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Executives

Doss R. Bourgeois - Executive Vice President of Exploration & Production

James C. Flores - Chairman, Chief Executive Officer and President

Scott D. Winters - Former Vice President of Corporate Communications

Winston M. Talbert - Chief Financial Officer and Executive Vice President

Analysts

Gregg Brody - JP Morgan Chase & Co, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

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

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Scott M. Wilmoth - Simmons & Company International, Research Division

Plains Exploration & Production (PXP) Q3 2011 Earnings Call November 4, 2011 9:00 AM ET

Operator

Good morning, my name is Jackie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Plains Exploration 2011 Third Quarter Earnings Results Conference Call. [Operator Instructions] I would now like to turn the call over to Scott Winters, Vice President of Corporate Planning and Research. Please go ahead.

Scott D. Winters

Jackie, thank you. Good morning, everyone, and welcome to our conference call. Earlier this morning, we issued our earnings release and filed our 10-Q and our full-year 2012 operational guidance with the SEC on our Form 8-K.

Our conference call today is being broadcast live on the Internet, and anyone may listen to the call by accessing our company website at pxp.com. We've posted a slide presentation to supplement our comments this morning, and we may refer to the slides during the call.

The webcast, the slides, the 10-Q, the 8-K and today's press release are all available on the website, in the Investor Information section.

Before we begin today's comments, I'd like to remind everybody that during this call, there will be forward-looking statements as defined by the SEC. These statements are based on current expectations and projections about future events, and involve certain assumptions, known as well as unknown risks, uncertainties and other factors that could cause our actual results to differ materially. Please refer to our filings with the SEC, including our Form 10-K for a discussion of these risks.

In our press release, slide presentation and our prepared comments this morning, we present non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release.

On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Doss Bourgeois, our Executive Vice President of Exploration and Production; Winston Talbert, Executive Vice President and Chief Financial Officer; John Wombwell, our Executive Vice President and General Counsel; and Hance Myers, Vice President Corporate Information Director.

For the third quarter of 2011, PXP reported a net loss of approximately $88 million or $0.62 per diluted share, compared to net income of approximately $19 million or $0.13 per diluted share for the third quarter of 2010.

The net loss includes the impact of realized and unrealized gains and losses on our mark-to-market derivative contracts, a $396 million unrealized loss on investment in McMoRan Exploration company's common stock and other items, which affect the comparability of operating results.

When considering these items, PXP reported net income of approximately $65 million or $0.45 per diluted share compared to net income of $41 million or approximately $0.29 per diluted share for the same period in 2010.

2011 third quarter daily sales volumes reached a record level and averaged 104.4 thousand barrels of oil equivalent per day. It represents a 15% increase compared to the third quarter of 2010, or a 26% increase pro forma for the 2010 asset sale.

Average daily liquids sales volumes increased 9% compared to the third quarter of 2010, or 16% pro forma for the 2010 asset sale.

During the third quarter of 2011, gross margin per BOE was $21.35 and cash margin per BOE was $36.73, a 27% and an 18% increase over the third quarter of 2010, respectively.

Higher realized prices and higher production were the primary drivers for this increase. For the third quarter of 2011, oil and gas revenues increased 29% compared to the third quarter of 2010.

Oil revenues increased approximately $103 million, reflecting higher average realized prices benefited by California crude postings, which remain strong relative to NYMEX, and higher sales volumes. Gas revenues increased approximately $11 million reflecting higher sales volumes, partially offset by lower average realized prices.

Lease operating expenses increased approximately $12 million to $80 million in the quarter, reflecting an increased number of producing wells at our Eagle Ford Shale and Panhandle properties, and higher scheduled repair and maintenance and well workovers, primarily at our California properties.

Production and ad valorem taxes increased approximately $2 million to about $11 million in 2011, reflecting increased production primarily from our Eagle Ford and Panhandle properties, partially offset by lower ad valorem taxes.

Steam gas costs, electricity and gathering and transportation costs were flat to the third quarter of 2010 costs, but lower than the prior year period on a per-unit basis.

For steam gas costs in the third quarter of 2011, we burned approximately 4.1 Bcf of natural gas at a cost of approximately $4.18 per MMBtu compared to 4.1 Bcf at a cost of $4.21 per MMBtu in the third quarter of 2010.

Depreciation, depletion, and amortization expense increased approximately $35 million to $168 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to the increased production and higher per-unit rate.

Our oil and gas unit of production rate increased to $16.86 per BOE in 2011, compared to $15.33 per BOE in 2010, primarily due to the transfer of costs related to the Friesian project into the amortization base.

Income from operations was approximately $169 million during the third quarter of 2011 compared to approximately $97 million for the same period in 2010.

The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are mark-to-market each quarter, with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement.

Cash flow is only impacted to the extent the actual settlements under these contracts result in making a payment to or receiving a payment from the counter party. We recognized a $126 million gain on mark-to-market derivative contracts in the third quarter of 2011, which was primarily associated with an increase in the fair value of our 2012 and 2013 crude oil contracts due to lower forward prices.

A summary of PXP's derivatives position is included with the financial tables in the press release.

PXP owns 51 million shares of McMoRan common stock and measures the equity investment at fair value, as determined by the stock's closing price discounted for certain restrictions on the marketability of the shares.

On September 30 of 2011, the McMoRan shares were valued at approximately $379 million based on McMoRan's closing stock price of $9.93. This fair value compared to the fair value of the investment on June 30, 2011, of $775 million, which is based on McMoRan's closing stock of $18.48, resulted in the loss of $396 million for the quarter.

McMoRan's common stock's closing price on November 3, 2011, was $12.92.

Operationally, in the Eagle Ford, PXP has 5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. One additional rig is expected to begin operations in December.

Initial production rates on recently completed wells are as follows: the Dougherty #1H and Dougherty #2H achieved peak rate of 2,579 gross BOEs per day and 2,212 gross BOEs per day. And for both of those wells, we have 100% working interest.

The Deleon-Reinhard Unit #1H achieved a peak rate of 2,435 gross BOEs per day, and the Deleon-Wiatrek Unit #1H achieved peak rate of 2,440 gross BOEs per day. For each of those wells, we have a 50% working interest.

Third quarter daily sales volumes averaged approximately 5,170 BOEs per day net to PXP, compared to 2,330 BOEs per day net to PXP in the second quarter of 2011.

For the month of October, daily sales volumes averaged approximately 9,600 BOEs per day net. And the company expects to exit the year above 10,000 BOEs net per day.

In California, PXP has 3 drilling rigs operating onshore, where PXP continues its multiyear development program in the Los Angeles and San Joaquin Basins. Year-to-date drilling results were in line with expectations. Sales volumes are consistently strong and the large operating margin is improving due to the higher liquids price realizations.

Third quarter daily sales volumes onshore and offshore averaged 39,700 BOEs per day net to PXP, and are expected to be above 40,000 BOEs net per day by the year end of 2011.

In the Haynesville Shale, PXP's primary operator is currently operating 21 rigs, down from 31 rigs reported in August 2011. Third quarter daily sales volumes averaged 201.3 million cubic feet equivalent per day net to PXP, compared to 181.7 million cubic feet equivalent per day net to PXP in the second quarter of 2011.

The rate of increase in the sales volume is anticipated to slow, as the rig count continues to decline over the remainder of this year.

Now a few comments on our 2012 full year operational guidance. We filed a form 8-K this morning with the 2012 full-year operating guidance. Here are some of the highlights. For sales volumes, the range is between 92,000 BOEs per day and 96,000 BOE per day, of which 50% is oil, 5% NGLs and 45% natural gas.

Per product price realizations on an unhedged basis, oil price realization is expected between 98% and 102% of Brent with a $5 quality transportation expense, NGL is expected to be 49% of WTI and natural gas is 100% of Henry Hub with a $0.15 quality transportation expense.

Total production cost range is between $15.20 and $17.40 per BOE. The components of total production costs include LOE, steam gas costs, electricity production and ad valorem taxes and gathering and transportation costs. Guidance for each of these items is provided in the 8-K.

With respect to capital expenditures, PXP's 2012 capital is estimated to be $1.366 billion and Gulf of Mexico capital, funded by Plains Offshore, is approximately $230 million. This totals $1.6 billion and includes capitalized interest and G&A expense.

Now we have recently announced a number of transactions, so I'd like to quickly give you a quick summary.

In August, PXP announced a new marketing contract for its California crude production. The new contract becomes effective January 1, 2012, covers approximately 90% of PXP's California production, extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach.

In a separate transaction, PXP executed an agreement with a third-party purchaser to sell its Eagle Ford crude oil using a Light Louisiana Sweet-based pricing mechanism.

In September, we announced an updated derivatives position to align our hedging strategy with the crude oil marketing contracts and to enhance future cash flows by reducing PXP's 2012 deferred premium.

PXP realigned its 2012 WTI crude oil derivatives by acquiring Brent crude oil derivatives, modified a portion of its 2012 natural gas derivatives and added Brent crude oil derivatives in 2013.

In October, PXP secured $450 million of cash proceeds in exchange for a 20% equity interest in Plains Offshore Operations, Inc., a wholly-owned subsidiary of PXP, established to hold all of PXP's Gulf of Mexico assets. While this transaction values our Gulf of Mexico business at $2.25 billion including cash, the financing provides a capital for the development of Lucius, drilling at Phobos and other high-potential prospects going forward.

And today, we announced that PXP and certain of its subsidiaries had entered into definitive purchase and sale agreements to divest all its working interest in oil and gas properties located in Texas Panhandle, and its conventional natural gas properties in South Texas for $785 million in cash. Proceeds are expected to reduce debt.

With that, I'll turn the call over to Jim.

James C. Flores

Thank you, Scott, and good morning, everyone. We have a full team here, and we're ready to answer questions. A few short comments and then we'll go into the questions. Obviously, PXP is hitting on all cylinders with the strong production growth. We're able to control our costs because of our large California position.

And on the oil side, obviously, we're seeing inflation in the Eagle Ford, and we saw it in the Granite Wash and also in the Haynesville because of all the important shale drilling that's going on and frac costs and completion costs that continue to squeeze margins on the oil side, and obviously they just continue to impact negative margins on the gas side. Our goal today with the asset sales allowed a couple of things. Number one, we minimized our exposure to that inflationary market. We think with oil prices staying high, it will continue to be an important negative theme in our industry next year, and so we're very concerned about that.

So alleviating our exposure to the Panhandle and even South Texas, where we weren't putting much capital, is an important part of our strategy -- controlling those costs. We are forecasting a 10% to 12% inflation in our business next year in our 2012 budget. And that's primarily driven by the Eagle Ford and what remaining Haynesville drilling we'll have. And California's pretty static because of the control that the large operators have out there.

The strong operating profits will continue as oil price and our margins continue to widen, as we work on the cost side but just strictly because of our asset intensity. The strong Eagle Ford wells are continuing to get better and better and be in a position to really outsize our engineering acquisition expectations. We think about some of the comments that -- some of the previous conference calls that Mark and Scott made about downsizing wells and more productivity per acre. We certainly see that in our opportunity set and our acreage, since we're partners with EOG and a portion of it we're surrounded by both those guys.

And we couldn't be more pleased with the quality of our asset base there. Remember, we're moving very quickly to try to get it all under production systems. So we'll start drilling development wells by the end of 2012, or for sure by beginning of '13, get all our production facilities in and continue to be able to control our cost and inflation there.

The backs of the Eagle Ford growth on top of California and with our newly financed Deepwater Gulf of Mexico business, highlighting our Lucius development, the next 5 years of PXP's oil growth -- and it's oil. It's not natural gas liquids. We've eliminated that basically from our portfolio by leaving the Panhandle. I think it's second to none because our margins will be expanding in the next 5 years. When you bring on the Gulf of Mexico production, there's very little maintenance CapEx going forward.

So in 2014, we'll have back those margins expanding rapidly. At the same point in time, as the Eagle Ford continues to fund itself in late '12 or early '13, then we'll have all the California margins.

So PXP is well on its way to having some strong, strong earnings and operating margin expansion going forward, which -- what we covenant for the next 5 years. Minimize inflation is going to be a key part of our program going forward, and with the asset sales -- I mean, everybody can do the financial math, but it needs to be stated: unlocking our balance sheet and being able to lower our fixed cost interest charges was obviously a key metric. I mean, Winston will talk in the $50 million to $60 million range as far as interest savings, and when you add that to the -- or offset that with the cash flows in the Panhandle and so forth, selling the properties is a great opportunity for us to take advantage of that arbitrage. And once we do that, then we'll be locked down and going forward with a very strong balance sheet from there.

I've got Winston, Doss and everyone here, so we will open it up for questions, and I'm happy to present the third quarter to you guys. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Phil McPherson with Global Hunter Securities.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

I was wondering if you could give us a little bit breakdown on the 2012 CapEx. The slides didn't have as much detail as before, and I was just kind of looking back at some previous presentations. It looked like California's around $300 million, the Eagle Ford is around $530 million. And now that Granite Wash is gone, I'm wondering where that capital's going to be redeployed at.

James C. Flores

Well, we wanted to save a lot of the capital detail for our analyst meeting November 15, because we've had -- even in fact in 2011, we need to give you some color today on the call, because there's a lot of ins and outs in '11 and how the math works in '12. So let's at about 12 first, and then we'll come back to '11 so it will make some sense. Obviously, about $200 million of capital was allocated to the Panhandle for 2012. So that would be a reduction. We announced in our 8-K that the board has approved a $1.6 billion budget. That is again in light of strong oil prices in 2012, next year. So we have about $1.5 billion of projects approved for our budget right now. So our internal operating plan is $1.5 billion, but we do have a $1.6 billion board-approved budget. So if there's any discrepancy between what we put out in the past of $1.5 million and $1.6 billion, it's just a matter of if we see new opportunities or want to buy some leases or that type of thing. We're about $100 million over our development operating plan that we've been articulating to everybody. So when you look at the $1.5 billion worth of projects, you take $200 million of Panhandle off of that. On top of that $1.5 billion you also take out $235 million of Gulf of Mexico, which is funded by the cash inside POI. So with $400 million on our balance sheet starting Jan 1, 2012, we'll use existing cash and cash flow to fund our CapEx in 2012 and 2013. All right, then we'll go through that as much as you need, but that's basically -- you add those 2 together and then it's the Gulf of Mexico spending. So if you net-net, you net out the Gulf of Mexico spending and you net out the Panhandle, you get to a pretty low number from the standpoint of where we are as far as CapEx for 2012. Let's talk about 2011 a little bit. 2011, with the ins and outs, we were spending about $250 million in the Panhandle Granite Wash. We've made agreements with the buyers to continue our operation as normal. So that's going to go, but there's net-net. When we net out the sales from the effective date, it's where the capital goes and so forth. So we think -- and then we actually spent a little more money in the Haynesville because of delays in rig drops in the Haynesville and so forth, so -- and a little inflation, plus we've added another rig. We have another rig coming in December. It'll give us 7 total rigs gross in the Eagle Ford, plus some additional facilities. As I said, we're accelerating the Eagle Ford quite rapidly. All that in, you're talking about another $125 million, $150 million over our $1.5 billion budget. Then you have to add in $100 million worth of Gulf of Mexico, of which half of that, $50 million, will be reimbursed by EIG. So that's about another $50 million net. So net-net, we're somewhere around $1.7 billion, we think. But we just got all these deals signed in the last 24 hours. There's some ins and outs. So we will give everybody full detail at the November 15 analyst meeting and how it breaks down, with a lot of math. But there are so many moving parts, we decided not to. We decided to talk about it on the conference call and give everybody kind of a look. So if you're looking from a standpoint -- about $1.7 billion, I think, is where CapEx probably comes in. $1.7 billion, $1.75 billion, something like that net of cash on hand for the Gulf of Mexico sale, when we go through the whole process

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Great, that's helpful. And since you brought up kind of the leasing idea, it looked like that your leases in California expanded by about 6,000 acres from a couple of different presentations. Can you talk about where you might be getting more aggressive at?

James C. Flores

I wouldn't call 6,000 acres more aggressive. I am not aware of any acres being bought in California, so that may be a typo. And maybe a dribble over from the Rocky Mountains or from Wyoming.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Okay. And just one more and then I'll hop back in the queue. Can you just give us a little color on the decision to not proceed with the Friesian?

James C. Flores

It was strictly -- it was an engineering call, the aspects with the new scrutiny in Gulf of Mexico, of regulatory and so forth. All of the operators are being very, very diligent in their thought process of what they can commit to and what they can't be. And it's such a backlog of projects. For instance, 2 operators we were talking to -- it was BP and Chevron, so many concerns about whether they have personnel even to work on a third-party project, whether they have water-handling capacity for the deals. And there were so many contingencies built in there, we felt like the risk to the project's being successful, our timing and so forth was high. When we compare that to what we had going on at Lucius, which is project on time, on schedule, Anadarko, our operator, is firmly committed to it. I think we're already cutting steel on that thing, and so forth. And the economics were so superior, we felt like when we looked at our portfolio early in the year and said, "Where are we going to spend our money? Where are we going to invest our capital in the highest rate of return projects -- not the volumes, but the highest rate of return projects?" Obviously Friesian fell out, obviously South Texas fell out, and obviously the Granite Wash became salable at that point in time. And what happened there -- obviously, we would've monetized Friesian if we could, but we were beyond the expiration date of the leases and we fell within the -- we didn't fall within the suspension of production provisions of BOEMRE and therefore we had to relinquish the leases. The biggest thing about that from this takeaway is that PXP is not going to do a project that's not going to make money for its shareholders. And with Lucius and the value of Lucius and the $100 oil range and so forth, it more than makes up for any value at Frieisan. And having it fully financed in an 80% carry in that project from the PXP share with no cost out is much superior than anything else we can do in the Gulf of Mexico at this point in time.

Operator

Your next question comes from the line of Leo Mariani with RBC.

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

Just a couple of questions on sort of your balance sheet funding situation here. Obviously, you guys just raised a nice chunk of cash here from the Deepwater financing. And obviously, you just sold some pretty significant assets. I think that puts the balance sheet in great shape. How do you guys think about your position in McMoRan? I know in the past you've talked about monetizing some of that in 2012. Does that sort of change your thoughts here on that, given the strength of the balance sheet?

James C. Flores

Leo, Winston was all ready to answer your question until you brought up McMoRan. He looked at me and says, "You want to take that?" And I will take it. I'll let Winston backfill some of the balance sheet issues. It does. We've been articulate about pay. Oil's $100. We're an oil company. We should be able to strengthen our balance sheet even though we're trying to grow very rapidly, get our growth engine started. So those are 2 high achievements to do on their own, but doing them together, you've got to look at taking some swift action. Obviously, by the $785 million we're raising in the asset sales takes the pressure off of anything along those lines. The way we're looking at McMoRan going forward, the way we'll look at it as well as any the other asset. I mean, McMoRan from a standpoint, it's is got the Davy Jones well test coming up. It's got a lot of rigs drilling some big structures. I think you're going to hear some exciting things out of McMoRan in the next 3 to 6 months, about plans for 2012 that are mind-blowing. And what we think from a standpoint of McMoRan will be an opportunistic asset for us. Where an opportunistic asset would be is that if we want to expand in another area that was beyond our capital budget, maybe that'd be a place to harvest some funds over time. I think from a couple-year outlook on the McMoRan holding, I think it's very important to not only our holdings, as we're owner there, but also to the McMoRan shareholders as well. But we're definitely not -- we've definitely changed our focus there of it being the primary asset to enhance our balance sheet. We've accomplished those objectives, as you just said, with the asset sales. And that will be opportunistically -- opportunistic shareholder there in 2012 and '13 and be long-term in nature. Winston, you want to add some color on the balance sheet?

Winston M. Talbert

Yes. If you look at the asset sales we just did, we've got a pretty significant NOL so we don't see paying any taxes on that and we don't really see paying any taxes until probably late 2013, 2014 when Lucius comes on. So we're going to get the full benefit of the cash coming in. And so we think that's a pretty, pretty powerful debt reduction. And because of the structure of our debt, we've got all of this callable debt over the next 18 months. We thought this was a great opportunity to just go ahead and start lowering some interest costs.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Got you. And to that point, how do you guys think about potentially adding some acreage? Obviously, the Eagle Ford-- clearly it's a core area for you guys, versus kind of paying off debt. How are you thinking about the balance then? And I guess, Jim, you'd mentioned potentially another area for PXP at some point.

James C. Flores

Well, Leo, you know we tested that around here. I mean, that's obviously -- you're not paying us to just pay on debt all the time, although it's an important part of our value creation right now because of the amount we have and the cost of it. At the same point in time, with the asset intensity we have, with California, the high margins, the super durability, which is basically the proved reserve right -- life plus the inventory, this is obviously the class asset. The Eagle Ford, even though the margins aren't there on a cash basis, they're on a invested capital basis because of the high LOEs, plus we have a large inventory, plus the growth rate's so high. It's obviously a key asset. The Gulf of Mexico is -- it fits in that category because we have obviously huge margins in those barrels once they come on in 2014. And we have all the capital properly financed, so we have a carry on that. So that's a fantastic asset. Our gas assets of Haynesville and Madden Field, the Madden obviously offsets our gas burn in California. It keeps us hedged there. Haynesville is our gas speculation, if you will. The key about our business can be controlling our gas drilling exposure next year, which we're committed to doing within our gas business cash flow. And then we have McMoRan shares which has the tremendous exploration on the gas side. We look at our asset portfolio and we look at our exposure to Brent on the coastlines, we don't see assets within pad 2 area of the crude oil world that compete with those margins. So we're not going to be out there looking for assets to dilute those margins. We're going to be looking for assets that expand the areas where we have these great margins. Now those areas where we have great margins happen to be where the most expensive assets are. That's not saying we're going to go out and buy those assets, we're just saying we're committed to not diluting the margins we have. We have all the gas exposure we need and everybody's got tons of gas. There's TCS [ph] laying everywhere and so we don't want to invest capital in that and destroy our margins on a near-term basis. We don't want to invest in capital in the condensate world or the natural gas liquids world that destroyed those huge margins we just built with our Brent contracts. So we're pretty much locked in operationally to our strategy of maximizing exposure to Brent. Our growth rate of 15%, we have ways to accelerate that. We accelerate in the Eagle Ford, but we're going to manage that all the way until Deepwater comes on, which will be a beast of its own. Our big exposure is going to be in things like Phobos, where you're going to see Phobos being drilled, which is one of the biggest projects to be drilled next year. There's not another well we can drill next year exploratory-wise that would have the same impact. So we're very pleased with the hand that we have. And so it's working on the interest cost and working on controlling our inflation cost and doing some things like that. And just working on the operation right here is going to keep our hands full for a while.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Okay, great. In terms of the Eagle Ford you talked about some inflation, can you just let us know kind of where you're seeing the well costs running there?

James C. Flores

Well, what's happening, everybody's moving to -- moving some production facilities. You see really see it in the production facilities. Tanks that cost $9,000 now cost $21,000, and that's just a small example. But I'm talking about -- everybody says, "What factor do you use?" Well, that's a 3:1, 300% inflation on just one item. And it's just shortage of everything. And when you've got big players like BHP and Marathon trying to get their positions put up and their operations and so forth, and they're wading into an already-tight market and they're using acquisition economics and extra capital, or they're using their oil revenues diverted. You've got a tremendous amount of pressure. And you're seeing it everywhere, the Eagle Ford, the Bakken, the Permian Basin, all 3 of those oil provinces. And the key about that is that you want to at least be in Eagle Ford, where you're selling oil at Brent, versus selling oil at WTI. And you've got big quality -- or big transportation discounts. And so that's what's keeping us focused in the Eagle Ford. I think what we'll end up doing as our ramp-up kind of drilling rigs, that's -- the drilling rig costs are just one thing. Most of those are contracts or kind of fixed charges. But it's all the variables. It's the people, it's the pipeline, things like that. We just got to be on our game and we're fully up to it. We're actually going to redirect a lot of our personnel that was in the Granite Wash to really give us some flexibility in the Eagle Ford, to make sure we are able to keep all of our employees not only busy, but more to the standpoint, have enough capacity to effectively execute in the Eagle Ford because it's a big project for us. So it's just going to be a battle. Oil prices are driving inflation. If inflation kills the dry gas business, then we could be more positive on gas into '13, '14. But until this inflation gets worked through all the budgets this year and next year and all the gas drillers, we're continuing to be pessimistic on any kind of rebound in gas. Now is gas going to go down another 10% or 20%, we have no idea. But it's continued to have downward pressure on it, so we're going to continue to minimize our investment exposure to natural gas and continue to hold our options at Haynesville, Madden and McMoRan because we think the inflation rate in the cost of doing the gas business is continuing to go up. And so even if prices are able to rebound a little bit, the inflation rate they have there is going to eat all of the profits until we see significantly higher gas prices. So there's a change coming, but we don't think it's anytime in 2012.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Okay, that's great. And I guess just one last question for you guys, just thoughts on regulatory issues there in California. I guess a couple of other operators kind of got hit with that recently. Just wanted to get your sense on kind of the landscape over there and if they're kind of tightening things up and putting any new regulations on you guys.

James C. Flores

Yes. I'm not going to say what I was going to say. But I was going to nominate Steve Jasen [ph] for something. So anyway, the California regulatory situation for us is pretty benign after the rodeo we did offshore. Our onshore business we planned 3 years ahead. I mean -- and people come in there, you've got to follow the rules and it was pretty stringent on what the new outlook was. And it's very, very hard to do a development project, a new field -- a new greenfield development project in California. We've been saying that for the last 5 years. Somebody's asked us about when are you going to expand in California, how are you going -- the answer back to that, they don't want -- the regulatory situation not set up for that. Now people like Oxy and so forth that have the power and the chutzpah to do it, I mean, they can do it. We're not in a position to do that, and we wouldn't want to expose our business plan and shareholders to that type of expectation, because we think the Eagle Ford is a much better place to expand. And I think we're proving that every day with the drill bit.

Operator

Your next question comes from the line of Scott Wilmoth with Simmons & Company.

Scott M. Wilmoth - Simmons & Company International, Research Division

I apologize if I missed this, but have you guys updated -- can we get an updated fourth quarter production and full-year production, post divestitures?

James C. Flores

We haven't updated anything on a quarterly basis. If you just look at pro forma, pro forma will probably be -- we're looking to average around 100,000 barrels a day. So you're looking probably pro forma 80,000 BOE a day net of divestitures. And obviously, the fourth quarter is higher, above our average, because the first quarter was below. So we're significantly above that from a standpoint of fourth quarter -- fourth quarter production, when you do your math.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay, that's helpful. And then when I think about 2012 production guidance, how much Eagle Ford growth are you guys baking in there?

James C. Flores

The correct amount, we have 15%-plus production growth company-wide, and you'll see that consistently for the next 5 years. Now whether we're above that or not depends on how much capital we deploy or whatever, but you can count on the 15%.

Scott M. Wilmoth - Simmons & Company International, Research Division

And just what about the Eagle Ford component only?

James C. Flores

We'll break all that down on the 15th of November on asset by asset, and please come to that because you'll understand everything we're doing.

Scott M. Wilmoth - Simmons & Company International, Research Division

Sounds good. Okay. And then, lastly on Phobos, you mentioned a spread [ph] in 2012, can you give us an update on the permitting process and when we can expect that to get drilled?

James C. Flores

Well, obviously, Anadarko's in control of that aspect. We've got it for second half of 2012. And again, the Gulf of Mexico is not a 3-week permitting process, so those plans and procedures and meetings and pre-meetings and pre-filings are already been in place. I mean, Anadarko's been very successful, if not the most successful in getting all the permits in the Gulf of Mexico. We were able to flow-test Lucius before we were able to drill a well. So it's really amazing what they're able to do. And Doss, if you want to add anything to that.

Doss R. Bourgeois

It looks like the permits are starting to come out a little quicker. The other day, the last week, I think there were 13 that got released, so --the drilling permits.

James C. Flores

We certainly are going to take Anadarko's call on that for permit drilling and rigs and all that stuff. We just know, where the seismic that we continue to process and look at and so forth becomes clearer, that the information comes out about the adjoining wells around us, we continue to feel better and better about the Phobos prospect. It continues to get stronger with every bit of new data.

Operator

Your next question comes from the line of Jessica Chipman with Tudor, Pickering and Holt.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just going to press a little bit on the California regulatory question. I think there was an article out last night. Basically, it looks like it could be pretty good news from a permitting standpoint in California with the removal of Elena Miller. As we think about your...

James C. Flores

That's kind of personal, isn't it? Well, think about it this way. Think about it this way, that California is going to be very diligent in their permitting process. There's going to be a new administrator in there, just the aspect of that. The facts of the matter, California is very -- administration's very focused on jobs and very focused on economic improvement. And they're going to strive for balance. I think we've had probably 7 different administrators in there during our career here and so forth. We deal with each one. We've had a Republican administration, we've had Democratic administration. The great thing about that California, it does not and will not go away, from an oil production standpoint. And the thought process is they haven't had an expansion in California in a long time. Oxy's trying to do that right now. They're having to wrestle with some -- probably some new ideas. And so it's going to take some good thoughts, but there are a lot of smart people out there that are going to figure it out. And from a standpoint, I hate to think that this was good news, somebody being fired at this time when the world's so unemployed around here. So let's be a little careful there.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Second question, just looking at capital budget -- and I know that you're going to give more detail on this at the Analyst Day. Just removing the spending in the Granite Wash, been looking at growth previously expected. It looks like CapEx was up a bit, but production is essentially in line. Can you just help us reconcile the difference directionally? Is production probably biased higher and it's probably oilier?

James C. Flores

Well, I think you're catching us at our traditional point where production is being managed and CapEx is being recognized for a little inflation. And so capital's probably a little more target and then production will be the variable. But that's traditionally where we are at this time of year, and just see how things go throughout the rest of the year. The big thing we want to highlight is we feel pretty good about the $1.5 billion because of our hedges that are in place, because of the revenues we see out of our Brent contracts in California. So we can give a little tighter -- we can give a little tighter CapEx number from that standpoint. Production is going to be depending on a lot of things, and we'll manage CapEx if prices are lower. And obviously, that would have some effects to production. You get $80 Brent and $65 WTI, we're going to have to manage some CapEx around here. But if we have $110 Brent like we have right now, then we're going to probably be a little more important on the production side. So I think that's kind of traditionally where we are. And you look back in the past year, it's just probably -- it's in line over that thinking.

Operator

Your next question comes from the line of Marshall Carver with Capital One.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

On the IP rates and the Eagle Ford, you highlighted some great wells. How do those wells compare to average wells that you put online in the quarter? And how are those wells holding in compared to the IP rate?

James C. Flores

They obviously compare better, Marshall. But same point in time, one of the keynotes here, these are our -- I don't want to call them regular fracs. This is our traditional frac crews and highway -- these are not highway fracs and so forth. All of the engineering adjustment down there -- I mean, there's so much innovation going on realtime on the ground, trying to get things going. I mean, obviously, the wells -- I mean, I could tell you the wells can flow more if we had the facilities and enough tanks and so forth. These are very, very strong production rates, very strong wells, and they're obviously going to change the dynamics of PXP as well as all the other companies down there. What we're more excited about is being in the situation of prospectivity of the acreage. We're going to be able to mine it harder at this point in time because of the infill drilling that I know Mark was articulate about in his conference call, about some down spacing or closure [ph] laterals, as we call it. But we're going to continue to monitor it. We continue to see these type of wells. Our EURs are going to go up, our recoveries are going to go up and so forth. But we're basically going to stay in line with everybody else. The key is about having the right acreage and the right position, and also the marketing aspect. Our marketing contracts, with about 7, 7.50 [ph] off of LLS, which is basically Brent, which includes at the well head, it includes all transportation costs, are superior to most contracts in the field or at least are on par with the bigger operators. And that's going to give us significant advantage to continue to invest capital on an accelerated basis. It can drive these kind of results going forward. So we love our position there, we love the size of it and we love the resource we're putting in it, and we also love the marketing aspect of it.

Operator

Your next question comes from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Jim, just a follow-up on what Marshall just asked. You've looked at the wells you've highlighted in the first, second and now the third quarter release in the Eagle Ford, the results are getting measurably better each period. Are you -- can you talk about anything you're doing differently in terms of lateral length or number of frac stages, especially since this doesn't even really account yet for the implementation of the highway frac?

James C. Flores

Yes, Ron, they're specifics. But again, these are all great Analyst Day questions and so forth. Get it from the horse's mouth. But on the end, it may be 20% improvement there, but it also may be 20% of change of procedure, like how far apart the fracs are, this type of thing. Maybe 500 feet more in lateral, 500 less. It's really about location of the acreage. And then that robin [ph], in that thick part of the Eagle Ford where we are, the heart of Eagle Ford is a spectacular place. So I'm looking forward to everyone really seeing, with our position there in the heart of the Eagle Ford, at our Analyst Day and go through it. So we haven't done a tremendous amount of changes. We've only drilled about 30 or 40 wells in there total, and EOG's drilled some and so forth. It's so brand new, and we haven't had to tweak it much to really get these type of results. So I think you'll feel the importance of our acreage in the reservoir more than the technology changing at Eagle Ford once you get a under-the-hood look on November 15. I sound like an advertisement for that, but that's really -- I want to save some stuff for that too, as well. Sorry.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

I know Exxon on their conference call, last week or the week before, upgraded the pay thickness at their Hadrian-5 well, which bodes well for your Lucius complex. Can you also talk about beyond just what that means for Lucius, but also -- what that can also help you with it, as you look to drill Phobos next year.

James C. Flores

Yes. I mean, Ron, we're excited about -- that's -- between California and the Eagle Ford and obviously our Lucius Gulf of Mexico projects and all the projects we have, that's going to be a key part of our Analyst Day coming up because people have heard about Lucius and then Hadrian in Exxon's call. There's going to be a lot of information that we can't show, but there's going to be as much information as we can show to give everybody a feel -- I think everybody will get a real clean look at the wells and the thought process we have around the power of Lucius -- not only the strong economics because of the great reservoir and the shallowness of it, but how the Lucius/Hadrian complex really sets Phobos up as we learn through this thing and the adjoining prospects that we bought prior to the suspension of operations in the Gulf of Mexico by BOEMRE. And we bought them in March and that incident happen in April. So we're just getting started with a brand-new trend and all the excitement around there in '12 and '13. And I think between us and Anadarko -- and they're excited. I think we can show everybody that we've had to hold onto ourselves internally -- and we've been running around financing, that's been so important, and to get that type of financing in the Deepwater. These are smart guys at EIG and so forth, in being able to recognize what we had. We had several other players that we left at the altar that obviously, that -- one is as aggressive as EIG. And that validation helps everybody, but really excited about you guys coming and seeing some of the data.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Great. And I think just these next 2 won't be an Analyst Day question. Just in terms of the timing in the asset sales, in relation to Scott's question on the fourth quarter production, shouldn't we assume -- I think in the press release, assuming that those acquisitions or those asset sales close at year end, so you would still have benefit of that full production stream for most of this quarter, correct?

James C. Flores

There's ins and outs. And maybe Hance can follow up with the effective dates, because they're both different. And we have capital going in the Panhandle -- we call it all the Granite Wash and Panhandle. And we don't have any capital going into South Texas, so there's some ins and outs there, but predominantly that's the case.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And with the proceeds, that'll allow you, at least initially, to fully pay off your revolver. And I assume you'll have a cash position you'll be working through next year.

James C. Flores

We'll have that cash position, but also the cash position out of Plains Offshore, the EIG financing. We'll sit on [ph] their additional $400 million. Now in the aspect of the cash position you're talking about, that's whether or not Winston goes to work on our fixed cost interest and just pay down some of our fixed debt which is callable at this point. Winston, you want to...

Winston M. Talbert

Yes, I mean, if you look at where we are, we think our barn base [ph] is going to go up substantially even after the asset sales, just by virtue of the contracts and some of the things we've done to strengthen our position. So we fully expect to use the revolver as part of our capital structure going forward. So we're going to be looking at the -- we've got a note that's callable right now, 7 3/4%. We've got notes that are callable in early next year. So we're going to look at all of our capital structure and the exercise here is to-- not only to reduce the amount of debt but the cost of our debt. And I think that's going to be really important for our shareholders.

James C. Flores

Ron, something we talked about all year, there's 3 financial objectives: one, is try to maximize our oil revenues through exposure to Brent. We were able to do that in California and also in the Eagle Ford. Number two is offset our derivative charges and restructure our derivatives so that we're not taking a $90 million charge for our put insurance. We were able to do that. And the third thing is obviously lower our fixed cost interest and take advantage of these historically low interest rates. And so with these asset sales, it's going to allow us to do that as well, and accomplish those 3 financial objectives, at the same point in time keeping an eye on the ball and the operational objectives.

Operator

Your next question comes from the line of the Gregg Brody with JPMorgan.

Gregg Brody - JP Morgan Chase & Co, Research Division

Just following up on the debt questions. I recognize you're reducing debt. What are you targeting for in a metrics perspective to arrive at that reduction levels you want to be at?

Winston M. Talbert

Well, I think the way we look at it is, we look at it on debt per proved developed basis, and we think we're going to be definitely improving that with these transactions. Debt per proved, our fixed charge coverage is going to go way up. So we think on just every metric that we can think of, this is going to get better. We're not really big debt-to-cap people but we are going to improve our debt to cap this year and through next year.

James C. Flores

And then if you think on our net debt basis including the McMoRan shares, we'll be below 40% pretty soon.

Winston M. Talbert

Yes. And the other thing that this does, especially alongside the EIG transaction, is make sure that we can stay within cash flow pretty easily over the next couple of years as we bring Lucius on. And when Lucius comes on in 2014, all bets are off.

James C. Flores

I think all bets are on.

Winston M. Talbert

All bets are on, okay. Because the cash flow's going to be so strong coming out of that.

Gregg Brody - JP Morgan Chase & Co, Research Division

Are there any specific numbers you're thinking about? I know you mentioned the metrics.

Winston M. Talbert

No, there's no specific numbers. We internalize what we think would be a good credit. We think we're just -- we had a little bit heavy leverage. We also thought we were a little heavy on the natural gas, given the current market conditions in natural gas, so we decided to kill 2 birds with one stone.

Gregg Brody - JP Morgan Chase & Co, Research Division

Okay. And then just on PXP Offshore, what's the current plan there from a capital-raising perspective, just as you think about IPO down the line and your ultimate ownership in that entity?

James C. Flores

Gregg, there's a couple of historical models that we're looking at -- really the Bastar [ph] Arco model. And one thing Bastar [ph] did, they sold 50% of the company from the get-go and they were kind of locked in, so they couldn't raise more capital and they couldn't -- and they had a lost operational success. That was a pure exploratory play, but we're doing development with follow-ups, so it's a lot lower beta on the operation side. So we want to maximize our interest in POI. The operational plan with risk success has POI producing more oil than PXP by year 5 of POI's life. That's 2016. So if that comes about, then there'll be few assets to rival California's importance to PXP, and the Gulf of Mexico will. So we don't foresee PXP -- POI being separated from PXP or further dilution there. At the same point in time, with the financing and so forth, as an exit event, we did put some of those provisions in the possible path to exit for our financer. Obviously, they're going to want liquidity, or potentially want liquidity. But if everything works out well, they've articulated they'd be happy to stick around throughout the life. So we I think this is a long-term joint venture to build long-term value in the Gulf of Mexico. It's properly financed in a way that's not costing the PXP shareholder any carry throughout the buildout stage of production in the big platforms in the Deepwater for these large production systems. And that, to us, we believe is the key value creation, where you start looking at the $800 billion of cash flow that's going to come out of this thing -- and starting in 2014, '15, '16, it's not going to go away, and start giving a discount to that and pick up that valuation for our stakeholders today.

Gregg Brody - JP Morgan Chase & Co, Research Division

Just so I'm clear, the 450 raise, [ph] it should pretty much stay with that entity just to fund it.

James C. Flores

Yes, in the slides we sent out so forth, you've got a situation on page 8. You've got kind of the business plan going forward on POI and it's representative of the CapEx and the cash flow going forward. Now there's a supplement of additional PXP capital in year 2014, because of the timing of when production comes on and when CapEx -- but that's strictly a combination through a bank credit, and whether PXP is still the guarantor of that 2014 or not remains to be seen, because it should be a standalone entity. So yes, it's designed for the financing that we received from EIG to be the final and permanent financing from that standpoint.

Gregg Brody - JP Morgan Chase & Co, Research Division

That's very helpful. And just one nit question on the proved reserve numbers for the assets you sold. If you have them, could you just provide the mix of oil, gas and liquids for the assets and then just the proved developed percentage, if you happen to have it?

James C. Flores

It's 90% gas, 8% liquids, 2% oil, okay? But we're going to yield to the buyers on the proved reserves, let the buyers talk about their proved reserves. Obviously, they're going to be the owners going forward of what the assets are, and let them articulate -- I think Glenn[ph] did some of that in their press release. I mean, if you can get those numbers out of Oxy, good luck.

Operator

[Operator Instructions] Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Apologies if these questions have been asked, but just -- I think you mentioned commitment to debt paydown with the proceeds coming from these asset sales. As you look at your portfolio and you look at your Eagle Ford position in particular, do you feel you're sized well for the next couple of years? Or do you see opportunities to expand via either bolt-on or larger acquisitions?

James C. Flores

Well, here's the problem. We're sized perfectly, Brian, but the rate of return we have putting our capital in our Eagle Ford versus start buying somebody else's Eagle Ford to start over is so superior that we're locked in by our own prosperity for those next several years. And with Lucius coming on, we'd just be diluting that -- our production profile and our returns. So we're not going to dilute our returns. We'll stay with our plan. We have plenty of acreage for the next 5, 7 years of drilling in Eagle Ford and, yes, we'll just be opportunistic, but it would have to be at competitive returns. It's not a size thing. It's not an inventory thing. We have tons of that. We've already increased our inventory probably by 50%, just some of the down spacing discussions that we're having around here. So it's continuing to grow and get larger. And we're not seeing anything that's accretive to our existing portfolio or accretive to returns. We're seeing good acreage. It's just so expensive, it destroys what we created.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, that's helpful. And again, at the risk of asking something that was already asked, I think you had mentioned that the 4 wells that you announced in the Eagle Ford did not benefit or did not use the highway frac. Can you just kind of talk about your plans there, especially after the strong well that you discussed in your last call?

James C. Flores

Yes, well -- and you asked the question perfectly, Brian. That's French for "yes, they were less expensive" from that standpoint. When our engineers pushed back on us, they felt like we were pushing the technology meter too far, at the expense of press release-type numbers, except we're going to make some changes in our fracs and see if we can't do some things. And they've responded and so what I'm saying is, the innovation is just beginning in the Eagle Ford. I mean, as far as what's going to happen and just on-the -ground tweaks and so forth they are trying, just applaud all the effort our operations and engineering people responding and continuing to expand on a cost-effective basis. And that's really what that's about. So technology's great. We got people thinking and moving, but you've still got to do it and deploy it cost effectively. And that's what our guys were able to do here and do it in spades. And we will get into any kind of technical relationships and changes and so forth at the analyst meeting on the 15th and so forth. And we like the same questions, Brian, because these are all good questions to ask -- or answer. So don't worry about it.

Operator

At this time we have no further questions. I'd now like to turn the floor back over to management for any closing remarks.

James C. Flores

Okay. One, I want to apologize to everybody for piling on, on these conference calls and -- with all the other operators. We'll try to spread it out next time. And thanks, everybody. We look forward to a big fourth quarter, year end, and on into 2012. We hope to see everybody November 15 at our Analyst Meeting. Good afternoon. Good morning.

Operator

Thank you. And this concludes today's conference call. You may now disconnect.

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