay. Great, great. And Granite Wash just thinking about this the right way, you referenced reserve potential in Stiles Range over the years somewhere about half – that includes I suspect a big chunk of that maybe half of the potential was vertical locations. And so with the horizontal program I suspect you totally displaced the vertical locations. So, what do you think the net change is in the Stiles Range resource potential?

Lee Boothby

Yes. I would say that, all I want to say at this point is the net change is a small and upward positive. But that's probably all you need to know about that. I think this is a strong positive incremental for Newfield and Stiles Ranch, Mid-Con and business units.

Subash Chandra – Jefferies

Great. And so – in sort of comparing horizontal/vertical program, the verticals is sort of 3D wells, and where you – did you get to 40 acres in the vertical program?

Lee Boothby

We got to 40 acres in a few portions of the field, not to 40 acres but to the entirety of the feed. As far as the vertical well, really they improved from the early days, when the 3ish Bcf type number that you referenced would have been probably a little good number. I think when our folks were walking and rolling in 2008 for Mid-Con business units in all horizontal program and in the area, they were routinely bringing vertical wells on line at 5 million cubic feet, 6 million cubic feet a day and those wells had reserve realization 3.5 Bcf, 4Bcf type numbers. So, production there is well established. As I've said I think three, four times, we know a lot about the fields, we know a lot about the reservoirs, and yet learned a lot as the industry has told the last several years on how to drill and complete. And I don't make this sound too simple, one of the issues that we managed beyond just capital living within cash flow is a. We are trying to do our part not to exacerbate the oversupply conditions, and b. We are very sensitive to not over-stressing our organization. I think level loading being smart about how to run your business, batting for average and maintaining momentum are keys, and those are all part of our decision making each and every day.

Subash Chandra – Jefferies

Understood. Want to make sure, looking at the right numbers here for apples to apples, when we talk about styles ranch and you referred at 150 a day were sort of a peak rate out there and may be in Q4 is 130, now running on 112. Is that – is it – what’s going on there, the capacity additions, base decline. And so what this – I guess is our theoretic limit 150, which is the capacity therefore?

Lee Boothby

First of all I think, it might be just the way we just started or how we talked about. Like I think you’ve got apples and oranges in your numbers. Number one, we talked about [Inaudible] district. So, we have a field office in city Oklahoma and handles all the production in that region. Generally when we talk about [Inaudible] production, we talk about it in total out of that district. So there 100 million cubic foot type number that would represent our current deliverability capacity, production capacity out of that region in [Inaudible] Wash. It’s just that. The 112 million cubic feet per day you referenced is specific to the to the styles ranch field. And I mentioned earlier that when we are completing wells, we have a standard procedure and protocol on shutting in the offset produces.

So if you drill a horizontal well, vertical well or any other well for that matter addition to existing producing wells, resource place we shut the offset wells in a period of time so that we don't lose all of the energy to the completed portion of the volume associated with the offset wells. It's just marked business. And some we do in the Woodford, some we do in the [Inaudible], it’s common practice in all places.

So that induces, and one thing in terms of the very early production when you are shutting down some of these big wells. In terms of the infrastructure, we’ve continued to expand the infrastructure in that region from the very early days when we started drilling, and the also have a relationship that carried from Oklahoma ranch from the northwest. – active out in the area and we got a good relationship with them and they are writing infrastructure into the region as well. So, we don't have any update issues, and if you do have them that will be relatively short-term events. Let me let me get Gary add some additional color on that.

Gary Packer

Yes. Couple of comments. I guess few people have referenced uptick here. We've got a lot of flexibility, previously reported on the firm take away out of the Mid Continent Express and we stack with [Inaudible] 650 million a day. Currently, that gas is not moving from Stales or 3-D systems. We have good access up to four different pipelines on the west side in Texas. We can access [Inaudible]. So we have got pretty favorable differentials on the system today. We just have a lot of options that enable us as we move forward.

Subash Chandra – Jefferies

So, apples to apples, fair to say that Stiles Ranch last several quarters production might be up 30%, 40%?

Lee Boothby

You broke up the question. Could you repeat that?

Subash Chandra – Jefferies

Yes, sure. Apples to apples, fair to say that Stiles Ranch production is up 30% to 40% over the last several quarters?

Gary Packer

Yes. It's going to be pretty lumpy as we move forward. As we’ve already referenced, we bring a number of these wells on and then we start to amend as we go ahead and drill the offset. So it's pretty hard to say 30%, 40%. At any one time that may be the case, but as we have already seen it's going to decline quite a bit at times as we shut wells in. You can reference the facts included that is a production process that shows the production from this area and it illustrates exactly on top of it.

Subash Chandra – Jefferies

Right. Thank you. And just last one, there is derivative talk in the elimination of the OTC market or regulation. Any thought on how that changes, how you hedge, and if you think it's more smoke than fire at the moment?

Lee Boothby

[Inaudible].will take that one..

Gary Packer

I think it's very serious concern for the ENT (ph) community. The way it has been proposed and you have exchange contracts isn't as this concerning as fact it has – . So, yes if we had post lateral in our current arrangements with all of our – I think it was rightly hedged. And we have the underlying assets, and the fact we produce less quantity of gas that provide support for counter parties if they don't view us in the context of being a risk or a speculative – having a relationship with us. So if we have to collateralize that, then there would be a huge change. And a good example, if you look at the change in our position and this is just what we call in-house – disclosed and financial segment as fair value. So that kind of lump sum of all the positions put together. And between the end of the first quarter in 2008, the end of the year, our position changed in fair value by more than almost $1.5 billion.

So if you can imagine reserving liquidity or capacity to be able post lateral and the amount like that if it were to slip back the other way because you don't get a net position and the actual changes in the liability side can easily be greater. Then it would basically take that risk management tool away from us, as a Company and I think away from the ENP community as an industry. So it is something that’s grave concern. Next week I'm going to be in Washington where the ranking members of the House [Inaudible] committee, talking about just this issue, potentially spend more time there trying to make sure that the unintending consequences of the legislation that's being proposed clearly understood. Our industry as well as many other industries will be very adversely affected by it, and [Inaudible]

.

Subash Chandra – Jefferies

Great. Congrats on the great year.

Gary Packer

Thanks.

Operator

Next we will turn to Joe Allman – J.P. Morgan.

Joe Allman – J.P. Morgan

Yes. Thank you. Good morning everybody.

Terry Rathert

Good morning, Joe.

Joe Allman – J.P. Morgan

Could you help us think about the spacing and [Inaudible]. How should we think about that?

Terry Rathert

You mean like ultimate spacing or –?

Joe Allman – J.P. Morgan

Yes, ultimate spacing and also the seven wells that you drilled horizontally, how close to the ones that are closest to each other?

Terry Rathert

I can give you a real quick example. When you look at the – and this is just we are at, remember we were only here. So we got to say modeling and performance, size, – horizontal wells as we’ve done – the same work out in Styles Ranch. There are three wells on the list. In the wells, those three wells, all drilled in the same section. So, that the horizontal wells in that section. So we tell you at this point, tells you, tell us that – we think that it’s safe and reasonable approach. I can't tell you what the optimal spacing is going to be, we talked about the – 660 foot lateral in our opinion. It's too early for us to what that answer is. [Inaudible]. Three wells per section doesn’t scare me. – is a bigger issue. I think when you think about sections, I like to think about Stiles Ranch in terms of how to relate it to other resource play, we talk about 30 individual rounds, and a 20,000 net acre position. You should think about the ultimate potential being something like 30 times that acreage footprint. So, and I think it's much other than that because the infrastructure is in place, just displaying the vertical section. And obviously you want to risk that in terms of the well – maybe all 30 of them work, but if 10 of those work, 10 times 20,000 acres is 200,000 acres. I think that's pretty exciting math in my view. It is helpful. And so I mean, so potentially you could be doing a dual lateral, I mean do more than I thought, but –

Terry Rathert

We have got a lot of work to do to figure out exactly what the optimum mechanical hardware configuration is and the offset, I mean, we want to enjoy the seven wells of 22 million a day for a well before we get going of advancing, but we will be working on at the second half and we will tell you just as soon as we got a position in those areas.

Joe Allman – J.P. Morgan

So there are 150 vertical well, it doesn’t preclude you from going into the same sections and drilling horizontal wells where there is vertical wells are producing from, is that right?

Terry Rathert

It does not.

Joe Allman – J.P. Morgan

Okay. That is helpful. What, you know your results appear to be better than most other operators; do you think it is geology or is it technique, can you address that somewhat?

Terry Rathert

People. How's that?

Joe Allman – J.P. Morgan

Does that mean technique?

Terry Rathert

Yes we got a great team. I can’t comment, it is not our year – we don’t comment, you’ve talked to us enough times. I can tell you about what our competitors do in their place, you know ask them, they can tell you, we tell you about what we do, what our teams are doing and I'll end with where I started. We got a great team and great people and that is a huge part of the success, no doubt about it.

Joe Allman – J.P. Morgan

And it's helpful. And on another topic, production curtailment's obviously by not completing Woodford wells, that is curtailing production somewhat. Are you curtailing any production anywhere else just because of the gas price?

Terry Rathert

Our view was that exactly what you said that by curtailing our activity and differing compilations we are going to be better positioned in terms of the cost environment, when we did complete those wells and in effect instead of having to complete having the capital tied up and shutting in a well, we are differing production as well. But Gary Packer and business unit leaders they have got a team and let me just say, they are all over that issue in terms of optimizing, managing, and thinking about the options. I look at it as a really nice thing to have in our portfolio at this stage.

Joe Allman – J.P. Morgan

Okay. Alright it is very helpful thank you.

Terry Rathert

Thank you.

Operator

And now we will move to David Kistler with Simmons & Company.

David Kistler – Simmons & Company International

Good morning guys.

Terry Rathert

Good morning David.

David Kistler – Simmons & Company International

Following up on Joe's question on the drill down completed wells, 25 in the Woodford looking like that is going up by year-end, you know have an estimate of what that number might be by year-end?

Terry Rathert

I going to let Gary Packer answer that one.

Gary Packer

As you have said, we have got 25 to date. We anticipate having probably a little north of 30 by year-end in the Woodford and then as somebody else had suggested earlier, we have got another seven wells to drill in styles this year and will probably have five or six of those deferred to the end of the year.

David Kistler – Simmons & Company International

Great. And then thinking about kind of the gas that you are at least holding back at this point, I am sure it is not fully open, coming out of the Granite Wash, if I took those 35 wells and what you are curtailing elsewhere, can you give me a rough estimate of how much gas you think that is that you are curtailing at this point?

Terry Rathert

Well I don't think we look at those as curtailments, if you are asking me could the wells that we have in amount front of Wash had made 35 or 40 million a day and we are going to put those kind of IP rates down. I will tell you yes. The curtailments if you will are more operational, production, and engineering base, production strategies that we think are sound and prudent with regard to how to manage those assets. You know ultimately these resource players you know [Inaudible] reservoirs, the reality is they all perform very, very similarly. So, you guys have studied and after that in terms of decline trends and deliverability and well counts that, you know how to model it as well as we do at this point.

David Kistler – Simmons & Company International

Great appreciate that color. Then just thinking about the optionality that you guys have been looking at, if we had gas prices just as inventories continues to get fall that fell below cash costs, would you guys consider shutting in more gas and closing out hedges just try and understand the thought process there?

Terry Rathert

I think we would certainly shut in anything rather than producing and have to pay the market to deliver gas. And I don't believe that anybody will fault us for taking a few Bcf out of our production to conserve cash and wait for a better time, I don't know that we would need to close out our hedge position in essence we, you think about them in the grad scheme of things, if we didn’t produce them, but we settle the hedge it, is $9 or $10 against a market cost of two and you know we have got – paid $7 for not producing Mcf as well. But clearly it makes no sense to produce at a cash loss in pricing together.

David Kistler – Simmons & Company International

Okay that is very helpful and then just hopping over to the Williston for a bit, as you guys explore Sanish Three Forks and the Bakken, any thoughts on the communication between those two zones and whether or not some areas you could actually go after and look formations or any kind of color or like that?

Terry Rathert

We are doing quite a bit of work on that as is the rest of the industry and I can say our buyers just for inspection at the strata and the course that we have taken is that it would be separate and I think that is probably, predominantly the feeling of industry. We are collecting and are doing looking at chemistries of the oils and everything that we continue to see would suggest that they are separate and then the answer to your last question is it would be would we considered drilling both those in the same section and the answer is absolutely yes.

David Kistler – Simmons & Company International

Great. Well thank you guys very much for the additional color and a fantastic job.

Terry Rathert

Thanks, David.

Operator

And we will turn to Joseph Magner with Tristone Capital.

Joseph Magner – Tristone Capital

Good morning thanks. Just back to the Granite Wash, how many frac stages have you tested over the various lateral lines that you have drilled to date in those well?

Terry Rathert

We have averaged eight stages in the wells that we have drilled to date.

Joseph Magner – Tristone Capital

Okay. And have any of those horizontal wells have been drilled near any existing vertical producers that have been completed in the same zone as we had a task whether or not you are picking up any incremental recoveries from a sense of refracing or recompleting in your – near those good vertical?

Terry Rathert

In the wells that we have drilled to date, I don't believe Joe that any of them are drilled in any immediate proximity to vertical wells.

Joseph Magner – Tristone Capital

Okay. I think Joel Allman talked about sort of dual stack laterals, is there effective or adequate down-hole equipment available now that will allow you to do that from the same vertical well below or would you have to drill separate wells and stack with laterals in individual locations?

Terry Rathert

I think the technology exist to do it and that has been done, it certainly poses a lot of operational risk and you know the fact of the matter is Joe these wells are incredibly economic and our buyers at this point would just continue to imply some of the same learning’s and benefits that we have seen in the Woodford because to the Granite Wash and continue to push these wells out further and further beyond the 4000 feet or so that we have currently drill that is kind of the next place we tack this. And I think it can be overstated, the learning’s that we have been able to apply from the Woodford over the stocks. If you look at the cost structure, you know we are starting this play, you know drilling wells much more efficient than we ever could have imagined two or three years ago and this was first proposed. And you know to see wells that early on were in a $10 million zip code as Lee reported earlier, most recent where $7.5 million. I for one, am just amazed how quickly we have been able to get up that learning curve and apply it over here in [Inaudible].

Joseph Magner – Tristone Capital

Okay thanks and over to the Williston Basin, what sort of, how do you EUR assumptions vary between Bakken type curve and a Sanish Three Forks type curve looks like there is quite a bit of all of in average 38 rates on a Sanish relative to Bakken securities how that affect the EUR between the two?

Gary Packer

And Joe, it is pretty early for us to really fully appreciate that. We have to look far beyond just our wells to get a feel for that. I can tell you going into it, we felt that the wells were typically going to be in a 320 MBO a typical Bracken well and we felt that the Sanish Three Forks was going to be north of that maybe pushing 400 MBO. I would say based on the results that we are seeing thus far, we see more upward momentum in the Barking wells and I just Sanish Three Forks, it is a little too early to tell. We're just three of our wells and it really a small subset of industry wells now in the public record, it is just too early to say.

Joseph Magner – Tristone Capital

Okay thanks. Do you have any sort of update on there is some other areas of the Williston that you're going to be testing from an exploration perspective, has that been sort of hold or do you have any update to provide on some of those?

Gary Packer

No it has not going to put on hold, we drilled our first step out into a new area earlier this year and it is in their completion phase right now. And as we speak we continue to drill further and further off the plank of the Nesson Anticline and we have one well currently drilling there and when the rigs finish their we are going to step into a new exploration area towards that. So, I would say, he will be looking to us to report more on that in the third and early fourth quarter.

Joseph Magner – Tristone Capital

Okay and just one last question. Terry do you have any estimate of what your collateral requirements would be based on your existing hedge positions or how that may vary, have you talked about how the value has changed, what would that entail or what would that imply for a collateral account?

Terry Rathert

Today because the markets are so weak relative to the positions that we have in place, our collateral accounts would probably be less than $100 million. Even I looked at the value for example and asked the corporate development guys, you know what price am I neutral from a kind of fair value perspective for 2010 natural gas that works out to $6.60? But there are still $30 million worth of assets and $30 million liabilities. What has been proposed is that you would post that collateral with an exchange. Well I would put up $30 million from my liabilities, but I wouldn't get credit or I wouldn't get an offset form a $30 million worth of assets. So somebody on the other side would put $30 million as well and so it would be $60 million sitting at the exchange and neither one of us get the benefit of the other person's cash. It’s the big changes in that because the volatility of the commodity markets that’s really of concern. Today because where commodity prices are in our relative hedge fund position, it would be a relatively small number.

Joseph Magner – Tristone Capital

Okay, that’s helpful. Thank you.

Operator

Rehan Rashid with FBR Capital Markets. Please go ahead.

Rehan Rashid – FBR Capital Markets

Good morning, just a one quick question on monument butte. Are we the $12 to $13 differential that seems substantially lower than what you had been running, is this going to systemic? And second, once you add a fourth rig, what kind of growth rate should we expect may be couple of quarters out from this asset base? Thanks.

Terry Rathert

Rehan, you are right. Last year, I think we exited the year at about $17 differential off NYMEX and we have narrowed that considerably. We probably have been there for, I don’t know four months or so. We have seen it narrow and its kind of help flat about in there. As far as the additional rigs and easily referenced, we will likely be mobilizing a rig in the September timeframe and we will be looking at actually additional additions in 2010. It’s kind of hard to translate that into a three or four quarter growth rate. I would say that if we get back to the levels that we have been in the past and that’s a five rig program we can project a 10%, 12% growth rate reasonably. That’s not something that’s going to happen instantaneously though.

Rehan Rashid – FBR Capital Markets

Sure, sure, sure. And again I am sorry, so that $12 to $13 per barrel, is it transitory? Or we should see this forbid?

Terry Rathert

I would, as we able to – we are projecting that forward $12 number.

Rehan Rashid – FBR Capital Markets

Got it.

Terry Rathert

At the current NYMEX-type of zip code.

Rehan Rashid – FBR Capital Markets

Sure.

Terry Rathert

[inaudible] NYMEX price and that should be approximately the differentials we experience.

Rehan Rashid – FBR Capital Markets

Fair enough. And going back to the beginning of the call, 5 million and change for a recent Woodford well, is this the first well on our pad or is this is the eighth well on our pad basically or something in-between?

Terry Rathert

Well, what we were talking about and trying to recall exactly what I said, Rehan, but what we talk about when we think about the Woodford now with what we at, we are 280 wells into the drilling. We've got what we what we call our Northern area which is everything but the far south. We look at that as kind of core development acreage. At this point if you go to our NFX publication, Steve actually put some graphs in there that I think will be very useful to you.

One of those shows the cost improvements overtime from the first well to the eighth well, so those will be average relative to the wells the pads that match up to those well counts. And you could see a really good trend line in terms of drilling costs for lateral foot and it’s pretty easy to follow through. So simply put, first well on the section, most expensive even though we are well done on the warning curve because of its initial infrastructure, initial earnings etcetera. Eighth well in this section on average is the cheapest and it’s a nice trend line from one through eight. If you look at the graph, I think it’s pretty easy to understand what we are trying to say.

Rehan Rashid – FBR Capital Markets

Okay. I will take a look at that. Thanks.

Terry Rathert

Okay. Yes.

Operator

David Tameron with Wells Fargo. Please go ahead.

David Tameron – Wells Fargo Securities

Hi, congrats on a great quarter. Let me go back to the boring Woodford play. You guys mentioned in your at NFX you talk about stand up 640s. Understand the concept, but can you explain to me what that would mean as far as development opportunities go forward and how to change the way you attack the field.

Lee Boothby

Gary is looking tired so I actually going to let Jim Addison from [inaudible] explain that to you. Jim, you still there?

Jim Addison

Lee, I am.

Lee Boothby

Okay.

Jim Addison

Standup 640 is essentially taking two 640s or 1280 and splitting it right down the middle. And so we would be able to drill lateral lengths up to 10,000 feet. So we are working with the OCC here in Oklahoma to establish as many of those units as possible.

David Tameron – Wells Fargo Securities

Is there any, what’s the hurdle to get that done?

Jim Addison

Time and agreement with the other working interest owners if we don’t operate those sections.

David Tameron – Wells Fargo Securities

Okay. And that sounds like it will cut down on your well coast going forward.

Jim Addison

Well, certainly does and it improvement on our FND. The other thing we are doing for soon in Oklahoma is trying to form a very large unit. We filed our plan with the OCC and that would be located in the south and would comprise about 27 operated sections and just provide us with tremendous opportunities for extending the lateral.

Lee Boothby

And just one point of clarification, the longer laterals total well cost will be higher, but the unit FND costs are lower.

David Tameron – Wells Fargo Securities

Yes.

Jim Addison

Okay.

David Tameron – Wells Fargo Securities

Good. Okay. Thanks for that color.

Lee Boothby

I am glad to hear we are boring now.

David Tameron – Wells Fargo Securities

Yes. Little facetious there. Let me move to the Rockies a little bit so Gary may not get off the hook, but there has been a lot of talk about people drilling some deep oil wells in the powder chasing [inaudible] chasing different plays among a number of operators. Can you guys talk about what’s have you done thus far outside of the Bakken and [inaudible] are what you are seeing for the operators. Any color you can add on that?

Terry Rathert

Well, I mean specifically if you want to talk about the powder and Maury it's something that we are familiar with. Over the last few years, we build an acreage position largely HBT 35,000 acres approximately in that position. It does give us exposure to their play. Clearly in the environment that we are in right now, our focus has been in the Monument Butte Field in Williston basin. Last year, we picked up about 6,000 or 7,000 additional acres in the Powder River basin to compliment what we have, ten year leases and its something that we have a team looking at.

David Tameron – Wells Fargo Securities

Okay. So a little early on your acreage to say anything definitive?

Terry Rathert

That's correct.

David Tameron – Wells Fargo Securities

All right. That’s all I got. Thanks everybody.

Terry Rathert

Thanks a lot.

Operator

Next up is Shannon Nome [ph] with Macquarie [ph].

Shannon Nome – Macquarie Capital

Hi and congratulations on some great results. I have two questions. The first one, can you give us a bit more color on how you got your LOE down so far? And then the second question is, where do you think well costs in granite wash go on sort of a 12 month time horizon?

Terry Rathert

Yes, the LOE question is a good one and we have, say, made some very material improvements there. I would say that, there is a bit of noise in there that have to do with the timing and processing fees and various deepwater developments and a few things like that. As by and large, its water, water and water as we continue and as we have already discussed, the deferral of various completions in different areas, that’s a whole lot of flow back water that we don’t have to take to disposal sites and process. And that’s certainly been a part of what we are talking about.

We have put our own salt water disposal wells in certain areas and we have been able to defer some pretty major work over projects on the major expense side that have allowed us in some of the areas that are of the higher cost to move and we deferred those out in the future years. We have seen the benefits from labor. I have also continued to a downward trajectory as well as compression in other salt water disposal costs. So it’s a lot of different things, I can say our Vice-President of production is traveled to each one of the business units and working with all the people in the field trying to look for creative ways to continue to push our cost structure down there.

You asked about the well cost at styles. As I said, we were traditionally and we are very early days here in a $10 million zip code with the last well at being $7.5. I don’t know that we are ready to say that that’s the norm these days, but I would say if there is any learning’s that we have from the Woodford is, that is we drill more well and we will continue to push those cost down. We have redefined what our target or goal wells are in the Woodford and we continue to do that. I think we are beyond where we thought we would be in south at this point.

Shannon Nome – Macquarie Capital

You don’t have to put [inaudible] if you done that.

Lee Boothby

I am sorry, could you repeat.

Shannon Nome – Macquarie Capital

You don’t want to take a ballpark figure or percentage improvement.

Terry Rathert

No, I have been doing this to longer term to number hierarchy.

Lee Boothby

I am going to help you with that. It’s too early to tell and for point of reference, the $7.5 million well is a record well, the horizontal wells in the granite wash. So to say that we will be able to repeat the record well on average is probably a big ask at this point, but we will push the cost down from the start, no doubt about that.

Shannon Nome – Macquarie Capital

Okay. Thanks.

Terry Rathert

Thank you.

Operator

And now, we will turn back to Subash Chandra with Jefferies.

Subash Chandra – Jefferies & Company

Yes, just a couple of follow-ups. In the offshore, west camp 142, is that on or what’s the timing of that?

Terry Rathert

I will let John Jasek talk about the offshore.

John Jasek

I am not sure about less than 142, but we have a west camp 149 that has been online for quite sometime that's producing around 16 million a day in the Gulf of Mexico.

Subash Chandra – Jefferies & Company

[inaudible]. And then in the Woodford, you are talking about the southern plays. Is that Cole County?

Terry Rathert

Yes, it will be the farthest southern edge. It's actually I think it will be Jim, why don't you take that. I think it's Hughes, Cole and – I will let Jim Addison and keep us straight there on actual location.

Jim Addison

There would be Cole and Toko [ph] counties.

Subash Chandra – Jefferies & Company

Okay. Great. Thank you.

Operator

And gentlemen, there are no further questions in the queue. I will turn the conference back to you for any additional or closing remarks.

Lee Boothby

Well, just to make it very brief, we certainly appreciate everybody’s interest in Newfield. Thank you again for your time and we look forward to updating you as we continue to progress through 2009. Thank you for your support and we look forward to talking about more good results as the year unfolds. Have a good day.

Operator

And with that, we will conclude today’s conference. Thank you everyone for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: [e-mail]. Thank you!