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Executives

Lee K. Boothby - Chairman of the Board, Chief Executive Officer and President

Gary D. Packer - Chief Operating Officer and Executive Vice President

Stephen C. Campbell - Vice President of Investor Relations

Analysts

David W. Kistler - Simmons & Company International, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

William B. D. Butler - Stephens Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

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

Dan McSpirit - BMO Capital Markets U.S.

Newfield Exploration (NFX) Q3 2012 Earnings Call October 24, 2012 9:30 AM ET

Operator

Good day, everyone, and welcome to Newfield Exploration's Third Quarter 2012 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 2011 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 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 K. Boothby

Thank you, and good morning, and welcome to Newfield's Third Quarter Conference Call. We've had a good year and are well along on our journey transitioning to an oil company. Our shift to oil began in mid-2009 when we made the decisions to defer activities in natural gas and focus on cash flow generation from our oil and liquids-rich assets. This has not been an easy transition. In fact, it's much easier to grow production and reserves than the development of natural gas assets. I know we're making the right economic choices to create the most value for our shareholders over the long term.

Our list of year-to-date achievements is growing. We've seen solid execution in our field operations. Our teams have done a great job of executing at the field level in each our core areas. We've delivered on our promises and raised our production guidance throughout the year. We've delivered strong results from our Cana Woodford play. Our South Cana wet gas results demonstrate that we are development-ready, and our exciting assessment program is evaluating the oil and liquids phase across our growing acreage position. We'll share more details with you later in today's call.

We're working to unlock the vast potential of the Utah's Uinta Basin. We're assessing multiple horizontal plays north of our Monument Butte field in an area we call the Central Basin. Here we are fortunate to have an oil sub-stratigraphic column that span several thousand feet and multiple oil plays are being tested. We're very encouraged with the results from our first 2 horizontal wells in the Wasatch.

Our SXL wells in the Eagle Ford are pointing to EURs of more than 500,000 barrels. Our SXL campaign in the Eagle Ford has been successful and we plan to increase our investment in the region in 2013. We've improved on our execution and are delivering outstanding results from the Williston Basin.

Today, we have reduced our days-to-depth to just over 20, lowered well cost, transitioned to pad drilling, optimized our completions and decreased the number of days up from rig release to oil -- first oil sales. Combined, these sections have dramatically improved our returns and we plan to increase our activity level in the Williston in 2013.

Our 2012 volumes benefited from significantly higher-than-expected oil production offshore Malaysia. In fact, our current estimates are about 1.5 million barrels higher than our beginning-of-year expectations. This achievement is the combined effect of better-than-expected field performance and proactive steps we took to accelerate oil production in net present value. We've improved our focus through the continued sale of nonstrategic assets. Over the last 18 months, we've monetized nearly $1 billion in properties. The most recent transaction was the sale of our remaining Gulf of Mexico assets. These assets contributed about 14 Bcf to our 2012 volumes through closing. Although we sold our shelf assets in 2007, the recent sale of our remaining assets in the Gulf was the final chapter in a 25-year story. The Gulf was damn good to Newfield over this quarter century. We got our start there, grew up there, made a lot of money over the years. This success allowed for expansion into onshore regions and internationally and served as the foundation for the development of today's portfolio of assets.

Our asset sales since 2007 have allowed us to better focus our people and our capital on plays for our future, while providing the funds to bridge the delta between our cash flow and our annual capital investments during our transformation. Proceeds are being used to aid our transition to oil and accelerate our domestic liquids growth.

When we embarked on our journey to oil in mid-2009, we knew that our absolute production growth rate would suffer. In fact, periods of flat-to-declining absolute production were anticipated. But we knew that our focus was on the right commodity, oil. And we had confidence that our investments would be accretive to cash flow and would add value over the long term.

As I mentioned, one of the keys to our recent oil growth has been Malaysia. In 2012, we benefited from flush production from new developments and the acceleration of our plant development drilling at East Belumut and East Piatu. In addition, debottlenecking the downstream infrastructure at East Belumut allowed for volumes to increase dramatically from this field, which has already produced more than 25 million barrels to-date. Our gross production in Malaysia recently crusted 78,000 barrels of oil equivalent per day, and our net production from our international operations is today about 36,000 barrels of oil equivalent per day.

These volumes are significantly higher than our beginning-of-year expectations. In fact, our Malaysian volumes are expected to be up 50% this year. I applaud our international team for the innovative work they have done over the last year to take us to new highs. The timing of this increase was well timed with the strength of the Brent oil prices.

These are very lucrative investments and we achieved payout in only 9 months at East Piatu, our most recent oil development. At East Belumut, the field paid out in about 1 year and has already returned more than twice our initial investment. These fields will experience natural declines from their recent production highs in 2013. Due to the fact that we accelerated our 2012 production in Malaysia, while simultaneously benefiting from higher oil prices, the change in our net revenue interest in 2013 will occur earlier than originally anticipated. Essentially, our net production is dictated by terms of our various production-sharing contracts. As a result, we expect that our 2013 international oil volumes will decline up to 25% from 2012 levels.

We're confident that our international oil volumes will show strong production growth again in 2014 and beyond driven by our Pearl oil field development offshore China, which will commence production in early 2014 and add about 15,000 barrels of oil per day net at peak production. In addition, we have several new oil and gas initiatives underway in Malaysia today. However, we are not yet in a position to disclose those details.

Onshore in the U.S., I'm encouraged with our progress to-date and I'm very excited about the potential of the oil and liquids-rich plays in our portfolio. The Uinta Basin, the Williston Basin, the Cana Woodford and the Anadarko Basin and our Eagle Ford program in South Texas, driven by our recent SXL success. The work in 2012 was dedicated to rapidly assessing these areas and expediting their move towards ultimate development. I'd be remiss not to point out that on October 5, the very day we closed on the sale of the Gulf of Mexico's deepwater assets, Newfield achieved a new all-time high to-date production rate of 923 million cubic feet equivalent per day. Post the Gulf asset sale, our production is now 52% oil and liquids. We still expect that our total liquids growth will be up 30% in 2012. As we say repeatedly, it's not just about absolute production growth that matters, it's cash flow growth and that's our singular focus today.

As to our planning for 2013, I can tell you that we're working on various budget scenarios and we'll have the specifics to share with you soon. I can assure you that our people and capital will be aligned to exploit our best oil and liquids-rich assets. I'm confident in our ability to continue to show strong growth in our domestic oil volumes. For 2013, we expect that our domestic oil volumes will again grow by more than 20%, which is consistent with our liquids growth trend over the last 4 years. Before we move to operational highlights, I'll quickly cover our financial results from the third quarter.

For the third quarter of 2012, we reported a net loss of $33 million or $0.24 per share. The loss was driven primarily by 2 items: first, we had an unrealized loss in commodity derivatives of $85 million after tax or $0.63 per share; second, we had a onetime charges of approximately $20 million that were reflected in the cash expenses for the quarter. The largest component of this was associated with the tender in early redemption of our notes due in 2016. Stated without the effect of these items, our net income in the third quarter would have been $65 million or $0.48 per share. Revenues for the third quarter were $615 million. For the period, nearly half our total production was oil and liquids, and that accounted for about 80% of our company revenues. Cash flow for the period was $308 million.

We continue to focus on growing oil and liquids volumes. Oil and liquid liftings in the third quarter of 2012 were up 20% over the comparable period in 2011 to 6.1 million barrels or an average of about 66,000 barrels of oil per day. Our NGL volumes for the quarter were about 700,000 barrels or about 6% of our total production. Our natural gas production in the quarter was just under 39 Bcf, an average of about 420 million cubic feet per day. Natural gas volumes year-over-year have fallen about 14%. We realized $3.41 per Mcf in our natural gas sales during the third quarter, $91.50 on our oil liftings and NGLs were sold for $26.71 per barrel. We'll be happy to address any specific questions related to our financials at the end of our prepared remarks. I'll now turn it over to Gary Packer, our Chief Operating Officer, for a few operational highlights.

Gary D. Packer

Thank you, Lee. Let's start with an update of an area that has certainly been thrust into the spotlight of late, the Cana Woodford. We are very encouraged with our results to-date. We're currently running 4 operated rigs in the area. We did a pretty good job of keeping this play quiet for much of the last 2 years. Over that time, we were able to amass a sizable acreage position. Since the last call, we have increased our acreage by an additional 7,000 acres. We now hold 142,000 acres. We included some new wells on last night's operations release and also updated production on the wells we've previously announced to include 100 days or so of data. Our controlled flowback techniques are keeping reservoir pressures higher, allowing for very strong flow rates over an extended period of time and enhancing ultimate recovery of hydrocarbons in place.

Our acreage today is in the heart of the play. In addition to the 10 wells we have released to-date, we have participated in about 40 industry wells operated by others, of which 25 are producing to-date. Our interest in these outside-operated wells has also provided us with increased confidence about the quality of our own acreage position. The lion's share of our activity to-date has focused on our southern acreage which covers about 80,000 net acres. One of Newfield's undeniable core competencies is our drilling completion expertise. By applying lessons learned in horizontal drilling throughout our focus areas, we have made huge progress in reducing days versus depth and total well costs. Our first well in this play took about 100 days to drill. We are now drilling in casing wells in just over 40 days. We know from experience that there is still ample room for improvement as we move this play further into development. Based on production so far, we estimate gross EURs of between 1.1 million and 1.9 million barrels equivalent. With the current cost and commodity prices, this results in 35% to well over 50% rates of return.

We also are actively assessing the old window along trend. To the north, we see the potential for a development with very high oil composition. In yesterday's release, we highlighted our first 10,000-foot lateral well drilled in the north area. This SXL well called the Klade has an additional -- has initial gross IP of about 925 barrels equivalent per day and a 30-day average of over 600 barrels equivalent per day. The production stream on this well is over 90% oil.

We have proven time and time again that extended laterals improve returns, and we will continue to drill SXLs through our acreage position. In addition to the prolific Cana Woodford play, we have other creative ideas to test and exploit [ph] in this thick stratigraphic column present across our acreage position. We are also close to finalizing a midstream deal that will give us the required capacity we need to march forth with aggressive development. We expect that our ultimate NGL pricing will be tied to Mont Belvieu and not the Conway hub. More on these details later this year as they get inked and put into motion.

Before we lead the Mid-Con, I want to point out that earlier this year, we moved one of our operated rigs that was running in the Cana over to the Granite Wash to test for Hogshooter play. Our first well was a barn burner with an initial gross production of more than 5,000 equivalent per day -- barrels equivalent per day. This well has averaged about 4,200 barrels a day over the first 30 days. Our working interest in this well is about 100%. We have a rig dedicated to the play now and we will be drilling -- and we are drilling our second well currently.

Now let's move to the Uinta Basin where our production is now 39,000 barrels equivalent per day gross or about 30,000 barrels of oil per day. In yesterday's release, we reported encouraging results from our first 2 horizontal Wasatch wells. The Wasatch is a high potential formation that spans more than 1,200-foot in thickness and has several specific targets. As you know, we've been actively assessing the Wasatch over the last 18 months and have drilled 35 vertical wells to-date. These vertical wells are highly economic and are providing us with comprehensive data along the entire stratigraphic column. History also tells us that we can enhance ultimate value creation through horizontal exploitation. Our 2 initial horizontal wells were drilled about 5 miles apart and tested the same geologic horizon, the uppermost portion of the Wasatch. Gross initial production from these wells has averaged about 1,200 barrels of oil equivalent per day and the composition was 88% oil. The wells' average 30-day production was about 750 barrels of oil equivalent per day gross and the 90-day average was about 625 equivalent. We are impressed by how production from these wells has held up over the 90 days and are anxious to drill additional horizontal wells.

Now when making comparisons to our 40 vertical wells to-date, it's critically important to consider that the fact that these completed laterals in these wells has only averaged just 3,200 feet. As we have mentioned more than once today, the key to ultimate economic success lies in longer lateral completions. When we project potential flow rates to 5,000 or 7,500-foot laterals in the Wasatch, I get awful excited. Our collective energy is being channeled to make this happen as quickly as possible. We are now working with regulators on a plan to allow for 1,280-acre units in long lateral lengths for ultimate field development.

As we have proven time and time again, longer laterals will provide positive benefits for all parties, like the higher percentage -- like a higher percentage of total developed acreage, reduced surface disturbances, higher recoveries of oil in plays, increased private and state royalties and increased production and severance taxes. We will keep you apprised of our progress as we move ahead. Over the next several months, we expect to spud 2 additional horizontal Wasatch wells. We will continue with an active vertical campaign as well.

In yesterday's operating report, we also provided an update on our Uteland Butte horizontal drilling program in the Central Basin. To-date, we have drilled 2 dozen wells in the play, about half of them are in the pressured areas. This play will continue to be actively assessed next year. Our strongest returns to-date in the Uteland Butte have come from the pressured regime where we have more than 70,000 net perspective acres. We've seen flow rates as high as 1,500 [ph] barrels of oil equivalent per day and oil content upwards of 90%.

And now onto Eagle Ford. We recently turned to sales our fourth SXL, and the early data looks consistent with our previous 3 wells. The most recent well averaged 730 barrels of oil equivalent gross over its first 10 days of production. Our super extended laterals in the Eagle Ford have performed extremely well. The wells averaged -- have averaged 530 barrels of oil equivalent per day over the first 180 days. This translates to an EUR of more than 500,000 barrels. Again, we are using controlled flowback to manage the production, limit pressure drawdown and maximize EURs. Our South Texas drilling team is able to drill and case these wells in 12 days for less than $3 million. We are seeing some relief in completion cost and expect the favorable trends to continue into 2013.

Once in the development mode, we reiterate our belief that we can drill and complete 7,500-foot lateral wells from common pads for less than $8 million gross. Our Eagle Ford SXL wells to-date generate internal rate of return between 35% and 50%. We are confident returns will further improve as we continue to apply our learnings timely to create value.

For 2013, we will be increasing our planned development activities in the Eagle Ford and expect to drill as many as 35 wells. In addition, we will be working more than 200,000-plus net acre position into the economic window. I'll now turn it back to Lee.

Lee K. Boothby

My apologies for the call in there. We weren't brave enough to hit the do-not-disturb button but Shell Trading apparently was trying to call into our call so, hopefully, they'll call back to the right number a little later. We'll continue on. So, thank you, Gary. And thank you to all of you for your investments in our company. We're excited about the results we're seeing today and our onshore focus areas. We entered 2012 with a game plan that called for rapid assessment of new liquids plays in the Cana Woodford, the Uinta Basin and the Eagle Ford. Our results are very good and we have very strong returns in each of these areas. We will continue to allocate our capital to these years and drive strong domestic liquids growth from our portfolio. We're confident that this is the right decision to create value for our shareholders, and we're going to continue working hard to make it happen each and every day. This time, we'll open it up to questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] We'll go first to David Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly focusing on the international production down about 25% in '13. Can you give us just a rough estimate on what you think that's going to do to corporate EBITDA and how we should be thinking about that with respect to capital spending for '13, and your comments on living within cash flow?

Gary D. Packer

Well, that would be, of course, the barrels there are going to be missed from a cash flow perspective, but we, so far, have not set our capital budget for 2013. As we go through that process and decide how to allocate capital, both domestically and in the international arena, we'll be in a better position to share thoughts on that with you when we come out with our capital plan in '13. But probably there would go -- will be a few barrels that won't be delivering revenue in 2013 as a result of having produced those barrels in 2012.

David W. Kistler - Simmons & Company International, Research Division

Okay. Maybe just to dive into that a smidge more though, looking at the EBITDA contribution from your International business, I would speculate it would probably, with the exception of asset sales, lead to CapEx being down on a year-over-year basis. Am I off the mark on that?

Gary D. Packer

Well, if we used EBITDA as one component or our cash flow as one component of the sources for CapEx, then we'd have to clearly say that there is a lesser amount there to fund CapEx. But we have other alternatives, and again, we haven't established the 2012 -- 2013 capital budget for neither the international or domestic piece. And prior to doing that, it would be premature to say what the implications on our CapEx budget is going to be.

Lee K. Boothby

Dave, we've got our Board Strategy Session in early November. So we're not going to comment much more than that until after we've had a chance to play out our process to go through internally. We're on the same schedule that we've been on for what seems like forever and a day. We'll go through that session, we'll work our plan and when we get our 2013 details put together, we'll share them with you. But we wanted to give everybody a heads up on accelerating 1.5 million barrels into '12. We can't manufacture barrels so we're accelerating activities that impact 2013. Net-net, it's been a positive. We've got some challenges there in 2013 and we've got some options. So let us work through our plan and we'll give you more details at an appropriate time.

Gary D. Packer

I would just -- one other thing, David, and that is in the context of -- we're talking about growing our domestic production oil at the same pace [ph] or better than we have in the past and so those barrels deliver a lot of cash, just like the international barrels. So, you do have a very rapidly growing cash flow stream from the domestic production.

David W. Kistler - Simmons & Company International, Research Division

I appreciate that clarification. One just a quick one if you can, on the Cana forest, if you can kind of walk through the latest cost on the super extended laterals there, kind of well design. And then are you guys going to be trying to target specifically more of an oil window than you have in the past? Or do you have enough well results to be able to delineate what is a larger portion of the oil window there?

Lee K. Boothby

Well, we would tell you that clearly, David, you recall that we entered 2012 with a strong assessment program in the Cana Woodford. We did focus most of that capital spending in '12 down in the south for obvious reasons, and we've gotten really good results. I think our team has, over the course of the last year, grown our production out of that area to upwards of 10,000 barrels of oil equivalent per day from a standing start. So we've got good momentum there and good, strong well results but we are going to have to continue to assess the various regions of the play as well. So you'll see a heavier emphasis on development going to '13, but we're going to continue to step out and evaluate our acreage. You'll further recall that we -- when we put that position together, we talked a lot about this over the last year that about half of our acreage we felt was in the wet gas condensate window and about half of it was in the oil window. So clearly, as we move through the acreage block, we're going to have a distribution of wet gas and oil. We'll just have to drill the wells, get the results, and then we can give you a stronger opinion in terms of how to think about the portfolio distribution between those 2 phases. But also I'll let Gary comment on the cost and then we'll move on. [Operator Instructions]

Gary D. Packer

Gary again. Yes, Dave, as far as the cost go, in the Cana for development, we're still targeting something a little over $9 million a well. Well cost by industry and certainly, we're no exception in 2012, a bit higher than that -- have higher than that as we've climbed that learning curve, really happy where we sit right now. Our wells are a little longer than what industry has drilled . We're about 4,700 feet with industry drilling about 4,000-foot laterals. I would have to be projecting for you to talk about the SXLs. So if you allow me to -- the fact that we've only drilled one of these, these wells would be about 7,500-foot or so. I would expect EURs to rise considerably from the 1.9 million-barrel range that I spoke about earlier. These wells would be 2.5 million to 3 million barrels or so and the well cost would probably, on a development basis, move up from that $9 million a well or so to probably something that would be more in the order of $11 million for that 3 -- that 2.5 million to 3 million barrels. Very, very strong economics. Some of the best we would see in our entire portfolio.

Operator

We'll go next to David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

A couple -- let me spend my bullets on the Uinta. If I look at that, and I know it's early, but the Wasatch versus the Uteland Butte, it looks like those first 2 Wasatch wells, and again it's only 2 wells, but it looks like they're tracking above the Uteland Butte. Are you seeing anything different? Or what's different zone or can you talk any more about the difference between the 2?

Gary D. Packer

I would share the same observation, as you, David. The wells are tracking slightly about -- above the Uteland Butte. It's really too early. With 2 wells, that's all we have to deal with. As you're probably familiar with, there's a whole series of stack zones and it's very important -- you don't have the level of continuity across the acreage position in the Wasatch so you're relying on frac-ing across multiple intervals. We've proven in our first 2 wells that we can do that. I certainly wouldn't say 2 wells demonstrates the consistency by which we can deliver that production but we're highly confident, and as I said in the earlier, we're going to go ahead and drill several wells over the next few months and validate that. The benefit of the Uteland Butte is the fact that we see a high degree of continuity across the acreage position. So at this point, I would tell you geologically, high continuity across the entire acreage position in the Uteland Butte, still driving to improve our completion techniques, which will ultimately really drive the return there. Wasatch, a little different. Really focusing on getting the wells drilled to the entire length, more diversity, geologically. But certainly, really like what we see to-date, and yes, it looks like it would generate a return that would be a little better than we would see in the Uteland Butte.

Lee K. Boothby

Yes, David, Gary touched on it in the call. I'll just throw this in. Remember the 35 wells that we drilled in the vertical section, they're completed in multiple intervals within the 1,200-foot section. I think, on average, we've had a half a dozen completion intervals in each of those wells. So we're getting a pretty good data set to know that we're moving oil out of a significant total percentage of that 1,200-foot from the vertical wells. A key next step is going to be working through, getting to the point that Gary talked about where we can drill the longer laterals. That's really where you get the leverage out of it, but we're very excited. It's only 2 wells. It's the only 2 wells we have but a good place to start.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And then for a follow-up, a year ago, and Steve this is similar question I asked you last night, but a year ago, you guys 5 to 6 rigs running, you thought you were going to ramp to 8 to 9. You've kind of stayed at the 5 to 6. Can you just talk about why the lower rig count this year versus what you had previously expected, what's driving that?

Stephen C. Campbell

Sure. I think it's a good question, David. We look to capital allocation. We look across all the investment opportunities we have in the company. You're well familiar with our commitment to live within our resources. As we looked into this year, we were assessing multiple areas, both in the Cana, the Eagle Ford and the Uinta. What we saw this year was there's a high degree of consistency in the results that we were getting out of the early Eagle Ford and the South Cana. As a result of that, we made sure that we pounded away at those to deliver the production commitments that we had made. What we've of served in the Uinta is that we really like the results that we're seeing, but we still haven't narrowed in -- narrowed down that distribution. We're seeing results both extraordinarily high and we're seeing some poorer wells as well. So we've made the decision as we -- going into the back half of 2012, and you'll likely see this as we enter 2013, is to continue to drill more wells there, but we need to refine the distribution. I would caution you to not count rigs. I would tell you this year -- next year, we will drill more wells in the Central Basin than we drilled -- horizontal wells than we drilled in 2012. We're just seeing some pretty incredible improvements in efficiencies that allow us to drill more with less as well.

Lee K. Boothby

And other thing, David, one of our objectives going into this year was to have multiple developable oil plays within North America. So exiting '12, we've got good strong success in 4 areas, and I think it takes some of the near-term stress off the Uinta so that we can take that methodical march through the assessment program, get our learning curves in order, as Gary indicated, and be prepared to ramp up as the refining volumes start coming available late '13 and '14 going into '15. So I think we're in good shape there and we'll continue pressing ahead, but I like the fact that we've got 4 areas we can allocate capital to this year relative -- excuse, going into next year relative to oil in North America.

Operator

We'll go next to Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just a question on the Cana here. Trying to get a sense of what percentage of your 142,000 net acres in the play has been de-risked at this point?

Gary D. Packer

Well, Leo, the area that we have the most well control to-date by both Newfield and industry would be the 80,000 or so that we have to the South. So clearly, that's the area that we would feel most confident right now. If you look at the entire area, Newfield has participated in about 46 wells that have been drilled in that 80,000 acres, of which about 22 are on production. So my highest confidence is there. There are certainly holes in that 80,000 that we have to fill in through additional drilling, but it's the area that we have the highest confidence. As we move to the north, Newfield in the oil window, which is what we'll be targeting, only has a handful of wells. Really, our second well that we drilled up there, the oil window, this Klade, that's the 10,000-foot well. So I would advise you that the balance of that acreage position, we like what we see in the oil window but we certainly need more drilling before we can call it a development play and it's still very much assessment.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, thanks. And I guess unrelated question here. Just trying to get a sense of what your well cost was on the first Hogshooter well. And maybe you can you talk about well cost in the horizontal Wasatch and the Horizontal Uteland Butte currently.

Gary D. Packer

In regards to the Hogshooter, that well cost us a little over $8 million. And if you go back and you want to talk about the Cana, I think you specifically referenced the horizontal Uteland Butte wells and the Wasatch. The wells in the horizontal Uteland Butte in the geo-pressured section, and I think this is a good proxy for the Wasatch as well, those wells will be somewhere in the vicinity in the development mode of about $5.5 million or so. Just like I referenced in the Cana earlier, in 2012, our cost have been higher there because we are drilling -- these wells were never drilled before 2012. So we certainly had a learning curve. So you can add a couple million to each of those as you think about the actual realized cost in 2012. But when we think about the depth of the portfolio and several thousand locations we have, we're really targeting a $5.5 million well. The rest of it is really investments for science.

Operator

We'll go next to Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

First question is on the '13 international oil volume outlook. How much of that is related to production declines expected at the sea level versus the net oil number you show having reached payout? And if it is a payout issue, does that change as you get some exploration success or is everything ring-fenced?

Lee K. Boothby

Let me jump in and I'll let Gary give you whatever details that I leave out. I think the PSE structure, as you return capital from the project coming online, you go through a series of payout tranches, if you will. Generally, as the projects have returned the capital, you get to lower net revenue interest, so lower net barrels coming back. So a portion of the decline year-over-year because of the acceleration is related to that activity. The other piece of the puzzle is that we've had the benefit of flush production in a couple of these key fields and they've way outperformed. So we know going into 2013, one would expect that you'll see natural field-level declines. I'm going to guess that, off the top of head, and Gary can set this straight, but I'm going to guess that from what I've seen that it's somewhere around 50-50, 40-60 depending on how you slice it because remember price -- product price is part of the equation as well in terms of determining net barrels. So if you could tell us the oil price, we can probably nail it down closer than that. But I think that's a reasonable proxy.

Gary D. Packer

I think you're pretty close, Lee. Certainly a majority of the decline is something that we have not observed yet in our East Belumut PM 323 field. This is the area that we've accelerated now into our third phase of development drilling. We're observing the movements in context [ph], but the well -- the field is producing great. But just doing the modeling that we've done, we would anticipate that we would come off plateau in 2013 and that's what's been baked into our numbers. Your observation on additional investments, we have a Phase 4 drilling campaign. If we were able to get Phase 4 approved, that would result in incremental capital, a change in the payout structure, and we could see our net the barrels increase as a result of that investment that we would make but that is something that's not approved yet.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just a follow-up question on the '12 CapEx. Are you still comfortable with the $1.7 billion, and if you can just confirm that's a growth number, not a net CapEx number, and then just timing of when you will be putting out the '13 guidance.

Stephen C. Campbell

Yes. We're still within the guidance range on capital that we previously communicated. In the vicinity of $1.7 billion, that's correct.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

And -- I'm sorry, and '13 guidance is -- I know mentioned soon. Is that December or February?

Lee K. Boothby

Well go through the process in November. Generally, we take the input from the board, refine that process through year end. Historically, we'd come out, generally, in early part of the year, notionally, February with guidance. I would tell you it would take place likely sometime between year end and February we'll be in a position to communicate.

Operator

We'll go next to Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

First on the Maverick Basin, what was the cost of that extended lateral? And remind me if this was a normally pressured part of the play or not.

Lee K. Boothby

Well it's -- as far as the cost, I'll let Gary get to you on the cost. The Eagle Ford that we're drilling, first of all, our acreage is all in the oil window, so it's black oil and it's all slightly overpressured, I guess, relative to normal. I don't have the number, but I'd say slightly overpressured relative to normal.

Gary D. Packer

Yes. You're right on the pressure, Lee. In regards to the well cost, we've only drilled one well. So you have to put it in that same population like I was talking about the Klade, the 10,000-foot well there. You ought to be thinking about a well cost as we get into pad development within the 7,500-foot, which is what our wells have been to-date of the something in the vicinity or right under $8 million, that's what I believe we'll be drilling our wells for. When we step out and drill the 10,000-foot laterals, those wells will be in the $9 million to $10 million window. Now because of the configuration of our acreage position, we will not be able to go to entirely one well or another. I would tell you, you should be thinking about the vast majority, maybe 3/4 of the wells in the play to be in and around the 7,500-foot lateral. Balance is filling in the corners, and to the greatest degree possible, 5,000 and 10,000-foot laterals.

Subash Chandra - Jefferies & Company, Inc., Research Division

And final one for me, is there a reserve impact on -- for the Malaysian PSE?

Gary D. Packer

No. There's no reserve impact. Those values are all calculated into the numbers we have at year end. Of course, every time you prepare a reserve report, you use a price at that point in time. So depending upon what the pricing will be for this year end, the volumes in those contracts, regardless of field performance, go up and down purely as a function of price. So it'll be a combination of the 2, but we've already accounted for those in our reserves.

Operator

We'll go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Going back to one of the earlier questions on South Cana, Woodford. Are you seeing a major difference in well costs in the wells that are tracking 50% or more oil versus those that are tracking 30% or less? And can you talk to whether you feel that can isolate the higher liquids wells from a drilling program, and what percent of your southern acreage that represents?

Gary D. Packer

We've got a lot of questions in there, Brian.

Lee K. Boothby

A lot of questions in the assets. I hope you remember them all.

Gary D. Packer

We do not see a material metal difference in the well cost between an oil well and a wet gas well, okay? In regards to our ability to distinguish between wet gas and oil, certainly there's a difference as we move from the shallower. If you think about an east-west look through the play, whether it's in the north or the south, we see the oil window somewhere in the vicinity of 8,000 to 12,000-feet or so, and you see the gas window coming in at about 12,000 feet down to about 6 [ph] feet. If you look at our acreage position, there's only a few thousand feet difference between what we would place from TVD standpoint between the oil and the wet gas. There is not a big difference. We are still defining exactly -- we had some lines drawn that we thought we had a pretty good understanding of where the oil wet gas line was. We've recently completed 3 wells, some of which are in the materials we've released to-date that would demonstrate, it's kind of a blurred line. And so I would have to kind of visit -- get back with you later we'd -- to really see what the relative proportions are. In general, I'd say you're probably 2/3 wet gas to 1/3 oil. But that's still something that's changing.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, that's helpful. And if I'm allowed a follow-up after my 3 questions, first question, can I ask on the Hogshooter, you mentioned in the press release 90% of the 5,100 BOE a day was liquids. Can you talk about the NGL oil split there and repeatability?

Gary D. Packer

Yes. I mean, what I'll tell you is, is just some -- I have a 40-day number handy. So that 40-day number is, as I referenced earlier, about 4,000 barrels equivalent per day. The constitution of that was about 2,650 barrels of oil, 780 barrels of NGLs and about 3.9 million cubic feet a day. And that's a 40-day average. So that's, what, 75% oil, 90% liquids or so.

Operator

We'll go next to William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

In terms of the Eagle Ford, and you all broadening the acreage that you think is perspective from recently 40,000, I believe, up back towards the 230,000, can you all be more specific on what has changed for you all to you make that area more perspective in your minds? Is it well cost? Is it completion methods? Is it offset operators? What combination of sort of if you could rank them, what's changed and where are you so much more positive on it?

Gary D. Packer

Yes, well, let me clarify something you said there. We are not projecting now that the 200,000 acres is de-risked by any means. So let's first focus on the acreage position that we've been very active in. The biggest thing that's changed for us between 2011 and 2012 is the length of the lateral that we've drilled from 5,000 to 7,500-foot and probably more importantly than that, the great work that our completions teams have do in trying to figure out that special sauce that it's going to take to unlock something that is different from the Gulf Coast basin. We're really pleased with what we've done. And it's not just one thing. There is a number of things that they've gone to really unlock that and really create the value there for us. So our reference to the 200,000 acres in the balance of that acreage position, we'll be moving into a shallower section. It's certainly still all black oil, and what we'll be doing is applying for the first time these enhanced completion techniques that have worked so well for us on the 40 to that broader acreage position. We will be careful early on. We're going to moving up into the McKnight area. We'll still be staying in largely Dimmit and Zavala County. We'll drill a few wells early in the year. We'll assess those results, and if they look encouraging, we'll continue to expand that position where we try this new technique. But it's still early days in that regard.

William B. D. Butler - Stephens Inc., Research Division

Okay. And then you all mentioned there the 500,000 barrel EURs. So over what acreage position does that number apply then?

Lee K. Boothby

Well, I would tell you that the safest place to start is start with the 40,000-acre position that Gary was talking about. We said that, that position was a developable before we had, had this success and this success certainly enhances those results. The ultimate spacing in terms of a lateral offset between wells, our team's still working through pilots in that regard. That will have a -- be a factor in terms of the total well count and a totally EUR ultimately. We'll keep you apprised as that develops. Saying, greater than 500,000 barrels says that we're very confident with 500,000 barrels and there upside beyond that and it's going to take time to see what that upside looks like. So we need more time with the wells that we have online and more wells in total to get to where we've got a statistically valid subset. But we're very encouraged. And of the broader acreage position, remember we drilled assessment wells there back in 2010 and early 2011. So we know that, that acreage is oil productive. Our hope, to Gary's point, is that we can transport some of these learnings into those other areas and expand the economic footprint. And I think your question there is the right one. Just watch for an expansion in the economic footprint, go from something 40,000 acres to north of 40,000 acres, and as we've got confidence that it's expanding, we'll keep you updated.

Operator

We'll go next to John Herrlin with Societe General.

John P. Herrlin - Societe Generale Cross Asset Research

Most things have been asked. I was wondering with the Wasatch, whether you could see yourselves being totally horizontal there in the future? That's it.

Lee K. Boothby

I believe the answer to that is, yes, John. I think that we're very encouraged with the vertical well results that we've had, strong positive economics there. Once we get to a more favorable regulatory layout, the 1,280-acre pilots that are in the early stages of being permitted in the basin, I think you'll see a transition over to horizontal drilling. I think the future in the basin is horizontal, but clearly, we do have strong, positive vertical results in terms of economics and there'll a mix as we transition that direction. I'll let Gary give some additional color.

Gary D. Packer

Yes, John, the only thing that I'd add to that is I agree absolutely with what Lee said, that it really goes back to a question that was asked earlier, I think, by Brian regarding the well counts. If you think about 2012, we drilled about 30 vertical Wasatch wells. Due to the success that we've had in the horizontal program thus far, we really have hit the pause button on the vertical program. We'll drill some wells to get the required geological control, but we don't want to fall into a trap where we overdrill the vertical and then we have issues by drilling horizontals in the same spacing. So that is an issue. I would expect us certainly to some vertical drilling in 2013. But it will be a fraction of what we did in 2012 for all the reasons I just said.

Operator

We'll go next to Brian Lively with Tudor, Pickering.

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

I know there's a lot of questions on international, but just have a few more. Can you remind us, in 2012, what is the international as a group? What is that as a percentage of the total EBITDA for the company?

Gary D. Packer

In 2012, it would probably be in the range of 40%.

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

Okay. And so if you think about that for next year, 40% production is declining, I guess, you guys said about 25%. So you are losing that EBITDA. But how much CapEx are you going to deploy in Malaysia next year?

Gary D. Packer

Well the final -- like I said earlier, the final of CapEx that we are going to deploy in both the international and domestic arena is not settled at this time because we're going through those processes. I think Lee mentioned that we have a number of things that we're working on there that we're really not in a position to talk about. They will influence our thoughts around CapEx, depending upon how they come together and the timing of when they come together. The largest component of CapEx that we know is committed is the Pearl development in China and that's all -- China and Malaysia both make up the international component. I'll focus you again on the domestic growth in liquids as the offset to this because our liquids growth in domestic arena, and when we have more liquids in the domestic arena and we're going it in the domestic arena, and it makes up a big chunk as a difference between what we're going to see as a result of the contract terms in international and 2013 and 2014 international is a growing story again.

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

Yes, I'm just thinking about next year in terms of how much capital you guys have put to work this year, what the potential for spending is next year. I'm assuming it's lower than $300 million, which is plus or minus, I guess, what you guys have spent this year and the free cash flow change over that international asset as it relates to your ability to use that free cash to plow into the domestic assets. And so I guess the question is, is, I mean, what other opportunities are you guys looking at in terms of -- are you looking at more asset sales to help maybe fund that gap, if there is, to keep the oil growth going domestically?

Lee K. Boothby

Well, Brian, I'd love to engage and have a discussion on all those points. But again, I've got to respect our process. We've got a board meeting in 2 weeks, we'll talk about all these things. Get board-level support, and we'll work diligently from that point forward to provide you guys with the information that you need. We can't talk about the other things that we've got in the air at this point, and historically, that means that we're not in a position to talk about it. As soon as we are, I think you'll have some clarity on a couple of those questions that you've asked. So we'll keep you apprised. We're just not prepared to say any more than what we've said today.

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

Okay. That's understandable. Just one clarification. When you say 25% product declines next year, do you mean exit over exit or are you talking about average over average? Just a mechanical question.

Lee K. Boothby

I was talking about average over average and I said up to 25%. So remember, we accelerated 1.5 million-plus barrels into this year. One of the ways to think about is if we'd left the plan as it was and hadn't attacked it, that we'd had that distributed over the 2-year period. So our team has done great work there, each of the last 3 years, and they've found a way to outperform. Hell, I'm counting on them again. But at this point, we wanted to at least turn the lights on and let you know that this is an issue that we're working on. We thought it was something that you'd want to know about, and we're going to work it just like we have the last 3 years.

Operator

We'll go to Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

On the subject of decline rates, can you give me an estimate on what the underlying -- what the decline rate is on the underlying gas asset base, the domestic natural gas asset base?

Lee K. Boothby

Oh, I was waiting for somebody to answer. I guess you're talking to me, Dan. I'll jump in. Well, I'll start you with -- we said in the call that 14% is what we've seen kind of year-over-year in the comparable period. Remember we said that we thought natural gas declines this year would be up to 15%. I think we've been just under that during the course of the year. Obviously we're not investing in the dry gas when you think about the dry gas portion being the underlying assets. Year-over-year I would expect the decline rate to be something less than that, kind of in total relative to those assets and then we'll get the offsetting benefits of the associated gas that's going to come onto the equation -- come into the equation with our oil development. So 14% is what we've seen over the last 12 months and I guess 2% to 3% on the base underneath that, but I don't have a firm final estimate at this point. I'll let Gary give you any additional color that he might want to add.

Gary D. Packer

No, I think that's about right.

Lee K. Boothby

Yes.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And as a follow-up, recognizing the relatively low oil cuts at least on the southern part of your acreage perspective for Cana, can you speak to how Cana well produces over time? That is, how does the gas cut and the NGL cut change over time and maybe use the right 1H-9 well as one example since that's the model well and those from the larger sample set. At least an estimate, please?

Lee K. Boothby

Dan, I don't have it in front me this morning but Steve included recently a slide where we went ahead and did the calculations of the -- I'll remind everybody that when we report the oil cuts that those are separated volumes. All you have is the raw gas and the condensate being reported as that cut. So when you go through the conversion through NGLs, the way to do the math is roughly the following: you'll start with your separator volume, shrink those -- excuse me, start with the separator volumes. The yield on those is around 130 barrels per million NGLs. So a $10 million a day type stream would yield 1,300 barrels of NGLs. Shrink the gas volume by 30%. So you'd end up with 7 million cubic feet a day of sales gas, the 1,300 barrels of NGLs plus the condensate that would have been reported. And I think when you go through the math, those low percentage separator yields turn into 2/3 or more total liquids, and I would expect that over the life of the wells that you'd probably track plus or minus 5%, one way or the other, around that midpoint. If you haven't seen that slide, get in touch with Steve and Danny, and they can put it in your hand. I think that it lays all that out relative to the well, but I didn't bring it in here with me this morning.

Operator

Due to time constraints, I would now like to turn the conference back over to the speakers for any additional or closing remarks.

Lee K. Boothby

Well, I'd just like to thank everybody for your interest and investment in Newfield. I hope the takeaway for you this morning is we're very excited about the success that we've had on the operational front in multiple areas with regard to the aggressive assessment programs that we've executed in 2012. We've got great results. We got a wonderful team. They're going to deliver going into '13. It would be the fourth year in a row that we've had a 20-plus percent liquids growth in North America, and we're going to do that again in 2013 and I think the future is bright for Newfield. So appreciate your interest and we look forward to updating you on our progress in the weeks and months ahead. Thank you.

Operator

This does conclude today's conference. Thank you for your participation.

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