Newfield Exploration's CEO Discusses Q2 2011 Results - Earnings Call Transcript

Jul.22.11 | About: Newfield Exploration (NFX)

Newfield Exploration (NYSE:NFX)

Q2 2011 Earnings Call

July 21, 2011 9:30 am ET

Executives

John Jasek - Vice President of Onshore Gulf Coast

Lee Boothby - Chairman, Chief Executive Officer and President

Gary Packer - Chief Operating Officer and Executive Vice President

Daryll Howard - Vice President of Rocky Mountains

Analysts

Leo Mariani - RBC Capital Markets, LLC

Subash Chandra - Jefferies & Company, Inc.

Stephen Berman - Pritchard Capital Partners, LLC

John Herrlin - Societe Generale Cross Asset Research

David Kistler - Simmons & Company

Joseph Allman - JP Morgan Chase & Co

Richard Tullis - Capital One Southcoast, Inc.

Unknown Analyst -

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Operator

Good day, everyone and welcome to Newfield Exploration's Second Quarter 2011 Conference Call. Just a reminder, today's call is being recorded. And before we get started, one housekeeping matter. Our discussion with you today will contain forward-looking statements, such as estimated production and timing, drilling and development plans, expected cost reductions and planned capital expenditures.

Although we believe that the expectations reflected in these statements are reasonable, they are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors and risks, some of which may be unknown. Please see Newfield's 2010 annual report on Form 10-K and subsequent quarterly reports on Form 10-Q for a discussion of factors that may cause actual results to vary.

Forward-looking statements made during this call speak only as of today's date and unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements.

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

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

Lee Boothby

Thank you very much. Good morning and welcome to our second quarter conference call. As usual, I think Newfield is one of the first to report quarterly results and we appreciate you dialing in to the call this morning.

I'm joined in Houston by other members of our leadership team, including Terry Rathert, our CFO; Brian Rickmers, our Controller; John Jasek, Vice President, Onshore Gulf Coast; Daryll Howard, Vice President of Rockies; Bill Schneider, Vice President Gulf of Mexico and International. And we're joined also on the call in from Denver by Gary Packer, our Chief Operating Officer; and we have George Dunn on the line as well from Tulsa, our Vice President of Mid-Continent.

In addition to our financial and operating results, we also released a very detailed update last night on the Uinta Basin. We're excited about the huge potential we have in this oil basin, both in the shallow oil zones we've been exploiting since 2004, as well as the new zones we announced last night. We'll spend a good portion of our time today discussing our future plans in the Uinta Basin. It's a compelling story and it will drive our future oil production growth.

Let me begin today with some comments on the big picture and reiterate Newfield's top priorities in 2011 and how we are positioning the company for strong performance in 2012. In the first half of the year, we produced about 146 Bcfe. As originally forecast, our growth this year is back end weighted, with new oil developments commencing production in the fourth quarter. In last night's release, we stated that we expect our 2011 volumes will remain in our original production guidance range. Year-to-date, we've sold properties that would have contributed to about 3 Bcfe to this year's volume.

In addition, we deferred about 200,000 barrels in Malaysia following a mechanical issue on our Abu facilities, and we've faced challenging weather in both the Mid-Continent and the Rockies regions during the first half of the year. There's a short table in the release you may find helpful. To be clear, without the asset sales, the Malaysian repairs and the weather issues referenced, our production would have rolled up to the midpoint of our original range.

Importantly, our big development projects are on schedule, and we expect our year end exit rate for oil and liquids will be more than 65,000 barrels of oil per day net. Through the end of the second quarter, we have sold $131 million in nonstrategic assets, and additional sales are underway. We expect to monetize somewhere between $200 million and $300 million in nonstrategic assets, and we'll use these proceeds to balance the budget during the course of 2011.

Our capital budget for 2011 remains unchanged at about $1.9 billion, excluding our May acquisition in the Uinta Basin. Our investments in 2011 are front end loaded as we develop large oil projects in multiple areas. Expected ramp in production late in the year and our outlook for reduced capital spending in the second half will allow us to execute our planned activities within the current budget.

As we pointed out in our first quarter call, our industry is facing increasing cost pressures related to equipment, labor, and services. Team Newfield is working harder than ever to counter the escalating service costs in many of our active drilling areas today. Our operations teams are doing yeoman's job of building efficiency gains into our programs as evidenced with recent best-in-class wells in our Granite Wash, Williston Basin and Eagle Ford programs.

Let's cover our financial and operating results for the second quarter. As always, Terry Rathert will be available during the Q&A session to take any questions you may have. Our earnings before FAS 133 gains were $138 million or $1.02 per share. Revenues in the second quarter were $621 million. Net cash provided by operating activities before changes in operating assets and liabilities was $393 million or $2.91 per share, topping First Call cash flow per share estimates.

Our natural gas production was 47 Bcf, or about 517 million cubic feet per day. Our oil liftings and liquids volumes were 4.4 million barrels, or about 48,000 barrels per day. We're continuing to channel our investments toward oil. As a result, our gas volumes are declining. We believe that this is the right economic choice in today's gas prices, while our hedges preserve profitability.

In the guidance we provided in last night's release, our expected increase in oil can be seen in the fourth quarter, with large new developments commencing production late this year. This is happening both domestically and in the international arena. Our guidance for costs and expenses for the remainder of the year has been updated in the release as well.

Let's move now to updates on just a couple of our key drilling programs. Again, I want to save ample time for a thorough discussion of our increased resource potential and enhanced growth outlook in the Uinta Basin. In the Granite Wash, we're continuing to see excellent results, both in the form of drilling performance and production. Our gross production recently set a new high at 190 million cubic feet per day or about 135 million cubic feet equivalent net. To date, we've drilled 47 horizontal wells in the play and our gross IP rates continue to average about 16 million cubic feet equivalent per day. This play has been relatively consistent for Newfield, and the Stiles/Britt Ranch asset is a great asset to own.

As you know, the Marmaton formation is our target this year due to its liquid-rich composition. Our most recent wells in the Marmaton have commenced production between 16 and 23 Mcfe per day gross. Oil and condensate comprise more than 500 to 600 barrels of oil per day in these recent wells. Our working interest averages about 75%. Our drilling efficiency gains in this play have offset rising service costs year-to-date. We drilled a recent best-in-class well in just 24 days, and we're averaging about 28 days on each of the wells that we drilled today. We are moving towards longer lateral completions and have a few wells planned and will have lateral lengths in excess of 8,000 feet later this year.

Our efficiency gains are allowing us to drill more wells with the same rig fleet. We now expect to drill more than 30 wells in the Granite Wash in 2011 and to grow our production here by more than 25% over 2010. We've added about -- we have about 50,000 net acres in the Granite Wash plate today, including about 10,000 net acres in new prospective areas. Our assessment of these new areas is now underway and we'll have additional details to share with you later this year.

In the oil at Woodford, we're running 2 operated rigs. We recently completed several new wells and they're cleaning up following recent fracture stimulation. Our drilling today is being done on pads so the duration between completions is longer. We expect results to be consistent with our first batch of wells released earlier this year. In the Williston Basin, we continue to run a five-rig program. As you undoubtedly have heard, operations in the wells have been more challenged, with blizzards, rain, flooding, and road closures in the second quarter. Road closures, and the inability to lift oil, moderately impacted our second quarter sales.

In addition, weather events led to deferred completions, and we're only able to complete 9 out our 15 planned wells in the quarter. Today, we have an inventory of about 10 wells awaiting completion.

During the quarter, we posted a record IP for Newfield in the Williston Basin of 5,200 barrels of oil equivalent per day, missing the Williston Basin record by just 100 barrels per day. It's quite a well, and important to note that it's a 5,300-foot lateral with 26 frac stages. The well cost about $5.9 million gross to drill and complete, showing that we continue to learn and optimize our completions.

Quickly, on to the southern operated basin. Our assessment program continues. To date, we've drilled 7 vertical wells, completed 2 horizontal wells. We're preparing to initiate fracture and testing operations on 4 vertical wells in the next week or so. This will give us data on several geologic horizons. We remain encouraged that all of our wells to date have encountered oil over a very large early extent. We have increased our acreage in the play to more than 320,000 net acres today.

And wrapping up with Malaysia. Let me just say that we completed our repairs to PM 318 Abu facilities in June, and the field has resumed production. Our PM 323 fields continue to outperform, with recent gross production averaging over 32,000 barrels of oil per day, inclusive of a new daily production record. Outstanding job by our team. If you have any additional questions on any of our other operating areas, we'll be happy to address them during the Q&A.

So now let's move on to the Uinta. If you've not reviewed our new slide deck on the web, I would encourage you to do so. It's a detailed presentation that should leave you no doubt as to why we're excited about our future in the oil basin. We have updated our resource potential on the Green River formation, provided resource estimates for 2 new plays, and published tight curves on our economic assumptions for each of these plays.

I will reference a few of these slides by number in my final remarks today. The Uinta Basin is our crown jewel oil play, with increasing resource potential in a basin where we have demonstrated a track record of creating value. We are confident in our ability to more rapidly grow oil production from the area in the future. With more than a decade of inventory, increasing activity is key to creating present value.

We have some distinct competitive advantages in the Uinta Basin. First, we're a proven operator. Newfield has been active in the Uinta Basin since 2004. We have demonstrated our ability to manage a giant waterflood asset, deliver more than 15% compound annualized production and reserve growth, and build relationships with refineries that have allowed our growth to be commensurate with the Black Wax capacity expansions.

In the field, we have a team of more than 400 people that manage this asset. This team is in place today and prepared to develop our new plays and drive higher growth rates. I can assure you that they understand the mission.

Second, we have scale in our operations. Today, we are the largest oil producer in the state of Utah, and we represent nearly 1/2 of the Uinta Basin's daily oil output. Since late 2004, we've grown our acreage position from 88,000 net acres to about 250,000 net acres, all largely contiguous. Our gross production has grown from about 7,500 barrels of oil equivalent per day to about 22,000 barrels of oil equivalent per day now.

Over the coming months, we plan to increase our operated rig count from a historic 5-rig program to at least 8 operated rigs in 2012. For next year, we expect that this will result in at least a 25% production growth over 2011. At the same time, we are making significant field infrastructure investments that will accommodate our growth from the area north of Monument Butte, an area we call the Central Basin. These investments are expected to total $175 million for 2011 and 2012 combined, and will facilitate our future growth.

We control our operations in the Uinta with high working interest, averaging about 70%. Furthermore, we have successfully employed vertical integration, owning rigs and other services that lead to improved profit margins. This ownership helps guarantee that we have the services to meet our operational needs.

Third, our acreage has multiple play types. Our Uinta Basin acreage has multiple prolific stacked oil and gas plays, ranging from about 4,500 feet TVD to more than 16,000 feet TVD. Over the last year, we've drilled wells into new oil formations and have been very encouraged with the results. In yesterday's release, we disclosed well results from 2 of the new plays, the Uteland Butte and the Wasatch, and provided information on our net resource potential in the basin. We believe that our Uinta Basin assets have net undeveloped resource potential in excess of 700 million barrels of oil equivalent.

Next, we're reducing our traditional growth constraints. Our growth in the Uinta Basin has historically been limited by the number of drilling permits we receive, and the refining capacity for our oil. Our recent acquisition of acreage in the Central Basin provides us with acreage under state jurisdiction and another governing authority through which to permit. This allows us to run rigs in both state and BOM lands, and provides flexibility in our work programs.

We're planning to add rigs into the basin, and we will be executing development programs in our Uteland Butte and Wasatch plays in the second half of this year. This increase in activity will provide great momentum for our oil growth as we move into 2012.

We have many more options today to move capital rigs and personnel to the plays that create the most value. The demand for crude in the Uinta Basin has been strong and as always, we are working with area refiners to ensure their capacity expansions match our growth projections. We have agreements in place today for 2012, and are working with our refining partners to secure long-term arrangements that support our future growth outlook.

And my final point, our returns in the Uinta Basin are superior. Our before tax returns in these oil plays today are greater than 100%. Please reference Page 11 in the slide deck. These returns mandate that we push every available investment dollar toward their rapid development.

Let me quickly make some comments on each of our active oil developments in the Uinta. In the Green River oil play, more than 2,100 wells have been drilled on our acreage and we have a remaining inventory of more than 4,000 locations. Our drilling efficiency gains now allow us to drill wells in as few as 4 days for less than $1 million drilling complete cost. We have a high working interest and estimate our net resource potential to be about $360 million barrels of oil equivalent. A detailed table on Slide 7 depicts our resource potential by area, and provides insights on our recovery estimates.

Until recently, substantially all of our drilling was being done in the Green River. Today, we've expanded our drilling to include new oil plays at Monument Butte and north into the central basin. We've essentially doubled our view of recoverable resource from the area. Our Uteland Butte horizontal oil play is prevalent on about 200,000 net acres or about 80% of our total acreage footprint in the basin, and is perspective from about 6,000 to 9,000 feet TVD. This is an organic rich play where we target oil saturated limestone and dolomites. The rock is naturally fractured and lends itself to effective fracture stimulations. This creates more connectivity in the reservoir and should lead to higher recovery of oil in place.

Over the last year, we've drilled 6 horizontal wells in the Uteland Butte play and our most recent wells have initial gross production rates of about 500 barrels of oil equivalent per day. Our work indicates the potential to drill more than 1,800 wells to develop about 300 million barrels of oil equivalent. There's additional upside as we learn more about the geopressured portions of this play and determine ultimate spacing of the development wells.

Our initial permits are coming in today, and we plan to drill about 10 wells in this play in 2011, largely on state lands, followed by at least 30 wells in 2012. In the Wasatch play, we have about 70,000 prospective acres or roughly 30% of our total acreage in the basin. This play is productive throughout the Central basin and we see the potential to drill more than 380 wells to develop more than 45 million barrels of oil equivalent.

Our early assumptions include 320-acre spacing. However, 160-acre spacing is certainly possible and will be tested in the near future. This play encompasses 600 to 800 feet of interbedded organic rich shales, carbonates and sand stones. In the Central basin, the hydrocarbon generation process created areas of overpressure, leading to wells with higher production rates and recoveries.

Various play types exist within the Wasatch, ranging from the more shallow, and normally pressured sections that can be drilled and completed for about $1 million, to the deeper geopressured sweet spots that have significantly higher EURs and can be drilled and completed for about $3 million.

Recent wells drilled in the geopressured areas have seen gross IP rates as high as 1,500 barrels of oil equivalent per day, and we're averaging more than 1,000 barrels of oil equivalent per day. Ultimately, we may also apply horizontal drilling in the Wasatch.

For the second half of 2011, we plan to drill about 25 wells in this play, largely in the normally pressured areas, where we have available rigs and existing permits. In 2012, we will drill at least 50 wells and exploit the deeper geopressured portions of the play.

The summary slide on Page 10 details our 3 play types, totaling net resource potential of more than 700 million barrels of oil equivalent. This is in addition to our deep gas play, where we've we drilled 6 wells to date and confirmed its presence throughout our acreage. In addition to these formations, we're studying other perspective horizons. Our geologic assessment of these plays continues and we will have more to share with you in the future.

Before we move to the question-and-answer session, let me summarize the key takeaways from today's call. Number one, we are working hard to deliver on our production promises and stay within our original guidance range and adhere to our capital budget. We expect to see a significant increase in our oil production in the second half of this year, and our personnel are aligned to deliver on our growth promises in 2011.

Number two, we're combating the meteoric rise in service cost where we can. We are intentionally limiting activities in hot plays that have experienced rapid inflation in favor of more attractive investments elsewhere. Our precious people and capital resources continue to be deployed towards areas with the highest rates of return. This is the right thing to do. We're committed to our $1.9 billion capital budget and are more apt to decrease activity than increase our planned expenditures.

Number three, we have large oil and liquids rich assessments that are in various stages today. The Eagle Ford, the Southern Alberta basin, new acreage in the Granite Wash and an undisclosed stealth play where new leasing has pushed us over 100,000 net acres.

We remain committed to building for our future. I realize that you all want more details now, but our assessment programs are science based and thoroughly executed. I can assure you that we will have detailed updates for you like we did in today's Uinta overview when we gather all of the pertinent facts. Believe me, I'm just as anxious as you are.

That concludes our prepared remarks today and we're delighted to take your questions at this time. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Joseph Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

Lee, the pace of development of the Eagle Ford in the southern Alberta basin seems slower than your development here with these new plays in the Uinta. Is that correct and what's the reason for them seeming to develop a lot slower?

Lee Boothby

That's a good question, Joe. I think that your observations are correct. And I think the circumstances are a little bit different in each of the play areas. First of all, the Uinta Basin is an established development area where we've got infrastructure and personnel in place. The 400 people that I referenced literally live and work right on top of our acreage. So we've got all the resources in place to be able to shift around in the different play types and the acquisition that we closed in May, adding the 70,000 plus acres to the position, put us in a position to accelerate the exploitation of that play. We were very judicious in how we approached the Uteland Butte play. Our team was actually anxious to drill more wells as early as 2009 but we made the election to delay our activities there in favor of consolidating the position. So today, we've got the acreage we need. We're in a position to be able to accelerate. That's the story there. In the Eagle Ford, John Jasek and his team continue to drill wells. We're focusing this year on regions offsetting the areas where we had success in the early drilling last year. But frankly, we've seen a blowout in the service cost, particularly in the pressure pumping side of the equation. And I hate to use this phrase but it's margin destruction. So John is running a minimal program there in the Eagle Ford that gives his team a chance to digest the technical data, move judiciously through that information and plan for the future. But first and foremost, we've got to get the service side of the business in line and realize that it's better for all of us to have a win-win environment than a win-lose environment. So we're not going to accelerate activity in the Eagle Ford because we don't have to. So we're going to execute a low go strategy there and we'll be ready to ramp up when the time comes that those margins compete in other parts of the portfolio. In the southern Alberta basin, we've continued to grow our acreage position over the course of the last 18 months. We announced some 320,000 net acres that we have today. We drilled the vertical wells that we told you that we were going to drill. We've got a couple of horizontal wells that we've completed. We're going into a vertical testing program right now. Frankly, that's part of our assessment program. The only thing that's held us back there, and I'd say we're a few months behind of the original schedule that we talked about, is just getting services and equipment into the region because that's a service and equipment poor area and anything within 150, 200 miles of the Williston Basin, here's the giant sucking sound of the Williston Basin gravitational pull. So we've got the time there to actually take our time. We're going to test these wells in the third quarter and we recognize that you guys are waiting to hear some information. When we get it packaged up, we'll tell you what we think. But we're excited about what we've seen in terms of oil potential, and we're excited about what we continue to hear with respect to offset operators in the area. So each one's different but that's kind of the storyline.

Joseph Allman - JP Morgan Chase & Co

It's very helpful. And then related to the Williston, so your average cost for the Bakken wells in the second quarter were -- or the average was $9.8 million, up from I think $8 million prior quarter? What's the big driver there, and what are current costs right now? Have they come down from that $9.8 million?

Lee Boothby

I'll let Gary take that question.

Gary Packer

Joe, I think previously, when we talked about the cost of the Williston basin wells, we were in a $9.2 million zip code. So we haven't seen quite the inflation that your question would imply. We see it very regionally dependent, as Lee communicated in the call there. This most recent well was a 640-acre, the 5,200-barrel a day well. And it was 640-acre well, and it was just in the zip code of $6 million. So there's a lot of noise and it's regionally dependent. As far as the costs go, I'd say it's marginally on the drilling. I think drilling our teams have done a really nice job of using efficiency gains to offset cost increase and the increase that we've seen has all been on the completion side.

Joseph Allman - JP Morgan Chase & Co

Going forward, that $9.8 million, would you expect that to be lower in the third quarter? I know it's locationally dependent.

Gary Packer

I would expect it to go down.

Lee Boothby

And Joe, remember the lateral length in the completion side of that leverage, I mean as the lateral lengths vary one period to the next, you're going to see some noise with the average lateral lengths increasing.

Operator

Moving on, we'll go to Steve Berman with Pritchard Capital Partners.

Stephen Berman - Pritchard Capital Partners, LLC

Can you break down the oil versus gas in the Uteland Butte and Wasatch or either in the reserve assumptions for in the production flow?

Lee Boothby

It's dominantly oil. I'll let Gary or Daryll comment in terms of percentages, but its primary product production is oil. It's black oil with the normal GUR that you'd see with solution GUR-type numbers. But I'll let them jump in and give you some additional color.

Gary Packer

We have various plays that we're pursuing out there, as Lee alluded to. We're seeing a variation in GURs. I'd say in the Green River typically, we're in a 500 to 2,000 barrel of oil or standard cubic feet per barrel of oil. Monument Butte typically runs between 1,000 and 2,000 GUR. And the Wasatch has a little broader distribution, somewhere in the 800 to 2,000 range.

Stephen Berman - Pritchard Capital Partners, LLC

Can you tell us moving to the Williston where the 5,200-barrel a day well is?

Gary Packer

I believe it was in the Westberg area.

Stephen Berman - Pritchard Capital Partners, LLC

Within the -- I don't have the presentation in front of me, what county is that in?

Lee Boothby

Kennedy County.

Operator

And now we'll open the floor up to RBC Capital Markets' Leo Mariani.

Leo Mariani - RBC Capital Markets, LLC

A question on the Uteland Butte. It sounds like you've got 6 wells. Just trying to get a sense of production history there on terms of how long they've been producing. Obviously, you guys have come out with EUR estimates so I'm kind of assuming you've got at least several months there. Can you just comment on that?

Lee Boothby

Sure. I'll let Gary Packer take that question.

Gary Packer

Leo, typically those wells have ranged from 60 to 90 days of production history. And I think we've got enough experience in the area and elsewhere that we're able to make some pretty reasonable estimates of EUR at that point. I would say and if you look at the slide deck there, you'll see that we've had a steadily improving result. When you're sitting on 1,800 completions, it's been exciting to see how the teams have actually optimized some of the completion practices thus far. And as implied here, we've already taken it from some 300 barrels a day to 500 barrels a day IPs, and I suspect this is just going to continue to go up from there.

Leo Mariani - RBC Capital Markets, LLC

Just looking at the Eagle Ford, I guess you guys reported another tranche of wells here in the second quarter. You had a pretty highly variable IP range. You guys talked about anywhere between 400 and 1,400 BOE per day, trying to get a sense of kind of where that average shakes out given how wide the range is.

Lee Boothby

Well, the range -- I'll speak to the range and then I'll turn it over to John Jasek. He can give you a little color on that, on the average. But remember that we're mixing our activities down there. We've constrained John with a limited rig count. So he's using his capital very judiciously. He continues to step out and test new areas farther to the north, as well as to drill development and pilot wells, adjacent or in close proximity to the wells that were drilled in 2010. So it's kind of a mixed bag in terms of the geographic areas of those wells. That's what's driving the spread. But John, any color you want to offer?

John Jasek

I mean there's various things going on in terms of where we are in our development between spacing pilots and different completion techniques that we're trying out to try to optimize that. That's part of why you see the wide range. We were focusing our areas to the south, which is where the IP quote came from in the release. Our average is around 600 to 700 BOE per day range. It's an average for those wells that we're drilling as part of the release.

Leo Mariani - RBC Capital Markets, LLC

I guess in terms of your lease operating expense guidance, it looks like it's kind of ramped up in the high end pretty significantly, as we get into the second half of the year here. Just wanted to see if you guys had any color in terms of what's driving that?

Gary Packer

Yes, I mean typically, the meteoric inflation that Lee referenced earlier, it doesn't only affect capital. It certainly effects the operating expense side of the business as well. I'd say water hauling, water handling has been probably the single biggest area that we've seen increases. But just anything from the human resources have gotten more expensive throughout the business. Chemicals, everything is higher than what it once was.

Leo Mariani - RBC Capital Markets, LLC

Definitely, it makes sense there. With respect to CapEx, you guys talked about...

Lee Boothby

Let me jump in, I want to throw one other thing in before we run off in that question. There's a couple of other things to remember in the second half of the year. We're bringing new oil development projects online, both domestically and internationally. So you're getting a whole list of new projects that are running in. And if you look out late in the year on a unit basis, you'll actually see that it's declining. So you got to put all the pieces together before you can make the judgments on the cost. So total costs are up because total production volumes are up. We're adding new developments into the mix but unit costs were actually declining out towards the end of the year because of the increased volumes.

Leo Mariani - RBC Capital Markets, LLC

Looking at CapEx, I guess you guys had said in your prepared remarks that you expect it to be a little bit lower in the second half of the year than the first half of the year. Can you just give us a little bit more color in terms of what's driving the reduction there? Was it just reduced activity? Are there sort of some other factors there or maybe some of your bigger projects you spent all the money on in the first half?

Gary Packer

Yes, I think a lot of what you're seeing there is just timing. We have been executing our development activities internationally, building platforms and structures for East Piatu Field, which are now largely installed and behind us. And we were certainly front end loaded on some of the completion activities coming out of 2010 which will be behind us as we enter into the second half, and basically turn the proved undeveloped resources to production as we've talked about in a number of our major projects, both internationally and domestically.

Operator

Now, we'll hear from Dave Kistler with Simmons & Company.

David Kistler - Simmons & Company

Thank you first for all the additional information on the Monument Butte assets. It's helpful. One of the things that you guys have pounded down pretty hard is the ability to be flexible with your redirection of capital. Can you talk a little bit about how high you could take the rig count up in Monument Butte in the coming 6, 12, 24 month period?

Lee Boothby

That's a great lead in, Dave. First off, I'd like to tell you that my favorite color is green, and that's green for oil. So when you look at the margins that are generated on the oil side of the ledger with the great operating leverage that we have in the Rockies, in our Uinta Basin, fabulous team out there that's delivered multiyear growth with all the constraints and issues that we've had to work under, additionally opens the door up in that regard. So being in a position now to see an acceleration opportunity in that basin behind the execution that we've already delivered there is a really strong argument. And I'll let Gary Packer give you some additional color.

Gary Packer

Dave, the only thing I'd add to that is we have to just be cognizant of the infrastructure and make sure that it grows commensurate with our production growth specifically in the central basin area. I'd say right now we're looking to 8 to 9 rigs as we look into '12 and we're holding back at that. Certainly, the resource would merit more than that. I would say if I had to just look out another year beyond that, 10 to 12 rigs is probably a reasonable expectation as long as we can continue to expand both not only the refining but more importantly some of the gas gathering infrastructure out in the central basin.

David Kistler - Simmons & Company

That's helpful. And maybe if I could ask for a little bit more color on what you guys are doing on the refining front. Obviously, you're kind of the largest player in that area right now but to just get a sense in terms of what you're looking at contractually. I think you're covered through '12. Kind of what you're doing on a longer-term basis, and then maybe tie that to what's happening with how you're distributing the rig count around Monument Butte? I mean obviously off the returns you gave us last night, it would favor sort of focusing on Uteland and Wasatch more than anything else, but that may be prohibited as a result of kind of the infrastructure comments you made.

Lee Boothby

Dave, I guess that sitting here halfway through '11 and having said we're covered through '12, I'm going to respectfully decline to give you any additional color at this stage. We're covered through '12. We've told you what we think we can do in terms of growth in '12. Stay tuned. We'll give you some additional information at the appropriate time in the relatively near future. How's that?

David Kistler - Simmons & Company

I appreciate that. And then just one last one for me. With capital going to Monument Butte from other areas where obviously the oil content is a little bit higher than some of the other areas, should we be thinking about what's happening from a mix shift standpoint as far as the oil content accelerating relative to total production or what we've kind of looked at previously?

Lee Boothby

Well, certainly you're going to see a continued shift. I mean it just makes sense, we can't tell you on the one hand that we've got virtually 100% of our capital budget allocated to oil projects and not have that shift pretty strongly underway. Hopefully, this gives you the visibility. I would expect to see the total oil percentage continue to tick up as we bring these new projects online. We talked about being north of 65,000 barrels a day exit rate net, total oil production at year end. I mean that's something around I don't know, 40%, 50%, 35%, 40% I guess improvement from what we did in the second quarter. So we're certainly moving pretty strongly in that direction and since we're not investing in our dry gas portions of our portfolio today, then those portions of the portfolio are on decline as we indicated. So you'll continue to see that mix and we'll provide some additional color kind of as it unfolds during the course of 2011 and some pretty strong guidance going into 2012 in that regard.

Operator

And now, we'll hear from Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc.

First question is on the lower Wasatch and the 8 wells you referenced. Was there a Newfield-operated well in the mix or are these carryovers from the Harvest transaction?

Lee Boothby

It's a combination. I'll let Gary Packer take that question out of the Rockies since he's got all the guys there that can answer those questions specifically.

Gary Packer

The Wasatch wells that Newfield have drilled has not been brought on production yet. We've completed some of these wells but the mix that you're looking at here, we're already in the drilling phase at the time we transitioned through the acquisition to Newfield.

Subash Chandra - Jefferies & Company, Inc.

The wells that are not brought on yet, I guess you may have implied that those were in the normally pressured and not in the overpressured. Is that correct?

Gary Packer

It's a combination of both. A few of the wells that we've drilled are in the pressured section and the rest are in the normally pressured section. Through the remainder of this year, we anticipate that a lot of the drilling is going to take place where we actually -- and this is more of a permitting situation than anything else. We can go back in to prior permits that we've had and basically deepen them into the Wasatch section. And a lot of those are in the normally pressured area. The good news is while we anticipate that these wells may have an IP that's light to the one that's represented here, the cost structure ought to be a lot less as well. So we'll be able to preserve the margins and returns in both of the play types that we have here.

Subash Chandra - Jefferies & Company, Inc.

Final one, just on this point, the 320-acre spacing, is that across all the play types of that area, or do you think the deeper horizons could be also repeatable at that pace?

Gary Packer

It's premature for us to say that at this point. We've studied Altamont as an analog, and as you may be familiar with, we see everything from 640s to 320s and now down to 160s successfully and it's regionally dependent. So at this point, I think we've taken a rather conservative position in it. And ultimately, I would anticipate that there will be areas here that are downspaced to 160s as suggested in the slide deck. I expected horizontal drilling to become part of the Wasatch in the future. I think we're taking about as conservative a position as we can in this formation.

Subash Chandra - Jefferies & Company, Inc.

There was an El Paso gas gathering line or something that was supposed to come on. Is that on at this point?

Gary Packer

El Paso has a lot of gas gathering. There is one in the general vicinity of the central basin and that is one of the options that Newfield has available to it as we look to develop our infrastructure.

Subash Chandra - Jefferies & Company, Inc.

Last question for me. So reports here in the TXCO's marine shale, any commentary on how ambitious you want to get there, what you might be seeing and what you like about that particular play?

Lee Boothby

I left Louisiana in 1989. [Indiscernible]

Operator

Now, we'll go to John Herrlin with Societe Generale.

John Herrlin - Societe Generale Cross Asset Research

What kind of IP decline rates are you anticipating for the Wasatch?

Gary Packer

Decline rates are pretty steep in all of these. I think 60% to 80%, potentially as high as 85% would not be unreasonable. I think what we see is, and I'm not going to drop the b factors on you, John, but I know you're thinking it. Needless to say that the Uteland Butte has a flatter decline than what we see in the Wasatch, hence the fact that we can come on at a lower IP. And actually, we anticipate having a higher EUR. But thus far -- but 60% to 85% would be in the right zip code.

Lee Boothby

John, I don't if you had a chance to look at the slide deck, but 16, 17, and 18 on the slide decks are the tight curves, and the other point to remember is the Wasatch wells as modeled here are vertical, Monument Butte are horizontal wells.

John Herrlin - Societe Generale Cross Asset Research

With the Green River, what kind of flow rates are you getting? Because you said you'd also consider waterflood. Would it be water steaming, or waterflood's enough to mobilize things?

Gary Packer

The IP rates that we typically see in the Green River is in the order of 80 barrels a day or so. As we've moved to the north, into the central basin area, where we've drilled about 300 wells, those IPs have come up. I'd suggest to you maybe 110, 120 barrels a day would be in the right zip code. We've also seen increased IPs as we downspaced to 20 acres in the field proper where we get into an area that's been pressured due to our water injection. And certainly, in excess of 125 barrels a day is within the distribution of what we typically see there.

John Herrlin - Societe Generale Cross Asset Research

When do you think we'll have something more definitive like you just did with the Uinta on the Alberta basin time-wise?

Lee Boothby

We're going to have to get this work completed. I mentioned that we're going to start the vertical testing operations hopefully within the week. We've got multiple horizons and multiple wells that we're going to be working on and then we'll need a little bit of time on the back end. But notionally we've talked off and on about third quarter. I would expect the earliest to be probably late third quarter, if we can get some time to make sense of those numbers. But somewhere around there, late third quarter, early fourth quarter, I'm guessing we'll have some opinions on what that data is telling us.

Operator

And now, we'll go to Tudor, Pickering, Holt, Brian Lively.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Just is a clarification, there's nothing wrong with the state of Louisiana, is that correct?

Lee Boothby

I'm a proud graduate of LSU in Baton Rouge. There's nothing wrong with the state of Louisiana. I just had heard those rumors were floating around and that's not a shale play that we're chasing. So all of our competitors have got it to themselves for the time being anyways.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Thanks for that clarification. But since you were so open with the TMS[ph], can you comment on maybe other plays like the [indiscernible] [Uinta?]

Lee Boothby

Probably, since you gave me a softball earlier in the Q&A on the Tuscaloosa, I'll just stand down and say that we're not in the Tuscaloosa, how about that?

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

That's helpful. Just going back to Monument Butte and the new plays, and you talked about the geologic characteristics. I'm curious though, what kind of evolution on your interpretation of this play and just how you gain confidence in the spacing and the consistency when you provided the inventory guidance?

Gary Packer

Well, as far as the evolution of the plays, as far as Newfield goes, and I don't know if this is exactly where you're at, Brian, but we entered the play back in 2004 really thinking of this thing strictly as a vertical play with romance of drilling these pad developments in 20-acre down spacing. We did not have a vision for what could lie to the north of the field, which was conventionally thought to be basically devoid of any sands and resource. Now, clearly, not only Newfield but industry's view of that has changed over time as we continue to step out, we took some very early initiatives to step out pretty far from the field proper that we kept quiet, that allowed us to test the section, a township or so away, from our historical control and once we had success there, that gave us the encouragement to go ahead and do a series of joint ventures with the Ute Indian Tribe that we've well documented, 3 of those and then ultimately the pursuit of the H&R deal. I would tell you that for a considerable period of time, we have been looking for where we could apply the horizontal, multistage, stimulation techniques that we were honing our skills on in the Williston Basin and the Woodford, where we could apply that at Monument Butte. We originally targeted the Ute Land Butte in a series of vertical wells with pretty modest success. But fortunately, the team here really pressed on with that and we turned it horizontal, and have seen some nice success there. So it's something that our vision has evolved over time. The broad application of horizontal drilling over this area, we were able to start on that about a year ago. And as Lee alluded to, and in my prior comment did as well, we see other targets here as well on our acreage position that we think we could go sideways in and have some success as well. The other applications that we've used, micro seismic, has given us a good indication of where the fracture systems lie and our ability to stimulate it. And then we also have some 3D seismic that quite honestly, we're probably behind on and the team has pushed forward. And we're applying 3D seismic now in the field, which is long overdue.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

That was really helpful. On the permitting process, I kind of generally understand the difference between federal and state, but can you update us sort of what the run rate is, what's the timing on permits right now between federal and state? And then how tribal land may differ from that?

Gary Packer

So on the state lands, we're typically looking at 30 to 60 days on a state permit based on -- and we've been permitting state wells within Monument Butte for years on the state sections. Generally speaking on the Fed, 6 to 8 months has been a good number depending on the area, of course. It could extend beyond that and I would say that the tribal permits look more like a federal permit than they do a state permit. So, that's kind of how we think about that. We've got probably 400 to 500 permits in at any one time on the Fed and tribal side through BIA. And we're just really ramping up the state permitting process to facilitate 2012 activity for us. So it's really kind of boxed us in a corner in 2011 as far as how much flexibility we've had there.

Operator

And now, we'll go to Richard Tullis with Capital One.

Richard Tullis - Capital One Southcoast, Inc.

Looking at the Williston, Lee, it looked like I guess the average IP rate ticked down a bit in the second quarter versus first quarter. What's the main driver there, particularly with the good well that you had?

Gary Packer

Richard, I think probably the biggest driver, and Daryll jump in on this if you have any more color you want to add, our early drilling was all focused in the Westberg area, where we clearly have the special sauce there in order to drive wells, such as 5,000 barrels a day. As we move out of these areas, we've enjoyed a great deal of success in some of the other areas that we now call development such as our Aquarium and our Watford areas. But our experience would suggest as you move into these new areas, it takes a while to go ahead and really optimize the completions. Each one of these areas are different. We can't apply one technique in one area and anticipate having the same successes immediately in another. So I'd say that's probably the biggest driving factor, is a broader distribution of wells, all very economic but they're not all going to look like each other. It's just going to take us awhile to get our legs underneath this. Daryll, is there anything else you want to add to that?

Daryll Howard

There'll be variations quarter on quarter. As you mentioned Gary, that we expand in the different areas and change that well mix into our high confidence development areas into more of our assessment areas.

Richard Tullis - Capital One Southcoast, Inc.

And what are you looking for in EUR basis and Williston currently?

Daryll Howard

Yes, in our higher confidence areas, in and along the Anticline, I believe that we're in the zip code of 400 Mboe as we step off, I believe we're in the mid-300s.

Richard Tullis - Capital One Southcoast, Inc.

And a strategic question, how are viewing the Gulf of Mexico now, I mean return to drilling or dispose of assets? How is that process going?

Gary Packer

We've been watching it carefully. We've been preparing for what a future drilling program would look like. You've probably seen 2 EPs that were approved for Newfield that would allow us to initiate an APD process. I think we're still watching it carefully. We still need to see some assurance that future lease sales will in fact take place and we're going to understand what the regulatory environment, and just as important as that, what the cost structure is as we look out there. We're concerned at the rig count out there and we've seen some of the better rigs leave the gulf and how we would navigate some of the cost and the regulatory issues still or something that's of great interest for us. And we're going to be I guess cautiously stepping into 2012 as the best I could describe it, as we put together our programs out there. We have no approved wells in '12 at this time but we're going to have some opportunities to invest for sure.

Richard Tullis - Capital One Southcoast, Inc.

Finally, what's the potential for adding additional acreage in Uinta?

Lee Boothby

Well obviously, if you'd asked us that question some years ago, we'd have said, "Well we hope that we're going to be able to add acreage and have great aspirations in that regard. But when you look at acreage position we've built, we now run from Monument Butte in the south all the way to Altamont Bluebell on the north. There's just not a lot of acreage left in and around that area. But clearly, if we've got the opportunities to add acreage, we'll continue to do that if it makes sense economically. But I wouldn't expect any huge incremental gains in terms of acreage blocks in the Uinta.

Operator

Our next question comes from Gordon [indiscernible] with Wells Fargo.

Unknown Analyst -

Couple of more Uinta questions for you. Looking at Uteland Butte, it looks like your wells today have been concentrated kind of in the western portion of the Monument Butte field. And just wondering if that's more of a function of permitting or how you look to spread the wells out over the next couple of years there?

Lee Boothby

First up, I'll take the lead in, and then I'll let Gary and Daryll add some additional color. I mentioned in the earlier comments that the team is pushing to accelerate activity in this play. Some 2 years ago, and we had to ask them to be patient, put the brakes on and the reason that we started drilling in Monument Butte proper is because we were able to do it somewhat off the radar screen. We did get asked, I think a year or so ago, about the horizontal well that we had drilled. And we acknowledged that we had in fact drilled the horizontal well. We didn't say anything more about it. It was one of these wells. It was an area to go ahead and start testing. We had permits, we had infrastructure in place. It was just an easy place to go ahead and do that without drawing attention to what we were really interested in, which is the acreage further to the north. So we had to be very judicious with regard to how we approached that and our team had to be very patient because frankly, we held them back from what they might have otherwise like to have done in that regard. So we're happy to be at a point now where we're able to talk about the play. And I think the team's happy to be at a point where they're going to be able to stomp on the accelerator. Gary?

Gary Packer

That was well said, Lee. The only thing I would add to that is our early focus on state sections allowed us to kind of fly under the radar screen, as you alluded to and execute those permits, which are different from what we've historically done out there.

Lee Boothby

I'd also remind you it's a huge area. We used to show Monument Butte proper. We'd talk about Manhattan in terms of size and scale. And if you look at the scale on the bottom of the map on Page 8, there's 10 miles or so diagonally between the wells and we've already tested a pretty significant sized area within Monument Butte proper.

Gary Packer

And the wells that we've drilled to the north, both those that we now have modern technology logs on throughout the central basin, whether we drilled the wells or even some of our recent drilling has confirmed the presence and our geological models as we push through the north. So we'll be heading up there here in short order and getting some horizontals drilled on that new acreage.

Unknown Analyst -

One other question on permitting, as it relates to the tribal lands. We've heard from other operators in the area that there's sort of a consortium going on between industry and the BIA trying to streamline the process. I'm just wondering if you're participating in such a process. And how you think that might streamline?

Lee Boothby

I'll let Daryll take that question.

Daryll Howard

Yes, Gordon, we work with the Ute Tribe continually. There has been multiple consortiums that attempt to streamline the permitting process. I can tell you that we do participate in most of those from a discussion standpoint, but we also work individually with the tribes to make sure that we're doing all we can to facilitate the streamlining of the permitting process.

Operator

And ladies and gentlemen, that is all the time that we have for questions today. At this time, it is my pleasure to turn it back to Mr. Boothby for any closing or additional remarks.

Lee Boothby

It will be short and sweet. I'll just thank everybody for your time, your interest, and investment in Newfield. And we look forward to reporting on additional results as the year unfolds. Thank you very much.

Operator

And ladies and gentlemen, that does conclude our conference call for today. We thank you for your participation.

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