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Plains Exploration & Production Company (PXP)

November 15, 2011 2:30 pm ET

Executives

Rowdy Lemoine -

Mark Kidder -

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

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

Randall Vines -

Hance Myers - Vice President of Investor Relations

Stephen Laperouse -

Jeff Heppermann -

J. Wright Williamson -

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

Steven P. Rusch - Vice President of Environmental, Health, Safety and Government Affairs

Analysts

Unknown Analyst

Hance Myers

I think we're ready to get started, right on time. Good afternoon, for those of you who I have not met, my name is Hance Myers. I'm Vice President and Corporate Information Director here at PXP. I thank all of you for joining us this afternoon. We have had a fantastic response and turnout for the event. This is the first Analyst Day we've had since 2004, so we have a lot of stuff to share with you.

I'd like to give you a brief outline of the afternoon. Jim will begin by giving a recap of 2011, then I'll share some ideas on regarding our operational strategy. At that point, we'll begin discussion of our assets, and that will be led by Wright Williamson, Rowdy Lemoine, Mark Kidder and Jeff Heppermann, who I'll introduce shortly. You are also welcome to ask questions as they arise. After the asset summary, Winston Talbert, our CFO, will discuss our financial strategy. Depending upon the time left, we'll then have a Q&A at the end, which will be followed by a cocktail reception and dinner. Cocktails are planned to start around 5:45. We also have a break scheduled at 3:15 with refreshments and snacks.

And before we begin, I'd like to remind everyone that during this presentation, there will be forward-looking statements as defined by the SEC. These statements are based on our 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.

So with the housekeeping items out of the way, I'd like to introduce the members of our management team that are present today. If you wouldn't mind, please raise your hand so that when I introduce you, so everyone can put a name with the face. And also at dinner tonight, there will be 2 people from management per table, so you may want to think about who you'd like to sit with when that time comes.

And with that, I'd like to introduce Jim Flores, our Chairman, President and CEO; Doss Bourgeois, our Executive Vice President of Exploration and Development -- and Production, sorry; Winston Talbert, our Executive Vice President and CFO; John Wombwell, in the back, our Executive Vice President and General Counsel; Anthony Duenner, our Vice President of New Ventures; Marc Hensel, our Vice President of A&D. I think Marc is not here yet. Jeff Heppermann, our Vice President of Exploration; Mark Kidder, Vice President of Operation; Jim Kimble, Vice President and Treasurer, who is not here yet; Stephen Laperouse, Vice President, Exploration Land; Rowdy Lemoine, Vice President, Development; Steve Rusch, Vice President, Environmental Health, Safety and Government Affairs; Randy Vines, our Vice President of Drilling; Wright Williamson, our Vice President of Engineering; and Scott Winters, our Vice President of Corporate Planning and Research.

And with that, I'd like to turn it over to Jim and Doss.

James C. Flores

Good morning. You got it? It works, okay, great. [Technical Difficulty] So that's a rousing introduction of everybody.[Technical Difficulty] There we go. Now it's like an LSU football game, much better.

I just wear an LSU garb today, just in commemoration of our #1 team. We win every 4 years. We win the national championship. We won the 2003, 2007. We're trying in 2011. Kind of like Plains in our analyst meetings, 2004, 2011. We've got some consistency going now.

Anyway, it's an exciting day for us at Plains. Doss, his team has of course worked very hard to put together business for everyone that I think is accretive for our business. Market is very tough, tough natural gas prices, and really focused and concentrated on the high-margin oil prices that we're seeing around the world today. It's a distressed market, we've gone through huge technological innovations, we've gone through huge geographic, marketing changes and so forth, but PXP has never been positioned better in the marketplace than we are today, and I think everybody here is curious and somewhat recognizes part of it. We want to do a deep dive into the assets. We want to do a quick summary of where we are strategy-wise, where we are and where we look at our business and look at our position, which is going to surprise everyone that it's -- that's all perfect from our standpoint, and that we've got a lot of growth ahead of us. I think we'll be well recognized today by everybody.

This is kind of the overview. In 2011, with the consistently strong operating results, those are on the backs of the Granite Wash early on and the Eagle Ford later this year and that was our purchase in fourth quarter last year of our oil position in the eastern side of [indiscernible] Wilson County area. That has given PXP the growth profile of oil that [indiscernible] tried to develop in deepwater in the past that has been -- come on, guys, there's plenty of room, couple of seats right here in the middle, you can just make yourself at home. And with that, it's just the operating results that everybody's enjoyed, this year we expect to continue. We'll show you how that happens.

The 15% year-over-year production growth, that's accelerated post the sales of the natural gas assets in South Texas and Granite Wash. We issued $600 million of 6 5/8% notes, some of it, I'd just like to note that we've seen out there and taken advantage of low interest rate environment. The pricing mechanism in the Eagle Ford and California was spectacular. I was just talking to Duane Grubert [indiscernible] engineer of that, if he ever thinks we'd be selling along California over WTI or over Brent, and we both collectively said no.

At 10 years ago, when I came to flying by, Purvin & Gertz the big refining guru, and I said will you ever going to sell oil in California cheaper? More expensive than [indiscernible] never ever [indiscernible]. So it's really been interesting when you talk about some of the most prevailing minds of the industry, and they're well thought out plans, you have to deplete Alaska to make something like that happen. Well, we've had these huge changes and PXP's in the position to take advantage of that great pricing. Winston is going to go over it in detail with you guys and you guys can get a feel of why we think it's so durable.

Our hedge position is to be able to define our -- we call them our costless collars on a go-forward basis and given our downside, put protection on outside years gives you a good look at what we think cash flow is going to be going forward, really protects our capital budget to supports our debt structure over the entire corporation.

Our Eagle Ford development results continue to improve. We've got better and better flow rates. Obviously, that points to higher EURs at some point in time on the curve, if we can fill the acreage. We let a lot of people continue to fan those, but you guys have got a good spread of what those are. But as long as the volumes will continue going up. We're very pleased there.

And then we spent most of the year financing our Gulf of Mexico business, which we had meetings and interest from around the world and settled on a preferred stock structure with -- at the subsidiary level with EIG and with Lucius' sanctions this year between us and Anadarko, and our position is already sanctioned, but officially sanctioned later this year. It's going to be one of the spectacular production drivers for PXP starting 2014 and it's all well financed without using our own internal cash flow.

And then we divested South Texas and Panhandle to further concentrate our business on the crude oil side, on the Brent pricing and out of the natural gas market. We think that it's going to be continued dismal, like it has the last 3 years. It's going to get worse and worse going forward.

So with that, we're going to go forward into pro forma, the sale of 2011 assets. The PXP pro forma, the sale of $350 million barrels at proved reserves as of last year, then I'll see it changing when we do our proved reserves this year. 2016 resource potential, 68 year R/P, that's our development reserves that we have cash within hand. That's without any exploration. About 80,000 barrels a day is netting out of South Texas and Panhandle production rate, and we'll be growing that at 15% plus over the next 5 years. We really like to say 15% plus, because 15% we feel is the minimum.

If you do the math, with 15% growth rate off of the 80,000 BOEs, you get to the low end of our 2012 guidance, operational at 92,000 barrels a day. And obviously, we're guiding at midpoint higher than that. So it's going to -- depends what the acceleration of the Eagle Ford and the rig count is going to be, is one of the main drivers of that for the next couple of years.

We have 13,000 future locations in the company. A significant amount of those are in the Haynesville, but another significant amount is also in the Eagle Ford. And going forward, we'll break those down for you. In 2012, cash margin at $110 Brent, which is a little below where pricing is in natural gas at $4, about where the strip is, a little bit above that. It's about $600 million of cash margin, the $47 per BOE, and the $64 realized BOE at those prices, with 11/1 differentials.

Today, our differentials are much tighter than these. Obviously, we're getting higher realizations and higher margins because of the way the differences continue to move in our favor. With about $600 million of CapEx, total CapEx plus G&A and interest expense, less the $234 million of Gulf of Mexico capital. Basically saying that we're growing our cash flow of our business quite nicely with our own internal cash flow going forward, so about $2 million adjusted cash flow, basically 0.

Our net present value at 10% strip for assets. When you look at it from the standpoint of $14.397 billion, that's net of our proved reserves, and includes our exploration multiple, which is a big chunk of this is in the Gulf of Mexico, and around our Phobos project that will be highlighted in the guidance today, offsetting our Lucius reserve [ph]. And a total resource potential net of the proved reserves almost 1.666 billion barrels.

World class position. All we can say, graced over, all we have cash flow for.

Our operational strategy is to grow reserves 15%, 15% to 20% per year. We've been very consistent there. The key is we're more focused on the oil side than the gas side compared to several years ago. And we talked about growing production at 15% per year. Effectively manage our business, focusing on cost reduction. That's going to be the #1 issue for this industry in 2012, until crude oil prices settle down, is cost inflation and cost control. We're very concentrated at California [indiscernible] it's a low inflation environment, so is the Gulf of Mexico. And the high inflation environment we deal in is basically the Haynesville, inflation is reducing activity so we don't think that's going to be a big problem. But the Eagle Ford, we're very mindful of that, and we'll discuss a lot of that in the assets slides going forward. And then also focus on oil development projects to increase our total percentage of oil production.

The pro forma strip for asset sales strip pricing, our reserves, we expect our reserves to grow at these rates. On a proved basis, continue to expand, on a proved developed basis, obviously underpinning our debt structure of our proved, undeveloped well because of the nature of the resource plays and booking additional locations for every producing well.

Our total of BOE resource potential, 1.8 billion barrels. You can see how it breaks down per area. You guys have seen these slides before and understand what they look like.

Our strong asset intensity, this is one of the key things that sets us apart from the standpoint of a lot of other companies. How do we have strong margins in California? Because of the asset intensity. We have a long inventory of projects, we have high cash margins, a lot of great repeatability. So I think that when you look at companies and our peer groups, their asset intensity doesn't match up to ours. You look at Major, you look at [indiscernible] yes, they have assets like these. They have like California with the high margins and the great durability, the long reserve life and extensive inventory.

Some companies have just one, we have several. And when you look at California, the Brent pricing with a 14-year R/P on proved, a resource potential of 26 years and 2,300 locations, I mean when you add that to the margin, that's a spectacular asset. California LLS, you've got 46-year R/P, higher growth rate in 500 to 650 locations. The Gulf of Mexico, with a proved R/P, it's not on production yet, the resource potential of 59 years. This is just the Lucius project now, because that's the only one we're counting here as far as the asset intensity, at 8 locations in 59 years. Obviously, when it comes on, it will be reducing its resource R/P but we hope to get other projects like Phobos and other drills by that point in time, we'll continue to extend that.

If we get a natural gas asset, it's a map of 21-year resource R/P and Haynesville of course, 82 years at 11,000 locations. And with this, this is a good assets either on the gas or the oil side. When you look at the growth targets and the amount of liquids that we're going to be growing in oil, not just natural gas liquids, mainly oil on a percentage basis on a 15% growth rate, that's what this is tagged off of. We'll continue to have a larger and larger expansion of our crude oil and crude oil margins and our asset mix, our product mix than we've ever had before. So we're very excited about this. This is well in hand, and Doss, I believe, if you have anything to say but he will just kind of run through get it by, unless he'll make some comments.

It's obviously a slide we're very proud of. It's something that's well documented in our business plan. You can see that the gas business down here at the bottom it's a base business. It's going to have base production. Gas goes to $5 over our lifetime, or $6, we're going to make some money there and so forth, but we're definitely not going to lose any money in our gas business, our gas option.

California is a tremendous amount of cash flow. And it's continuing -- the production is going to continue to climb. Eagle Ford is our big growth for the next couple of years and our Gulf of Mexico Lucius, which is fully financed and in development right now, provides a lot of free cash flow. And so when you look at our Gulf of Mexico risked exploration success, it didn't come on until 2016 from a standpoint. So having that financed through our EIG partnership and not taking capital today, and some of our cash flow and drilling that is real important as well. So we feel like up until 2016 and 1/2 and so forth, we're looking at a situation of a well-documented, in-hand inventory to grow our production and grow our reserves and increase our cash flow going forward.

You look at the life of a resource play, and this is something I think is key to break down what these assets each mean. You look at California and California has been producing for 50 years, 100 years on the scale. The aspect is still proved. It's on the mature end of the resource and this is where all the profit is. So if you look at California at 40,000 barrels a day, and think about it in a peak scenario, it probably -- if you were to drill at all with horizontal a new technology today, it probably would've peaked at 400,000 barrels a day, during the peak part of its life. We're down on the tail, with the tail sitting there, it's sitting there, it's on the process of how you manage it and obviously price is a big part. That's driven, but it's not a lot of variability in the cost and it's in that and what you do with that cash flow is really important.

When you look at the Eagle Ford in the other side. It's early in its life, and so forth. Obviously it's a lot of growth. We're putting a lot of capital in it and so forth, and you look at the Haynesville, it's in the middle part. It's kind of it's going to be peaking or maturing, a lot of it has to do with price. Remember when we develop -- we didn't develop it, but the industry developed the Barnett Shale. The Barnett Shale was developed with an increasing gas price. The Haynesville's been developed with a decreasing gas price. It shows you how powerful this field is to continue to go to full development with a decrease in gas price, and it just, it depends on where you are in the price cycle and where you are in the life cycle of the resource play and how that gets developed.

But I think that kinds of give a good kind of illustration of how we look at and where our assets play out and why the mixture of our assets is not a complexity. It's really a stable base and a platform by which we can continue to grow at a much lower risk and a lot better margins than most people that are single-asset-focused.

And then when you look at our CapEx program in 2011, when we had so many ins and outs in the call, we told you we'd give you the detail. Obviously, by the end of the third quarter, at $1.364 billion. When you add in the Gulf of Mexico and the ins and outs and so forth, another $431 million. The $92 million in California is as planned. The $143 million is increasing the rigs in the Eagle Ford. Doss, we're up to 7 rigs in the Eagle Ford, correct? So we're adding rigs ahead of our plan. We're adding production facilities ahead of our plan to further accelerate that. So your information is, what we're doing at Eagle Ford, is a little stale, you'll get updated today. Plus in the Gulf of Mexico, we had $12 million spend here in the fourth quarter, we'll get a $50 million credit from the EIG financing to pay for it. So the ins and outs there.

And then in Haynesville, we're decreasing the rigs, but we'll continue the completion inventory, completing the inventory at the same pace, therefore, shortening our inventory going forward in the Haynesville, that you'll get some data on for the $72 million, then for the $64 million. And then we had $72 million divested in the Granite Wash and the rest is $48 million capitalized interest and G&A, and then obviously our Mowry exploration expense. So it should be very clear, ins and outs, acquisition proceeds. You go and do your models and get a fix on that.

The capital allocation program, 2012 we're looking at all our major areas: California, Eagle Ford, Gulf of Mexico, Haynesville and others, cap, G&A and interest, basically, and you see a well-diversified program with the majority of the capital going to the Eagle Ford and our coveted [ph] oil window based there in the Grovin [ph] and [indiscernible] Wilson County. When you roll all these together, as far as our operational plan at $110 Brent, remember we have floors at $100 on our Brent crude for most of it in 2012, you're looking at a situation where you have very controlled CapEx. CapEx is actually flat to be trending down over time, and you have exploding cash flow and exploding production off of the Eagle Ford growth and the Gulf of Mexico oil production starting in 2014.

There's nothing that's going to get in the way of us realizing this for the 141 million shareholders that we have today. And that's the commitment this management team has made to everybody. We've done it formally in the past. We've done it, we're going to do it again today and this is all we're focused on, it's delivering these results to everyone here in this room and everybody that holds our shares going forward.

With that, comments or any other comments from you, Doss. Do you want to make a comment? Go first, then we'll open for questions at this point.

Doss R. Bourgeois

I think our big item here from operations, people they fix a step up here in just a minute, or it's actually referred back to top of Slide 12, where we talk about asset intensity, our margins, our durability of our assets, that's what you're going to be able to understand and wrap your arms around, we'll give you data so that you'll feel good about that.

James C. Flores

Right. Does anybody have questions that you want me to cover or detail? Or we jump straight into assets. Right, everybody's well-informed on our business. Okay, the ops guys, you guys come on up and we'll go forward, okay?

[Technical Difficulty]

J. Wright Williamson

Sorry, my throat is a little sore today. We're going to start out talking about one of our, if not, our key asset, California. Before I do that, I want to [indiscernible] I'm Wright Williamson. I'm Vice President of Engineering. I've been with Doss on their team for over 15 years now. Really most of this measuring team has been together for that long. Prior to that, I was with Sun Oil Company and Forest Oil Company. So I've been in the industry since 1977, all as a reservoir engineer. So I've been an engineer my whole career.

One of the things I've had experienced a lot in the Gulf of Mexico, a lot in on-shore, Lower 48, Canada, international, so I've kind of been around the world a lot. I've seen a lot of big fields, I've been exposed to a lot of big resource plays. None quite like California. One of the unique things about California is just how thick and shallow some of these reservoirs are. They do have some characteristics like being heavy oil and things like that, that you have to overcome, but very easily to overcome. I've never really seen a place that with a small a footprint has as much oil in place as these California assets. I think as we go through this, you'll start to see some of the acres involved and realize how big some of the original oil in places are. I'm going to let Rowdy, we're going to kind of tag team through some of these. So I'm going to let him sort of give you a little introduction on himself as well.

Rowdy Lemoine

My name is Rowdy Lemoine. I'm the Vice President of Development. As Wright mentioned, we'll kind of go back and forth on a lot of these slides. Like Wright, I've been with Jim and Doss for over 15 years. Part of that time period, I spent a lot of time working for Texaco, working more conventional, assets, assets that had a lot more complexity, a lot more geologic structural and stratigraphic complications, assets that were a lot less predictable, assets that had high and steep declines, assets that require a lot of capital to try to arrest that decline.

In contrast, the assets that we'll show you today are quite contrary to that. These are low, as Wright mentioned, these are low-risk assets. We feel that the outcome and the results are very predictable, and probably as important if not more important, it's quite repeatable. And that's sort of, that will be sort of the theme that you'll see throughout the presentation this afternoon.

J. Wright Williamson

On this, Jim sort of already set up this slide for the whole company, but in green, we've got what we call oil and gas cash flow. It's also what I call operational cash margin. It's revenue minus, basically, lease operating expenses. Now one thing that's different between this and the total company slide is we don't include the corporate. We don't try to allocate the corporate capitalized G&A in interest or expense G&A interest to the individual assets.

So that's going to be missing on each of these asset slides. It's rolled up into our corporate slide. But you can see the cash flow from $1 billion forecast in our long-range plan to be over $1.6 billion over this period of time. Current production in the 40,000 BOE a day range, as Jim mentioned, going up to almost 60,000 BOE a day, with a pretty consistent and predictable cap on a $300 million to $400 million range.

Our interest is very high in California, 98% average working interest, 86% NRI, over 2,300 locations. Some definitions here. Whenever I'm referring throughout this presentation on proved net reserves, we're talking about end of year 2010 SEC-proved reserves. So those are record reserves on the books in the year 2010. When we say development resource potential, that's basically future locations is what we're talking about. What we drop out of that is the existing wells, the PDP and PDNP categories of reserves, and this is meant to give you a feel for the future drilling opportunities in the company.

You'll see some that include exploration, some that don't. We don't always say development and exploration. You're also going to see some, and I'll mention it when it comes up later, that are just resource potential or total resource potential. That's the all-in bag. That has the proved reserves and all the undeveloped and future locations included. These, the numbers for California, are very much an overview and kind of an average for the entire California asset, not that meaningful on a specific basis. As we drill down into assets, you're going to get specifics on each asset area.

Rowdy Lemoine

And before we actually dive off into the different asset areas as Wright describes, just to kind of give you a little flavor again to set up the rest of the presentation, a few years ago, industry coined a term "resource play." It's a catch bag. It means a lot of things to a lot of different people. Several of the characteristics of a resource play are long life and low-risk opportunities. The California assets have been resource plays for years. I mean they were resource plays before industry even talked about resource plays. And we're going to try to give you some flavor on that as we go through the presentation today.

Jim showed a slide earlier of the life cycle of a resource play and it characterized California as a mature asset, high margins, great cash flow. It's also a low-risk property or group of property as well. Legacy operators who own the assets that PXP currently own, through time, have drilled enough wells on all of these assets to define the commercial boundaries of all of the reservoir. And what we've done over the last few years is actually come inside of these boundaries, drilled infill wells, drilled areas that needed improved recovery, found areas that actually had bypass oil. So in fact, since 2007, PXP has drilled just over 900 wells in our California asset areas with tremendous success, nearly 100% success on those 900 wells.

J. Wright Williamson

I think everyone will recognize all of these terms, and Jim already mentioned the 26-year R/P and the 2,300 future well locations. Again, end of year 2010, proved reserves and total resource potential here.

This also is for California, onshore and offshore combined. You saw this type of analysis for the total company already. Cash margin being revenue less, in this case now, lease, total lease expenses. CapEx and operating cash flow being cash margin minus CapEx. That's the way the math works through all of these slides that we're going to go through the assets with. The cash margin is $60 a BOE, and that's based on a realized price of $85 per BOE.

One of the interesting things you -- and you'll get detail later, as Jim mentioned on the specifics of our new contracts. As you can see, the difference in '11 and '12, is we stand to realize a $97 per BOE price versus $85 this year. Again, the differentials are improving, and it would be another 5 barrels realized if we did today's differentials. So that's sort of what Jim was talking about earlier. But again, big cash flow out of our California. This increase in cash flow 2012 to '11 is a function of this price. Our production is not a lot bigger, a little bit bigger, in '12 versus '11 in California as [indiscernible]

Rowdy Lemoine

This map basically just sets up the activity, the current activity in 2011 and sort of what we predict from a rig standpoint in 2012. We're currently running 3 rigs in our 3 very prolific basins, San Joaquin Valley, Santa Maria and L.A. Basin. We'll go through some detail of each one of these assets as we go through the presentation. By the end of the year 2011, we'll have drilled close [audio gap] to 200 wells. You'll see our projected activity in 2012 is fewer wells. We'll drill a little over 100 wells in 2012, and that's really a function of 2 things, really.

We've got an increase in construction capital, as we actually develop and build out 2, what we'll call greenfield or new projects in 2012, one of which is a 19Z project. The second project is Arroyo Grande, and we'll go through some detail with that here in a minute. So we'll see an increase in construction capital, a little fewer wells drilled, and we're also in the budget and in our plan showing fewer wells in '12, as the regulatory and permit issues begin to show or begin to get a little more clarity on those issues in California. In fact, Steve Rusch, it might be a great time for you to comment on permitting, introduce yourself.

Steven P. Rusch

You hearing me okay? My name is Steve Rusch, and I'm Vice President of Environmental, Health, Safety and Government Affairs. My background is I've been with Jim now, I think, for 10 years. Prior to that, I was with Greg Armstrong at PLX, and I spent my first 20 years with Exxon, all out in California, I'm actually officed in California.

Regarding the permitting situation, PXP is extremely well positioned. And in fact, we pride ourselves on having a strong professional working relationship with our division of oil and gas and other agencies. And as recently as a couple of weeks ago, we cleared the path for another couple dozen wells in the diatomite in San Joaquin Valley and we'll continue to increase our inventory of wells that we can drill in California. So we're going to continue to work with the division and continue to make progress on that front. So thanks, Rowdy.

Rowdy Lemoine

Right here at the bottom of the slide, you see our future locations in North Shore, California. That's a very dynamic inventory. That inventory seems to grow every year as we drill more wells and start to get a better handle on what's remaining in some of these big assets.

J. Wright Williamson

Okay, I wanted to give you analysts a little bit of analytical data here. This is Onshore, a decline curve and our forecast for all of Onshore California. An interesting thing about it is that in 2008, 2009, most of you remember I certainly do, what happened to prices especially in California. The differentials blew out in the other direction. And we really had a period of virtually no capital activity except for kind of maintenance-type capital in that period.

And you can see our total rolled up assets had about an 11% decline. Well, even though we don't forecast our baseline decline based on that kind of trend, we actually forecast individual wells, small groups of wells that we think make sense, tank batteries, they all go to a common tank battery for example, or something. And we add all that up. But it's always a good check for us to come in and see that our baseline decline, which is this green curve, is fitting a period of known low activity.

So it gives us confidence that we're not over-forecasting the baseline and therefore, building in wedges on top of it and building a growth curve that we think we can achieve. So that's something we look for and I think you -- I'm going to show that to you on most of our assets, and it's what gives us confidence that we can achieve the growth we're going to show you today.

Rowdy Lemoine

We're going to start off in San Joaquin Valley. We're in Kern County, for those who don't know where we're located, about 30 miles west of Bakersfield. Kern County is the most prolific county in all of California. Our San Joaquin Valley fields produce plus or minus 20,000 barrels a day, characterized by heavy oil and oilfields, where most production requires steaming.

J. Wright Williamson

Again, a subset of all of California San Joaquin Valley, in this case, the thermal properties do have a little steeper decline than the total rolled up California 13% decline, but you see the same trends. You see it historically in this period of low activity. You see it in our forecast and our baseline decline. You see it with the 5-year rule now, you've only got 5 years of puds. And once you stop drilling your puds, you sort of see the same decline start dropping out on the pud wells that have been drilled during the 5 years. So all things that give us confidence in the way our forecast is being done.

You've seen the format of this slide before. I'm going to stop touching on everything on it. But proved reserves at San Joaquin Valley, again, yearend '10, $110. We're forecasting the -- you saw it on the last graph, with a 9% compounded annual growth rate, '11 through '15. 1,900 of our 2,300 locations in California are in the San Joaquin Valley. And clearly, excellent cash margins in the San Joaquin Valley. You can see that our realized price there is actually $106 compared to $110 Brent forecast. And if we did that today, it would actually be in excess of Brent, as Jim mentioned earlier.

Just a real quick overview for the guys that may not be familiar with thermal recovery. We have 2 types: steam flood and cyclic steam. I know you've heard the terms. I don't know if you've really realized what we're doing. This is a continuous steam injection well. We inject in the reservoir, it heats up a thick oil average 14 degree API in the San Joaquin Valley, allows that -- lowers the viscosity, allows it to be mobile. The steam eventually cools, turns into a lot of water. We make oil, gas and water out of continuous producers. And that's what we call a steam flood.

We do this type of recovery when we have connected correlatable sands. When we have sands that aren't interconnected, or they're very hard to correlate, which some of our things are, we go to a cyclic type of thermal recovery. Some people refer to it as huff and puff. It's where you inject steam into a well for a period of days, maybe even weeks sometimes, to heat up an area around the well. Then you let it soak a couple of days, just to make sure the heat has dissipated, and then you produce it for weeks to even months, sometimes. Some of our wells perform very well, with only a couple of steaming cycles a year. Others, we need to steam every month or 2. But it's just -- that's the mechanism that we call cyclic steam, where you both inject and produce out of the same well.

These fields have been operating since the '60s under thermal recovery. They're shallow, 600- to 2,500-foot zones, heavy crude. Again, currently we have about 2,000 producing wells and 400 dedicated injection wells. Some horizontals, some verticals, mostly verticals.

Rowdy Lemoine

I'll just catch a couple of comments on this slide. Really what we're doing here is we're setting up the next slide, which is going to basically take us through into some level of detail of 2 very distinct rock types that we have in the San Joaquin Valley. We have Tulare sandstones, and we have what we consider to be diatomite. We'll go into some detail there.

This basically is a strat chart. Again, we mentioned the Tulare, Pleistocene in age, as compared and contrasted to the diatomite that you see here in the Miocene. And again, this is all shallow production. Tulare production is typically less than 1,000 feet. Diatomite is typically less than 2,000 feet in depth. You can see, we've listed off, on the right, some of the characteristics of these 2 different rock types.

A couple of comments to make, the Tulare has great porosity, extremely high permeability and as Wright mentioned, when you have connection between the wells, the steam flood is the optimum way to drain some of these heavy oil reservoirs. Where the sands are more discontinuous, or you have the rock type that we call diatomite in this particular case, the cyclic steam processes is the most effective way to drain the reservoir.

Diatomite, in contrast to Tulare, has even higher porosity. You can see at some of the highest porosity that you'll have in a subsurface environment, very low permeability. We'll talk a little bit more about diatomite in a future slide,

J. Wright Williamson

Yes. We'll show some detail on that. And you can start to see, even though these are still fairly crude in big ranges for type curves, but this is kind of the format we're going to try to use, give you the reserve ranges of our type curves, the IP rates and the cost, so that you can model. Now as we drill into individual assets, you'll get -- those will become finer and finer detail, depending on how crude or detailed you want your model to be.

Jeff Heppermann

I'll tell you a bit about California, for exploration [ph] I get one page, so this will be quick. I've been in the industry 30-plus years, at Gulf, Chevron and came about 14 years ago Wright was my first engineer the South Pass west delta area and played on a softball team with Randy and Rowdy. So I've been around all these guys for quite some time.

So back to California. The little bit of exploration, we're doing the course we've all heard about, the Oxy discoveries. And they're leading right up to our Cymric area. So we actually formed an AMI with Aera and shot new 3D seismic. And our AMI will include all the deep rights below the currently producing horizons in the Cymric field. And Oxy just leading right up to our leases and our AMI.

So we're pretty excited about that. We've got a couple of wells planned for next year onshore and Rowdy will talk a little bit more about some maybe offshore work we've got planned as well. But that just kind of covers early, we're always looking for potential exploration and I tell them cut a core occasionally, I have a very limited budget in California, but if that's the right thing to do, we'll do it.

J. Wright Williamson

And Jeff, our answers on the AMI?

Jeff Heppermann

50-50 with Aera. We both threw in our acreage. They kind of equalize at a 50-50. So we're on trend, we're in the right place and we could see some exciting results next year. More from me in the Gulf of Mexico.

J. Wright Williamson

We'll start off looking at Cymric Field. You see we've got a huge inventory of locations, both Tulare and diatomite. Again, same format and not the way we truly forecast our baseline, but it's comforting to see that the forecasts do sum up to be something that fits a period of inactivity, including the tail out here on proved and developed.

A lot of words here. I'm just going to point out a few things. Our particular footprint, Cymric, is a huge field. We have a portion of it. And these oil in place numbers are for our portion of 176 million barrels of oil in place in our Tulare formations. Current recovery, about 39% of original in place, with a forecast as high as 51% of oil in place. In the diatomite, in 205-acre footprint, we have 149 million barrels of oil in place. Current recovery is about 24%, and modeling and ultimate recovery at 57% of original oil in place.

Rowdy Lemoine

That's basically what we're doing in California. Just, I mean, we've got great rocks, great porosity, huge oil in place numbers, and we're just trying to improve our recovery. This is a basically a label map of Cymric Field. In yellow are the PXP leases. I've got a type log off on the left for reference that shows that the thick package of sands that we developed in Tulare, in Cymric Field, all the little small dots that you see here are actually wells that have been drilled through and or producing or have produced or maybe abandoned through this formation.

The larger dots are actual wells that we drilled this year or plan to drill next. What I'm trying to do with the circles is just circle areas that we're focusing on year-over-year to improve our recoveries in this field. It's a very busy slide. It doesn't show up well in this format. But the message here is -- it's confusing, but the message is clear. We've got a lot of infill locations, we've got -- we target incremental recovery and bypass oil.

There's actually over 300 locations that we currently have identified in the Tulare. The diatomite, again, a little bit deeper. Stacked package of reservoir here. The green circles actually represent produced wells. The blue circles actually represent wells that we drilled this year. In red are all the additional opportunities that we've identified. And we did -- the field was originally developed at 2.5-acre spacing, and we've been down spacing ever since.

In fact, in 2006, we did a pilot program in this area where you see a conglomeration of green producing dots, where we actually drilled wells on 5/8 of an acre spacing. Basically drilling wells less than 150 feet apart from each other. Because of the stacked sequence of section that we have here, and the type of -- unique type of rocks that we have, a large number of the wells that we drilled in that pilot program showed original saturations, which means we're not truly effectively steaming a lot of the zones even when we drill at the spacing that we're currently at. So it's just a further validation and verification of the number of opportunities we have here, and I believe we've got 450 or so currently on the books for the diatomite in Cymric.

Okay, so you ask, how is it that we're drilling on such tight spacing and still finding areas that are not drained? Well, if the uniqueness of the rock or the formation that creates our reservoir, again, as Wright mentioned, a lot of work but really, what a diatomite is, it's a single-cell aquatic plant. And all of these things, all of these individual diatoms actually rain through the seafloor and gather up at the bottom of the ocean, the paleo ocean creating thick sequences of diatoms. And through time, in depth in burial, the soft tissue that makes up the diatom is actually converted to oil. And the outside of the shell, or the outside of the diatom, is actually surrounded by silica. So that's preserved in place.

So if you can envision what you're creating there, is you're creating basically a ball that's got oil inside the ball, but it has no way to escape out of it. So it has great porosity but very low permeability, and that's what we're showing here. But the reality is, and when you look at these different diagrams you're just basically zooming in more and more magnification through a diatomaceous sequence. All the black area on both of these slides is porosity. And that is all saturated in Cymric Field. So what we do through the steaming cycle is actually extract that oil and get it to come into the well bore.

J. Wright Williamson

So some really unique properties and ends up being a very concentrated and high oil in place per acre.

Rowdy Lemoine

Just a little geology across Cymric Field. Each one of these layers is a layer of about 50 to 75 feet of diatomic rock. The sequence, if you will...

J. Wright Williamson

[indiscernible]

Rowdy Lemoine

Right. All of this, it was further complicated. It was uplifted and eroded across the top and oil actually migrated and trapped against this Miocene unconformity. So you can see, depending on where you are in the field, you have a different sequence of diatomatic rock to actually produce.

If you're on the eastern edge of the field, you're actually developing this section here, that's marked by these series of perforations. But you will not drain the rocks on this side of the field. And what we're finding through our spacing pilots is actually wells drilled very close to each other are still not having effective drainage pattern. So we continue every year to continue to drill inside the Cymric Field.

J. Wright Williamson

Let's just get into some photographs of what our footprints look there, like there, and Mark Kidder, our Vice President of Operations.

Mark Kidder

What we wanted to do is give you guys -- well, let me tell you about, a little bit background. I've been with Jim and Doss probably about 20 years now. Started off with Tenneco and moved to Chevron in shale, then has been with oils and rocks of PXP ever since.

So just from an operational standpoint, you look at the geology and everything else associated with it, but some ways down the line we've got to produce this stuff. And so just to give you an idea of the modern equipment that it takes to do this, this is just one view of the Midway-Sunset Field which is probably indicative of most of the fields that we have in California. If you turn 360 degrees, you would just basically see the same thing.

And so how do we make that more efficient? What we've done over the last several years is we've employed a lot more telemetry so that we can basically monitor our production and get the steam where it belongs. The big issue is getting steam to these diatomite ancillary formations. So it's very critical to get the right amount of steam to the right formations, to get the maximum output. And that's what we've done with this SCADA data in telemetry.

This is typical of a rod pump that we use, all our extraction of oil and water basically is done with pumping units across the fields. This is just a series of pictures, just to give you an idea of what the equipment looks like. This right here is a steam piping that runs through the field. These are expansion loops because of the high temperatures, steam runs in the neighborhood of 550 to 600 degrees, probably around 1,200 psi. This is the solar panel with the associated antenna. This is telemetry that we use to monitor that steam condition. These are steam generators that are associated with producing that steam, anywhere from 5,000 to 30,000 barrels of steam per day per unit. This is a test separator manifold system, where we got ball testers. This is just a processing facility at our Arroyo Grande field, which we'll talk about a little bit later. Here's more processing equipment associated with, you see, the heater treaters, tankage, separation, again, more steam generators. This is the Reardon [ph] test facility. It's kind of the main facility at Reardon [ph]. You see these test separators, tank storage, manifolding. These are basically waste gas and compressors.

James C. Flores

Hi, Mark, before you move on, one thing back on the steam generators that you might want to discuss is that we create all our steam by burning natural gas. Our natural gas right now is extremely cheap. We forecast it to continue to be cheap, so the cost of natural gas being low out in there producing our barrels in the California actually also increase our margins. So the avenue of us looking at low gas prices out here in California doesn't hurt our feelings at all.

J. Wright Williamson

It is a natural fit. I'm going to jump over to Midway Sunset. We've got a number of leases. It's better part of the Midway Sunset field. We're going to focus mainly on the Bremer Lease, which has Spellacy and Potter opportunities. Again, there's detail there for you on our type curves in each of these and over 400 locations associated with Midway Sunset. Again you can look at these. In fact, I'm not going to go through them all, but you see the same pattern in all of them. Again, for us, it's a gut check as to whether we're forecasting our wells -- our current wells properly so that we can count on the wedges that we get from our new drills contributing to growth that you see in these graphs.

Rowdy Lemoine

Another busy map, but again the message is -- here in outline is the PXP lease. What I'm showing here with the circles is areas of opportunity, where we have drilled and plan to drill here in the future. To the northwest part of our lease in -- outlined in yellow is a section that we call the Marvic and the Spellacy, which is a Miocene sand section. This outline in blue is actually a channelized turbidite sand that we call the D Channel. And then this outline in red is Potter. And again, there is a lot of stratigraphic complexity in the field but a number of wells had been drilled in the past. We know where the reservoir is. We know where the 0 boundaries is -- or on the reservoir and basically infill drilling inside of it. We're looking at a cross section that basically takes us across the length of the field, and you can see what I'm trying to represent with the circles. On the Northwest, you can see the Spellacy section is the section that's developed. In other words, you drill a well here, you don't have more of a D Channel or Potter, but you actually have a good Spellacy development project. Same holds true as you get closer to the middle of the field, where you Marvic and D Channel opportunities. And again, these are very thick, very massive, easily correlated within the outlines of those circles that I drew, opportunities in the field. And here's the outline of the Potter.

J. Wright Williamson

Moving on to our South Belridge field. A familiar pattern, we have a lot of future locations, you can see our type curve characteristics right here. Resource potential -- total resource potential in this case, at 50 million barrels in a 3,600-acre footprint. Same format of curves, this one may deserve a little more comment because even in 2008 coming into early 2009, South Belridge was actually the last place that we were drilling wells in that period of time. We were making some really good wells. As you can see sort of the growth that jumped up in the Belridge, so we kept going, and we probably stopped near the end of the first quarter. And it took probably 2 quarters for it to settle out, to be what we feel is a representive baseline decline in South Belridge.

Rowdy Lemoine

A number of opportunities. We're looking at Tulare sands here in South Belridge. Each one of these sands are very discreet and behave separately, separate reservoir, separate injection. We've got -- these sands are anywhere between 25 and 50 feet thick individually. Some of our thicker sands, we actually developed with horizontal wells. But again, the theme is we've got over 200 locations here, infills, extensions and horizontal opportunities.

J. Wright Williamson

Moving on to 19Z field. This is a field that Rowdy mentioned earlier that we're calling a greenfield development. We don't have any producers right now on our 40-acre footprint. We have about a 10-million-barrel resource potential for it. And based on pilot wells that have been drilled and tested but not produced historically, we have diatomite and Tulare potential there in over 70 future locations, so we're in the process of developing right now. There's a feel to a little unique in as much as the -- if you remember, when we were talking about that Tulare sits above the diatomite, in 19Z, the reverse is true. The actually -- the Miocene diatomite was actually thrusted up above the Tulare due to the tectonic history in this part of the basin inside the valley. So it actually improves the commerciality of this particular opportunity. Now the diatomite, instead of being below the Tulare, is shallower. It's the most prolific rock, and it's easier to drill, much easier to complete, so our well costs are lower and our economics are better.

Rowdy Lemoine

This is just the 40-acre outline that Wright mentioned. Again, it is not on production, but we're surrounded by production. One of the offset operators has a very successful program drilling diatomite wells. And what we're doing this year and Mark Kidder will show you with some of the photographs coming up as we actually had to prepare the surface there to go in and actually put in facilities and drill the well. So plans over the next year or 2 are actually to go in, and each one of these dots represents a well that we plan to drill on those 40-acre -- on that 40-acre track. And it's going to develop both the diatomite and the Tulare, which is below the diatomite.

J. Wright Williamson

This is the project timeline. We've actually done quite a bit of work in 2011 and even in -- back in 2010, grading and shaping the land. You'll see what I'm talking about in just a minute. But as far as the actual installation and building out the facilities as planned, a lot of that is planned for '12. By the end of the first quarter of '13, we think we'll be up and running, generating steam. We'll drill our wells and hook them up in the latter stages of '12 and early '13, and hope to have first sales on this greenfield project in the second quarter of 2013.

Mark Kidder

This is kind of an aerial view of the Star Fee, which is in McKittrick, and here is 19Z over in the lower right-hand corner. It's about 3-miles distance. And what we're basically going to do is use some of the available capacity over at Star Fee for processing and basically take our 19Z production over there and bring steam over to 19Z for processing.

This is basically an initial diagram of how we wanted the field to look like from a terrace standpoint. You got to have a place to put drilling rigs, you got to place or put production equipment and piping to be able to produce these wells. This is what we've essentially wanted it to look like.

This is what we started with. You can see the rigorous terrain associated with this area here. This is Chevron over, producing their diatomite right next door, as you saw in the aerial.

This is what we wound up with. This is where we are right now. You can see the nice new terraces, everything else basically going back and thinking about that original drawing, that it basically mimics this whole contour that we're set up for, so we're ready to go.

Rowdy Lemoine

We'll jump over to the first field in the Santa Maria basin, it's Arroyo Grande. Arroyo Grande is actually the second of the 2 projects that I mentioned early on that require basically excess construction capital. Arroyo Grande is a field that's been around for over 100 years. It's hard to call a 100-year-old oil field a greenfield project, but this field is very unique geologically. Particularly, it's basically a tank, all enclosed reservoir, bounded on all sides by faults or shale outs, so it's a tank and has actually no underground water disposal option. So the plan at Arroyo Grande is actually to build a water plant for disposal. Mark will go into a little bit more of that in a second. What this plan will allow us to do is actually allow us to remove the water from the reservoir, inject steam more effectively and produce some of the heavy oil that's characteristic of the Arroyo Grande field.

J. Wright Williamson

We haven't done a lot of subsurface work in the last few years in Arroyo Grande. We've been focusing on building out the infrastructure for this water removal plant to condition and remove water from the bowl, as Rowdy mentioned. So we get a real clear cut. It's a very gradual 10% decline. You can see that in '13, we expect to be steaming new wells and evacuating water, and we expect to build from a current 1,000 barrel a day rate in excess of 4,000 barrels a day through our long-range plan. 100% working interest, 94% NRI, so it's virtually all ours here, as Rowdy mentioned, discovered 1906, big thick heavy oil column. You'll see a little more picture of that in a minute. Started cyclic steam in '72, it's been steam flooding since '87. Peak production to date was in 2001 at 2,100 barrels a day.

The produced water, and this is what it really is the basis of the Arroyo Grande redevelopment. It's a dewatering project. The produced water has historically been reinjected into the thermal pattern areas, so that's very inefficient, inefficient from a steam flooding standpoint. We're cooling in the same area that we're trying to heat up with the steam by injecting cooler water. The water handling, we're just cycling that water over and over so it is an increased fluid handling cost in our LOE. Since we can't really void the reservoir, we can't create room to create an effective steam chest and have a gravity drainage component to the thermal recovery, which is one of the big advantages of an efficient thermal recovery project. We can't lower the bottom hole pressure significantly because, again, we're having to continually cycle this water. We need to get it voided out of this bowl, and that's what this project is about. It will allow us to create an effective steam chest, improve the steam/oil ratio. And so that's what the project is, installing a water treatment plant. Reverse osmosis is what RO stands for, to clean the water for offsite disposal. This sort of says the same thing. It's just the start of a picture that sort of shows the bowl Rowdy was talking about and where the existing fill infrastructure is.

Rowdy Lemoine

Here's a -- really a graphic illustration of the bowl, again, bounded on by faults and pinch-outs, it's basically just that. It's basically just a tank of almost all oil. I mean, if you look at the rock quality that we have at Arroyo Grande, huge large porosity, 30% porosity, good perm, a very thick section that developed over 1,000 feet of oil-saturated sandstones that we have to develop. The issue here is to have the oil and, as Wright mentioned, we actually do have right in the middle of the field what we consider to be an active steam draw, and as the results of this active steam draw that we're using to project our model going forward. Now if you think back in time, we've -- wells have been drilled. We know where the edges of the reservoir are. This is actually an isopac[ph]map. We've got over 100 feet of net oil in the middle of the field, and we feel like we can develop everything inside of a -- that 50-foot boundary, which is there in green. All the dots are our future development plans to actually get to the production numbers that Wright mentioned.

J. Wright Williamson

Yes, in excess of 400 future development wells. Again, a timeline for the Arroyo Grande project, this sort of shows that we really have already started a lot of the, certainly, engineering, the groundwork. We're starting to even build the facilities in 2011; that continues through '12. We have already drilled quite a few wells that are just not completed, waiting on the RO plant and the water removal and the efficient steam chest before we start to [indiscernible] cycle water in those wells. So we're sort of predrilled and set up to really take advantage of this starting, again, at the tail end of the first quarter of 2013.

Mark Kidder

This is an aerial of the AG complex, basically the -- this is the area where the RO plant will go. This is the existing plant. One of the things we did, we went through rigorous testing associated with the technology for the RO plant. We spent about 16 weeks making sure that what we were going to put in place would actually work with the waters associated with AG reservoir. We spent a great deal of time making sure that we -- everything was compatible. Technology that's existing, it's been used by Chevron in their San Ardo field with very good success, so we're just applying very similar technology. It's -- in fact, it's a little bit updated.

So this is looking back kind of in the hill where the RO plant is going to go. This is standing on that hill looking back down. See where the foundations are associated with some of the tanks, and the actual RO unit is going to sit on this foundation right here. This is kind of a cartoon, really kind of depicting what we're going through. This is where the RO plant is going to be itself. The challenge with this whole project is to keep AG producing while we're installing new equipment and at the same time, meeting our production goals. So essentially, this cartoon represents all the changes that we're doing to the existing equipment while everything is going on, to basically take care of the main plant that produces oil and gas and water right now while we're building the RO plant, so a lot of work going on to get this project to move ahead.

J. Wright Williamson

I'm going to shift into the LA basin now. A development resource of future drills in the LA Basin, total up to 84 million barrels of resource potential. We got 5,500 acres in total. It's spread over several different fields. And the LA Basin is different than the San Joaquin Valley in that it is a waterflood recovery basin. The oil is not as heavy. It responds very well to water flooding, as opposed to requiring thermal recovery.

Again, the same format of curve, the waterflood curves generally do have a little bit lower decline than the thermal recoveries do as a baseline decline, and you can kind of see that in the 11% versus some of the 13% or 15% that we were seeing in -- throughout the SJV. But again a period of inactivity back in '09 gives us confidence that we're projecting a proper baseline decline, and therefore, should have confidence that we can achieve this growth with our drilling programs. 88 million barrels of proved reserve here in '10, 129 total resource potential, we're making about 11,000 net barrels of oil a day out of the LA Basin. 400 -- over 400 future locations, forecasting about a 10% growth rate, again, excellent contribution to cash flow. You can also see the $90 realized price in '11 and the $95 in '12, that would again increase by, say, $4 or so if we updated differentials today. Pretty stable CapEx in the LA Basin, around $100 million, so the cash flow increase is really a result of the price increase in this case. And then the future growth, we'll see that cash flow grow even more.

Quick picture of a waterflood. It's just like a steam flood except it's water. We're injecting -- continues injection of water typically in a pattern where you have an injector surrounded by producers, or in some cases, producers surrounded by injectors. So it's an infill pattern that we shrink and shrink, that it's a -- we inject water. This oil is low enough viscosity to be able to bank up and be pushed by just water without thermal assistance. And then we produce both oil and a lot of water out and continue that cycle, so that's a waterflood as opposed to a steam flood.

Rowdy Lemoine

In reality, this is a very simplified diagram. Well, look at a log here in a second that shows what we're looking is a stacked sequence of very mappable and discreet sand units. Some of these sand units, they -- each one has varying oil saturation. Some have actually been swept and are what we consider to be thief zones. So in other words, when you're injecting water, it will go preferentially into that zone and won't be an effective waterflood for some of the other zones that have the higher oil saturation.

So it's probably a good time to introduce Randy Vines and some of the things that the operational folks are doing to improve that efficiency.

Randall Vines

All right, I'm Randy Vines, Vice President of Drilling, and I started working at San Joaquin Valley and some of these Los Angeles basin assets back in '85 with Mobil. As drilling, span of work mid-continent, Gulf of Mexico, overseas in Qatar for 3 years, and then came back and teamed up with Jim and Doss in the Gulf of Mexico, [indiscernible] Rocks and Ocean Energy, now PXP. What we're doing here is we're basically trying to control water and the gas inside. And with -- by doing that, we run our profile modifications. We run logs, understands which sands have been swept, and then we can run injection mandrills and we inject approximately 2,000 barrels of water a day, so we can put it from 1 to 5 zones and try to sweep these zones. There's other things we can do as far as running dual streams injectors. And we've only got a couple of unswept sands.

And then also on the producing side, we're running these isolation liners that basically are cut type packers and then a hanger on top. So on the producers, we try to eliminate some of the water that we're handling because that's the whole deal. It's just -- it's basically trying to keep the water -- prevent yourself from having the water over [indiscernible].

J. Wright Williamson

Yes, it's a constant redevelopment because of the different perms in each layer and finding a bypass hole, identifying it with new wells, producing it with new wells [ph]. So thanks man.

Inglewood Oil Field, a little bit of an overview of it. It is a big -- it produces about 7,000 barrels a day net to us. It has oil and gas. It's got 2 big gas processing plants that can handle up to 20 million a day. We do produce propane and NGL out of those plants. We got a big, as you can imagine, water plant and clarification and filtration to be able to handle up to 450,000 barrels of water a day, and the same goes for water injection facilities, oil dehydration and storage facilities, the 20,000 barrels a day capacity.

The LA Basin -- our LA Basin footprint is in parts of downtown LA. This is an actual picture of Inglewood, so it's been an oil field for a long time, as you can tell, but it is surrounded by LA, resource potential at 93 million barrels. Inglewood itself exhibits a 12% decline, but again, we look at that to get confidence in our forecast.

These are just some facts about Inglewood Field. Again, it's been around a long time. Peak production, like Jim mentioned, this is one of those that made 50,000 barrels a day. We're currently making 7 [ph] but we're on that tail, 1 billion barrel original in place, 285 million barrels recovered to date. One of our current target for expanding the waterflood and infilling the waterflood is the Vickers-Rindge, a couple of zones, you may have seen a picture of this in a minute from Rowdy, but it has a 37% recovery with an EUR of 50%. So that's kind of where we are in the vintage of depleting the Inglewood Field.

Rowdy Lemoine

You're looking at here is the schematic cross section that basically goes from the southwest side of the field all the way across to the northeast side. The field is basically cut in half by a large strike-slip fault, which actually creates a boundary on either side of the reservoir. But what's also important here are the smaller faults that are bifurcating off of the main strike-slip fault. It's these individual faults that create compartmentalization within the reservoir. I have a structure map I'll show you in a second. Wright mentioned the Vickers-Rindge. I've actually colored it or circled it here in red. The characteristics of the Vickers-Rindge are shown here to the right. We've got additional development opportunities in the Rubel-Moynier. And again, look at the depth here, everything here is shallower than 5,000 feet. Most of the wells that we drill -- that we have drilled this year have all targeted the Vickers-Rindge, and they all TD [ph] and probably less than 2,500-foot range. In the Vickers, we have some of the best porosity and best perm rock in Inglewood Field. You can see the EURs associated with that quality rock and the well cost is part of the microfrac [indiscernible] inside that [indiscernible] for Inglewood. Here's a structure map of the Vickers. I actually [indiscernible] the top of the Vickers D sands. A couple of things to point out, again, here's the stack sequence of sands that we are actually completing [indiscernible] So here's our stack sequence of sands that we actually developed. And again, each one of these sands behave independently or as a discrete member, as Randy mentioned when he was talking about how we address some of the water issues and bypassed oil issues. Off to the left is the structure map, and again, the opportunities are all shaded in dark green or this magenta color, either a circle or a triangle, depending on whether it's a producer or an injector. The lines that you see running across the structure map are actually the faults that I mentioned previously, and each one of those faults has its own separate compartment. Each one of the sands has its own separate discrete layer. So within this complexity creates the opportunities and as part of our development plan going forward.

More the same, this is the next sequence down, Rubel-Moynier is a little deeper. Most of the opportunities are actually expansion on the south side of the field or infill drilling, where we map much thicker Rubel-Moynier section.

J. Wright Williamson

This is just -- yes, go ahead.

Mark Kidder

Just quickly, this is our -- as Wright mentioned the gas line a little bit earlier, where we separate our propanes and NGLs at the gas line over Inglewood, but also this is kind of typical of the dehydration facility that we use in the field to take water out of the oil.

J. Wright Williamson

Montebello, again, it's another one of our urban fields. We won't go into a lot of the details of the geology there, but again, it's a very similar asset. It's got a little bit smaller in size but it has a huge number of future locations. [indiscernible]

Montebello field, again, as you can see really, the last couple of years, we haven't had a lot of subsurface activity in Montebello field, a few work overs, a few pump replacements, things like that. At such enhancement, quite stable at 12% baseline decline. We do have a future development plan in Montebello. It's been around a long time, like the other LA Basin fields, 1917. Water flooding began in the '60s, so it's very much a redevelopment. It's well described by the different stringers that aren't necessarily correlative from well to well. We've done a lot of reservoir and modeling and detailed reservoir characterization over the last few years. We think we've got a good candidate for waterflood redevelopment here. You'll see some of the characteristics of it below, and really, what we're trying to do is get from a 37% [indiscernible] recovery of the 146 million barrels in place to a 41%, so it's not a huge tail, but when you're talking about 146 million barrels, it's a worthy target.

This is just showing a couple of our other urban sites. You can see that these have very small surface footprints. In this case, the drilling rig is behind the building facade. In this case, the facility is right in between some big infrastructures in downtown LA, small surface footprint, highly directional wells, targeting some really prolific fields. We have a few locations remaining. It's the same drill as in Inglewood and Montebello, we just have a bigger footprint there to work with, but we're developing the same type reservoirs and improving waterflood efficiency is what we're looking for.

This gives a little overview of Packard and San Vicente, 2 of those fields, Las Cienegas, another urban drill site, very similar properties and very similar potential. We have 15 future locations identified there. A couple of hundred thousand barrels each, it makes about 1,000 barrels a day on a very stable current decline, a lot of water.

Rowdy Lemoine

To switch gears. Our Offshore California assets, which does include an Orangeville [ph] field called Lompoc, and all that we produce offshore or a large percentage of it is actually a pipe back to Lompoc field for processing. We've got -- we produce plus or minus 9,000 barrels a day production from this asset area. We've got information for type curves on our Lompoc field and Offshore California. The target here is the Miocene Monterey. The Monterey, we've heard mentioned by many different people, it's actually the source rock for the oil in all of California or in most of California. And where you see the Monterey in a fractured environment -- of naturally fractured environment, it's actually a reservoir, and that's the source, or that's the reservoir that we drill in our fields here.

J. Wright Williamson

Offshore California has been on a pretty stable decline. We have drilled a few wells in the past. And you can see what we forecast from our future drilling there. Now this is a risk-weighted forecast. These wells come on initially anywhere from 750 barrels to over 1,000 barrels a day. They do go to -- they make a lot of water, their own subsurface pumps, so we make a lot of total fluid. Say, to get 1,000 barrels a day, we may move as much as 15,000 barrels to 20,000 barrels of water out of that individual well. But a very efficient operation, we just upgraded that platform. A lot of you all probably remember that we shut this in, in the first quarter of 2011, had a pretty a successful upgrade project. Mark, I don't know if you're going to talk about any of that, but we'll switch into Lompoc and just show you a couple of opportunities that are there.

Mark Kidder

Lompoc doesn't quite have the deliverability of the recent work that Wright mentioned for the Offshore in terms of barrels of oil per day, but it does have a lot of opportunities. We've got several locations that I show here in light green, that basically are based on some work that we did in 2007, 2008 timeframe. We actually drilled the well, a high-angle well, almost horizontal across the crust of the structure here. It was called the Purisima 90. That well has accum'd [ph] over 60,000 barrels in the last 3 or 4 years. It's averaged 50 barrels a day steady during that time frame. It actually outputted [ph] about 300 barrels a day. This sort of opportunities that we continue to find some of the older fields. The green dots here represent actual production, historical production from this same zone, so what we're looking for is bypassed oil in and around the wells that have been drilled historically. One thing that's not shown on the structure map is another opportunity. It's just to the northwest, it's called -- it's almost an exploration opportunity although there's a fair amount of geologic wells in the area that actually define it, and it's undrilled structure that we can access from one of our current facilities. And it has anywhere between 5 and 10 follow-up locations if successful, and again, this would be oil on a structure that has not yet been produced, so it could have much higher deliverabilities in some of these older fields.

Rowdy Lemoine

Switch over to Offshore California and the fields associated with our Offshore California asset. Offshore California is characterized by a very large anaclinal structure, and that's basically what you see that I have circled and outlined around some of our platforms. PXP actually operates 4 platforms in Offshore California, shown by these rig symbols. This is Point Arguello field. This is Point Pedernales field. Again, as I mentioned previously, the reservoir here is the Monterey shale. It's a very brittle shale. It's highly fractured particularly over the basement holes that create these large anaclines. The reservoir itself is accessed from these platforms, limited number of platforms. We drill very high-angle wells, basically horizontal in some cases. Some of the reach on some these wells is over 15,000 feet laterally, so we drill some very high angle wells. The target itself is at about 3,000 feet to 4,000 feet TVD [ph]. But we actually TD [ph] a lot of these wells at plus or minus 18,000- to 20,000-foot measure as we encounter a lot of the fractures that are associated with the Monterey.

Our 2012 plan and beyond is to drill some of these wells that we show here with these purple dots. These dots represent locations that we either have permits in hand or in the process of permitting. You can see in Point Pedernales, we're actually fine to drill a well that's actually beyond the -- some of the previously drilled wells in the field. So again, we're trying to intersect these fractures, these oil-saturated fractures. If we get beyond where our current production is, we should start to see really high deliverabilities. Some of the wells that we drilled inside the field, as Wright mentioned, have IPs in 1,000 barrel a day range to 2,000 barrels a day. We feel if we get out to the edges of some of these fields where we still have good oil saturation, encounter a couple of these fractures, the natural factures that I'm discussing, we can get IPs in the 2,000-plus barrel a day range.

We're also planning to drill a structure, an undrilled structure to the northwest of Point Arguello. These structures have been defined by vertical wells that were drilled. These were exploratory wells drilled in the '80s and production-tested, so we know we have oil. We know it flows. We got 3D seismic data over this whole area, the map closure. And we'll just access this undrained structure from one of our existing platform rigs in the Point Arguello field.

J. Wright Williamson

That exploration opportunity that Rowdy was just describing is not included in this. That would be about a 10 million to 15 million barrel resource facility. If we add to this [indiscernible]. So hopefully, we will get to drill that this coming year. We're waiting -- it's going to be filed for a permit soon, and we'll have to go through the whole sort of federal permitting process, but we think that's doable, and we'll be able to drill it.

8,700 barrels a day, again, good cash flow contributions from Offshore California, about $100 million a year. You can see, we are drilling one of those high-angle wells and point in Point Ped [ph] this year. That's why the capital is up just a little here. But a -- again, a good realized gas price. Not quite the same as LA Basin and SJV, but it does take the benefit of these new contracts. You can see that's coming up here. And again, the $4 or $5 bump with current differentials would impact this and its margins as well.

Rowdy Lemoine

This is a geologic structure map on the top of the Monterey. The green lines represent actual completions within the Monterey, so they are high-angle completions. The type log is shown off here to the right. We segment out the Monterey into 5 different zones. The more prolific section is actually the lower Monterey. You can see the purple bands actually represent drilling opportunities. The well that Wright mentioned, the high-angle well, the budget [ph] for 2012 which were shown by the dots that I had on the previous slide [ph] is actually this well bore here. It's offsetting probably the most prolific well that we have in the field. This is called the A21, and if you can envision as you're drilling from the platform to the North, starting across the Monterey section and you're cutting across at a very, very low angle, so you're intersecting a lot of this rock along the trend set to this well bore. So at the -- we'll call it the heel of the well because we're used to talking about horizontal wells. Back here, you're actually cutting across Zone 3, and the actual toe of the completion is embedded into Zone 5. So what we're planning to do with this offset well is actually drill a lateral or drill a high-angle well, actually penetrating Zone 3 at the edge of the reservoir. So it's this sort of work that we've done historically to identify some of these areas that are really being ineffectively drained by existing oil control.

Mark Kidder

As Wright mentioned, we recently did an upgrade at the beginning of the year to go in and modify our water handling equipment. The effort was to take a lot of the burden off the Lompoc field, where we send our water to. What we are capable of doing now is taking that 90,000-odd barrels and basically injecting it out offshore at the platforms versus sending it in for injection. So we also use the opportunity to revamp our control system and actually increase our compressor capacity on the platforms.

J. Wright Williamson

I think this is where we plan to take a little break. Okay. Leaving California, we'll head into the Eagle Ford. As Jim mentioned, we are -- for 2012, we have -- we are picking up rigs. We expect to continue to pick up a few rigs through 2012 and maintain them through '12, '13, '14, '15 and see we're maintaining sort of between $500 million and $600 million capital that's consistent with non-operated rigs and a -- 2 rigs that EOG operates in our AMI.

You can see, our production is forecast for 2012 to be about 20,000 barrels a day, peaking at near 30, about 29, and then starting a gradual climb. What's going on in the back end of this curve in the Eagle Ford is that we're starting to drill lower interest -- lower working interest wells because we're having the born [ph] units instead of drilling 100% wells on leases. So we're developing our stranded acreage. If we don't form units with all other operators is really what's going on there.

I guess, that's really what I wanted to say with this. But, Rowdy, did you have anything to add?

Rowdy Lemoine

It's good.

J. Wright Williamson

PXP's average working interest, 73%, 56% NRI; over 500 potential locations; development resource potential, 163 million barrels, that's again as a resource potential associated with future drills; we've got about 7 million barrels of resource potential associated with wells we've already drilled; average well cost, this is sort of a long-term well cost, I'll show later on; type curves, we're 7.5 to 8.5 right now, so that's our central -- that's sort of an all-in cost, drill complete hookup for us. And as our central facilities, we stop building them, then we start using them with extra development wells. We think our average cost is going to be about $7.5 million. Our average gross research potential per well is 483 MBOE. There'll be more detail on our specific types of type curves later in this presentation. And our current F&D is in the $23 per BOE range.

Rowdy Lemoine

PXP has a lease position in the Eagle Ford, primarily in Karnes County, with some acreage in Wilson County. We'll go into a little more detail on that when we look at some of the maps that I'll show in future slides. We have just over 58,000 net acres that we control in this area. We've spent a lot of time looking at a lot of opportunities across the Eagle Ford trend, as almost everyone knows, that extends over a much larger and expansive area, with 20,000 square miles. But we think we've zeroed in on what we considered to be the most prolific part of the play. Regionally, it's within the Karnes trough. Sub-regionally, some of our acreage is actually within the Karnes's trough, and you'll see the significance of that here in a few slides.

J. Wright Williamson

A lot of redundant information here. With what I just said, with 168 million barrels of total resource potential, 10,000 barrel a day current rate, 500 plus locations. Like the original slide shown about a resource play that we're building, there's a lot of CapEx involved in building that initial production curve and getting up to peak production. And that's the phase we're in, in the Eagle Ford especially in '11. In '12, you can see we're starting to bill a base decline, and our cash flow is coming out in '13 and beyond. You see us go cash -- operational cash flow positive.

Rowdy Lemoine

This is a -- basically a geologic block diagram that represents what the Eagle Ford look like at the time of deposition. We spent a lot of time and effort looking at the area that we consider to be -- that had the most -- the best characteristics of producing characteristics within the Eagle Ford, looking for areas that has the highest TOC [ph], the best rock quality, the best porosity and perm, and we focused a lot of our effort on this area in a back reef environment. And again, organic rich, lagunal force[ph] rock, and within this overall back reef environment, we focused a lot of effort. And a lot of our leases are within areas that we have localized thick, so we can see a localized thick along the trend of thinning as you go to the north, both here right behind the back reef, where we've got drilling opportunities within the condensate window, and then as you get over towards our oil window acreage within what I just mentioned as the Karnes trough, and again, another localized thick within the Eagle Ford.

Quick look at the type log. We're pretty consistent with other operators in the area. We target the area that's called the lower Eagle Ford, and it's shaded in this cross-section in yellow. Again, this is the [indiscernible] that has the -- some of the better rock quality in terms of porosity and perm, lower clay content, highest TOCs and probably as important, if not more important, it's the most brittle rock within the overall sequence. Being brittle gives you much more effective fractures.

This was a block diagram that I had my guys put together, and it basically reflects the typical development plan of the Eagle Ford on a -- for example, a 640-acre unit, just for round numbers. Some of the original wells that we drilled and some of the offset operators had drilled were spaced in a plus or minus 1,000 feet apart. Now obviously, the spacing between the wells has a direct correlation between the thickness of the Eagle Ford and also the geology in where you can drill along the lateral. So we incorporate all of that information into entire pool development plan, and there were sections, as I mentioned, where we actually have these sub or localized thick, that they actually have been down-spaced to -- in fact, we're drilling some wells now at a 650-foot space in between wells. Some of our laterals were less faulted, and we'll have a few examples coming in on a few slides. We're actually drilling laterals in the 5,500 to 6,000 foot [indiscernible]. So all of this information is all integrated in our development plan. It's all part of the plan that Wright and his guys put together and we'll have some graphics that sort of show you how we develop our leases using some of that information.

Just a general regional structure map. This is pretty common for most operators in the Eagle Ford, it shows our lease position. Again, within what I mentioned as the Karnes trough, it's bounded by the San Marcos arch to the north, the Pertal [ph] arch to the south and to the west. Our oil window acreage, the structural contour, that plus or minus 10,000 feet TVD; our gas condensate, our condensate window acreage, it's a little deeper. It's about 2,000-foot deeper. TVD is about 12,000 feet. And we also have a position in the shallower part of the oil window, a lot of it in Wilson County, that we feel we can develop commercially. It's as shallow as 7,000 feet but it's an area where we think we can drill some really long laterals.

I've mentioned faulting several times. We've got 3D seismic, either in-house currently being used as part of our development planning or in the future, we've got some surveys that are actually being processed and planned for acquisition, including this acreage in the northeast part of Wilson County, actually Southeast Wilson County. So we've got -- when it's all said and done, we'll have over 95% of our acreage covered with 3D seismic.

We'll zoom in now on our acreage position within Karnes. The brown streaks here are actual faults. So when people talk about the faulted gravin [ph], we're talking about this area in through here. The Karnes trough is actually a little more expansive, all the way across Karnes. It's within that Karnes trough where we see thickening of the Eagle Ford section. You can see we've got opportunities in the condensate window, just to the South of our primary lease position. We've drilled a couple of wells here. We currently are running actually at 7 rigs. As of this week, we picked up our seventh rig. That's our current operated activity in the Eagle Ford. We have plans and our model to go to 9 rigs in 2012. We'll drill in excess of 80 wells; that's included PXP-operated and partner-operated wells in and around the Karnes gravin and some of our other lease tracks.

At the last earnings, we announced 2 recent IPs in the oil window. This is a repeat of information that's already gone public. Those wells produced, I believe one was 2,200 barrels equivalent, and the other was 2,500 barrels equivalent. This was the initial production rate, but we also have 4 wells that we'd put on production within the condensate window that have sustained production at over 1,100 barrels a day after, this says 24 days, but actually, production has been holding flat since I built this slides, so you're kind of looking at a 30-day average for the 4 wells. So we designed our facilities not for the max initial rate but for the more sustained rate or the 30-day average rate. So a lot of times, when we bring our wells on, they're not at the max deliverability, but you can see our opportunities actually have good sustained production, which meets our type curves.

There's 2 stars, and I'll go through 2 real quick well bores. They're zoomed-in sections, and it shows how geologically we try to stay or we stay in zone within the faulted section, and how long a lateral we can drill outside of the faulted area.

This is one of the wells that was drilled earlier this year. These lines, these vertical lines are actually representing faults that we've intersected with the well bore. Our targeted section like you saw on the log example that I showed is this bright yellow [indiscernible], but what we're doing here is we're trying to stay at the top part of the lower Eagle Ford, embedding this down to the -- up to the coast or down to the north fault which will actually fault us into the deeper section, so we designed all of our wells, as do a lot of our competitors and other operators in the area, anticipate some of the structural complexity and try to keep the well in what we consider to be the sweet spot of the Eagle Ford. This well actually TD'd that 16,500 feet round numbers and had 4,700 feet of section that we actually completed with 15 stages of well IP'd at over 1,000 barrels a day. And again, that's not the max deliverability. It would be much higher, but we typically bring on several wells at the same time into the facility, so it's sort of facility constrained, if you will, at least under that production.

J. Wright Williamson

Certainly for the first half of the first month at least.

Rowdy Lemoine

Next slide is -- shows the well that was obviously much simpler, geologically, to drill, which is basically looking at regional dip. We stayed in zone in this particular well for 5,500-foot. That's the section that we actually completed. It's actually 18 stages, and you can see some of the details here. Look, you can see its actual completion formula for this one particular well. And this was one of the 4 wells that I mentioned that's sustained production in over 1,100 barrels a day.

It IP-ed at over 2,000 barrels oil a day [indiscernible]. Just a cross-section, a dip cross-section, across our acreage. Basically connecting the area that I'm referring to, the faulted Grover [ph] area, to the un-faulted section. Showing, basically, the dip as you go from the west to the east. Really, the primary point with this particular cross-section is the targeted lower Eagle Ford is very correlative across all of our leads. It's a very easy marker to follow and we've had lot of success staying in zone.

The next few slides -- back up one more. The next two -- few slides. What I'm going to do next is we're going to zoom in on these 2 areas. Here to the south and this acreage position to the north. So I, actually, had to crop the slide and pull the 2 leases together. And basically, what I'm going to demonstrate over the next 5 to 6 slides is show you, in essence, our full field development. Incorporating a lot of the information I mentioned previously, as far as spacing, link to laterals, and whatnot. And how we complete -- how we plan to completely develop all of our acreage. So what we'll do is we'll go -- I'll do it relatively quickly, we'll go year-by-year. Starting in 2010, this was basically our inventory of drilled wells. There, show up as red, as each year, then they'll turn gray. So at the end of 2011, where we had drilled [indiscernible] 25 wells that we had previously. That's shown in gray, then 2012. Keep growing right, '13, '14, '15, and then finally the last, as Wright mentioned, involve wells with lower nets and basically a full cycle. So there are actually additional locations that are filling in some of these tracks, that have either lower working interest, lower nets or require pooling. But you can see, at the end of the day when we finish developing all of this acreage, this meets the 600-plus locations that we mentioned in the previous slide.

Okay. This is meant to depict our type-curve. This is oil window type-curve. Let me set the slide up a little bit. We've got -- this is oil rate, not BOE rate, on the left-hand scale, the Cartesian plot. This is days along the X axis. And yellow is depicting the number of producing wells at any point in time. So you can see the wells that I've got producing for 15 or 20 days is 37 wells when this slide was made. And the wells, I've only -- I've got producing 150 days is only 10 or 12 wells, okay? These are -- this is a normalized plot, and every well's rate, it -- so normalized means that you pretend every well started on the same day as its first production, okay? So they're all backed up to just one point in time. And then their average by the well count. So as the well count drops, as wells -- our oldest wells are the only ones that are out here, okay? are very early walls. What it shows -- the black is actually our type-curve for this -- these are all oil window wells and they're all within what Rowdy really calls the faulted robin [ph] area. Our type-curve in there is 300,000 to 400,000 barrels of oil. I mentioned earlier 7 to 8 million a well, 7.5 as an average. IP, 800 to 1,200. Again, on average, and that's more than just an instantaneous rate. It's at least probably a 3- or 4-day rate. And they're 75% to 85% oil. We don't have -- we're just starting to develop condensate window wells, so I don't have a lot of history. We clearly have a different type-curve for the condensate window. Wells [indiscernible] a little more there, a little deeper. We're generally drilling a little longer lateral well. But the EURs on an BOE basis are 900 to 1,000, or 900,000 to 1 million barrels a well. IP, 1,500 to 2,000 BOE a well. Obviously they can be higher than that. We just announced a few higher that, that were even in the oil window. But 55% to 65% liquid and 30% to 35% oil. The remaining, about half of that liquid, is -- or 40% of that liquid is NGL. So those are basically our types of type-curves. We can have subsets of those curves but you can see that using all our oil window wells, normalizing them and average them, we really feel like we've got a good type-curve and that we're realizing the results that we're forecasting. And that's what our forecast is based on, is this type-curve, okay? In future, we can do an analysis, like this, on the condensate window and show you how those are holding up, but right now it's a little early for that.

What this slide was meant to show is just that -- we said it several times that our upfront costs, especially on the building and hookup side, are a little higher because we are planning for the future. All these stars represent central facilities that are either already built or under construction or are planned to be built, I think, maybe even through 2012. I'm not sure it goes beyond that. But up to 20 -- anywhere from 12 to 20 wells, there's a few isolated places where, for lease reasons, we've got a smaller facility. But basically, we're planning the facilities out so that we can take advantage of hooking up wells quickly and cheaply in the future. And it does cause the current curve to be a little choppier as we're building because we'll bring on blocks of wells as these facilities come on line. But in time, that'll all smooth itself out in time. Our duration from spud to first-sales will shorten because all this infrastructure will be available to us.

Randy, you want to talk about some rigs and stuff?

Randall Vines

All right. I think this is a great picture. It's probably because I took it. But this is an ideal rig for drilling Eagle Ford wells. Especially multiple wells from a single pad. This is a walking rig and it can walk about 20 feet -- 20 to 30 feet to the next well in a couple of hours and then they can be spudded the same day. And so our typical development plan is 2 wells per pad, we also have some 4 wells per pads, which bring a lot more efficiencies for us. This rig, this is a 1,500-horsepower rig with a top drive, a hydraulic catwalk, pipe wranglers. It's -- has a BOP handler, it basically has the most modern, safe equipment which allows us to drill them safer and faster that has been done in the past. And so, one of the other things it can do is it can walk with the drill pipe in the derrick. So that brings -- that helps us with our efficiencies as far as picking up the pipe once, drilling say, 4 surface holes, and getting them cased, and then switching over to oil-based mud, and drill your 4 production holes. You don't have to clean your pitch, you don't have to lay down your drill pipe, and these are 3 to 4 days per well savings that we're going to realize by using a rig that can walk.

This here is our zipper-frac setup. And these -- you can see the 2 wells here, 25-foot apart, and what a zipper-frac allows us to do is basically do continuous operations. We can be frac-ing on one well, which would be this well here. As we perforate -- this particular well, this is a wire line BOP system and a lubricator above that. We put our guns in there and we go down, pump the guns down and perforate our 4 clusters. In the meantime, while on this well frac-ing, we have a -- what is this? It's called a zipper manifold back here, we've got our 14 pump trucks, 2,000-horsepower each. And this just allows a much more efficient operation. It's and safer, you only rig this iron up one time, it saves on your mobilization. And so this is -- this wellbore is a cartoon of what we're trying to do. To make sure everybody understands, we do -- this is a plug-and-perf method. So we perforate and we frac, and then we pump down a perforation gun with a plug on the bottom, we set a plug and isolate these perfs here. Perforate what would be stage 2, and then we drop a ball with some acid. The ball will seed in the frac plug and we frac stage 2, and then we just repeat that process and back our way out of the hole. So your final stage is 13. Rig up, pull tubing, go down, drill out all our frac plugs, and then we'll run a packer in tubing. We're able to do that, jumping back and forth between the wells, getting our stored energy in what we call a zipper-frac. Our typical completion depends on the lateral link but it's roughly 293, 300 feet per stage, 4 clusters, 80 feet between the stages, and we pump -- right now, we're pumping approximately 300,000 pounds per stage. We'll pump both 40, 70 and 30, 50 sand. And so that comes out to approximately, on an overall basis of 3.5 million to 4.5 million pounds per well. Our treating pressures there were 9,500 pounds. We're...

Unknown Analyst

Sorry, did I go too quick?

Randall Vines

No, no. We're good. That's it.

Mark Kidder

Our oil wells in the oil window basically go on rod bump for about 2 to 3 months of production. And the gas wells, basically, continue to flow on their own to depletion. So talk about our central facility. This is a good example of what our central facilities look like, kind of looks like California, it was so dry in Texas over the last year. But this is our separation equipment, here's our treaters associated with cleaning up our production, here's our storage facilities as far as tankage. And this particular facility has about 8 wells going through right now and, eventually, we'll have about 13 wells going to this facility. Now all the wells come to this facility via flow lines at -- basically, from the surrounding area.

J. Wright Williamson

Okay. Any questions about Eagle Ford?

Question-and-Answer Session

Unknown Analyst

Talk about 3,000 a day of oil in the wells [indiscernible]

J. Wright Williamson

Yes. We've really got 2 type-curves. One is closer to 400,000 barrels, one is closer to the 300,000 barrels. The 2,000 barrel a day wells would be the 400,000 barrel of the range, so it would be the high end of the range I showed as a type-curve. Most of my wells, when I said they were faulted Robin [ph] wells, are more of the 1,000 barrel a day initial rate wells. And so that type-curve analysis, with the history in it, was really formed on that, and that's closer to the 300,000 barrel a day type-curve as well. Does that answer your question?

Unknown Analyst

On a multiyear production forecast, rates are [indiscernible]

J. Wright Williamson

Down-spacing would be one answer. Although that plan does include those 600-some-odd wells that Rowdy showed in the development plan, the latter stage of it being lower interest wells. But beyond that, yes, you saw some extra drain on there. We would have to do additional unitization or something like that or pick up more acreage, absolutely. And we're always looking.

Unknown Analyst

[Question Inaudible]

J. Wright Williamson

Yes, we're drilling some wells right now with EOG. They're doing what they call a pilot that's 500 feet deep. Our lowest, as Rowdy mentioned, we're getting down in the 600 to 700 range. But I do think that's the direction everything is going as long. As you have enough room between plugs [ph] and stuff to get along the lateral, because it's sort of a 3-dimensional puzzle that you're trying to solve to get the optimum drainage area. And lateral length is one component, the thickness of the Eagle Ford is another, and the spacing between wells is a third.

Unknown Analyst

[indiscernible] gas [indiscernible]

J. Wright Williamson

When we get the BOE it'll be a shrunk gas because it'll be processed, and then we'll count the NGLs, which is what's shrunk out of the gas and add it to just the raw oil or condensate if it's a gas condensate well.

James C. Flores

Right, it's Jim. David, I want to elaborate a little bit about your question, about we'd buy more acreage. The acreage is being bought right now. It's bought at multiples of 5, 6, 7x of what we pay for acreage. There's not going to be acreage available for us to add at that point in time and that's why we kind of go with the integrated approach, where -- the Eagle Ford is going to be what it's going to be. It's going to continue to grow through '13, '14 and into '15 we think. But that's when the Gulf -- later on the Gulf of Mexico. So we're not going to be looking at an asset-specific, drill the Eagle Ford at all cost and continue to invest there in acreage and diminish our returns that we see in the near term. The key part of our strategy going forward -- and there's probably 6 asset packages that are around us, that we passed on, just in the past year. And there's probably 3 or 4 floating around right now that we're not interested in doing either, because it doesn't fit in our near-term strategy. So I just want to be clear on that. That I don't think adding acreage is really a possibility, at a point in time, to offset our inventory. That make sense?

Unknown Analyst

What percentage your acreage in your oil window [indiscernible]

J. Wright Williamson

We're probably 75% to 80% in the oil window and 15% to 20% gas condensate.

J. Wright Williamson

Okay. We'll move on to the Gulf of Mexico. And you're familiar with the formats of this and we've mentioned some of these things, even as early as when Jim was talking. But this is our current capital layout to develop the Lucius discovery. It also includes the Phobos exploration well. It shows production starting in mid-'14, so we project. This is a fractional year, it's the only reason it's down this low. It's a half a year number because we're starting in the -- excuse me, pointing at production. I was pointing at cash flow and was talking about production. But we're starting at the roughly 24,000 to 25,000 barrel a day rate in midyear '14. You can see that the cash flow is extremely robust as soon as it comes online and well in excess of any capital. This is future, just carry-on capital associated with the platform maintenance and starting to bring on, maybe, some deeper Miocene tests in the future.

Stephen you going to talk this?

Stephen Laperouse

Hi, my name is Stephen Laperouse. I am the Vice President of Exploration Land. For the last 16 years I've had the pleasure of working with Jim and Doss. Prior to that, I was at Conoco for 15 years, working the lower 48 and the Gulf of Mexico. Jeff and I worked together on the exploration team. We have evaluated probably hundreds of opportunities since we've been at PXP. And our Gulf of Mexico represents to us various partnerships with Anadarko, with Shell, Chevron, Exxon, and others. The map that you're looking at illustrates our current acreage position in the Gulf. We have about 102 blocks in the Gulf, constituting 191,000 acres, covering 29 exploratory block -- prospects, excuse me. Primarily in the Miocene and Pliocene play. Jeff and Rowdy will later discuss in more detail, our Lucius development, as well as the Phobos and other exploration opportunity.

The development resource potential component of our Gulf of Mexico resource potential is Lucius, the 106 million barrel of oil equivalent net. The 409 million barrel is the near-term exploration resource potential. It doesn't include all of the 29, I believe it was, prospects that Stephen just mentioned. But it does include the ones that we think will be drilled by '15 to '16 timeframe. Lucius' first production 7/'14. We've said most of this. The initial development does envision 6 wells coming online initially, with 2 development locations coming online within the next year and a half to 2. As I mentioned, really strong operational cash flow, especially this full year 2015, as soon as it comes online.

Rowdy Lemoine

Basically, just a series of bullet slides, publicly released information over the last year primarily. Jim mentioned one of the key components in that sanctioning is planned for the end of this year. The other key bullet is this bullet here, announced by the operator that drilled the adoptive [ph] well within the unit, the join unit that I'll show you in a second. And that well was critical because it helped to establish reservoir continuity and correlations across the field that's just really validated our reservoir model.

Generalized map showing the relationship between Lucius, Hadrian, and our exploration prospect. That'll be covered by Jeff Heppermann. The partners -- the Lucius partners and the Hadrian partners agreed to unitize this block that's outlined here in red, including parts of Keathley Canyon 874, 875, 919, and 918. The well, one of the critical things that's occurred, it was late this summer, was the extended flow test announced by the operator on the Lucius 1 sidetrack. Where we've actually produced over 15,000 barrels of oil a day into a test facility that was facility constrained. And again, this whole area, the development of this project will be sanctioned by end of this year.

Doss R. Bourgeois

Very successful well test, did see some boundaries within the reservoir but they were infinite acting, basically, overall. So they never saw a closed system and, as Rowdy mentioned, facility constrained. The projected rates are in excess, 25,000 to 30,000 barrels a day on these wells.

Stephen Laperouse

What we're showing here on this next 2 cartoon blob maps are the publicly released logs from the Hadrian wells that are grilled on the south side of the Lucius structure. And they're really just shown to demonstrate the quality of the reservoir the -- it's great reservoir quality, great porosity, great perm, very thick massive sand sequences. And all of this, this Pliocene -- all of these Pliocene sands correlate to our wells on the north side of the salt feature, which is the Lucius discovery. We've logged oil play -- pay in all 4 of these wells. Actually, we logged 3 Pliocene oil sand and we've logged one Miocene oil sand, and these have been logged in all of these well.

The difference between the previous map and this map is now we're actually a little bit deeper in the section. The first map was Pliocene. It's well delineated and that's what was covered and colored in the dark green. We feel like we fully delineated the Pliocene reservoir where we still have a tremendous amount of upside to our model. Our development remodel, if you will, is the Miocene sands, and that's what I'm trying to demonstrate here between the dark green and the light green colors here. Only 3 of these wells actually penetrated the Miocene section. One of the wells did not drill deep enough to test it but our go-forward plans are to drill additional wells down through the Miocene, to try to fully delineate this reservoir. But what I'm demonstrating here in the light green is all upside to our model.

Doss R. Bourgeois

This is a mockup of the spar that's going to be set to produce the Lucius prospect. This is the waterline, give you an idea of size, it's diameter-wise, about 110 feet in diameter. From bottom of the production deck to the bottom of the spar is about 605 feet. Platform size is about 136 by 188. Sits in -- did I tell you? It sits in 7,000 feet of water. Processing capacity, it's going to start off at 80,000 barrels a day. It's expandable to 120,000 a day. Gas capacity, 450 million. 350 million of that is going to come from the Hadrian -- South Hadrian wells, and 100 million associated with the Lucius prospect. And start-up is slated for 2014.

Jeff Heppermann

Jeff Heppermann again. I'm going to back up a little bit to how the oil got to Lucius. So I'll start at the lower tertiary structures that we see at Jack, in St. Malo, Cascade, Chinook, Kaskida, Tiber are just lower tertiary. Billions of barrels of oil on the plays. The reason they work is because they're so thick, there's so much oil in place, but the reservoir rock in the lower tertiary is very poor quality. But it works up with the thickness. So now can we get that to work for us? Well, it turns out, at Lucius, the Exxon well, what you don't see is they're a lower tertiary. They drilled this deeper and it failed in the lower tertiary but there was residual oil. All that good quality, lower tertiary oil has escaped. This is the great Hadrian oil escape. Comes up a long trend and starts filling up these wonderful reservoir rocks in the Pliocene. We got 30% porosity, great permeability, great deliverability. So we've got all the advantages of the lower tertiary in a reservoir that's 1/3 as deep easier to drill, normal pressure, and just bringing it up to where we can really access this. Now this is all filled up. Every well that's been drilled has found oil in the Pliocene. So where do we go from there? We have got a great four-way structure that sits just to the south, that we call the Phobos prospect. If you bring it over here, using the laws of physics and buoyancy, where's the next molecule of oil going to go? It's going to start filling the Phobos, and we have got some new wide-azimuth seismic data, get a peek at here. And what we see at the Hadrian,too, we have got oil in these C Sands, and where is it going to go? I mean, again, laws of physics is going to put it up into the next structure, and that's the Phobos structure. We see it underpinned, about as good. Another lower tertiary, Wilcox, going to have potential down here, we'll check that out. But it comes up on the fault, fills up, it'll fill the Phobos structure. If we go back and look at the depictions, our dear friends at Exxon have claimed 700 million barrels of oil in the Hadrian structures. If you just use your rule of thumb and just kind of see how many of these we could put in here, gives us some idea of the scope of the magnitude of the reserves we could be looking at, at Phobos.

Again, great structure. We zoom in on this area here, and we're get a really good image. We're doing proprietary processing of this latest WesternGeco wide-azimuth data, state-of-the-art imaging, and we getting a good, first look at this stuff. And the potential here is, again -- just add up all those blocks, over 5,000 acres a block. And this is a -- could be world-class, we've heard a lot of hyperbola from Exxon at Julia [ph], but this could be bigger yet. So stay tuned, we'll spud the Phobos well in 2012, third quarter. Once the Anadarko gets a rig back in and this will be the hottest thing going and we've got more of these Lucius-type things to come. We've went through another lease sale, and post-discovery and pre-Macondo, where picked up a number of follow-ups to this as well. So Gulf of Mexico is looking good, we've got them queued up and this'll be the first one out and swinging for the fence here.

Unknown Analyst

Jeff, PXP's interest on Phobos?

Jeff Heppermann

50%. So we recognized this even our partners at Anadarko did. After our Lucius discovery -- well before we drill we always like to have a follow-up discovery. So we approached them and said, we'll join you at Lucius as long as you throw in the Phobos prospect. At the time they hadn't recognized that, so -- well, we did.

Doss R. Bourgeois

Again, as a point of comparison, we're at 23% is our unitized interest at Lucius here.

Jeff Heppermann

Increase the size, increase interest, it'll work great. And that'll wrap it up for the Gulf of Mexico, with the additional follow-up prospects and resource potential that we see after Phobos. Again, more Lucius-type developments, a new trend. The Pliocene, just all sits out there, again, kind of at the edge of the soupy salt [ph]. We have our more traditional plays up in the Miocene around Tahiti, Knotty Head. And to give you a kind of a block diagram of what those look like, Miocene plays, typical sub-salt, you see here Tahitis, we were in discovery at Caesar and Bigfoot. And these are just follow-ups along that way. We have these prospects in inventory from Winter Park, Surge, Giverny, and Silver Fox. Actually pretty excited about the Silver Fox well. That'll be coming up and the Pliocene as we push out further with this unrestricted great reservoir sands. Put them up, trap them in the salt bring up the hydrocarbons from the lower Wilcox, and we've got numerous follow-ups to Lucius, Hadrian South. Phobos sits out here but we've Dutch, Augustus, Corsica, Capri, and number of others. We just build on success out here.

Unknown Analyst

[indiscernible] your Phobos [indiscernible]. Seems like you've got, substantially, if you gutted [ph] the number at the table. You've increased [indiscernible]. What happens if you [indiscernible] inside?

Jeff Heppermann

Well, the one thing is we became more familiar with the C Sand, it's oil. In every penetration so far we've seen oil. So as opposed to a gas reservoir, while we do see some gas but it's typically in the shallower sands, in the A and the B Sands. So far the C has only encountered oil. So we're just getting a better look at the reservoirs and a better understanding of our different segregated sands.

Stephen Laperouse

I think it's thickness, it's multiple objectives, and it's oil versus gas. It's the 3 components to making it bigger. Now, the aerial extent, we always saw it pretty big. It's being verified.

Unknown Analyst

On Hadrian and Hadrian South, what do we know about the separation between the 2, and not know? And how do you decide to communicate [indiscernible]

Jeff Heppermann

It's as one but the actual structure. We know the Lucius and Hadrian are really on both sides of this salt dome. Hadrian South is separated, probably fault separated. And we'll just take a quick peek at the -- again, this is the Hadrian South. As you move back to the north, to Lucius and the other Hadrian, you go through a little [indiscernible] before you come back up. Underpinned on the salt joins up with, probably, a spire. So...

Unknown Analyst

What's the next delineation [indiscernible] there or [indiscernible] Hadrian North or conclusion[ph] indiscernible]

Jeff Heppermann

Lucius, we had planned to -- Lucius 2 was going to sidetracked at some point. And we're also going to drill 874. So once we get the rig -- the number one sidetrack is part of the reservoir test. That well has been completed. It is ready to flow as soon as the pipelines and the spar show up we can hook that well up right now.

Unknown Analyst

And what are you thinking about 920? [indiscernible]

Jeff Heppermann

920, we just picked that up on the way to this lease sale. Again, this is just a depiction, but that'll probably be a tie-in, as facilities. As it becomes space, we hope to max-out the facility with the additional initial wells. And 920 would be a great to plateau the facility.

Unknown Analyst

And what's the ownership there?

Stephen Laperouse

That's 33%. That's what we call Lucius offset. It's a 33% interest that we have in...

Jeff Heppermann

Apache has a 1/6, we have 1/3, and Anadarko 1/2.

James C. Flores

You had 2 questions.

Stephen Laperouse

Can you give us a piece of G for Phobos?

Jeff Heppermann

A piece of G? As we get more data, I get more -- exploration wells, mother nature, has a way of humbling you. So it's better than 30%, but I wouldn't push an exploration well much higher than that. But we have the reservoir, we have the trap mapped, we have the migration pathways. All the key elements are favorable.

Unknown Analyst

[indiscernible] situation where you need additional capacity [indiscernible] standing option [indiscernible] does -- perhaps with a...

Jeff Heppermann

Well, the best part is we'll have the takeaway, we'll have gas takeaway. And then Mark probably could -- everything from the FPSO, to additional spar, to -- if Phobos is as big, it will -- it'll need its own liquid.

Stephen Laperouse

If it were some small satellite thing, yes, there is some [indiscernible] at Lucius [indiscernible] but that's [indiscernible]

Unknown Analyst

[Question Inaudible]

Jeff Heppermann

Well we have -- that's one of our unit wells. We have all that information and we're one of the initial production wells. We'll be a Miocene well. So we're going to do.

Stephen Laperouse

We just can't stand in front of them saying that the partnership -- it's not just Exxon, it's the partnership.

Unknown Analyst

Okay. [indiscernible] refer [indiscernible] percentage...

James C. Flores

I think the key take away there is we'll participate in our unit interest in the Miocene until we get it fully delineated. We see more Miocene potential on our acreage than we do on Exxon's acreage, from that standpoint. Talking about risk and so forth, as Phobos is already risked in our model, but what are the P10 reserves for Phobos so that I can apply the appropriate risk they see as we see on a pre-drill basis, right? And, Jeff?

Jeff Heppermann

And I don't have that on the top of my head Jim, but...

James C. Flores

I can help you, it's 1.3 billion barrels. The number just sticks in my head. Okay, something like that. And that's the P10 and, obviously, we have it risked at 30% in our model. It's kind of what the math I want you to go through.

Unknown Analyst

[indiscernible]

Stephen Laperouse

That is gross So you did a 50% then you risk it from there. It's easy math with 25,000 acres and 100 feet of pay, and type probably could put recoveries in the Pliocene, so forth.

Unknown Analyst

A question on the unification. What's the difference between the Hadrian North and Hadrian South. Hadrian North, you had 23%. That's where the 8 wells will be? In the Hadrian South...

Stephen Laperouse

No, no, no. Well, let me straighten out Hadrian North and South. Can you go back to that previous picture? Yes. Okay, the unit is Lucius, okay? Hadrian North is what has that Hadrian 3 well in it, okay? And Hadrian South would be down there where the Hadrian 2 well is. So we have no interest in any of that. We are planning to process gas from the Hadrian 2 well, or that reservoir up, to the Lucius facility.

Jeff Heppermann

Now, Hadrian did name one of our Lucius wells in the unit, the Hadrian-5. So...

Stephen Laperouse

Yes. It's confusing I know, but Hadrian North is a different deal.

Unknown Analyst

[indiscernible]

Stephen Laperouse

Yes.

Jeff Heppermann

Correct.

Unknown Analyst

And is does the partnership [indiscernible] processing fee for the Hadrian South to offset [indiscernible] do you know what that is yet or pricing you have in order [ph]?

J. Wright Williamson

Yes, that agreement is totally executed, I can't quote what it is right now. But it's totally executed as part of the unitization agreement.

Unknown Analyst

Have you already awarded for a construction on the spar? Or 3P or where are you on that [ph]?

Jeff Heppermann

Doss Bourgeois can address that. It looks like...

Unknown Analyst

On the [indiscernible] the [indiscernible] spar [indiscernible]

Stephen Laperouse

[indiscernible] the information. Anadarko will be the one that will put that information out, but they've let most of the contract, okay? It's kind of hard for us to get in front of Anadarko and say what they're actually doing, I don't think it's right, but that process is moving quite rapidly.

J. Wright Williamson

The key thing to keep in mind on this process is you have it 50.1% of the interest approve the sanctioning. It has to be 2 or more partners. We add up Anadarko's 35% and our 23%, just Anadarko and PXP actually approved sanctioning. But it takes a longer time with the other partners and their approvals and their worldwide operation. That's why we keep saying sanctioning by year end, but effectively it's sanctioned at this point in time with PXP and Anadarko's approval.

Unknown Analyst

A question on some CapEx numbers. [indiscernible] spending in the Gulf. That's just includes the growth on the exploration side, it does not include any of the cross [indiscernible]

Stephen Laperouse

That particular schedule did just show Phobos and Lucius development.

Unknown Analyst

Any type of kind of ballpark estimate of what you might spend on the exploration side? Gulf [indiscernible]

Jeff Heppermann

We'll look at -- a lot of these, we've picked up with our partnership with Anadarko and we'll see what their rig schedules play out to be. Right now, the rig that's going to drill Phobos is not back in the Gulf yet. So we'll firm those up but...

Stephen Laperouse

I think the way to look at it, with the cash flow coming out of the business, 2014 and '15. We'll have a lot of flexibility but we're going to take that one step at a time, delineate Phobos. And if Phobos is going to require a develop project, obviously, that would have more impact of the budget than a couple of exploratory wells. Remember, we're talking about the second half of the decade, as far as the impact of production. And we're just going to do it in sequence instead of all on the top of each other. We have all those options in front of us and that's going to be -- let the assets tell us what direction we need to go with our CapEx.

Unknown Analyst

I assume the, perhaps [indiscernible] agreement [indiscernible] offsetting the [indiscernible] going forward does that matters [ph]?

Stephen Laperouse

Everything is up about $10 million.

Unknown Analyst

[indiscernible]

Stephen Laperouse

That particular reservoir is a lot more gas than anything [indiscernible]

Jeff Heppermann

Again, these are public logs. You can see they do have a gas oil contact in this well, and it looks like they're planning to produce the gas.

Stephen Laperouse

We've only seen one ten thin stringer of gas in Lucius. So not a big player there.

J. Wright Williamson

Then the relationship to Phobos, guys?

Stephen Laperouse

In relation to Phobos, again, we do see a C Sand member in the Pliocene which is oil. And all the like reservoirs at Lucius have seen oil in that reservoir.

J. Wright Williamson

And what's the structural definition between the Hadrian 2 structure and Phobos? Are we high at Phobos or at?

Stephen Laperouse

We're high to Hadrian South, yes. So, at the sea level, it leads to a bigger column. Right now we've not seen gas in column at the C Sand level. So, theoretically, it has to be drilled but it could have a gas cap, but it's been undersaturated oil. So we don't expect one. Oil, possibly, full of base. That's the large potential. And the B Sand, if it is in contact, the upper B Sand would probably be oil gas.

J. Wright Williamson

One more kind of general comment about the development here. It's taken a long time to acquire all the latest seismic on this project, and we just have gotten the latest WAZ data in the last 30 days. So we basically did our financing and all of our showing to all the various consultants, and so forth, with our older data that was very substandard as far as defining, really, the clarity underneath the soil of the Phobos structure. It was fine for Lucius, but going further into Phobos, it had a lot of question marks. We're most excited about the new WAZ data and our processing, defining what we felt was there all along. But now we have some spectacular data to do it and so our confidence is rising on the project instead of diminishing. That's kind of the general trend there.

Unknown Analyst

Just one last one. [indiscernible] partnership includes Phobos. Assuming that's a success, they would have to come up with the work capital for development?

Jeff Heppermann

Yes.

Unknown Analyst

Yes. And on your other prospects, it is not included, but could you eventually drop that down in that partnership?

J. Wright Williamson

They have all the leases. All the leases in POI. So EIG owns a portion of POI. If Phobos is good, POI is going to have to raise money to develop Phobos. But, of course, it does have about a $1 billion of cash coming every single year, from 2014, '15, '16, to help pay for that. So I think it's going to be able raise money.

Stephen Laperouse

As well as any additional prospects.

J. Wright Williamson

Right.

Unknown Analyst

Numbers are invested in POI?

J. Wright Williamson

Yes, that's to POI. All of those are POI's interest.

J. Wright Williamson

Okay. We're going to launch into our cash assets now. Madden, in the Rocky Mountains, for us it's a net 4,000 BOE a day on a gradual decline. We'll go through sort of what makes up Madden here in just a minute. It requires very little capital and net capital in the $5 million range each year. And it is cash flow positive even at the current less than probably $4 realized rocky prices right now, so...

And just to sort of set the stage from a location standpoint. We're in the Wind River Basin. As Wright mentioned, we have a small working interest at this asset, but it's a cash positive gas resource for us. It's operated by ConocoPhillips. To give you a feel for the scale, what I've got here are 2 of the primary reservoirs that we've been developing or will plan to develop in the future, the Lower Fort Union is the shallower of the 2 reservoirs. It's at about 7,000 feet. And then we have what's considered the to be the deep Madison Reservoir. Give you a feel for scale, that green outline is about 40 square miles. So it's a huge reservoir in the Wind River Basin.

J. Wright Williamson

It's not quite as big as Phobos.

Unknown Analyst

[indiscernible]

Stephen Laperouse

ConocoPhillips.

J. Wright Williamson

What this is -- it's real choppy, I'll apologize for that, but that's the way the field behaves. The primary production from Madden is from the deep Madison Reservoir. Rowdy's going to show you that in just a bit. But it does have H2S and CO2 with it, about 33% impurities. And so there's facilities there to remove the CO2 and H2S. Those require annual maintenance and a downtime of about a month each. There's -- they do it in 2 stages and you can -- so you can see, even our projections in the future, we're forecasting these probably second quarter and near the end of third quarter downtimes each year. They have occurred in the past. We've also had some unusual downtimes in the past but it seems that things are pretty stable, we're in to this annual maintenance cycle. It's about a 3% decline, very predictable, doesn't require a lot of cash, nice cash flow property going.

Talking BCF now. 152 BCFE of proved reserves. Again, yearend '10, 187 resource potential. It's well-defined, well known. Currently making $26 million a day net to us. 3% decline forecast. Again, you can see we had $20 million of cash flow above CapEx in expenses. Really with a $4.54. We're forecasting $4 for 2012. $3.76 realized after transportation. So a little less cash flow in '12 then '11, but it's purely a function of the cash flow forecast. It pops right back up once we go to $5 and beyond on the gas.

A couple of different distinct targets here. The upper part of the section, or to the left of the slide, is the Lower Fort Union. And again, all these sands that typically shallower than 10,000. You can you can see that it's a bunch of stacked fluvial channel sandstones. Historically, the field was developed by wells drilled, basically to the upper portion of the Lower Fort Union. Where, admittedly the porosity was a little higher than it is as you get down to be lower part of that same sequence. However, we've had some success, over the last few years -- we haven't drilled a well there in a year or 2, but prior to that point, there have been a lot wells drilled down into this deeper section and completed -- built completed with stack completions in the Lower Ford Union. And contrast that to the carbonate section, which at deep Madison. And again, this is at plus or minus 25,000 feet. It is a carbonate reservoir. The average porosity, just to kind of give you a feel for what we're looking at there. It's probably 8%, but it ranges from anywhere between 2% to as high as 20% depending on where you are in the reservoir and if you capture a fracture or you're in a zone where you've some dissolution or solution porosity. So, as Wright mentioned, it's a high-rate, high-deliverable carbonate formation, although it does have some CO2 in the stream.

James C. Flores

Well defined with material balance. We'll show you a map in a minute, but the tank is well defined and behaving like a depletion drive reservoir. Very predictable. Busy map, it's basically showing the opportunities in green, considered as puds, and then there's some additional probables and possibles that we plan to drill, to completely develop the Lower Fort Union. And the next map as the Madison, obviously, we're draining a much larger area with the rock quality that we see in that carbonate reservoir. There's only 8 wells that are either currently producing or have produced the Madison historically. But, as Wright mentioned and I mentioned, it's a very large reservoir it's over 12,000 feet of column, here, that we're developing with some of these deep oil.

Stephen Laperouse

This is net of 33% CO2, H2S, 2.8 Tcf original gas in plays. 2.1 Tcfe EUR, 1.1 [indiscernible] to date. These are gross numbers. And 1 TCF remaining. The probable outline is just what is the real abandonment pressure on this predictable p over z and f material balance to have a proved and probable components to the reserve.

Haynesville. We've probably talked about this a lot in the past with you guys. But this is how we're seeing the Haynesville go forward in our long-range plan right now. We're in a period where the acreage is predominantly earned by Chesapeake and the other operators that we share an interest in wells with. There are a few sections still being earned, but the rig count, both for Chesapeake and the operators, is forecast to, and we're giving guidance on all of them to go down versus what we've been doing for the last few years, for the next, we've assumed, 2 to 3 years.

It has not quite built itself into a cash flow position, where the cash flow exceeds the capital, but we are forecasting that to happen in '13 and beyond here. This is kind of ramping back up to a growth profile once you could assume gas prices came back. Now I will say, this cash flow has not assumed -- this is a flat $5 cash flow prediction.

So we've assumed that, that's conservative and that we will start growing production again because gas prices will respond. If they don't, then that aggressiveness would probably not occur as quick as that forecast. But we have roughly 3 years flat and then start a growth profile. I will say part of that growth profile is also that the Bossier is assumed to be start to develop in 2016.

I think everybody knows we have a 20% working interest in Chesapeake's position. If Chesapeake has a lower interest in some units, then we'll be correspondingly lower a little bit than 20%. Chesapeake, 86,000 current net acres, 1,000 -- almost 1,100 potential net locations. Again, that development resource potential future locations here, 0.2 TCF. Average, 7.5 million per well. The 6.5 Bs, I'll give you some confidence on our type curve again. But we're very confident that it's 6.5 or even 6.5 Bs plus. And you can see our total project cost forward F&D $1.5 per Mcf.

This, basically, just sort of clears view of the amount of activity -- or the wells that we'll have drilled at the end of 2011. We'll have working interest in 324 wells, that's not a net well count. As been discussed previously, most of the activity to date was to hold acreage, so you can see by the end of the year, we'll have almost 950 units held over a 640 acreage unit, that's a gross number.

2012, as Wright mentioned, we're projecting less rig activity. In most of our acreage will have already been held by the end of this year, with few units that will be remaining to held -- to be held will be drilled early on in 2012. And again, that's within the area that we consider the Haynesville sweet spot where we're seeing the higher EURs and some of the higher IPs. And that's consistent with most industry activity. The peak rig count for the Haynesville, as most of you guys know, was, in July of 2010, where we almost reached 200 rigs as an industry, and now the current rig count there in the Haynesville is probably at 100.

We've realized a really stellar growth profile quarter-over-quarter, over quarter. Again, we're projecting this from the 34,000 BOE equivalent in Q3 that we just reported to be much flatter with this level of rig activity here. But it does stay stable with gradual growth.

Just some stats. Currently on the Haynesville, again, the proved reserve was our year-end 10, 5.5 total TCF resource potential, 5.2 being the development resource potential. Currently, making 192 million to 200 million cubic feet net to us a day. Our forecast, the short-term forecast, I showed you how flat it was at 1% incline, the 11,000 future locations or gross locations.

You've seen -- you saw net on the previous slide, but these are gross. And I mentioned that we weren't cash flow positive in '11, at least relative to being above CapEx. We're very close to being that in '12, and we forecasted to be cash flow positive above CapEx in '13.

Just a Paleo map at time of deposition in the Jurassic when the Haynesville was deposited. As I've mentioned previously, really, the sweet spot for the Haynesville, as we've drilled and matured this asset, it's fairly consistent with what we believe to be the deepest part of the basin during deposition of the Haynesville. It's within the deepest part of the basin where you have less clay, you have more calcite, better porosity, more brittle rock. Again, that's mapped out to be some of the higher EURs in the Haynesville .

Just a quick slide showing what we consider to be the sweet spot. Again, it's over 200 feet thick, see a nice gas effect when we look at look at both density curves and sonics which is not shown on this slide. One thing that Wright mentioned that's not on the slide is the Bossier is turning out to be a viable target within the play.

There's a lot of acreage that actually has what appears to be a nice Bossier that we are a part of. The Bossier actually comes in about 400 feet above the Haynesville, so it requires a separate lateral and a separate completion. And there are some areas, and you'll see in a curve that I'll show in a second, where you do have coincidence between where the Bossier is prolific and where the Haynesville is prolific.

This is the type curve, same format that I was going through with Eagle Ford. We started out with more of a traditional type curve, at a high 12 million, 14 million a day initial rate. With Chesapeake, they basically stand -- started, much as we said we were doing in the Eagle Ford. It's not anymore for a 8 million to 9 million a day initial rate. All that flat for a couple of months, start kind of the decline that we reported on from -- if you put it at 14 million. And you're avoiding some of that real steep decline in the very early part and having to build the facilities to accommodate that.

That being said, you can see that our history, and again, in this history, the yellow as well count again here, and that's the 711 wells that are contributing to this analysis. Rate is on the left-hand side. This is 8 million a day, 10 million a day gas rate. It's a dry gas, as most of you know, I'm sure. This is days on the bottom, so we're almost to 2 years, with probably 60 wells contributing 2 years worth of production in this analysis.

You'll see that the growth -- this is a reverse growth profile of the well count, the producing well count in the Eagle Ford. But this is a running cumulative between what is the actual cum bend versus our type curve. And you can see we started out well above it, 90 days, you kind of even with it. It's still 6% above this type curve even out here, 1.75 year level.

So again, there's probably going to be adjustments to this curve in the future, maybe it will flatten even more in this midpoint because we're definitely outrunning the cum of the original type curve. But in total, it's very good validation to this type curve, and this works.

Now, the good news is that the Bossier, at what early data we have -- again, I don't have enough of it to do this kind of analysis on a quantitative basis. But it's starting to look like Bossier may have equal rates, if not equally EURs to the Haynesville. We always thought about it initially as slightly less, but it may hold up to be the same creature. So that's kind of the state of development of the Bossier or exploration, I guess I should say, of the Bossier.

And this is a block diagram, which happens to be in an area where, as I mentioned previously, where you actually have Haynesville and Bossier, coincident. And it's basically developing a full section, 1 mile across and 640 acres. Again, what we've done today is primarily just drill one well to hold this whole unit. So this is not an area that we've fully developed, but this would be kind of a go-forward plan at some point in the future as per our rights development plan that we showed. So I mean, there are areas where we actually have leases where a single section will have 8 completions in the Haynesville and 8 separate completions in the Bossier.

Stephen Laperouse

Yes, sir?

Unknown Analyst

[indiscernible]

Winston M. Talbert

Well I'm just saying -- I'm just saying that the revenue curve was based on a $5 flat gas price assumption, through that whole graph. So if you raised -- gas price will be raising revenue, which will then revenue less expenses with that green curve. Is that what you're asking? Or what...

Unknown Analyst

[indiscernible] Can I get a sense of [indiscernible]

Winston M. Talbert

I think anything north of 5 and it will round back up.

Unknown Analyst

[indiscernible] Is there a gas price that we would go non consent on Haynesville well, since it's HPP now?

Winston M. Talbert

Well, I think it's there right now, we've not been non-consenting wells for a while in the Haynesville right now. Just from an economic standpoint, that depends on the lease contracts, where all the leases are not that type of thing, but nothing prohibits us from doing that. That's one of our key strategies going forward, if gas price continues to get tougher and tougher, then we'll have that flexibility, because it's definitely not going to be part of our financial strategy to drill noneconomic gas wells. So it's a very much a part of our work. Yes, we have non-consented, both Chesapeake and non-Chesapeake wells recently.

Unknown Analyst

[indiscernible]

James C. Flores

But if it's based on rate of return, of course, we would have to have at least 15% rate of return, so it depends on the matrix and the math of that. And the biggest driver there, the biggest bear-up to that, is what's the service cost, what the well costs are. As oil is driving service costs right now and service costs continue to go up, that price becomes higher and higher. I'm not trying to dodge the question, but it's a moving target, but based on what we think we got the wells drilled for. So I think, you could say just on a gas-on-gas basis, $5, $5.50, something like that, but next year it might be $6 looking into 2013 based on inflation.

Unknown Analyst

[indiscernible]

James C. Flores

I think most of we're being guided by Chesapeake, of course, that most of their drilling for 2012 will be pad drilling. They'll be doing some of the down spacing that Rowdy mentioned to as pilots, if you will. They've got several different ways to down-space, bigger spacing between wells and larger fracs, smaller spacing between wells and smaller fracs. And they're looking for the optimum so that they are ready to pull the trigger when the environment is right. But most of next year's program for them is that it's experimenting with Bossier and it's experimenting with the proper pad drilling scenario to develop -- to ultimately develop the Haynesville.

Unknown Analyst

[indiscernible]

James C. Flores

I don't know. They didn't tell us that, but if they said that, then they said it I don't know. I can't comment on that.

Unknown Analyst

[indiscernible]

James C. Flores

As Jim has mentioned several times, the cost are a little higher than they were a year ago. And the Haynesville has had some inflation, too. We do think with the laying down the rigs that the pressure's going to come off of that in the Haynesville play. That's obviously our view.

Unknown Analyst

[indiscernible]

James C. Flores

Well, that was current rigs this year, which we've already laid down a lot of rigs this year versus planned rigs for next year. So that we had a lot more rigs running earlier through the first 3 quarters of this year. Well, that's operated, and you saw total rig count there, the non-operated end. Early on in the year, we were at 50-plus, during 3 quarters, we were only 50. And that was just the current snapshot.

Winston M. Talbert

As everybody's searching for answers on how you think Haynesville is going to be developed and so forth. Each operator has their different financial structure, their different takeaway commitments and so forth and their different reasons to drill wells. The unique position that we're in is that we can manage our own gas book the way we want to manage it. We can non-consent wells. We can go to the wells. We obviously would look favorably going to the best unit wells in terms of the whole acreage. We're at the twilight of our holding acreage. We've got 11,000 locations HPP right now. So I'm not sure there's a whole lot more for us to do there. So we're going to manage our gas book so that it doesn't erode into our revenues, and also, we're not going to be subsidizing our gas business without liquids. It's kind of the answer. that's why it's hard to answer these questions. What other people may or may not do because -- I mean, EXCO is running 12 rigs right now in the Haynesville. So they, obviously, have a different mindset than we do. They probably have a higher gas forecast mixture than we do. And we can't control that, we just can -- we can either go consent or non-consent based on our own efforts. But it's not going to affect our business play going forward. I think that's the thing they were showing, that the durability of Haynesville, when gas prices do come back to some economic level, we're going to be there with a very nice large position that seems to be meaningful.

Unknown Analyst

[indiscernible]

James C. Flores

No, you can ask it to me, Tom. He's just trying to summarize. Just talk loudly. Yes?

Unknown Analyst

[indiscernible]

James C. Flores

You had to pay our royalty if you -- from the standpoint of non-consenting because there's a back-end clause, and that figures into it with these low gas prices. It's not going to be that big a deal expect for the first year's billings to add to the well cost or in an inverted fees. But paying royalties is not going to be a reason to go forward on noneconomic wells. It just makes it more noneconomic. And the key about that is that just making sure that you don't caught up in trying to develop acreage that there would be better developed in $6 gas or $7 gas and just trying to meet some of those other operator's commitments. We're not going to be in the business in doing that. The interesting thing about the unit wells is that when you drill the first unit well -- or when you want to drill subsequent unit wells, you're just not consenting that well. You're none consenting the unit. So it's not very painful from the standpoint of surrendering additional opportunities.

Unknown Analyst

On the well cost, you're above 7.5 [indiscernible]

Winston M. Talbert

Yes. We're in the 8.5 range right now with Chesapeake AFD [ph].

James C. Flores

One of the things about the pad drilling is that the theory is finding out where the well costs could go to, as far as going lower efficiency and information. So it's got all the scientific and technical reasons to do it, it's just a tough economic environment, [indiscernible] to go out and do that type science when you really don't have to.

Winston M. Talbert

Well, we really wanted to have this really as a deep dive into our assets, so we also want to kind of round up and talk a little bit about what we've done this year. The reasons behind what we did and what we think is really the strategy going forward from a financial standpoint.

James C. Flores

This is Winston Talbert, our CFO by the way.

Winston M. Talbert

Some of the things that we did, were our reaction to what was going on in the market. We saw a very big duplication between WTI and Brent, and then we also saw a pretty big duplication between WTI and what was going on in the California spot market. I'll talk a little bit about that.

We had a strategy next year and what we employed a couple of years ago is putting in foot spread and then selling costs on top of it to relieve the premiums that we're going to pay. We're getting close to 2012, and so we're looking for an opportunity to take out that $90 million that we're going to pay next year.

We also want to look at reducing our leverage, and we have a very great opportunity with the cost structure of our bond, where we are in the cap structure to be able to reduce some leverage and to reduce our interest costs going forward and increase our maturities. So that was something that we wanted to do this year.

The other thing is because of what's really going on in the natural gas market, we are really trying to reduce our CapEx on some of these long-dated projects, such as the Gulf of Mexico. So we spent most of the year doing our financing for the deepwater Gulf of Mexico. And then just recently, and really in response to enhance the strengthening of the capital structure and reducing our interest costs, we're selling the Panhandle assets in south Texas.

All these are impacts of the 2012 cash flow, and this is kind of the way we're thinking about it. Once, we couldn't really execute the hedging strategy until we got the crude oil marketing strategy put together. If you look at what we are looking at, we've got about 80% of our crude is out in California, all that production coming on. That's where we've seen a fairly big duplication between where contracts were and where the spot market was.

We're also looking at the Eagle Ford. We were putting together marketing contracts for all the Eagle Ford production. We are seeing the duplications in WTI, and so what we did is we went out and negotiated contracts to sell our crude at LLS prices, LLS minus $7 in the Eagle Ford and really reduce PXP's exposure to cushing.

We really believe that the dislocation you're seeing at WTI is going to last for a long time. It may not be $25 a barrel, it may not be 25% of what you're seeing this year, but there's always going to be, we think, for a significant period of time, a discount to Brent. And that's because you've got a lot of crude coming down from the Canadian oil sands enhanced by the Bakken and then piled on by all the mid-continent drilling for liquids that's going on.

And so there's always going to be a discount coming into the cushing because of the refiners have a lot of the purchasing power out there. And they've got the pricing power and, they're going to defend that refining margin at all cost. If you think about it, when the things really started going, in the first 3 months, in March, we saw a huge spike in Midway Sunset, and that's what really sparked our interest in trying to -- in understanding what was going on in California, and really sparked us to go ahead and start negotiating with Conoco on our contract.

We were selling about 70% of our crude to ConocoPhillips that was at an 88% discount to NYMEX. We always had this long-term contract with Conoco, in which we negotiate the discount or premium to NYMEX on a 2-year rolling basis. And it's -- the fortunate thing for us was the contract, the 2-year period was up this year. We knew we were going to have a tough negotiation coming up, and so what we decided to do is, we wanted to think about what exactly we wanted to do going forward especially since that contract was ending in 2014.

So what we did was we decided to go completely to the spot market in California because we believe the dislocation WTI is real. We think it's going to be ongoing, and we think that California crude production is going to be a lot more in line with world prices, then it really have nothing to do with WTI anymore.

If you look at this, what I'm trying to show you is if we had a contract in place at the beginning of the year, we would have a $200 million uplift just from changing the terms of the contract. I'll tell you that, 75% of that was in the last 6 months because it's gotten worse and worse and worse. The differentials in California have gotten much more favorable to PXP even after we negotiated the contract. It's continued to get better and better.

And what we think is driving this is something -- a phenomenon that we've seen basically since we bought Nuevo. And that is, out in California, you've got the declining California oil base, which is still a very prolific oil base in out in California, overlaid with Alaska crude that is declining.

And we picked up -- we bought Nuevo back in 2004, and as you can see since 2004, the amount of foreign crude that the refiners are having to buy to make up, the crude played at California has gotten wider and wider and wider. At some point this year, the refiners decided -- the integrated refiners out in California decided it was in their best interest to start getting margin for the California crude barrels rather than send them through the refining complexes at a discount.

So what happened, we think, in March, somebody decided that they're going to just flip the switch, and since ever since March, it's been narrowing and narrowing into Brent. And it's really because all the refiners out in California have to pick up water -- have to pick up oil out off the water. So that's reflected in the onshore barrels in California, and we do think this is a permanent situation because you're not going to see a whole lot of pickup in production in Alaska over the next few years.

I really doubt you're going to see a lot of oil sands in California. If you think it's hard to get approval for a pipeline to the Gulf of Mexico, just think about trying to put an oil sands pipeline across the Rockies into California. It's just not going to happen.

If you look at this, this is just since August. When we first started negotiating, crude in California was selling -- our crude baskets in California were selling at about 100% of NYMEX, and NYMEX was selling at a 15% to 20% discount to WTI. We knew that there was going to be an issue. Since the time that we finalized that contract, which I think was back in June, at the end of the second quarter, the thing has just narrowed and narrowed even more. And if you look at the last week or so and even the last 4 or 5 days, our crude basket now is trading above Brent.

Buena Vista crude, which is a small portion of our crude slate is selling at about $125 a barrel. You've got Midway Sunset trading at $5 above. Brent right now, is -- it's really because in California, it's becoming harder and harder to bring that crude in, and as they get more and more reliant on waterborne crude, it's going to get even more expensive because it has to -- a lot of that crude that they are buying to make up the difference was coming from South America.

But unfortunately, a lot of the basins that they were relying on are in decline. In Ecuador, there's not as much production available. Until Brazil comes on, they're going to have to start getting a lot more crude from the Middle East. All that crude is going to have to go by China. It's going to have to go by India on the way to California. It's going to make the waterborne crude a lot more expensive out in California. So we believe this is a permanent situation. We wanted to get prepared for it that's why we renegotiated the contract.

And we also wanted to make sure that we had a long-term contract with an operator, with the biggest refiner out there. And I think that we have a very good relationship with ConocoPhillips, and we really appreciate them working with us on that.

The other thing, once we redid the contracts, what we did was we looked at where we were on the hedging, and there is such a huge difference between Brent and WTI. The thing that we took advantage of is that the put spreads we had in place in WTI because TI was so low, we were in the money. So we unwound the TI hedges and put on Brent hedges, and at the same time, we went ahead and sold caps to eliminate that $90 million I was talking about.

So we did those both at the same time. We did it for 40,000 barrels a day. The crude market -- we did it right before the crude market came apart. We are going to do about 40,000 barrels a day for 2012. And we're looking at putting in a significant position into 2013.

We got 22,000 barrels a day in 2013. We'll look to acquire some more hedges in 2013. We'll go ahead and do some more for 2014 because we think that underpinning the long-term nature of our business is very, very important.

This is basically just a recap of where our hedge positions are. We've got about 160 a day of gas next year. We -- these are positions we put on about 1.5 years ago. We just went out and said, "Okay, we think crude's going to be low for a long time, let's put in $4 floors. And let's just kind of see what happens." Unfortunately, it not only went to $4, it went below. And that's one of the things that we're -- you'll see us over and over again.

We're about as bearish as it gets on natural gas. We think the thing is a long-term deal. We've done -- a lot of the steps we've taken is to reduce PXP's exposure to the natural gas market. We'll continue to do that. The whole discussion about non-consenting wells and those types of things and selling the Granite Wash and getting out of the south Texas gas properties are really just a reaction to what we think is going to be a fairly long-term problem in the natural gas market.

If you have medium-term gas like the Granite Wash, because we have maybe 150 locations left in the Granite Wash, most of them gas. We just felt like medium-term gas locations are not that valuable in this market because we just don't think gas is going to turn around for a while.

The other thing that we're doing is we're taking the money that we're getting from the asset sales. We don't have any -- we have a pretty large NOL position, about $1.1 billion right now, so all that money is going to be tax-free. We're going to take that money. We're going to reduce our debt.

And I'll go over the capital -- the debt structure in a second to show you the opportunity that we have. We're going to go ahead and reduce that, and the target is to reduce our interest cost, 30% to 40%, which sounds like a lot. But if you look at our debt structure, it's not really too hard to do. This is just what we talked about on the conference call. This is the nature of the assets that we sold.

The other thing that you think about when you think about the cash flow these-- if you look at the combined south Texas and Granite Wash, we're going to have negative cash flow of about $30 million. So that kind of -- it eliminates that $30 million, but it also reduces our exposure to the inflation that's going on, on those properties.

If you're out in the Panhandle and you're drilling wells, because of the nature of some of those wells out there, the inflation costs almost cannot be quantified. You can put 15% in the model, but you just don't know what it is. So what we've not only done is reduce what we think is negative cash flow out on the Granite Wash next year, but we've also reduced our exposure to the inflation out there.

If you look at our debt structure, we've got -- if you look at the $600 million, and the $565 million and the $500 million, the 7.75% and 10% notes and the 7% notes , you just draw a box around those. Those are all callable within the next 18 months. It's a huge opportunity for us to reduce -- not only to reduce leverage, but reduce our funded debt costs going forward. And right now our long bonds are trading a little over 6%.

So what we're going to do is to take this money, and along with the EIG proceeds, we think we've improved the credit profile of the company by dramatically, and so we're going to take advantage of what the capital markets -- whenever the capital markets open up to refinance a lot of our bonds. We can increase our maturities, lower interest costs and reduce the leverage of the company overall in, basically, 1 or 2 transactions. So that's the sort of the opportunity set that we have. That's how you reduce interest costs 30% to 40%. You take out the 10% notes, you take out the 7.75% notes, and you either pay them off through asset proceeds or you refinance it in the long bond line.

If you look at our liquidity, I mean, and I told Hance that at some point we're going to have to get away from this whole liquidity issue because when you talk about it, it means you're worried about it. But we're not worried about all the liquidity around here, we've got plenty of liquidity.

If you throw in EIG, we're going to have another $400 million sitting there. We intend to use our revolver. We think our revolver is very stable. We think our borrowing base is extremely stable. We intend to use $300 million to $500 million on our revolver. We're still going to have a $1.4 billion to $1.5 billion revolver, with probably a $2.2 billion to $2.5 billion borrowing base.

So we think our assets allow us to use our revolving credit because it's the cheapest debt out there. We want to have some short-term debt in our capital structure. And really, to me, this is really the end of the biggest -- what we saw was a pretty severe credit contraction in 2009, 2010, and we think we've kind of come through the other side of this, and we feel very good about where the structure and the tenor of where PXP is.

The other strategy that we have, and this is just going back to the EIG transaction itself. We're going to have about $400 million to $500 million of CapEx over the next few years in the deepwater without any -- having any production in the near term.

So one of the things that we decided to do was to go ahead and finance that in the markets by selling a percentage of the company in order to pay for all the CapEx within POI. So we dropped all the assets in the POI, we went out and created a structure and then went out and marketed it over a long period of time.

One of the reasons why it took so long is because we're asking somebody to take a lot of equity risk on this. And there's no guarantee by PXP that if they get paid back, there is -- what you're doing is you're using the asset within the company, which is Lucius in the drilling of Phobos and all the leases that we're putting in to the company, as the underpinning for the credit of this company and for the underpinning of the investment thesis to the outside investor.

So we think this is a very clean structure for PXP. It has incentives, all in the right places. We think it's credit enhancive, and we also think it creates a situation in which the PXP shareholder itself is exposed to 80% of a carried interest in a very valuable asset.

Basically, this is the structure of PXP. You got POI, all the leases down to POI. Other cash is going to be coming up through POI. We're going to be paying EIG a coupon, 6% cash and 2% deferred, until, obviously, Lucius has been done, and then we'll start paying going forward.

They do have the right in 4 years to create a liquidity event, which it will come to POI and I'll say, "Okay, POI, create a liquidity event, either sell the asset, either IPO the asset or buy us in." So those -- that's really the constructs of it. When that happens, Lucius is going to be on production. It's going to be producing 20,000, 25,000 barrels a day. It's going to be a good problem to solve and it'll be a great event for PXP.

James C. Flores

Thank you, Winston. But don't sit down yet. Any questions for Winston? With the lot of material, quickly, you can see the strength of the company has really the changed and gotten stronger. Question right there?

Unknown Analyst

[indiscernible]

James C. Flores

No, the risk -- not the risk but the buybacks, right? We don't know what's going to happen with Phobos, for example, the development of that. We don't know where oil prices are going to be. I mean, if we have a global meltdown, recession, we could have oil prices in Brent back in the 80s and WTI back in the 60s. We hope our hedging policy will underpin where we are. But if we're out there in 2013 with free cash flow and we've got good hedges in place and we've got plenty of extra capital and so forth, we're certainly not interested in expanding our share base. We would definitely be in business of reducing it. We're not real positive on using after-tax dollars to develop -- I mean, to buy the shares when you could use pretax dollars to grow barrels per share. So it's still our main focus and so forth. But if the world stays where it is, with $110, $120 oil, and we execute this plan and so forth, the only thing that would delay it would be lower commodity prices. And then we'd certainly look at that because we'd want to make sure that cash flow is priced in our share count, which it didn't right now.

Unknown Analyst

[indiscernible]

James C. Flores

Right. I don't know if I could scroll this thing back 200 pages that fast. But, all right, give me a page. Probably 17, I think it's the one I'm looking for. The thing about that decision, we're not in the mission to take that WTI line versus the Brent. We're working hard to get almost 100% exposure in Brent. # 17, I think. No? You missed it, well it's 30-something. Stop right there. Can I have control? That one right there, 37. Sorry, I was just guessing. With this production profile, we fully expect to make more Gulf of Mexico discoveries, and add to this going forward and have a pretty easy business plan. And what's the development of those costs? The initial thing about the Lucius project and the Pliocene and the reason why we cut loose our Friesian project, Friesian project on a per BOE basis was 3x more costly than Lucius. The Lucius project basically cannibalized the Friesian project, from the standpoint of saying, "Hey that a lot of operational risk, a lot more price risk, let's go and take the best project that is still diluted by that, and let's move forward in the impact in our company." If we find more Lucius looks alikes, we are going to have more free cash flow. There's not a better project out there. And so that's our game plan, and we'll be adding those on the next 3 years depending on Phobos and then also the cash flow out of Lucius and Phobos to continue -- out of Lucius and going forward to continue our exploration work. But that's basically add-on to our production profile, that we think is still selling. We don't see a lot of opportunity to enhance this model. If we see a lot of opportunity to dilute it, we will not do that by an acquisition or anything. Brian?

Unknown Analyst

[indiscernible]

James C. Flores

No. We don't see that against the -- the back half of that, there's some-- that's so far away, that's '16, '17. We're not going to panic over that until '16 or '17. I mean, it's not going to change the value proposition here because the value proposition here with Lucius, you're talking about $3.5 billion of cash flow that we're not -- if we were just -- if we have the same multiple today at 4x, that's a $15 billion equity company. Heaven forbid, we actually got a decent multiple like somebody else, like the rest of our peers, and we end up with maybe 5x. That's probably greedy. We have such a long way to go, let's just get on a horse. We're going to do our part as far as performing and so forth. We're going to talk about the McMoRan shares. We've got even more liquidity than Winston talked about. I had one of our long-time bondholders is asking me, "You guys -- he was like, " Your investment grade quality, I didn't like it. Is that a bad word around your shop?" It's always been a bad word because we never had assets with the durability and the growth rate that we have now. And so it's all -- the transition, I got to tell you, it feels great. So I can't -- I haven't seen a business out there stronger than this and have it come our way with the same type of differentials. We're not going to dilute this. So we're not worried about back half inventory, but we do have an opportunity to fill it in. Which, I think, a lot of people have to think about reloading on acreage and all that kind of stuff. We actually have the leases. The opportunities we haven't drilled it yet, we will know a lot about it late next year when we drill Phobos. So the Phobos, the P10s [ph would probably be too sparse. You have a question on the back?

Unknown Analyst

[indiscernible]

James C. Flores

Well, the equity kicker is there's a 6% -- well 5% cash. The bond, there's a 2% deferred coupon from that standpoint, and there's warrants also involved, the 7.5% warrants. But the warrants dilute their 20% equity, that's why instead of being 27%, it's 26%. Kind of a third grade explanation, but it'll get you there. And that's the event if we hold it to term, and they go forward. You could see us, at some point in time, they want cash and to be able to buy that at a discount and that type of thing at some point in time when things are in production and where everything is. Yes, Steve?

Unknown Analyst

Will you potentially be like [indiscernible]cash back?

James C. Flores

Well, that's the reason why we have the revolver in place. so we'll be putting -- we'll be [indiscernible] up and with upstream cash, it's all going to be fully taxable. But our shields in the Eagle Ford will probably offset that. And that's why we're talking about the tax basis, where we are, less in NOLs and so forth.

Winston M. Talbert

Yes, right now, we have -- I guess, we have about $1.1 billion. After we do these deals, we're probably at $400 million to $500 million under the models that we kind of put together for you guys. We were really not a taxpayer until the end of 2013, beginning of '14. And then at POI, the way the POI is going to work is all the development that we're going to be doing over the next 2 or 3 years is building that basis in POI itself. So when cash comes, you're just going to be -- you've got a natural shield to the first $500 million of cash flow. How about that?

Unknown Analyst

[indiscernible]

Winston M. Talbert

We really didn't have any basis in that, the assets, because all of it's in exploration that we've already expensed.

James C. Flores

David?

Unknown Analyst

[indiscernible]

James C. Flores

I'll let Steve kind of comment. Let me give you, I think, a couple of general comments. Basically, what we've been doing for the last 2.5 years is permitting this next 5 years of projects. So I mean, the projects that you get to the individual well permits and so forth. So Steve, you want to make a couple of comments on that?

Steven P. Rusch

[indiscernible] We've been bringing about 30 diatomite permits here, and we'll have built up an inventory. Once we get through this year and next year, we'll be able to support that. We were one of the first companies to get a diatomite permit back in September of 2010. We kind of led the industry in that. So that's opened up and freed up our ability to get the diatomite permits we need.

Unknown Analyst

[indiscernible]

Steven P. Rusch

We've been doing a lot of that all along, David. It's new for them. We were well aware of what was coming down 2 years ago about 2 years ahead of everybody else. So we've actually -- the increase -- we started submitting permits up to 6 months ahead of time where before we only had to submit 6 weeks ahead of time. So we've been able build up that inventory and be first in the queue at Dougher [ph] commission of oil and gas and geothermal reserves. So we've been able to build that up in the last [indiscernible]

Unknown Analyst

[indiscernible]

Steven P. Rusch

Well, for instance in the Valley, that's about 1,000 well bore diagrams, we're about halfway through that to support the programs we need in the next 5 years. So those are what Doug [ph] sees coming in from paper. So it's a huge load, but one that we're ahead of the curve on.

James C. Flores

And kudos, so we got a great organization that Steve runs. He's our Vice President on the ground in California, he'll be out in front. It's just communication. It's staying in front, it's not trying to hide the ball, being very open in front with our regulating bodies and working with them. And he's just done a fantastic job, and that open communication's paid off in dividends. We continue to get asked questions about other people's problems out there that we don't see. So I guess, it goes with the real estate for us here. Next?

Unknown Analyst

[indiscernible]

Steven P. Rusch

Cap and trade was passed about a month ago by the California Air Resources Board. And the entire industry is looking at that, I mean, as far as what the impacts are going to be. And things we are looking at obviously is offsets, but we need to know what our allowances are, and the trade associations are involved and still talking to CARB because CARB really doesn't understand how they develop those allowances. So there's still a lot of questions in the air as to what -- the industry is going to have to actually go out and purchase to offset whatever that allowance shortfall is. Because everybody will get an allowance and this is just like reclaim back in southern California air quality management district 20, 30 years ago. Everybody will get an allowance

[indiscernible] everbody's trying to determine what is that shortfall, and we don't really know yet.

Unknown Analyst

[indiscernible]

Steven P. Rusch

In part, that's true. There's a heavy oil factor and a light oil factor, and that goes into the determining the allowance. But we're still not there yet. We, and everybody else, as far as what that delta is between our allowance and what we're going need to offset. Right there?

Unknown Analyst

Yes. So quick questions. [indiscernible] kind of continue to maintain that ratio [indiscernible]

Steven P. Rusch

Yes, yes. POI is designed to be at a [indiscernible] Think about it, the model that we're going after is the ARCO Vastar [ph] model and avoid the mistakes, if they made. When they did Vastar, they sold 50% of the equity in the public right after that. So there's no self-funding of Vastar. If they could migrate the equity, it could -- has evolved the money in the lag time on capital. They got caught in that trap. By doing minority entries like this 20% and so forth, we might be able to sell more equity if we need to, to finance that. Again, it's back to a theory of financing long-term projects with project-level financing versus put it on our balance sheet. Because otherwise, we're not competitive to the rest of the world that's using short-term reserves in production projects with their cash flow. We're dedicated to that. Obviously, we've proven we can finance these projects successfully. EIG is a willing financier with a lot of capital. They would like to participate in any way possible. The interesting thing about POI is that it's going to be -- is the amount of cash flow coming out of that. In fact, the question there about buying stock is, how do we think about that, going forward? And where we are at oil prices, we're going to have a lot of flexibility. But the initial character of us being able to continue to finance these things outside of our initial cash flow is going to be the #1 priority.

We had a great tour this year raising money on this thing and figuring out just kind of where everything lives and a learned a lot about the projects. And we're very pleased with the flexibility of the structure that we have in our partner, with EIG. We're sorry for the ones who will get left at the altar.

James C. Flores

The bartender's at the bar out there. There's dinner served. We'll be around. And remember, if there are people from PXP, please ask any question you need. Thank you very much.

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Source: Plains Exploration & Production Company - Shareholder/Analyst Call
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