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Plains Exploration & Production Company (NYSE:PXP)

Q1 2010 Earnings Call Transcript

May 6, 2010 9:00 am ET

Executives

Scott Winters – VP, Corporate Communications

Jim Flores – Chairman, President and CEO

Analysts

David Heikkinen – Tudor, Pickering, Holt & Co.

David Kistler – Simmons & Company

Leo Mariani – RBC Capital Markets

Brian Corales – Howard Weil

Jeff Robertson – Barclays Capital

Duane Grubert – Susquehanna

Ann Hammeren [ph]

David Tameron – Wells Fargo

Operator

Good morning. My name is Debbie, and I will be your conference operator today. At this time, I would like to welcome everyone to the 2010 first quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions) Thank you. Mr. Scott Winters, Vice President of Corporate Communications. Please go ahead.

Scott Winters

Thank you, operator, and good morning, everybody. Welcome to PXP’s 2010 quarterly earnings conference call, which is also being broadcast live on the Internet. Anyone may listen to the call or the replay by accessing the Company’s Web site at pxp.com. Also located on the Web site are the earnings release, a slide presentation, and the Form 10-Q.

Before we begin today’s quarterly comments, I’d like to remind everyone that during this call 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. In our press release and our prepared comments this morning, we present some non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release.

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

For the first quarter 2010, revenues were $384.1 million and net income was $58.5 million or $0.41 per diluted share, compared to revenues of $228.5 million and net income of 5.2 million or $0.05 per diluted share for the first quarter of 2009. This improvement reflects higher commodity prices and higher sales volumes.

These results include certain items affecting comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contract which exclude the impact of the derivatives monetized in the first quarter of 2009 and some other items.

While considering these items, net income for the first quarter of 2010 was $43.5 million or $0.31 per diluted share compared to $10 million or $0.09 per diluted share for the first quarter of 2009. This is a non-GAAP measure.

Net cash provided by operating activities was $221.8 million, and operating cash flow which is 226.2 million for the first quarter of 2010 compared to net cash used in operating activities of 29.4 million and operating cash flow of 164.7 million for the first quarter of 2009. Operating cash flow is a non-GAAP measure.

Sales price realizations before derivative transactions were 86% for oil and 95% for natural gas during the first quarter 2010 versus 81% for oil and 86% for natural gas in the first quarter of 2009.

2010 quarterly oil and gas revenues when compared to the first quarter of 2009 were higher due primarily to an $18.80 per BOE increase in realized prices for derivatives and a 5% increase in sales volumes.

Average daily sales volumes were 85.1 thousand BOE compared to 80.9 thousand BOE, in the first quarter of 2009. Total production costs were $14.37 per BOE for the first quarter or 10% lower than the 2009 period, which was $15.89.

A quick review of some of the components of total production costs for the quarter is as follows. Lease operating expense decreased 16% to $8.16 per BOE in the first quarter of 2010 versus $9.74 per BOE in the first quarter of 2009, reflecting the results of our cost reduction program.

Lower taxes, both production and ad valorem per unit primarily reflect lower ad valorem taxes partially offset by increased production taxes. The reduction in ad valorem taxes reflects a lower commodity prices at the time of assessment while the increase in production taxes is a result of higher current commodity prices.

Higher gathering and transportation expenses on a per unit basis reflect an increase in production from our Haynesville Shale and properties.

As previously reported, PXP acquired Incremental Derivatives on a significant portion of its 2011 and 2012 crude oil production volumes during the recent strong oil price market. We continue to pull away our hedge strategy using a combination of put options and three way collars to protect our cash flows through 2012 and retain exposure to substantially all oil prices upside potential.

These two derivatives enhance our credit position and underpin our capital expenditure program thereby providing PXP greater flexibility to deliver double-digit production reserve gross targets.

PXP acquired crude oil production spread contracts on 31,000 barrels of oil per day in 2011 and 40,000 barrels of oil per day in 2012. Both the 2011 and 2012 put options have a floor price of $80 with a limit of $60 per barrel.

PXP also acquired crude oil three way collars that have a floor price at $80 with the limit of $60 and a ceiling price of $110 or 9,000 barrels of oil per day for 2011. We elected not to use hedge accounting for these two derivatives and constant weblink [ph] the derivatives will be mark-to-market each quarter with fair value gains and losses recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement.

A summary of PXP’s open commodity derivative positions is included with the financial tables in the press release.

We began 2010 well positioned to continue efficiently growing production reserve in the contribution from multiple asset areas. Here’s a quick update. In California, PXP continues to expand development of Incremental Diatomite, Non-Diatomite and Miocene projects to maintain production volumes.

The 2010 plan includes drilling over 100 onshore wells compared to the 12 wells we drill in 2009. In the Haynesville Shale first quarter average daily production increased 19% to approximately 89 million cubic feet equivalent at to PXP from approximately 75 million cubic feet equivalent per day net during the fourth quarter of 2009. Production is expected to continue to increase to approximately 125 million cubic feet equivalent net per day by year-end 2010.

In the Gulf of Mexico we have an active appraisal and exploration drilling program underway. In the Shallow Water, the Davy Jones offset appraisal well also known as Davy Jones #2 operated by McMoRan and located on South Marsh Island Block 234 is currently drilling towards proposed total depth of approximately 29,950 feet. Our working interest is 27.7%.

The Blackbeard East exploration well operated by McMoRan and located on South Timberlier Block 144 is currently drilling towards a proposed total depth of approximately 29,950 feet targeting middle and lower Miocene objectives.

In addition to drilling the objective section previously seen below 30,000 feet in the Blackbeard West well, Blackbeard East is designed to test a younger Miocene section due to a shallow salt exit point. PXP’s working interest is 31.5%.

The 2010 shallow water exploratory drilling plan also includes the following projects

The Lafitte exploration well, operated by McMoRan and located on Eugene Island Block 223 will target middle and lower Miocene objectives and is expected to commence drilling this year. PXP’s working interest is 26.25%.

Blueberry Hill sidetrack well operated by McMoRan and located on State Lease Block 340 is currently drilling towards a proposed total depth of approximately 24,000 feet. PXP’s working interest is 47.9%.

And the Hurricane Deep sidetrack well operated by Shevaron Corporation and located on South Marsh Island Block 217 will be redrilling during 2010. Our working interest is 30%.

In the Deepwater The Lucius #2 appraisal well operated by Anadarko Petroleum Corporation and located on Keathley Canyon Block 875 is currently drilling towards a proposed total depth of approximately 20,256 feet. The Lucius discovery well was announced in December of 2009 followed by a successful appraisal sidetrack in late January 2010 which confirmed a major oil discovery. PXP’s working interest is 33.3%.

The Lease Sale 213 PXP and its partners are apparent high bidders on 44 blocks on which they bid at the U.S. Minerals Management Service Central Gulf of Mexico Oil and Gas Lease Sale in March. PXP’s apparent high bid includes interest in 16 shelf blocks and 28 deepwater blocks. The company’s working interest on the blocks range from 25% to 100% with a net exposure of approximately 34 million.

PXP and its partners expect the lease (inaudible) over the next several months subject to MMS review and approval. In the Texas Panhandle, PXP recently finished drilling and set completion liners on two Granite Wash horizontal test wells, one in the Wheeler Field, and one in Marvin Lake Field.

Hydrocarbon shows during drilling operations for both wells are in line with pre-drill expectations. PXP expects first production from these wells by the end of the second quarter. And the 2010 plan includes drilling 13 Granite Wash wells from an inventory of over 100 potential locations.

In the Gulf Coast, drilling operations are underway at the Big Mac project in Southeast Texas. The proposed total depth on the first well is approximately 14,770 feet and the results are expected by the end of the second quarter. PXP is approximately 30 to 40 leads, all amplitude driven associated with its Big Mac project.

We reiterate our full year 2010 guidance originally published in February 2010 and we believe our balance portfolio of assets and ongoing hedge program position us for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities.

With that I will turn the call over to Jim.

Jim Flores

Thanks, Scott and good morning, everyone. As you see from our release we got a lot of activity, we got a strong quarter on the production side, 5% above the comparable quarter last year and with higher oil prices things are looking very bright operationally for the company and full expansive exploration program not only in the Gulf of Mexico but onshore in the Granite Wash and Big Mac, there’s a lot of good things to come from our exploration aspects.

The question and answer session will go and get started with that. Because I know a lot of people have questions on certain aspects of our release in industry issue. So, operator, you want to go and open up the questions.

Question-and-Answer Session

Operator

(Operator instructions). Your first question comes from the line of David Heikkinen.

David Heikkinen – Tudor, Pickering, Holt & Co.

Just is that I think about the 90,000 barrel a day midpoint of your production guidance this year, can you talk about the things that would cause you to be above or below those levels and then as part of that can you detail regional production for the first quarter?

Jim Flores

Good morning, David. Some of the things on we look at 90,000 barrels a day mostly at point where all the production growth we have in the second quarter and third quarter is going to be outpacing, obviously, the first quarter. Some of the things here in the first quarter that are I call it seasonal from a standpoint, our inventory at Haynesville wells of non-completed Haynesville wells is doubled from 45 to almost 100. That’s a seasonal issue in the first quarter.

We saw it last year from weather related delays on flow lines of things like that the transfer rates in the first quarter up there and our operators just speak and everybody else drilling on our acreage has done its good job they can, but it built a backlog, at the same point in time some of the service companies try to ramp through some service cost increases that cause us to pause some of our completion activities.

So that’s 1500 barrels a day to 1800 barrels a day from what it could be if we stayed on the same clip as we’re in the third quarter and fourth quarter. I fully expect that to close later in the year so that’s kind of an extraordinary event that will change throughout the year depending on, obviously, weather, service costs and also gas prices, how aggressively go to complete all these wells, and how fast, how much CapEx we want to ramp up, up there. So that’s called flexibility.

And the other big flexibility is our Granite Wash production potential. We’ve landed our first two wells there. We haven’t completed in yet, but they drill like they’re supposed to, we actually contract the third rig, going to move into a Wheeler area, and how much capital we push into that area as well as Big Mac or some of the incremental things beyond what our plan is.

But right now from the standpoint of recompletions that Flatrock that we expect here this summer to bring Flatrock production back up significantly. Some of the things we’ve done at a Point Ped as far as water handling and so forth that production was pretty strong for the second half of the year, David. If you want to break down on a quarter by quarter basis, give us Hance a call she’ll give it to you, okay?

David Heikkinen – Tudor, Pickering, Holt & Co

Okay, thanks.

Jim Flores

Sure.

Operator

Your next question comes from the line of David Kistler.

David Kistler – Simmons & Company

Good morning, guys.

Scott Winters

Good morning, David.

David Kistler – Simmons & Company

Thinking about the flexibility of your budget, obviously with what’s going on in the Gulf, can you talk a little bit about how you might redirect things if say, approvals for wells that you’re looking to drill get delayed or anything like that?

Jim Flores

David, there’s been a lot of conversations about all of that. First all, let me say this. The Mineral Management Services working properly. We’re seeing leases Friday that we’ve been the lease sale, the processing things, I talk to every operator I know in the Gulf of Mexico from majors to independents. Everybody has their well permits approved. The Gulf of Mexico is functioning normally. Obviously, it’s a heightened sense of awareness on the engineering side and the execution side. Make sure everything is done beyond properly. Double check, triple check, and the whole industry is responding in good stead, not only to the current operations but trying to help our brothers BP out as much as we can with their issues out there.

So from a standpoint of us seeing any delays and activity or any change in business environment in the Gulf of Mexico we do not see any nor do we expect to see any static environment going forward. Obviously, they got to get the Maconda spill under control and then the cleanup the or will get cleaned up, one thing we’re good at, we know how to clean up things as an industry and the situation there is aspect of if we had some type of moratorium, and so forth. Drilling activity for 18 months what you would see is anywhere between a 15-25% decrease in our capital expenditures, you would see very little production impact if any. So most of our production is onshore and most of our growth here in the next 24 months is onshore.

With our first big offshore flows coming in Davy Jones in 2012, projected and then also Friesian and 13 and loses and 14. So we don’t see a real impact of PXP from an operating standpoint other than what you see as a reduction of CapEx and a delay in some other development drilling of those projects which we could obviously find some (inaudible) with the money and pay down some debt straight from our balance sheet. So we have a flexibility. Since we don’t have a lot of Gulf of Mexico production yet to redirect capital to near-term benefit if that is the case.

But I want to reiterate that we don’t see that as a case and we see our ability to double our oil production and double our gas production in the next four years a big component of that will be coming out of Gulf of Mexico and developing all the discoveries we have and we are going to maintain that business plan because we think (inaudible) oil and gas affordably and safely is going to be what PXP’s going to be known about. So that’s our game plan presently and that’s what we (inaudible).

David Kistler – Simmons & Company

Great. That’s helpful clarification. I appreciate it. Just thinking about Davy Jones for second or some of the deep shelf targets you’re going after are there any updates relative to the equipment that you guys need to secure to be able to complete those wells or any kind of updates on the specs of that equipment that you’re trying to secure?

Jim Flores

There’s updates coming on that, Dave, I think it’s a positive development. I don’t characterize that way. We’re going to save all our comments until we get all of our plan from the MMS but their approval process go forward. But we see our situation clear and being well within the fair way of the MMS guidelines toward completion now. I think what we will probably do is take a more conservative rout and make sure we have all the equipment designed and so forth, the specs and outlook for any waivers in the current environment.

So I think you’re looking at a completion summer of 2011, but that will be a completion in to flow line of sales. That’s kind of what the present plan is but as far as the details in the equipment our service industry time rates are really (inaudible) technical group that we put together that is all involved in the metallurgy and all the things require have done a yeoman work and there is some good news coming on that, but I want the specifics to wait, so I have to do them a message I had a chance to opine.

David Kistler – Simmons & Company

Okay and then one last question from me ,on the Texas Panhandle, it looks like your gross acreage went down a little bit in your latest presentation, can you just talk about what area that was part of?

Jim Flores

That must have been a minor lease expiration, that’s insignificant.

David Kistler – Simmons & Company

Okay, perfect. Thanks guys. Appreciate it.

Operator

Your next question comes from the line of Leo Mariani.

Leo Mariani – RBC Capital Markets

Hey, good morning, guys.

Jim Flores

Good morning.

Leo Mariani – RBC Capital Markets

Just a couple of questions on California. Obviously, your program here has kicked off. Just curious as to kind of trajectory of volumes, have you started to stabilize production out there as a result of the drilling or is there something that we should expect later in the year?

Jim Flores

Usually we expect later in the year and really we will see the effects of the drilling really in 2011. That’s why we don’t quote a much of growth rates and things of that nature. But the volumes come in 2010 and 2011 exit rate should be comparable with, say, that 2009 production volumes here in 2010 because we will be getting a uplift on the fourth quarter and when we start getting north of 2009, we will be in mid-year 2011.

So it’s a constant growth and we will see that repeatable because of the additional dollars we have put in this year and next year and so forth. If we stay on a three year to five year track of spending not only the maintenance CapEx of $75 million, the production maintenance CapEx with an additional $50 million to keep it flat, the other $75 million of expansion CapEx will start kicking in, so you will start seeing some growth out of that in late 2011 or 2012 I think it will be important to us.

Leo Mariani – RBC Capital Markets

Okay. Obviously, there’s been a lot of discussion going on in the press lately regarding your T-Ridge projects. I guess Schwarzenegger’s made some statements saying he’s against it and obviously in light of what happened in the Gulf of Mexico, just curious as to whether or not you guys can access those reserves from federal waters and if that may be a route to take if your project isn’t approved.

Jim Flores

Well let’s kind of put discussion in brackets from our standpoint. Three years ago when the State Lands Commission voted down our project, we divorced our company from T-Ridge and made a point of looking for other ways to grow oil production. That’s why our forays in the deepwater because one of the strategic goals of our company was to double our oil production outside of California.

At the Governor’s request, we continued to work on T-Ridge and with his political support and his confidence that he could get the California Legislature to approve it after the State Lands Commission turned it down, we played ball and went through that tortuous process last summer. And then after that failed, he very much wanted to keep it alive for the people of California for the revenues and go back through the State Lands process in conjunction with the seating of Lieutenant Governor.

I think with Maconda accident, obviously, the political way, capital is too severe out there for even Arnold. And it’s his strategy class, but let’s be clear here, it’s a political process, we’re not in-charge of it. It was his political agenda. It’s what the people of California wanted from his perspective and if they said, no, they said no.

So from our standpoint, it’s got no effect in any of our plans. It’s got no effect on any of our financials, any of our operations, and we’ve made sure that all the modeling that we’ve done, that makes sure no one has any expectation for it other than a pure option.

So from our standpoint, our platforms are out there. The reserves are still there. California still has got their financial issues, but as long as Maconda accident, it’s going to be heavy on people’s minds. I think that’s going to be a very, very high yield to apply. So what you’ll see us doing is unwinding all of our agreements out there and going about our business and being a good citizen of California.

Leo Mariani – RBC Capital Markets

Okay. I guess jumping over to Big Mac, just curious as to what the plan is. I guess you guys are drilling right now. Are you planning to just drill one well there and evaluate or is this a multi well project and just try to get a sense of potential prospect size on your first load?

Jim Flores

We have a lot of confidence on prospect size. We’ve got a lot of good science on it and we want to make sure our repeatability that gas prices are still $4 and the aspect of expanding our risk profile beyond some of the exploratory work we’re doing in the Gulf is not something we’re seeking. We’re looking for more developmental type projects onshore, something that will compete with repeatability, something like the Granite Wash, probably won’t be as stated and repeatable as Haynesville, but it’s going to have high returns with high corner sites.

So basically we drill a couple of drill holes and Big Mac will probably have much enthusiasm for it, but if we’re able to tie a seismic and get repeatable results based on the seismic imaging and drill bit and reserve ads, you can see us at several rigs there and really wrap it up. We look at that as a really nice production out of the next couple of years. It’s all going to be drilled bit driven on success.

Leo Mariani – RBC Capital Markets

Okay. Just on Blueberry Hill. Sounds like I guess that’s re-drilling. Are you going to get over there and just try to get a sense of kind of where that well is at and what the potential time line is hit TD on?

Jim Flores

Blueberry Hill is kind of frustrating because we got a large acre spread there. We have got several follow-on prospects that we’re trying to delineate and understand what’s going on with the seismic. So we’re going to give it one more try to sidetrack it up to the southwest and really look at some of the deeper sands that we’ve not seen in any of the previous sidetracks.

We’ll keep trying to get down to the meat of the prospect and we have not gotten down there yet and we feel like this is the opportunity for us to do it and obviously, if this doesn’t work, then obviously we will be finished with it, but we have not seen the bigger sands and the prospect yet and we keep getting encouraging results, but not the ones that our geology. So as the drill bit continues to re-map our geology out there, we’re responding with sidetracking one more time.

Leo Mariani – RBC Capital Markets

Alright. Thanks guys.

Operator

Your next question comes from the line of Brian Corales.

Brian Corales – Howard Weil

Hey, guys. Just a question on Flatrock. I know McMoRan talked about some of the issues there. Can you just talk about how your production was affected and when the timing of those recompletions?

Jim Flores

Yes Brian. We’ve said all along that we’ve used the $200 million a day to $240 million a day type model that the productions are going to come on and off and certain zones are bigger than others and you’re going to have 400 meter a day wells, you are going to have mechanical issues. So it fits our production model. I mean we don’t play on the highs, we don’t play on the lows from that standpoint.

And the production models from recompletion is coming on this summer. They are going to boost production and we are going to see some well work over some areas that mechanical that need to have some maintenance, that we’re going to see stronger production at Flatrock the rest of the year. So that’s probably the best way I want to quantify, there’s too many variables unknowns with Chevron operating and rigs and timing alone what the exact operations might be.

Brian Corales – Howard Weil

Okay and just on Friesian. Have you all firmed up any development plans there or is it still kind in the works?

Jim Flores

It’s still very much in the works and we have to have some of the announcements this summer.

Brian Corales – Howard Weil

Okay, guys, thanks.

Operator

(Operator instructions). Your next question comes from the line of Jeff Robertson.

Jeff Robertson – Barclays Capital

Thanks, Jim. In the Gulf of Mexico, if business goes along as usual, would any of the prospects on the Blocks that you all picked up in the lease sale be moved into the 2010 drilling program or are those more 2011 or 2012?

Jim Flores

No Jeff. It’s going to be a bit more 2011 or 2012. We kind of looking at our exploratory additive parts. We will probably drill one of the subsalt Eocene prospects with McMoran, like a John Paul Jones or something like that each year, for the next three or four years. We have, let’s call it between four and six of those prospects on lease at this point in time. Davy Jones follow ups.

On the Lucius/Fobus thing we don’t drill Fobus this year, I think Anadarko still looking for a rig there. And then what we hope to do is have one of those follow-ups. We think we have two or three really good prospects which will get drilled over the next two year or three year period as Lucius/Fobus follow ups and then obviously Blackbeard East works then we will be doing the same thing in the Miocene subsalt trend there. So all three areas, I would see one prospect each success over the next three years or four years, based on continued success.

Jeff Robertson – Barclays Capital

And secondly, Jim, at Davy Jones, is the plan that you all are considering now, you sounded like to test it to its own facility. So will that allow you to bring the Davy Jones to well in 2011 as well?

Jim Flores

Just to clarify, we probably bring an end to existing facilities like our Tiger Shoals facility where Flatrock goes into. We have a 150 meter a day of excess capacity there. So it’d be a combination of, remember, we’re in 20 feet of water. So it’s nothing to bring gas around it, there are large facilities in that shoal, north end of the Gulf of Mexico right below Henry Hub. We would stay consistent with the completion operations and completing the number one well, then number two well right behind it if it was indeed successful.

Jeff Robertson – Barclays Capital

Okay, thank you.

Jim Flores

Yes.

Operator

Your next question comes from the line of Diane Grover [ph].

Duane Grubert – Susquehanna

I think Duane Grover from Susquehanna actually.

Jim Flores

I like Diane better.

Duane Grubert – Susquehanna

Well, she is not here to-date, you have to talk to me.

Jim Flores

Obviously, you hadn’t cut your hair.

Duane Grubert – Susquehanna

Hey, on the Granite Wash, some of that acreage or maybe all of it is residual from the Pogo acquisition. I’m wondering if you could comment on are there consolidation opportunities out there that you might pursue or is your position large enough where you want to get your hand along completions and stuff before you get too excited about it? And secondly are you doing completions along the lines of what Forest Oil is reported out there with in terms of horizontal with multi-stages or what are you guys doing at first?

Jim Flores

Well, a couple of things. It’s not residual from Pogo. It’s one of the cornerstones of the Pogo acquisition from there, but what we decided to do at the Granite Wash a year or two ago was not expand our acres let out by drill to us and de-risk our acreage. And that’s been successful with Forest new field patch, all of them drilling good wells at Chesapeake and everything.

And then as our capital recovered with higher prices like this year, we felt like the gas market had at least another year to heal and may grow close to recovery, we will start drilling and this really fit our plans perfectly. So from that standpoint, if we have success and we have ability to ramp up activity there, it would be a growth area for us with balance corner saving gas yields.

So from that standpoint it’s got pretty good economics. Not the best economics like right now we’re selling gas on a companywide basis, if you take all of our product in an Mcfe basis about 780 right now. So even the Granite Wash is not accretive to that model to what we have on our base production, but it does fit a nice slice of production growth moving forward.

As far as the completions, yes, they are going to be (inaudible) with the forest ten stage fraction horizontals and so forth. And we have got our initial drilling costs and initial drilling costs are fitting right in with everybody else’s since we have interest in several other wells out there.

As far as expansions, Dwayne, standpoint, we have all the acreage and opportunities we need for three years. Based on all the drilling and development we have. The Granite Wash, if we drill a 150 wells or 200 wells we have on all of our locations in the next three years or four years that’s going to be a fantastic position for PXP. We have to drill 30 wells or 40 wells and Big Mac behind that. That’s going to be a super position.

All of that is going to be behind the economics of the Davy Jones that we bring on multi Tcfs of gas and the Eocene subsalt trend. So we’re not looking to expand any of our place that we think will be behind the mega place that we have coming out of the Gulf of Mexico and the gas site.

On the oil site standpoint with Lucius and Friesian and so forth coming on, it’s very difficult for us to find projects compete with the economics of those, since we’re in the process of getting those fully developed and sanctioned and towards the tank. So from our standpoint, the plan is to stay within our operations and executing on bringing the reserves that we’ve established board. We’re not interested in expanding our growth opportunities at this point in time.

Duane Grubert – Susquehanna

Alright. That’s a super answer and one of the points you bring out is that the oil business is better than the gas business and the oil business is better than the wet gas business. In light of that, can you comment a little bit about how much could you ramp up in California? The words in your press release seemed very carefully chosen, talking about maintaining production on the diatomite program. And then if you could throw in a comment or two about where the Haynesville economics are stacking up versus your other projects, that would be great too?

Jim Flores

Well it’s California. The reason why we’re being cautious there from a standpoint, we’re going to let the production do the talking. There’s some variables at standpoint and we’re going to some new steam areas, we’re expanding, we think we have a lot of great things we’re doing there, but we want to make sure that before we start projecting some huge numbers from a standpoint, but we’re expanding and doing our diatomite new project, our 19-Z project is a new project out there that’s going to have a big contribution and then we’re going to have our Arroyo Grande projects funded.

All these projects were formerly puds that are now getting a lot of capital. So let’s wait 12 months to 18 months to figure out what our program looks like out there and I think there will be a lot of surprises.

When you talk about different economics and so forth, we’re in the free falling barrels in Mcf. We look at our California oil business as maintaining it. We look at California oil business as something we take that free cash flow and do good things with it, like grow a gas business when gas prices are low. So it’ll be valuable at some point in time when gas prices rebound or make some significant oil finds in the Gulf of Mexico with a lot of money to us and with a lot of money in the market place.

And so from our standpoint, when we look at our ability to redeploy the California capital as really to benefit, we don’t know if oil is going to be 80 or 110 next year. That’s a significant swing and that all option out there. We have the oil producer. We’re not swinging to be an oil company. We’re an oil company right now producing what the commodity price exposure over the next two years. PXP is the right spot to be, with a lot of oil coming on.

Respective to the Haynesville and the economics there, the economics are suffering from the standpoint with $7.5 million wells and for $394 gas and the light on the liquids is a tough place to do a pro-well economic analysis to feel very good about. What says the Haynesville is every well we’re drilling and each one of those units is really fine at 60 Bcf of gas. You’re going to spend $7.5 million to find 60 Bcf a gas and that’s going to take some more capital to get it out of the ground and drill the other locations and so forth. So for that and versus what lease costs up there, we’re right about break even.

Our goal is to have more than 750 to 800 unitize by the end of 2011. Right now we’re running almost on a 950 clip, 950 units being unitized and that’s because we’re running with almost 50 rigs out there, Chesapeake being in the mid-30s and our other operators being around 18 to 20. So with the amount of activity we’re getting on our Haynesville acreage, we’re going to accomplish all of our goals of having a fantastic gas asset there. I think at a time when gas is going to matter in 2012 and it also correlates with our plans at Davy Jones as well.

So we’re big on taking our California oil revenues and redirection and kind of cyclical on the gas business here, the businesses that we have, and try to maintain our returns where we’re today based on whatever the oil price is going to be. At the same point in time have a lot of production growth coming forward in the future as of 2012 on the gas site or as soon as possible on the oil side since oil prices are strong.

Duane Grubert – Susquehanna

Very good and then one final question about California markets, at least one of your competitors has floated the idea that both with the oxy discovery in Kern County, there would be local gas that could benefit your steam player as well as the ability to bring in LNG into the California market. Have you looked at bringing in straight board of LNG as a way to hedge your gas use in California at all?

Jim Flores

I have no idea where LNG would come in to California because every project has been shut down.

Duane Grubert – Susquehanna

The Baja stuff.

Jim Flores

Oh! That’s Mexico. Right, but Mexico is short of gas too, so, right now we’re exporting gas from Texas to Mexico, so I don’t understand how that works, but needless to say, more gas out there when you’ve got $394 gas and $85 oil, there is no finer place in the world than Bakersfield, California for producing oil.

Duane Grubert – Susquehanna

Very good. Thank you.

Operator

Your next question comes from the line Ann Hammeren [ph]

Ann Hammeren

Yes, good morning. Have you guys said which washes you’re targeting with your first Granite Wash wells?.

Jim Flores

We’re targeting different ones. We’ve got the number one and three, we’re looking at right now. We’ve got one, two and three on our acreage, plus the two at Telco [ph] washes, the lithology changes when you go from Wheeler to Marvin Lake and part of what we’re looking at when you talked about 20,000 acres up there, that’s not that much acreage, but you got 200,000 acres to 300,000 acres, but if you take that times four zones or five zones, divided by 80 acres, it’s a lot of drilling and it’s a big project. Since we have so much vertical well controlled we actually producing most of the acres haulage with vertical wells, that we have a lot of engineering already behind us as far as recoveries and reserve potential and so forth. We just want to see if the deliverabilities of these wells in which zones warrant the horizontal developmental and right now it looks encouraging.

Ann Hammeren

Okay, great thanks. I know you guys addressed this somewhat already, but the seam at your end was scaling down your exploration budget from ‘09 to ‘10, and I guess that was before the Davy Jones discovery. So you’ve outlined a little bit what wells you plan on drilling this year and maybe next year, but thinking longer-term, what chunk of your budget should we be thinking about it as being directed towards both deepwater and maybe the ultra-deep shell.

Jim Flores

Well, at Shoal projects development we still call it exploration, so we’ve got kind of a low mixture of color there because we look at Davy Jones too as an exploration well, okay, and our exploration group because we have sanctioned the project from the standpoint. We look at the second well at Lucius as more of an exploration project or exploitation more confirmation. So from a standpoint of just pure exploration, we’re going to try to keep it somewhere between $100 million and $150 million a year going forward. And those will be like the three projects I talked about, one in the Pliocene trend around Lucius, Pogo’s additional, the one in the subsalt Miocene trend, Blackbeard and one of the subsalt Eocene trend and then plus some stuff we will do onshore.

Ann Hammeren

Okay, great. Thank you.

Operator

Your last question comes from the line of David Tameron

David Tameron – Wells Fargo

Yes, good morning. Just a couple of questions. California environment emanate in general, obviously, everybody has gone to the Bakken, gone to the Permian, big boys dominate a lot of the acreage out there, but have you seen an increased activity level of people who poke around in California?

Jim Flores

Well, see, there’s us, Oxy, Venoco. I haven’t talked to Steve or Tim lately, so I have no idea. No other California M&A. California copies from that standpoint. We’re certainly not hearing it.

David Tameron – Wells Fargo

Okay, you run into different players in the field that I guess what I’m asking, are there new people trying to get into California?

Jim Flores

Your really can’t because I mean Oxy controls it right, they control that and they control the Permian, so it’s kind of whatever they decide they want to do as probably the better place to ask that question because there’s nobody else besides us and Venoco.

David Tameron – Wells Fargo

Alright, fair enough. Thanks.

Jim Flores

Okay, thank you.

Operator

At this time there are no further questions.

Jim Flores

Great operator, thank you very much. We will see you guys in the second quarter with some more updates. Thanks for listening.

Operator

This concludes today conference call. You may now disconnect.

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