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Executives

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

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

Terry W. Rathert - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Analysts

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

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Robert S. Morris - Citigroup Inc, Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Dan McSpirit - BMO Capital Markets U.S.

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

Unknown Analyst

Newfield Exploration (NFX) Q1 2012 Earnings Call April 25, 2012 9:30 AM ET

Operator

Good day, everyone, and welcome to Newfield Exploration's First Quarter of 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 reduction 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. Good morning, everyone. We're off to a good start in 2012 and I look forward to summarizing our first quarter results for you today. As always, we will take your questions at the end of the call.

Before we begin, let me introduce some of the members of the management team with me today. I'm joined by Terry Rathert, our Chief Financial Officer; Gary Packer, our Chief Operating Officer; and Steve Campbell, our Vice President, Investor Relations.

Our story today is relatively simple and is focused on 3 main things in 2012. First, accelerating our transition to an oil company. In early 2009, we started to shift significant resources towards the development of key oil plays. These efforts are paying dividends today and you can see the significant growth in our oil and liquids volumes. Oil and liquids accounted for 47% of our total volumes in the first quarter of 2012, and as we've said before, we have real oil. NGLs only accounted for about 5% of our total production. The second half of this year, we expect that more than half of our production will come from our oil and liquids plays.

Second, throughout our company, our people are aligned to deliver superlative execution in 2012. This means the diligent efforts to reduce cost and expenses where we can; to drill our highest margin oil and liquids plays; and to ensure that our wells are drilled, completed and turned to sales timely.

And third, we remain focused on the strength of our capital structure. These are challenging times in our business, with natural gas prices at decade lows. Our internal analysis does not show a near term rebound in natural gas prices, and we've insulated our company well through hedging, a shift of our people and capital to profitable oil developments, and the timely sale of nonstrategic assets in 2011.

I have confidence in both the quality of our assets and the depth of our prospect inventory in our oil and liquids plays. We have a deeper inventory of opportunities diversified over multiple plays than we have ever had in our history. This inventory is a competitive advantage today, and is being managed by the best people in the business. We're committed to the timely assessment of high-potential plays and executing in our development area. These actions will build momentum and oil growth going into 2013.

Since 2008, we've doubled our oil and liquids production and delivered a compound annual growth rate of 20%. We will do it again in 2012 and have the inventory for sustainable future oil growth in hand today.

On today's call, I will provide a quick summary of our first quarter financial and operating results, followed by some brief updates on our active oil and liquids-rich developments. Let's start with a look at our financial and operating results from the quarter.

Our net income in the first quarter, excluding FAS 133, was $122 million or $0.91 per share. Revenues were $678 million and our cash flow was $387 million. Our oil and liquids liftings in the first quarter of 2012 were 5.9 million barrels or an average of nearly 65,000 barrels of oil per day. This represents a 35% year-over-year increase when compared to the 2011 first quarter results. Our natural gas production in the quarter was 41 Bcf, an average of 447 million cubic feet per day. We realized $3.70 per Mcf on our natural gas sales, and $96.24 per barrel on our oil liftings. In the first quarter, 47% of our total production of 76 Bcf equivalent was oil and liquids. Our NGL volumes in the quarter were about 575,000 barrels or about 5% of our total production.

As I mentioned earlier, we're off to a good start in 2012. Let me offer what I see as our key highlights year-to-date. Our costs and expenses in the first quarter were in line or better than guidance in about every category. We're seeing improved cost structures in our development plays as a result of continued efficiency gains and reduced service cost, primarily in the completions arena. In our assessment areas, costs have moderated, the reduced natural gas rig count and increasing capacity in the service sectors having a positive impact on our bottom line, and we are hopeful that these trends will continue during the balance of the year.

Our production was ahead of our first quarter guidance and reflects the timing of well completions and strong performance across our business unit. Recall that in late 2011, we slowed our operational pace and deferred well completions in several business units to ensure that we held the line on our capital budget. Getting these deferred completions online in early 2012 in areas like the Granite Wash and the Bakken, for example, provided a boost to our first quarter production rates. Although not certain this qualifies as a highlight in lieu of today's gas market, our natural gas production, despite the fact that we're not running any gas rigs in our company today, was higher than guidance.

You can see in our release last night that we took our guidance expectations for the year slightly higher, simply reflecting the strength of our first quarter results. We now expect that our full year production will range from 292 billion to 302 billion cubic feet equivalent. Our range of expectations for capital spending remains unchanged at $1.5 billion to $1.7 billion, and our expenditures in 2012 are front-end loaded. Our growth is coming from the commodity accounts, and our oil production in the first quarter was about 400,000 barrels ahead of our guidance and reflects strong performance from our oil asset.

In Malaysia, we're producing a record 75,000 barrels of oil per day gross. That yields about 30,000 barrels a day net. Our Uinta Basin net production is today at a record 24,000 barrels of oil equivalent per day. And in the Bakken, we're seeing improved execution in the field and our production rate is approximately 8,000 barrels of oil equivalent per day, net.

We also have seen encouraging results from our first 2 extended lateral wells, or SXLs, in the Eagle Ford Shale play. We have 2 additional SXL wells underway today, and expect to drill more than 1/3 of our Eagle Ford wells this year as SXLs.

Consistent with our past practices in disclosure of well results, I will not release IP rates from 1 or 2 wells in isolation. As we have promised, we'll have an update on multiple plays around mid-year 2012. By then, we'll have results from up to 4 super extended lateral wells in the Eagle Ford; multiple wells in the Uinta Basin, including our first 2 pressured horizontal Uteland Butte wells and our first 2 horizontal Wasatch wells. We'll also have early results from our initial drilling in oil and liquids rich portion of the Cana Woodford. Our early results in these areas are encouraging, and we'll have a meaningful update for you around mid-year.

I'll close today's call with some updates on our key oil development. Let's start with Malaysia, where we're seeing record gross oil production today of about 75,000 barrels per day. This is an all-time high for us, driven by East Piatu, Puteri and East Belumut. Our net production today is about 30,000 barrels per day. Our East Piatu field came online late last year and is today producing about 12,000 barrels of oil per day. Puteri commenced production early in the fourth quarter of 2011 and is today producing about 7,000 barrels of oil per day. Our East Belumut and Chermingat complex is today producing more than 40,000 barrels per day gross, also a record level for the field, and reflects recent pipeline optimization work, the ongoing success of the development drilling program and better-than-expected performance from our existing wells.

We continue to see excellent field performance offshore in Malaysia, and our team is finding new and innovative ways to increase our oil and ensure that we have a pipeline of new opportunities for the future. These are very profitable investments, with projects generating 30% to more than 100% internal rates of return. We are the fourth largest producer in Malaysia today, and having 30,000 barrels of oil per day selling at Brent prices is a great piece of business for us.

The second half of this year, we will commence phase 2 development drilling at East Piatu. By drilling additional field development wells from the platform, we will keep production at maximum rates. We have some exciting international exploration wells planned in the second half of 2012. I look forward to updating you on these results later in the year.

Moving on to our domestic oil plays, let's start with the Uinta Basin, our largest investment area in 2012. Our oil production in the Uinta is expected to grow more than 20% in 2012. In the Uinta today, we're developing multiple oil plays on our more than 230,000 net acres. In addition to the ongoing waterflood and infill drilling of the giant Monument Butte field, we are testing new and exciting vertical and horizontal plays in the Central Basin region.

These new plays have tremendous resource potential and successful drive our domestic oil production growth in the future. We're running 4 operated rigs in the Central Basin region today, drilling wells in the Uteland Butte; Wasatch; and later this year, the Lower Black Shale. Our acreage in the Central Basin is characterized by multiple stacked pays and is perspective for many oil formations. We're drilling our 12th Uteland Butte horizontal well today, and soon we'll have the results from our first assessments in the pressured sections of the formation. We've recently drilled 2 pressured wells, and both are in various stages of completion. We expect initial oil production in the coming weeks.

In the Wasatch formation, we've drilled 24 vertical wells and are currently drilling our first 2 horizontal wells in the play. In last night's release, we disclosed a record vertical well, nearly 2,500 barrels of oil equivalent per day initial gross production rate and more than 2,100 barrels of oil equivalent per day, 10-day average. The most recent 8 vertical Wasatch wells completed in 2012 have averaged more than 1,000 barrels of oil equivalent per day, gross. Our results to date are consistent with our expectations, and we're looking forward to the production results from our first 2 horizontal wells, which we expect by mid-year.

In 2012, we expect to drill about 60 wells in the Central Basin, of which more than 1/3 are planned as horizontal wells. We're focused on driving outsized oil growth in this asset and doubling our basin production by 2015. Our new 7- and 10-year refining agreements for nearly 40,000 barrels of oil per day give us the certainty that refining capacity will keep pace with our production growth.

In the Bakken play, our operations are gaining steam after our brief slowdown in late 2011. This slowdown allowed us to reduce the backlog of uncompleted wells and improve our execution in the field. From the beginning of the year, we have completed 8 new wells. The average initial production rate from these wells was more than 2,600 barrels of oil equivalent per day. With the exception of one well, these were all super extended lateral wells. The one 5,000 foot lateral was actually one of the higher IP rates at nearly 3,000 barrels of oil equivalent per day. We expect that our Bakken production will grow about 35% over our 2011 levels.

Our drilling team is transitioning our operations to pad-based drilling in 2012. About 2/3 of our planned wells in the Bakken will be from multi-well pads. Our most recent laterals, 11,000 feet in total length with up to 40 frac stages, have been drilled in as few as 24 days. This compares to an average of 35 days in 2011 and more than 40 days in 2010. We've also reduced the number of days between rig release and first production, from 62 days in 2011 to about 40 to 45 days year-to-date.

We are executing our operations very well today. Our net production from the area is about 8,000 barrels of oil equivalent per day today, and we expect that our rig count in the region will grow in the second half of 2012. We have more than 250 identified development drilling locations and the economics of our current operations are supportive of the increased activity levels. We expect to run 2 to 4 operated rigs in the Bakken throughout 2012.

In the Cana Woodford, we're assessing our more than 125,000 net acres with a 5-rig operated program, likely increasing to 7 rigs later this year. Our very early results have been encouraging and in line with pre-assessment expectation. We will have results from a handful of new wells by mid-year, and we'll provide an update at that time. Our drilling today is focused on the liquids-rich and oil-prone extension of the Cana, and we are expecting strongly competitive returns from our investment. We have a long and proven history in exploiting the Woodford formation, and our aggressive assessment is designed to yield data and expedite our path to ultimate field development.

As we stated around year end, we now view our assets in the Gulf of Mexico as nonstrategic. A formal process to maximize the value of these assets is underway, and we expect to know more around the mid-year time horizon.

So our focus in 2012 is crystal clear: invest in oil and grow cash. We're off to a strong start this year and have confidence that we can deliver on our key goals and expectations and create value in today's market. I'm certain that we are taking the right steps today. Our view on natural gas has been spot-on for the last several years, and our expectations for a near-term price rebound is low. Natural gas prices will likely remain challenged in 2012 and going into 2013.

Focusing on oil, driving revenue and cash flow growth, maintaining the strength of our balance sheet are the key ingredients of our strategy today. Our transition to oil is well underway. Second half of 2012, we expect that more than 50% of our production will be from oil and liquid, up from 47% in the first quarter. I look forward to the day when we are not listed as a gas-weighted company in equity research coverage.

We are encouraged with the trends in the service costs we've seen early in 2012. Our 2012 capital budget is front-end loaded due to the carryover of deferred completions in several project areas, large offshore developments that commenced production in late 2011 and initial investments in our Pearl development in China. Positive trajectory in service costs coupled with improved efficiencies in our operations should have positive implications for us in the second half of this year.

That concludes our prepared remarks today, and we're happy to entertain your questions. [Operator Instructions] Thanks, operator. We're now ready to take any questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we will go first to Leo Mariani with RBC.

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

Just a quick question here on your well costs. In your prepared comments, there, Lee, you kind of spoke that service costs were driving well cost down in your key plays. Could you maybe give us an update on where your well costs are in, I guess, in the Bakken, Eagle Ford and the various plays joined in the Uinta?

Lee K. Boothby

I'm going to let Gary take the details of that question. I would try to tell you that we're encouraged by some of the early trends that we're seeing on cost kind of across the businesses. And I would say encouraged just given the pressure that we've had as an industry over the last couple of years and the positive trajectory. I'd say, mostly at this point, we've seen a flattening. We have expectations that we'll see some relief through the balance of the year. Certainly that's going to be a net positive. At this stage, we're not baking in material relief into our forecast. We'll take it as it comes. I think the wind is blowing in the right direction. It's time to get better balance relative to the whole service cost equation in the current commodity price environment. But I'll put that to Gary to let you -- give you some color on the specific well cost.

Gary D. Packer

Leo, specifically you asked about the Bakken. We're seeing somewhere in the range of an 8% to 17% reduction in our completed well cost in the Bakken these days. I would attribute primarily most of that to the fact that we're moving on to pad drilling, as Lee referenced. I think about 2/3 of the wells we'll be drilling this year are on pads, and that's allowing us to take somewhere between $400,000 and $700,000 per location out. Certainly, the execution is improved this year. Trouble time is down to almost nonexistent, so far, this year. So we're really liking where we sit there. Completion cost, rather flat year-to-date, but really projecting a lot of improvements in that as we look into the end of 2012 and on into 2013. So in general, I'd say we're sitting at about 640 acres, somewhere around $6.9 million or so completed on a 12 80; 10,000-, 11,000 foot lateral, somewhere around $11 million or so. Generally speaking, across the balance, the Eagle Ford, I'd say we're sitting pretty much flat right now. Really like the execution and the well results that we referenced in the call, but we're not seeing any downward pressure yet on cost. However, that's also anticipated. When I look into the Uinta Basin -- and those wells in the Eagle Ford are somewhere in the mid-$8 million range for a 7,500 foot lateral. As I look into the Uinta Basin, I think the -- we are seeing, year-to-date, some reductions in our more typical 20-acre GMBU program in Greater Monument Butte. And we're just getting started on the horizontal program, so I think it's too early to tell there. We're in a very steep learning curve, got all our wells down. We're getting all the wells completed as we speak, but I think it's really too early right now to project anything on that.

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

Okay, that's great. I guess one kind of additional question for you guys here. You spoke about your Malaysian oil production running roughly 30,000 barrels a day net. Just looking at your first quarter results, I guess I was kind of eyeballing it somewhere closer to 24,000 barrels a day net. Is it up significantly post the quarter? Because I thought your guidance for the full year maybe implied a little bit lower levels, or maybe I'm missing something here.

Lee K. Boothby

Well, it is up materially. We had some pipeline optimization work that our team undertook in Malaysia, right at the end of the first quarter, moving into the second quarter. And frankly, we've had exceptional results from that. That added some 6,000 to 7,000 barrels a day of gross production off of our East Belumut complex, so it did improve our ability to move liquid barrels out of the East Belumut field and get them into storage, so material positive improvement.

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

Because I think your guidance had maybe implied kind of a lower rate, do you expect that rate to continue for the balance of the year? I thought you'd talk about doing you all's best to drill development wells to keep it flattish.

Lee K. Boothby

We are interested, as I indicated in the call. Why don't you follow up with Steve? He can give you the color on the details there, but we'd like to probably move on to the next question so we can get to some other people in the queue.

Operator

And moving on, we do have a question from Brian Lively with Tudor, Pickering, Holt.

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

Just looking for some more color on the Wasatch. What is the breakdown of oil versus gas percentage? And what were the current -- or the cost of the vertical wells?

Lee K. Boothby

Gary?

Gary D. Packer

The well that was specifically referenced in the call, it produced about 2,200 barrels of oil a day and about 2 million cubic feet a day, so you can figure out the GUR [ph] from that. In regard to the well cost, a typical deep Wasatch well runs somewhere in the vicinity of, drilling complete, about $3.2 million or so.

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

And the GUR [ph] was about the same on the other wells?

Gary D. Packer

Off the top of my head, Brian, I think that's directionally correct. The well cost of $3.2 million, that's typically without facilities. You roll the facilities in there, you're typically pushing about $4 million on these early wells or so.

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

Okay. And my follow-up question is on that 2,500 barrel a day well, what is different about that well versus the 900 average for the others? Meaning, is it a different style completion? Is it different rock? Is there something that you can map out and glean from that, such that your rates on your future wells would be higher?

Lee K. Boothby

Brian, I would tell you that it's too early. We've got 10 days of production on that well. It's probably 12 now. We've got a 10-day average as we referenced. Clearly, it's exciting results. Remember, we've seen some pretty good results out there over the course of the last year. In the 2 dozen wells that have been drilled, we've had a handful of other wells that have been in 1,300, 1,400 barrels a day type IPs. The fact that we've got 24 wells averaging just under 1,000 barrels of oil equivalent a day, vertical, says we're in the early stages of learning. We've got our first 2 horizontal wells down. I'm going to ask you to just stay tuned. I think it's exciting. We're excited about it, and I guarantee our team in Denver is all over it in trying to answer the questions that you're talking about. They've done an excellent job executing. We continue to learn from the wells we have. And in all these plays, you know that part of the recipe is to tweak the completions and optimize. So we're starting to approach that point in the plan and we'll see if we can replicate it. But I'm excited about the 1,000 barrel a day average in the 2 dozen wells we've built over the last year. I think that's pretty exciting, because remember, those are all vertical, and I'm looking forward to the horizontal results.

Operator

And we will hear next from Dave Kistler with Simmons & Company.

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

Real quickly, Q1 production beat about 5% above guidance, but full year production increased about 1%. Can you kind of talk through the deviation that's taking place there? Or any anticipations and sort of maybe fall-offs in production elsewhere versus where your exit rate was at Q1?

Lee K. Boothby

Yes, I'll let Gary take that question, Dave.

Gary D. Packer

Yes, Dave. The beat in the first quarter is primarily attributed to some accelerated completions that we did on the oil side, primarily in the Mid-Continent. And then also, as we got back in the game in the Bakken play, we had some wells that had been shut in at year end. We were able to get those wells restored a little quicker than we had anticipated. So in regard to the disproportionate increase in the first quarter versus full year, it's just that acceleration moving that volume forward accounts for part of it. Now clearly we're seeing good results across the board, both domestically and internationally. Some of the plays, as Lee alluded to already, we're liking the results that we're seeing. And then internationally, while we had anticipated the split-stream improvements coming out of Malaysia, I think we got it on a little quicker than we had originally planned. We're seeing probably a few thousand barrels a day more than what we had baked into our plans. So I think generally improved performance plus acceleration.

Lee K. Boothby

And, Dave, remember, later in the year, we've got some built-in shutdown time both in Malaysia and China, on our international assets, for normal routine maintenance-type activities. So I think that's part of the second half guidance as well. It's already baked into the forecast.

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

Okay, I appreciate that clarification. As a follow-up, in the Maverick Basin, with respect to the double XL -- well, extended laterals. You referenced them as encouraging. I know you can't give us rates, or you don't want to until you have more wells, but can you put it in the context of how returns from those wells look relative to the rest of your portfolio? Or maybe what a threshold is to be determined encouraging?

Lee K. Boothby

I believe that the last call, we talked about Gary had lined up the team there to drill 4 Super Extended Laterals. I like your double XL. We'll have to think about that, and would make a shirt out of it or something here for you [ph]. But our objective, plain and simple, was to make those investments competitive within our portfolio. And we had confidence that the 7,500 foot lateral based on the technical data that we had acquired on the 5,000 foot laterals and our experience in the Woodford, the Granite Wash, the Williston Basin, drilling these extended laterals that would position it as such. To say we're encouraged, I would tell you that the first 2 results tell us that it can compete in the portfolio. That's positive. So stay tuned. We'll get some data and we'll give you the well results. Gary's got 2 more planned here in the second quarter. So going into mid-year, we should have results from 4 of those wells, and I think we'd be in a much better position to translate that in terms of repeatability and portfolio.

Operator

And we will hear next from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

You've talked to the strong rates from the Wasatch wells, and then that you were specific that your Cana Woodford wells are coming in line with your expectations. I know it's a bit early in both plays, but can you add any color on the decline rates associated with those wells so far in both areas versus your expectations?

Lee K. Boothby

Since it's too early, Brian, and I don't have decline rates to share with you as far as getting the data so that we've got 30-, 60-day, 90-day rates on a handful of wells, so I would tell you the best I can offer at this point when we tell you that we're encouraged and it's in line, that IP rates and early production are in line with our expectation. So that's why we say we're encouraged there. We'll give you the update that we promised sometime around mid-year.

Brian Singer - Goldman Sachs Group Inc., Research Division

And based on what you've seen so far in the Cana Woodford, are you comfortable with your acreage position where it is now? Or is that a region that you're looking to expand? And if so, is that -- what are the -- how likely or possible is that?

Lee K. Boothby

Well, 125,000 acres, 5 rigs running, going to 7, is quite a bit of activity. So I think that we've got a strong position. We like it. We've got a lot of work to do. I think we've said repeatedly over the last 3 or 4 months that with our accrued learnings from the last decade and resource plays, that what we're doing in the Cana Woodford is aggressively accelerating the assessment. The acquisition of the data and the information that we need to plan the future developments by accelerating the assessment, puts us in a position to accelerate the development behind that. Point of fact, we're always in the market to add acreage and positions in and around places where we're active. So certainly, we'll continue to have an opportunistic bent in that regard. But 125,000 acres, 6 months into the play, we've got a lot of work ahead of us, and I think I'm pretty comfortable with where we sit right at the moment.

Operator

And moving on, we do have a question from Bob Morris with Citi.

Robert S. Morris - Citigroup Inc, Research Division

Lee, last quarter you said that if natural gas prices dropped below $2, you'd take -- make some dramatic adjustments and probably shut in more gas production. I mean, gas prices are effectively below $2. What are you thinking of doing in that regard, particularly if prices continue to soften here into the summer and fall?

Lee K. Boothby

Good question, Bob. I don't know -- I don't remember saying it just that pointedly, but I'll take you at your word that, that's maybe how it sounded on the other end of the line. I would tell you that we were trying to paint a picture that we would remain in tune with what was going on in the market and that we would take some steps as we thought appropriate. And clearly, since the last call, part of what we did is materially strengthen our hedge position in '12 and '13 and started building a position in '14 as well. Some of that positioning was to insulate against a further slide in natural gas prices, and I think that's been a good move for us. So I think we're well hedged across that 2012, 2013 time horizon. Relative to investments, we have no dry gas rigs drilling and we plan to drill no dry gas wells in 2012. So that's the first time in the last 13 years that I've been with the company that we haven't had a rig drilling dry gas anywhere in the portfolio, and I think that's the right economic decision today. We said we're going to accept decline on our natural gas assets. We're doing that. I think that's a means of taking some pressure out of the market. When you look at the actual cash cost of operating our rig count, and then operating expenses are somewhere just below $0.50 or low $0.40s, $0.42, $0.43. So when you start thinking about shutting in gas volumes, we're still a long ways away from where you would probably have to make those decisions simply based upon our hedge position and the cash operating cost. So I would tell you that nothing is imminent in that regard, but we'll keep the options open just like we did in the last call, that if the market continues to further deteriorate that we'll reserve the right to take some production out of the market. But remember, it's easy to talk about that, and you've got a lot of partners and a lot of wells. And there's only a fraction of the total production that you could think about shutting in at any given region. I'll let Terry add some additional color.

Terry W. Rathert

And, Bob, I think, at the end of the day, as Lee alluded to, it really becomes an equation of where the incremental or the marginal cost to operate those wells and what is your view of the future. And if you defer that Mcf of production a day to 3, 4, 5 years out, and you think gas prices are still going to be a $3 or $4 proposition, then on a net present value basis, as long as the NPV is positive to produce today versus the future, that's the other element you have to think about. So we're not very bullish on natural gas. We monitor all those elements of that decision, and we'll make that call when it says it's not the right thing to continue to produce.

Robert S. Morris - Citigroup Inc, Research Division

Okay. You mentioned $0.41, $0.42 operating cost, I mean, kind of the thing you mentioned, the marginal cost to operate. What is your highest marginal cost to operate in your gas production?

Lee K. Boothby

Well, remember, we sold $300 million-plus of conventional gas assets along the Gulf Coast last year, so we've reduced our natural gas portfolio with those nonstrategic asset sales. We haven't drilled any gas wells in the Rockies, so that production has been on decline since late 2008. The bulk of our natural gas production is actually coming out of the Mid-Con. That's why I used that as a reference point. But I'll let Gary give you any other color he might -- anything else you want to add?

Gary D. Packer

No, I think you pretty much captured it. There are leads all coming out of the Mid-Con, and it's in a $0.40, $0.50 range.

Lee K. Boothby

Yes, when you think Newfield natural gas, Mid-Con dominates. The rest of it's round [ph] off.

Gary D. Packer

Yes, most of the other -- a lot of the other production, for example in the Rockies, are all associated natural gas.

Operator

And we will move next to Richard Tullis with Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Lee, taking a look at the Alberta Bakken, are you seeing anything there that might change your thinking to maybe get a little active there sometime this year? Or are you still kind of taking that wait-and-see approach?

Lee K. Boothby

Well, it's more than a wait-and-see. Part of our shift of resources last year is on focusing manpower and level-loading with it. We've got the Southern Alberta Basin being managed by our exploration new metrics [ph] team here in Houston. We've acquired a lot of data up there last year. So we continue to evaluate the data, core data, production data, log data, et cetera, that we've acquired in the region. And we continue to monitor the activity of others in the region. We've got a luxury, if you will, that most of our acreage there was put together in a deal with the Blackfeet Nation and provided for a 5-year exploratory phase. We've got probably 3.5 years or so remaining on that exploration phase. We have time, relative to monitoring the situation. Clearly what the basin needs, whether it's got a Newfield name on top the well header or one of our friends in the industry, is an obviously economically viable horizontal success, something that we could look at and deem worthy of drilling some additional wells and if you could have some hope of repeatability to the basin. The basin does have oil in multiple horizons. Industry continues to test different horizons on both sides of the border. And we remain where we've been, cautiously optimistic relative to the play. But we don't have any drilling program planned in 2012, because frankly, we don't need to drill any wells there in 2012. We've got about 85% of our drilling commitments with the Blackfeet satisfied, so we're drilling another couple wells and we'll have taken care of that commitment.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

And then just finally for me, in the Gulf of Mexico, how is the Pyrenees project performing?

Lee K. Boothby

I'll let Gary answer that question.

Gary D. Packer

Yes, Pyrenees is on production. It's about 35 million a day or so overall production. I'd say that in any of these new types of reservoirs where you've got these things defined seismically, I'd say we're seeing a little bit more pressure loss than we had originally anticipated in the reservoir, but it's all associated with the dynamics of the reservoir. And as far as the EUR that we see for the well, that's unchanged. So I'd say, within range, maybe producing a little light to the original plan.

Operator

And we will go next to Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Lee, in terms of the oily Woodford, so you're drilling no oily Woodford wells at this point. And is that because that those wells just don't compete from a rate-of-return perspective? Or is it because that play doesn't have the scale of some of the other plays where you're drilling? Or is it also because you've HBP-ed that and you have no need to drill that right now?

Lee K. Boothby

In the popular vernacular, that they have -- what if I choose some of all of the above? It's an all of the above solution. We're HBP, first and foremost, so we've got pressing evaluation needs in the Cana. So we don't have any need to drill wells there, and I think that's probably the dominant answer. Clearly, one of the issues that we've had relative to position near Cumbles [ph], what you're referencing, is scale. We have a 20,000-, 25,000-acre position there. We've got a 125,000-acre position in the Cana Woodford, so much larger in terms of the scale and scope of the play. But it's a little bit of all of the above in terms of your comments.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then a second question. So with the potential for meaningful results out of the Wasatch and the Uteland Butte and your traditional drilling in the Uinta Basin, could you comment on any possibility of increasing your offtake there versus what you already announced? And I know that the capacity to grow is great from here, but any moves afoot to increase it even further?

Lee K. Boothby

Well, I wouldn't say that there are moves afoot. I mean, I think doubling our production out of the basin in a 3-year time frame is a pretty significant achievement, and that's the path that we're on. So the 40,000 barrels that we secured, December and January this year, we think meet our needs inside of the 5-year time horizon. So we're not beating the bushes out there looking to dramatically expand that. I understand there are ongoing discussions with other operators in the basin and refiners that continue to talk about additional expansions. But we think that's a plus for the basin and certainly support it, but we're not going to drive those outcomes. In the near term, until the incremental capacity starts coming online, notionally second quarter, mid-year '13, there's a practical limitation in terms of upside volumes. I suspect when we get up around 30,000 barrels a day out of the Uinta that we'll start loading the existing capacity and we'll have to, at that point, wait for those additional tranches to come online in '13 and '14. Remember that our target is to be in the 40,000 to 50,000 barrel a day window in 2015, so that's the path that we're on at this point.

Operator

And moving on, we have a question from Dan McSpirit with BMO Capital.

Dan McSpirit - BMO Capital Markets U.S.

On Malaysia, you spoke to -- or at least spoke generally about the pipeline of opportunities. Can you relay greater texture on those opportunities and what that might mean for production growth in the periods ahead?

Lee K. Boothby

I'll tell you what, Gary just got back from a trip over there. I'll let Gary take that question and he can give you some color on what he's got going on in that arena.

Gary D. Packer

Dan, I'd say that in the near term, most of the production growth that we're going to see are going to be in staged development programs of the projects that we've already got in place, where we are concluding the third phase drilling program out of PM 323, and we anticipate a fourth phase there as well. And as Lee also alluded to, we look for a second phase at 329, and I expect we'll see a third phase of drilling out there. We're going to be -- we will be drilling a total of 3 exploratory wells this year. I think the results of those will be critical in kind of placing a path forward for us as far as what we've got left. One unnamed project that we'll be drilling on a more recent deal we've put together from an exploratory standpoint, and then we'll be following up on our discoveries at SK 310. And I'm optimistic we'll get our deepwater follow-up to our discovery that we made in Paus drilled this year. We are seeing and are optimistic about additional opportunities, both in Peninsular Malaysia and Sarawak, that we think align very well with the stuff that we've already got in hand and that would be all incremental to the projects that we see, but we're not free to talk about any of those at this point.

Dan McSpirit - BMO Capital Markets U.S.

And as a follow-up, can you speak to the Lower Black Shale that you're targeting, expectations, maybe timing, on results out of the Uinta Basin?

Lee K. Boothby

I'll start speaking to the Lower Black Shale, I guess I'll start by saying it's black. That's a creative name, but it's an organic-rich shale, obviously. You've probably heard something about it from the other operators in the basin talking about it. I think probably to give you just a little bit of a wrinkle, I'm going to -- been patting our Rockies team on the back quietly over the last several months. They perforated the Black Shale in a handful of vertical wells when we run production logs. So at this point, we know it's an organically rich shale sandwiched amongst all the other horizons that we're chasing in the Uinta Basin. It's got all the right characteristics. We perforated it in, as I mentioned, a handful of vertical wells and we can work to contribute meaningful volumes to the total flow from vertical wells. But clearly, you wouldn't drill this -- drill the play and plan to develop it vertically. So the key test there is, can we take the vertical results that we've seen from the production logs on some of the deep wells in the Central Basin and translate that to horizontal success economically? With success there, obviously, it would expand the -- further expand the resource potential and further expand our inventory of oil opportunities. So we're very intrigued by the Lower Black Shale. It's the next one of several horizons on the list. We didn't include the Black Shale in our July 2011 resource release, the 700 million barrels potential that we talked about in the Green River, Uteland Butte and Wasatch. So it would be entirely incremental to anything that we've put out at this point. First well, likely to be spud, probably late second quarter, early third quarter. So the results there would be later in the year, third, fourth quarter-type time frame. We won't have any results there by mid-year.

Operator

And we will hear next from David Tameron with Wells Fargo.

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

Can you guys speak to -- you sold part of your Bakken, but not all the Bakken. Can you talk about just the thought process there as far as why not either keep it all or keep none of it? Can you just talk about what the thought process was?

Gary D. Packer

Yes, Dave, this is Gary. As we accumulated the acreage position out there, as you're probably well aware, we have a very strong core position on the Nesson and then immediately south and southwest of the Nesson in our Watford and our Aquarium areas, as well as Westberg. As we look into Catwalk, we had a pretty significant amount of requirements this year as far as HBP activity. And at the time that we ended up disposing of that asset, when we look at our portfolio in the Bakken, we felt that we could generate more meaningful returns by drilling in the other areas. So rather than deploy incremental capital, we continued to manage the balance sheet and we elected to go ahead and monetize that, removing some of the HBP obligations that we had for 2012, and redeploy the capital and accelerating the results that we had in the rest of the Bakken, where Lee already talked to the fact that we're seeing real good results from those investments. So it wasn't condemning on the acreage position we sold. We just like the other stuff we had better.

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

Okay, that's helpful. And then as a follow-up to that, whoever wants to take this, but can you talk about, just in general, where do you see your portfolio today? Are there -- I assume you have some of the magical stealth plays that everybody has. But I mean, are you guys -- how do you feel about the portfolio? And obviously you can drive double-digit growth from liquids side, which you've talked about, but can you just give us your current thoughts on acquisition market or what you're feeling, what you're thinking?

Lee K. Boothby

Okay. Well, let me start with the last one. We're focused on delivering results from our existing portfolio in 2012. So the acquisition market, while intriguing and adventurous, I think patience is a virtue. And patience probably means that it's mostly going to be a place that we're going to be interested in outside of the 2012 time horizon. We've got plenty to do on our play today and plenty of depth in our inventory. I think that, in my opinion, the last few months, the most underappreciated aspect of Newfield has been the depth of our oil development inventory. We have thousands of oil development locations. That's a luxury in today's world. So we're going to attack that portfolio. We're going to continue to drive the 20% liquid growth that we've delivered every year since 2008. In time, it will take care of itself, because the product we're focused on growing is cash, all right? Because we grow cash, move past the 50% mark on total liquids, we get recognition as an oil company, we get stronger day-by-day, week-by-week, month-by-month, I think we'll be in a position to think more constructively about the M&A world post 2012. With regard to stealth opportunities, we talked about Black Shale. That's in our inventory. We've got other opportunities in inventory we haven't talked about. We're not out chasing big new stealth plays at this point because we've done a lot of work there. We added over 200,000 acres in 2011 in oil plays. And again, I like our position at this point. We know what we need to do. We're going to drive stealths, we're going to execute and climb the hill, and we're going to enjoy the success that our team is delivering today. I'm really proud of what they've done, repositioning talent around the organization, absorbing the project setbacks that we had in 2011, executing strong in 2012. There's a bright future ahead for Newfield, and we're going to go ahead and capture it.

Operator

At this time, we do have an additional question. And this question will come from Catherine O'Connor [ph] with Deutsche Bank.

Unknown Analyst

Just following up on what you were saying in terms of focusing on delivering in 2012 and putting off any acquisitions, can you talk about sort of how your asset sale target, including Gulf of Mexico, plays into that? And any sort of desire to become investment grade as part of that strategy?

Lee K. Boothby

I'll let Terry answer the question on the investment grade and kind of where all that takes it. We mentioned on the Gulf of Mexico that our objective is to maximize value. We said that we're plenty happy to hang on to the production and produce it out if that's the right answer. But I would tell you it's an attractive piece of business. It's got strong production from the producing-asset side, and it's a really strong exploratory portfolio. So the process is underway there. We'll have to see how that plays out. But clearly, at Newfield, we deem the deepwater Gulf of Mexico nonstrategic in the near term. Terry?

Terry W. Rathert

Yes, that's it. A pretty good summary, Lee. Yes, we'll just have to see how the Gulf of Mexico plays out in time. And we have our investment grade at S&P, have recently visited with all the rating agencies, updated them on our 2012 plan, reaffirmed that we delivered on our 2009, '10 and '11 operating results as we had communicated to them prior to each of those operating years. In 2011, if you include the asset sales that closed in the first quarter that really initiated in 2011, we sold $700 million worth of what we believe are nonstrategic assets. They didn't have a place in our future in driving growth. And we'll continue to review the portfolio for things that still fall in that category. Clearly, with natural gas prices where they are today, gas assets that may not have any drilling activity on them to date won't bring a lot of -- or may not be very attractive for somebody in the market, and we probably won't be pursuing sales of natural gas assets. And most of our oil assets are core or in the process of becoming foundational assets as we go through the assessment and development activity. So we'll continue to focus on improving the balance sheet. Asset sales -- nonstrategic asset sales are part of that equation. And we'll see how the Gulf of Mexico plays out, as we alluded to.

Unknown Analyst

I guess as a follow-up to that. When you spoke with the rating agencies, did they give you any sort of guidelines as to -- you've obviously just recently called your 2014 notes. Did they give you any sort of guidelines in terms of doing things like take -- calling those notes or any additional notes in order -- sort of like maybe like a path to what you would take to become investment grade in their eyes, for the 2 rating agencies that don't have you at the investment-grade level at this point?

Terry W. Rathert

I think, clearly, one of the elements is just scale. And the rating agencies -- or the way I would summarize, I think, have begun to move away from some of the pure metrics-based criteria. And looking at level of debt relative to proved developed reserves versus total proved reserves as a result of the change in the SEC guidelines several years ago has become more important. Clearly, it's a matter of -- each of them have their individual criteria, but in the end, there's other factors that come into play. And one of those is the way you run the business and the consistency in delivering results. And we have continued to deliver. They've provided no road map to investment grade, nor have they told us the road map to go the opposite direction. So we know what's required generally, which is continue to strengthening the balance sheet and reduce debt on a dollar of developed barrel going forward, strengthening cash flows, and that's the road map to investment grade.

Operator

And that is all the time that we have for questions today. I would now like to turn the call back over to Mr. Boothby for any additional or closing remarks.

Lee K. Boothby

I will be brief. Thank you for your interest in Newfield. Thank you for your time today. We look forward to updating you in a couple of months on our progress at the end of the second quarter. Have a good day. Thank you.

Operator

And again, that does conclude today's call. We do thank you for your participation.

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