Plains Exploration & Production's CEO Discusses Q1 2011 Results - Earnings Call Transcript

| About: Plains Exploration (PXP)

Plains Exploration & Production (NYSE:PXP)

Q1 2011 Earnings Call

May 05, 2011 9:00 am ET

Executives

Scott Winters -

James Flores - Chairman, Chief Executive Officer and President

Winston Talbert - Chief Financial Officer and Executive Vice President

Analysts

Philip McPherson - Global Hunter Securities, LLC

Jeffrey Robertson - Barclays Capital

Brian Singer - Goldman Sachs Group Inc.

David Kistler - Simmons & Company International

Leo Mariani - RBC Capital Markets, LLC

Anne Cameron - JP Morgan

David Heikkinen - Tudor, Pickering, Holt

Brian Corales - Howard Weil Incorporated

Nicholas P. Pope

Duane Grubert - Susquehanna Financial Group, LLLP

Gary Stromberg - Barclays Capital

Unknown Analyst -

Operator

Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to PXP's 2011 First Quarter Earnings Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Scott Winters, Vice President of Corporate Communications. Please go ahead, sir.

Scott Winters

Tiffany, thank you. Good morning, everybody, and welcome to our conference call. Earlier this morning, we issued our earnings release and filed our 10-Q. Our conference call today is being broadcast live on the Internet, and anyone may listen to the call by accessing our company website at pxp.com. We've posted a slide presentation to supplement our comments this morning, and we may refer to these slides during the call. The webcast, slides, 10-Q and today's press release are available on our website in the Investor Information section.

Before we begin today's comments, I'd like to remind everybody that during this call, there will be forward-looking statements as defined by the SEC. These statements are based on 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, slide presentation and our prepared comments this morning, we present non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release.

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

For the first quarter of 2011, PXP reported net income of $71 million or $0.49 per diluted share, compared to net income of $58.5 million or $0.41 per diluted share for the first quarter of 2010. Net income includes the impact of realized and unrealized gains and losses on our mark-to-market derivative contracts and unrealized gain on investment and other items, which affect the comparability of operating results.

When considering these items, PXP reported net income of $52.4 million or $0.37 per diluted share compared to net income of $43.5 million or $0.31 per diluted share for the same period in 2010.

First quarter income from operations was $133.8 million and net cash provided by operating activities was $290 million, representing a 13% and a 31% increase over first quarter 2010, respectively.

2011 first quarter daily sales volumes averaged approximately 88,000 barrels of oil per day, that is a 3% increase over first quarter 2010 average daily sales volume, despite shut-in volumes from planned facility upgrades, weather interruptions and the sale of all of our Gulf of Mexico production in the fourth quarter of 2010.

Pro forma for the asset sale, 2011 first quarter sales volumes increased 19%. With the downtime associated with the California offshore, Platform Irene completed in the January and February, harsh winter weather gone, March daily sales volumes averaged approximately 93,600 barrels of oil equivalent per day.

We reiterate our full year 2011 average daily sales volume range of 95,000 to 100,000 barrels of oil equivalent. For the first quarter of 2011, oil and gas revenues increased 12% compared to first quarter of 2010. Oil revenues increased approximately $56 million due to higher average realized oil prices benefited by California crude postings, which remain strong relative to NYMEX. Gas revenues decreased approximately $11 million reflecting lower average realized gas prices, partially offset by higher sales volumes.

Total production costs were $15.41 per BOE for the first quarter of 2011 compared to $14.37 per BOE in the first quarter of 2010. Lower steam gas costs and electricity per BOE were offset by higher lease operating, production and ad valorem taxes and gathering and transportation costs per BOE.

A quick review of the component with total production costs for the first quarter of 2011 compared to the first quarter of 2010 is as follows: Steam gas costs decreased approximately $4 million primarily reflecting the lower cost of gas used in steam generation, partially offset by higher volumes.

In 2011, we've earned approximately 4.1 Bcf of natural gas at a cost of approximately $3.88 per MMBtu compared to 3.7 Bcf at a cost of approximately $5.35 per MMBtu in 2010. Lease operating expenses increased approximately $10 million, reflecting scheduled repair and maintenance expenditures, primarily at our California property, and an increased number of producing well at our Eagle Ford Shale and Panhandle property.

Production and ad valorem taxes increased $3 million in 2011, reflecting higher ad valorem taxes due to an increase in the number of wells drilled at our Haynesville Shale property, and higher production taxes resulting from increased production, primarily from our Panhandle property.

Gathering and transportation expenses increased approximately $3 million, primarily reflecting an increase in production from our Haynesville Shale properties.

General and administrative expenses per BOE were approximately 7% lower than the first quarter of 2010 on higher volumes and lower costs. The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are mark-to-market each quarter with a fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement.

Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. We recognized a $51 million loss in mark-to-market derivative contracts in the first quarter of 2011, which is primarily associated with a decrease in the fair value of our 2011 and 2012 crude oil puts and our 2011 crude oil colors due to higher crude oil prices.

In the first quarter of 2010, we recognized a $7.9 million gain related to the mark-to-market derivative contracts. There have been no changes in our open derivative positions since our last quarterly report. And a summary of PXP's derivative positions is included with the financial tables in the press release.

At March 31, 2011, PXP owns 51 million shares of McMoRan common stock. We've elected to measure our equity investment at McMoRan at fair value. As a result, unrealized gains and losses on investment will be reported quarterly on our consolidated statement of income, which could result in volatility in our earnings.

In the first quarter of 2011, PXP reported a $67.3 million gain on investment. A complete discussion can be found in the 10-Q.

Operationally, PXP began 2011 well positioned to continue growing production and reserves with contribution from multiple asset areas, which include mature properties with long-lived reserves and significant development opportunity, as well as newer properties with development and exploration potential. We believe our portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside, as we develop our attractive resource opportunity including our California, Eagle Ford Shale, Granite Wash and Haynesville Shale resource plays.

Our drilling program remains active, and here's a quick update: In the Eagle Ford Shale, PXP has 5 drilling rigs operating; first quarter daily sales volumes averaged approximately 2,240 barrels of oil equivalent per day net to PXP; and we're in excess of 3,000 BOEs per day net to PXP at the end of the quarter.

The 2011 planned 3 net rig program sales volume exit rate is expected to be above 5,000 BOE per day net at year-end 2011. However, if the current 6 net rig program continues, PXP expects to exit the year above 10,000 BOE net per day.

In California, PXP has 4 drilling rigs operating onshore where the company continues its active development program in the Los Angeles and San Joaquin basins. Daily sales volumes onshore were just over 31,310 BOEs per day net to PXP, which is flat compared to the fourth quarter of 2010. Offshore volumes are back to pre-Platform Irene maintenance levels of approximately 9,000 BOEs per day net to PXP.

Average daily sales volumes are expected to be above 41,000 BOE net per day by the end of 2011. In the Texas Panhandle, PXP has 5 rigs drilling operating in the Granite Wash trend and expects to continue this level of activity through 2011. First quarter daily sales volume averaged approximately 8,940 barrels of oil equivalent per day net to PXP or 12% higher than the fourth quarter of 2010. Average daily sales volumes are expected to increase to approximately 17,000 barrels of oil equivalent net per day by year-end 2011.

In the Haynesville Shale, PXP's primary operator is currently operating 33 rigs and expects to reduce the rig count to an average of 25 rigs in 2011. Plus PXP expects 15 or more rigs by other operators on its acreage.

First quarter daily sales volumes averaged approximately 162 million cubic feet equivalent per day net to PXP, or 11% higher than the fourth quarter of 2010. The rate of increase in the sales volumes is anticipated to slow as the rig count decreases.

Average daily sales volumes are expected to be above 170 million cubic feet equivalent net per day at year-end 2011.

In the other asset areas, including the Madden Field in Wyoming and other Texas assets, average daily sales volumes are expected to be above 11,000 barrels of oil equivalent net per day by year-end 2011. Operationally, our 2011 growth objectives are on track, drilling results in each of our project areas have been strong and we look forward to a very active rest of this year.

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

James Flores

Thank you, Scott, and good morning, everyone. It's been a great quarter kicking off 2011 for PXP. We're obviously deep into the second quarter as well and continue to see good visibility on the assets toward production growth and well type curves and things of that nature that give us a lot of confidence for the rest of year.

We are not immune to the inflationary costs on the service side that's going on in our industry with the higher oil prices and the demand for rigs in the oil proved areas, where we're active, just like the Eagle Ford and Granite Wash and to a lesser extent, California. But there's still a lot of activity in all of those places, and with our continued that activity in the Haynesville, where we won all the units to be HBP. We're very active driller at this point in time.

But the backdrop of PXP is around -- our oil business is showing how powerful it is behind the recent price rise. And with our oil revenues growing now and expanding our margins, we're looking at 10-plus percent production growth on an annualized basis, but on a pro forma basis, you take out the Gulf of Mexico sales in the first quarter grew over 16%, so you could see some of the good work that we've done there.

And being financed by oil, our margins are continuing to expand. So we have a good offset for the inflation that I think everybody see in the oil patch, because as our revenues are growing a lot faster than inflation, obviously we're turning more to the bottom line.

So we're very positive with that right now because of the leverage we have in the business. And the way we're seeing our assets perform, we're going to be able to go through those, like, obviously your 2 questions. I'll tap a few things like our deepwater assets. Our present plans there are to put those in a subsidiary so we can get those financed. And by financed, be in -- come to the market either in a private placement or a public density, hopefully, sometime this summer depending on operational timing issues and filing issues. So we can, in the summer, this fall, pull a big window on it.

To get that financed so that deepwater business will be a separate entity that's funded beyond our onshore business, which will be dominating PXP going forward.

So with that, I'm going to open it up to questions and get everybody’s answers going this morning. So operator?

Question-and-Answer Session

Operator

[Operator Instructions] Your first question is from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Hey, Jim, in the slide presentation, you highlight a higher CapEx case in the event that oil prices stay high. Can you talk about the $1.5 billion potential plan? How much of that delta is related to increased activity versus cost inflation or other? And if it's the increased activity of suspect there might be in the Eagle Ford? What that translates to in terms of production impact?

James Flores

Well, we have the pie chart that's associated with that $1.5 billion scenario. That's $100 plus all-year long scenario of oil. And because our original budget, Brian, as you know, was done at $85, and every $6.50 increase in price oil needs an extra $100 million above our $85 oil price. The aspect of a scenario of having $100 average oil is realistic at this point in time, it's not concrete. We could easily see oil prices $100-plus. We can easily see oil prices $80. So we're not committing to any kind of increase, but we want to give everybody an opportunity to see what would happen if we continued spending at this rate, because we picked up so many rigs in the Eagle Ford early this year. I think we also articulated in the press release if we continued running as many rigs as we're running in the Eagle Ford this year, that we would be at higher production rates than what we had talked before with the 5,000 barrel a day exit target. And now we probably double that amount if we ran the entire 5 rigs. And back to your question where the capital goes, that's the lion's share of the money. There's still -- there's some additional money there if we drill a little bit more in the Haynesville because our operator, Chesapeake, is a little late bringing the rigs out in the second half of the year. It just -- it takes a rig down the fourth quarter, and there's some inflation in there. And we're somewhere between 8% and 10% on our inflation figure because it's hard to control as far as -- when you execute a plan like this. So between those 3 areas, that's kind of the spread and you see that spread across that pie chart in a percentage basis where the lion's share is going to the Eagle Ford.

Brian Singer - Goldman Sachs Group Inc.

And then in the Granite Wash, with the production having risen a decent amount here this last quarter versus the fourth quarter. Can you just talk a little bit more of granular about the well results that you're seeing, the consistency of those results and if you have a view on the number of wells per section in your key areas there.

James Flores

Yes. And Brian, it's a great question. Let me bring up one more thing about your earlier question was -- remember as we accelerate CapEx in the second half of the year, when we get past part of the middle of third quarter, all of that spending really nears to 2012 production. So we'll try to be more refining about our production guidance in the second half of the year if we end up at $100 a barrel a day case, but it's really going to be point toward increase in 2012 when you really account it on a fiscal basis. But onto the the Granite Wash standpoint, we have been very vocal about the Granite Wash being more of a conventional play than a shale play. It's got great resource economics, but it takes geology, it takes processes, it takes probability. You got tight sands, those are not shales, and so you've got an area with a lot of vertical wells. And we've been methodically kicking [ph] our way through the 7 Granite Wash zones as well as the 5 Atoka zones that we have in our 2 different fields, Marvin Lake and Wheeler. Let me give you a kind of a top-level view, Marvin Lake has surprised our guys more to the upside. Wheeler was more known so we had that model pretty correct, but we had Marvin Lake more conservative. If there's an area where we're adding potential, it's Marvin Lake. Wheeler is doing about what we thought. But when you get to a geographic wells per section, or those type of things, we don't think that's the right way to think about the Granite Wash. It's actually defined locations per reservoir and a very price-sensitive. We think out of the 7 Granite Wash reservoirs at today's prices, probably 4 to 5 of those are probably economic and 2 or 3 of the 5 Atoka zones are probably economic. Higher gas prices, a lot more Atoka zones, well, it will help the Granite Wash. Lower oil and gas prices would affect that because -- and so we've got -- we like our inventory of 150 locations right now. We think that's building a lot of integrity at what we think is a pretty low gas price. And as we drove more wells and get more information toward the end of the year, identify all different reservoirs and have a look at it, we may adjust it at that point in time, but we're pat where we are.

Brian Singer - Goldman Sachs Group Inc.

Great. If I could add -- ask one at the back of that. How was the ramp-up that you expect to get to the 17,000 barrels a day in the Granite Wash by the end of year versus the 9,000 or so in the first quarter? What percent roughly do you expect it to be liquids versus natural gas?

James Flores

Well, what we're running out there, and I don't expect this changing much, is 1/3 methane, a 1/3 NGLs and a 1/3 condensate.

Operator

Your next question is from the line Dave Kistler of Simmons & Co.

David Kistler - Simmons & Company International

Looking at your Haynesville production guidance, it looks like it's up about $10 million from the last quarter; for year end, about $170 million a day versus $160 million. What's the primarily driver of that?

James Flores

It's really our forecasting and on the completion schedule that Chesapeake has been pretty consistent. The big driver of that -- we're seeing a lot more non-Chesapeake operated activity in the Haynesville. A little befuddling. But I think a $0.50 rise in gas price will get these, I mean, rigs out there from all the non-Chesapeake operators. We were absorbing about 10 to 15, maybe 20 on a good day operated by other rigs. We have a small interest, 2% to 4%. But we've talked numbers in the last month as high as 30 rigs operating, that we're not operated by Chesapeake. And then add that to the 34 to 36 rigs that Chesapeake operated. There's a lot of rigs running in the Haynesville right now. So that pushed that number a little bit.

David Kistler - Simmons & Company International

Okay. So it's more non-op stuff and efficiency gains that you guys are seeing on drilling or anything like that?

James Flores

From a forecasting point. But we're seeing a plenty of efficiency gains on drilling because we're going to be doing some pad drilling later in the year that I think is going to be pretty interesting on the cost side. Just to identify the cost structure of that going forward, not from a standpoint of anything strategic. And then as we downsize the operations, it's going to get more efficient when they move the rigs out here later this year according to Chesapeake.

David Kistler - Simmons & Company International

Okay. And just one more on the Haynesville. Where are we these days on kind of drilled and uncompleted wells? Has Chesapeake shared that with you?

James Flores

Yes, we track it daily. We're still in the 160 wells number and still over 500 as an industry.

David Kistler - Simmons & Company International

Okay. Great. I appreciate that. And then one more in the Eagle Ford, it looks like your completion backlog crept up a little bit. Can you talk about that? Is that just from the pure drilling activity? Or are we having issues getting services completion?

James Flores

No. We're well modeled for slack and service and stuff. And one of the areas that will continue to impress or improve is that we're not going to make any kind of scheduled promises and that type of thing that we don't think we can deliver with a little room. So we're seeing a lot of efficiencies in getting frac crews and time and fitting our schedule and so forth. The biggest thing in the Granite Wash, our first production started at June of last year and started ramping the rigs up last year. So we're really hitting some good efficiency schedules there. And just -- so we're getting more rigs finished and then try to shop cost as much as anything at this point in time. In the Eagle Ford, it's going to be a little lumpier because we're just getting the rigs up a to drilling status and then we're doing a pad drilling, so you'll see the inventory in the Eagle Ford grow even more because the number one well in that pad will be not completed until we get the frac crew out there complete the #2, 3 and 4 for that thing. So and you'll see the inventory be cut in half in a month easily because of completing on a pad basis, until we get that up and running something smooth and statistical. That's going to be a little lumpy.

David Kistler - Simmons & Company International

Great. And last one, just looking at these kind of higher oil prices we've been experiencing recently and thinking about your sales agreements in California, when do you guys go through the process of renegotiating the differentials? And can you give us some thoughts on maybe where that could go?

James Flores

We were about -- 30% of our productions have posted, so we get more vested at 100%, but Buena Vista posted 105% of our NYMEX. That effected us greatly. You're referring to the 50% of our production contract we have with ConocoPhillips. The scheduled date for completion is late in the fourth quarter, or January 1, effective date. So those negotiations -- I'm sure, we've been going on for months and we'll continue for a while until we get some resolution that everybody is happy with. If we don't get to resolution, there's baseball arbitration and we go from there. But the market is very much tilted to where Conoco's in favor, so the historical aspects of it. And it should be a situation where it'd be a center for improvement to PXP going forward.

Operator

Your next question is from the line Leo Mariani of RBC.

Leo Mariani - RBC Capital Markets, LLC

A couple of quick questions here for you. Just trying to get a sense of sort of the higher rig count you experienced in the Eagle Ford. You talked about fixed rate, the plan is 3. Is that all EOG JV rigs? It's going to be higher than expected? Or have you guys had planned to actually add operating rig?

James Flores

No, we've got 5 operating rigs at that time, Leo, which is a lot more than we planned. What happened was when a lot of gas rigs came out of the Haynesville, we went ahead and grabbed them. We didn't know what the market conditions are going to be. We actually grabbed them if oil -- because oil prices were strong in the first quarter, then our plan -- and that's if oil prices stay strong, we told everybody where our extra capital go will be in Eagle Ford. And so we took the aggressive stance, grab the rigs, and we're just -- we're going to to decide later in the year depending on oil prices how many rigs will run. So that's an opportunistic. Now what's been great about it is our operational group could be able to grab 5 rigs, the production group catched with them from the standpoint of getting pads and locations and everything else is done. So we've basically jumpstarted our activity in Eagle Ford by 100% increase already. And the question is, how long do we keep that increased activity in place? And that's going to be determined of oil prices and our budget at this point in time. So I hope that gives you a kind of clear look at it. But EOG, to their standpoint, I think we have 2 rigs operating with them, which is considered one net rig out of the 6. So it will be 5 operating.

Leo Mariani - RBC Capital Markets, LLC

Got you. And just trying to get a sense of how many wells you guys have operated and turned to production and sort of how those have performed versus your expectations?

James Flores

Well, they performed right on our type curve. The last wells have been above our type curve. The initial wells we took over the previous offer have been below our type curve. So as an average, we're right on top of our type curve, but as the more well history we get out of our more recent wells. The ones that we drilled and completed, I think, you'll see that number going up. If we can see a determining factor as far as well performance, it's really the length of lateral. An extra 1,000 for the lateral really helps the productivity of the well and so forth. So we're still -- we've been adding about 100 days, 105 days or whatever in the Eagle Ford, and we're still going to be figuring that out. But it's good to see when a physical -- just a physical nature of drilling an extra 1,000 feet of lateral can make up nice 15%, 20% difference on what your well performance is, you got the right reservoir.

Leo Mariani - RBC Capital Markets, LLC

Got you. Okay. Any update on where you guys are in the Monterey? Have you drilled a well or two yet? Saw some comments in your prepared, I guess, press release in March that you are working on the Mowry, you've added some acreage there. I just wanted to get any color around the Monterey and your plant?

James Flores

Okay. On the Monterey, our plans are to do some testing and some vertical wells this fall, third and fourth quarter. We have not done a rig work at this point in time. Simply been geoscience work and geochemical and petrophysical work. The outcome of that could generate some horizontal drilling next year, so it's in the till. And when we say Monterey, Monterey is part of the Miocene Shale section out there. The Miocene Shale sec has the Antelope Shale, has the nodular shale and so forth. And when you jump to different basins, they're going to have different names and so forth. We've got Monterey production offshore and so forth. So we're going to be kind of playing more toward the Miocene Shale opportunities in California versus strictly Monterey and kind of go on from that standpoint. But for I guess, for your purposes, probably interchangeable. Onto the Mowry, yes, we took an opportunity to add some acreage up there after drilling the first well. The first well seemed to drill like a typical shale well. It's got kind of Eagle Ford-type characteristics. We haven't frac-ed it yet. We haven't produced any well -- any oil up there yet. And we're presently drilling the second well, and we expect to have some frac crews out there over the summer and see if we can get any production and see what we have up there. But those two projects, the Mowry and the Monterrey, would be projects that would fill in late 2012 and '13 and expand on top of our base business of the Eagle Ford, Granite Wash, Haynesville in California. So in our business plan that we have presented in our slides, it has no addition of Mowry or Monterey production reserves or expenses at this point in time.

Operator

Your next question is from the line Brian Corales of Howard Weil.

Brian Corales - Howard Weil Incorporated

The Gulf of Mexico, can you all talk about maybe -- I know it's a little bit of a guess, but timeframe on what's going to happen with Lucius?

[Technical Difficulty]

Operator

Your next question is from the line David Hakkinen of Tudor.

David Heikkinen - Tudor, Pickering, Holt

Just thinking about what your activity levels are in each area? Can you give us an update of current complete well costs for Haynesville, Eagle Ford and then expectations for Granite Wash and Mowry as well?

James Flores

Dave, we can go through that aspect but it's basically what Chesapeake's reported. From a standpoint of the latest wells are above 8 3 rather $8.3 million in the Haynesville. And the non-Chesapeake wells are above that, by about $1 million or so. The pad drilling is probably $1 million less on both those wells. We get down the low $7 million and low $8 million. The Granite Wash is anywhere between $9 million and $9.5 million on those wells. You're talking about -- sometimes in some of those wells, it's in the $8 million, from a standpoint kind of bouncing around. But on average, I'd call it $9 million. And in the Eagle Ford, we're talking about somewhere between around $8 million, $8.5 million on those wells right now. And we're putting a lot of facilities and everything else. And we think over time, when we drill the additional wells and so forth, we'd be cutting a lot of the costs in the standpoint. So when you look at our slides, that the average well costs and so forth, you're talking about -- with pad drilling and initial drilling combined.

David Heikkinen - Tudor, Pickering, Holt

Okay. And then just thinking about your capital budget that ranges between $1.2 billion and $1.5 billion and kind of activity levels ramping in each area. Can you talk about ability to mute service cost inflation in the back half of the year? Or should we think that 8% to 10% cost inflation that's in the budget, could it be biased a little higher?

James Flores

I don't think it can be biased a little higher. I think it captures the year. I think from a forecasting perspective, mute is the right word, but I think it captures all the costs. I mean, as the rig count is going up, services, supplies aspect going up. If prices go lower, then the rig count will fall and services will fall.

David Heikkinen - Tudor, Pickering, Holt

Unless it's gas.

James Flores

What's that?

David Heikkinen - Tudor, Pickering, Holt

Unless it's gas drilling for some.

James Flores

We're an oil business. So gas drilling, we obviously do not understand. But so the aspect of that is we're going to manage inflation by processes, by -- trying to get the best out of our equipment, zipper fracs, these types of things, more or less days up here and just try to manage overall cost. The offset though, what it makes really unique, I'm not saying that we're not cost vigilant, is that our operating margin continues to expand even in this environment. We're not gas driven from a production standpoint, we're oil driven, so if oil prices are going to drive service cost inflation, we're well hedged in our 3:4:1 basis as far as expansion there. As long as we drive our oil volumes, we'll be able to outpace that inflation and not squeeze margins. And if we have to drop the rig count, then the service inflation is going to come in as well. So I think we're in a good position. No one likes inflation but service -- when you're building more rigs, there's going to be a shortage of labor. Labor is going to want more money, and it's just one of the facts that we have to deal with, and we like our crews and we got to pay them more.

David Heikkinen - Tudor, Pickering, Holt

And I think what Brian was going to ask was kind of thinking about your capital in the Deepwater. He's talking about the Lucius flow test and kind of status for that additional drilling kind of -- to finance and capitalize that business. Just kind of thinking about how -- do you need $200 million to $500 million? And then how do you think about your activity level over the next several months between now and the fall that you would internally be paying before that financing?

James Flores

Between now and fall, depending on permits, it could be somewhere between $50 million and $70 million. To get Lucius on production, first production in 2014 is about $350 million. What we're looking at doing is raising around $500 million to drill Phobos and Capri and Sparks and these other plays around Lucius to see if we can develop a large production complex that we've seen geologically. So it's not a huge leap or a huge jump to finance the business properly and be in a position to see if we can develop a big oil business that we come in 2014, 2015. I think it might be a good time to add some barrels in the middle of the decade. So we're hoping to preserve that option for our shareholders at -- a large percentage of that option for our current shareholders at someone else's cost. Same way we did to McMoran situation where we've got the exposure to McMoran's exploration program and with the other investors paying for it. It's kind of same we're looking at our gas business being in a situation of not out spending, or continue to spend money in the and gas business beyond at which we think is required to maintain our assets and build up the Haynesville. And we put the floors in place at $4 so we've got everything above $4 for our PXP shareholders and the gas business is gravy and something that we can benefit from. So those are our 3 biggest options in the company. But the business, Dave, has been driven by our own true oil production and our own true oil development as we've articulated the past.

Operator

Your next question is from the line Brian Corales of Howard Weil.

Brian Corales - Howard Weil Incorporated

And actually, David, you basically asked what I was going to ask. But in terms of the Gulf of Mexico, the $350 million to get production online at Lucius, what other -- is there any other wells you're going to drill and potentially selling down a piece, I take it that's going to be a minority piece?

James Flores

Well, it'd be a financing. We're going to put the Deepwater in a subsidiary and then finance the subsidiary. Do you want to call it selling a piece, you can do that, but we call it a financing from this standpoint, which is all rolling up the lights to a percentage of the production. The earlier question, right now Anadarko, the operators are flow testing the number one well. Exxon is drilling the southernmost location in our Lucius unit, so we have 2 of that six rigs probably running out in the Gulf of Mexico, operating our Lucius unit. So we should have no news coming out of that end of the month to June out of our 2 operators. And then, the question then is moving towards sanction, is getting all the parties involved. It's not just Anadarko, Apache and Plains now. It's obviously Exxon and E&I because they're in the unit. And I think what the next operating plan would like to be, other what we permeated is to deepen the #2 well. That's the number that we had drilled through the main pace and looked so well -- so good geologically. And we stopped prematurely, but we want to go and deepen that on down to the Miocene and then probably drill some down to the sidetracks to define the eastern limits -- to try to define that eastern limits of a large reservoir there. So and that's if it gets permitted to do that in the fourth quarter. That's why I gave you a $50 million to $70 million swing there. And remember with the utilization, we now have a 23% interest of the whole reservoir instead of 1/3 interest of 75%. That's why the cost have kind of moved around a little bit

Brian Corales - Howard Weil Incorporated

Okay. And any update on Friesian?

James Flores

No update right now. We're still struggling with commitments from host platforms because they don't know what the rules are and what their obligations are in their own business. So we're still in limbo there.

Operator

Your next question is from the line Nick Pope of Dahlman Rose.

Nicholas P. Pope

I think you guys have covered everything I had, so I'm good.

James Flores

We like our business being simple, straightforward and clear for you guys. So hopefully, that's a precursor of things to continue along that path.

Operator

Your next question is from the line Jeff Robertson of Barclays Capital.

Jeffrey Robertson - Barclays Capital

Jim, just a question on the Mowry, will you all be able to complete both wells that you're drilling when you get your frac crews up there this summer?

James Flores

I'm not sure if it's going to be sequential or depending on timing and so forth. But our intention is to complete both wells. How's that? We plan on flow testing both wells at this point in time.

Jeffrey Robertson - Barclays Capital

And I know it's early, but can you talk about any constraints, if there are any, about more active development program in that part of the world?

James Flores

Jeff, we kind a look at this point the Big Horn Basin is mineral oil-producing basin. There's oil infrastructure, there's pipelines, there's gas pipelines going through that. So we don't see any real impediment, I guess, is the best way to talk about it be an area of development. We have no idea what the capacity is. It is the Rocky Mountains will be a little slow to get started from a standpoint of we've got to do some -- a lot of federal lands, so we have to do a lot of EI stuff and things of that -- EA stuff. We think the Mowry, if successful this year, would be a big part of our business in 2013, starting them. So you got to -- we're going to do a lot of testing. We've got over a 100,000 acres at this point in time. So we're well positioned. Now when we look at the deal initially, the 54,000 acres was going to potentially give us another profile asset like our Eagle Ford profile. 200 million barrels and maybe 25,000 barrels a day production doubled our acreage out there, and we think it's pretty good stuff, maybe increasing that. But we're getting way ahead of ourselves. We have to produce the first barrel of oil to see if it's even going to be -- probably we're going to able to do. But we're hoping to add on in 2012 and 2013 more of these type plays that we generate and have the right size acreage position for us. And if it's oily, then it's something we can continue to build our inventory into the second half of this decade onshore

Operator

Your next question is from the line of Duane Grubert of Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP

Jim, given that you do have a pretty clear view that you're going to be very busy onshore for a long time, use a lot of money in the Eagle Ford, in particular. Can you talk to us about how you guys have thought about vertical integration? Would you ever consider relatively near term picking up some rigs or frac fleets for example?

James Flores

I don't think we're in the mindset to do that, Duane, because we're going to run our business kind of in the $80 oil -- budget oil and range, and it just doesn't make sense at that level. If oil stays at a $100, $110, $120, $125, then we're going to have service cost inflation. And you can make the argument that vertical integration is -- could possibly be needed and that type of thing. It is fraught challenges, you're competing not only with your fellow EE&P company, you're now competing with the service companies. It's a lot of complications. But we want to basically be in a relationship that's arm's length where we can actually terminate the relationship if the work not being performed correct. And it's hard to fire yourself. So we want to make sure, and we're making a lot decisions based on geology and engineering and not how many rigs we own. So that's a philosophical difference. And the key here is going back to dealing with inflation is to make sure that your operating margins are going faster than inflation, and we have that situation because we have so much oil production.

Duane Grubert - Susquehanna Financial Group, LLLP

Okay. That's a really good answer. Secondly, could you update us all on what's going on in the diatomite permitting world?

James Flores

The diatomite permitting world is pretty solid. We've got our 19Z[ph] going forward project. The key about permitting in California, it's early, a lot and often. And when you permit the projects 3 years in advance and then you permit the wells within 2 years, and you go through it, you spend a lot of time with [indiscernible] there and so forth. And we're not expanding geographically like a lot of people are out there. We don't need to. We're still doing a lot on our own in our own areas, and 19Z, that's a geographic expansion move between 2 -- surrounded by producing wells, that we probably don't have the permitting challenges other people would have from this standpoint.

Duane Grubert - Susquehanna Financial Group, LLLP

And kind of related, in California, you've got a long-running program. I think you've got 4 rigs in California split, 2 in the Valley and 2 down south. What is a fundamental explanation on why wouldn't you pick up at least one more rig in the Valley given you've got years and years of activity there?

James Flores

Well, we've got a budget out there and the aspect of that. We think we can get a lot more volumes and be in a situation that we're going to be -- in growing our Eagle Ford production, we're focused there. But you also run the risk of interference on the surface and disrupting more production by bringing rigs in the close area. So we tested this model for 10 years now. And remember early on, we've tried to throw a lot of money in California. We basically did more production disruption than production increases and so forth. So we think we've got the right mix. When we keep about $200 million of spending, we'll keep production flat. And I challenge everybody to find another asset out in North America where they can spend 20% of the cash flow and keep production flat. And so then all incremental spending above the $200 million is really our expansion spending like our 19Z and then sequentially, our Rio Grande. So from our standpoint, our California business is doing exactly what it's supposed to be doing, expanding. And our real dynamic expansions are coming in the Granite Wash and the Eagle Ford. Duane, I have a question for you. Do you have in your wildest dreams as a Unical engineer out there, think that Buena Vista would be selling at 105% of NYMEX?

Duane Grubert - Susquehanna Financial Group, LLLP

Oh my god, no. I can remember driving out there in 1985 when it was selling at $9 per barrel. So it is just a different world.

James Flores

That was $18 NYMEX, 50% of NYMEX. That's right. So California, we're very focused on it. We're very focused on -- and just staying with ourselves not making any mistakes and those types of things. Duane, one more thing, too, note this morning. There's a lot of questions and thoughts about our McMoran shares and what to do and so forth standpoint. We're going to play that very simple and whatever we need to do around here from PXP's perspective of monetizing those or helping relieve some stress in our balance sheet. From a standpoint of what we'll do, we're not interested in doing anything strategic or acute with those from a standpoint. So it's going to be very plain vanilla. So I want you to hear that directly from me.

Operator

Your next question is from the line Phil McPherson of Global Hunter Securities.

Philip McPherson - Global Hunter Securities, LLC

Most of my questions have been answered. I just -- one curious thing on the 3D seismic shoot in California. Could you tell us how big and is it going to be in the San Joaquin or more out on the coastal areas?

James Flores

Well, it's the San Joaquin. It's kind of across some of our crestal properties. We're looking for some of the thrust fault that you see into the south. And we don't have a tremendous interest in that, air is really driving that. But we have -- it's about a 16,000-acre shoot, and we have probably 10% to 15% of it.

Philip McPherson - Global Hunter Securities, LLC

And as far as your potential Monterey wells, will you wait for that seismic? Or is that in other areas?

James Flores

We're probably going to be testing the Monterey and the LA Basin first, I meant Miocene, but it's the same thing.

Operator

Your next question is from Frashija Thunderman at Hardinar[ph].

Unknown Analyst -

Two questions. A couple of things. I was a little confused and I had to step away. I was a little confused on discussion about the Deepwater asset. Is your point that you would be spending it off into subsidiary but still within the PXP vehicle? Or has it become -- I mean, how does this work? I understand the financing part, but I do not understand how the entity works.

James Flores

The entity will be a wholly -- will be 100% owned subsidiary of PXP. So it'd be 100% owned. And then there'll be financing issue or securities issue at the subsidiary level to finance the Deepwater subsidiary.

Unknown Analyst -

So I mean, strategically, you're set up in the same place. So does it feel that you're -- does it mean that you're feeling better overall about your appetite to take on the potential -- the risk return of being in Deepwater --

James Flores

Yes, I mean, we obviously feel better about that, the well containment -- physically the industry is in 1,000% better shape to take on the aspect of it. So we won't repeat another Macondo-type experience where people will get the perception that this is going to ruin the world. That physically is we think a very smart -- a minute possibility at this point in time because of the capital and all the systems and everything has been built to a cap well, cap any well. If that horrible disaster would happen again in the next -- we'd cap it in a week to 10 days and would not be a worldwide phenomena. Number two, regulation does work when it comes to safety. It's very expensive but Boehmer [ph] is -- like when we tested the BOPs out on the Anadarko rig, there was 3 Boehmer inspectors out there watching everything on it. And so they're ramping up enforcement. So the aspect of safety has helped our view there same point in time. We want the option at this point in time to have the exposure to the Lucius project and all the joining fall blocks because the magnitude of it. It could potentially have more oil flowing net to PXP than PXP in 2015. So the aspect of that option to preserve it for our shareholders is initially what the financing at the subsidiary, and then every day forward, we'll be assessing that option whether it's something we need to sell or not. But with Lucius, such high economics from a standpoint of being able to bring that production on with low dollars and being high, high margin dollars in the world, I think, at 2015, there may need a few more barrels of oil, I think it's the business we're in, as long as we feel good about the risk and may have improved significantly.

Unknown Analyst -

But I mean, the data -- other the fact that there was a shutdown for a period of time, the data in front of you from the point of view -- and I'm sorry if mistaken, but the data in front of you from the Lucius well and that project and so forth wasn't really very different at the time of the event of April 2010. So -- the BP event. So I'm just curious, it's a fairly dramatic change from what you were discussing perhaps in the fall of 2010. I'm wondering whether that was just maybe an immediate reaction, because the data in front of you surely hasn't changed quite that dramatically.

James Flores

Well, let me help you. Obviously, we've got better vision than you because we're here in the middle of it. The data has changed from a standpoint. We've gotten some additional seismic data out there and then additional geologic and geophysical work that we're very positive on the aspect. What has changed eventually is that the risk in the Gulf of Mexico have been reduced physically and regulatory wise. And then number two -- number three, the value of Lucius quarter or the opportunity for Lucius is much greater than what the marketplace put on it in 2010 and early this year. And as we improve with well tests and additional drilling and those types of things, we think it's going to continue to improve and look stronger going forward.

The aspect of making that decision, oil prices were $60 a barrel, we made that decision in May. And now oil prices have topped $100. But we have $80 floors in place going forward and we'll be extending those probably in the 2013. So the financial position of the company is in a different shape. And also the capital available to the financial business like this is available right now according to the 10-or-so bankers that have come through our offices. So we take things at times slices and look forward and the position now is that the shareholders that I've talked to in the last week or so had been very supportive of us preserving the option of 75%, 80% of the Lucius potential to the existing shales of PXP through the structure. And maybe we can spend some more time with you and kind of gets comfortable with it, but that's -- we're getting a pretty good feedback on preserving that option along with the same ways we preserve the McMoRan option and also the way we've done our gas business. That's just a lot of upside extemporaneous to PXP besides just growing oil production, which we think is the here and now.

Unknown Analyst -

Could I just ask you how that changes the way you think about your cash flow and your CapEx because obviously, with the change in regulation and so forth, it's probably a very high value proposition but on the other hand, it's probably higher costs as well because of the divestiture of the portfolio, does that just sort of gets mitigated by that? Or it doesn't come out fully?

James Flores

Well, I'm glad you ask that question because there's no Deepwater reflected in our CapEx at this point in time. And that's the reason why we're going to finance it at the subsidiary level. Now the interesting about Lucius, it's really a spotlight project, we believe, because of the economics are so strong. No one likes to have more cost, but regulation does cost, but we want the regulation to be in the situation of safety. So the aspect of if this was a very low margin project, then it would have very much more bearing. And what the regulation will do in the Gulf of Mexico, besides the top 10 or 50 projects, it's going to marginalize all the low returning projects that were done, and you will never get back -- you want to get back to the 30-rig count and semi submersibles for a long, long period of time because only the best projects are going to get done, and we are only able to consider this because Lucius is in that category and the economics are so strong that another day or 2 of rig time testing BOPs is something that -- is built in for safety and it's just cost more than what it did before.

Unknown Analyst -

Okay. I think that makes sense. And so just on the CapEx thing, your point is because it will be a self-financing entity, you would not talk about the CapEx related to the Deepwater asset within sort of the rest of PXP in sort of earnings call generally?

James Flores

We would break it out because the financing -- the capital would still be in the subsidiary, so you'd have a cash balance in the subsidiary and netting out whatever CapEx it came into the Deepwater asset. So it wouldn't be affecting the business plan that you're looking at today.

Unknown Analyst -

Okay. And finally on the Mowry Shale, so you all have drilled one well. Is it that you don't have the results of that or don't have anything to discuss, or don't want to discuss? I'm wondering how you all are thinking -- and you did give an explanation sort of the longer term, but just as it's developing.

James Flores

We have not produced a barrel of oil out there. And the minute we -- and when we do and we have some results, we'll be disclosing it to everybody.

Operator

Your next question is from the line Bill Frazier [ph] of Greenhill Capital.

Unknown Analyst -

A couple of quick ones. The Lucius well, is that being appraised right now? And did you say that Anadarko will come up with something probably at the end of May or early June?

James Flores

I never speak for Anadarko, Bill, you know that. But they are the operators, so they have to disclose any information. I know there will be -- we're scheduled to be finished by the end of May or June. So whenever they decide to make the release or information known, they will.

Unknown Analyst -

A few years ago you made a ton of money with a double dose of puts on your hedges. And the current set up, puts are out of the money a good $20. Are you thinking at least putting in some more, buying some more puts to lock in the $100 price?

James Flores

Not necessarily, they are pretty expensive at this juncture and so forth. We bought the $110 puts and oil busted to $125, so it was a little easier decision. We're always in a position to take advantage of the market if it gets really dislocated. What we'd be interested in looking at doing is adding some 2013 -- adding some length at this point in time to our put strategy kind of traditional by mid-year, we roll it forward to keep a 2-year growth situation. But the market, from a standpoint, I know everybody is probably sensitive. It's dropped $10 or whatever in the last week. But anything above $95 a barrel is pretty solid for PXP. If we don't see a real blowup to above $125 or whatever, then we'll be pretty benign on the trading standpoint.

Unknown Analyst -

Okay. Great. Now the Conoco contract, does that -- I know it's going to be renegotiated at the end of the year. Does that commit PXP to certain volume levels as well as the price level?

James Flores

High. It's 50% of our crude oil production in California. That was a 15-year commitment. That was executed about 11 years ago before I was even year. But what gets redetermined is the differential discount in NYMEX. And when they first executed the contract, it was at 70% of NYMEX, and we're at 80% of NYMEX with improving tightness in the differential market. So a lot higher than 88%. So we go back and do a historical analysis where the contract has been for the last 2 years and then do a true-up and kind of arm wrestle negotiations with Conoco and find something fair for both parties and move forward. Every 2 years, we'll do that. Obviously, this is the most favorable conditions we've ever had to have those discussions, so we're enthusiastic about getting engaged on them.

Operator

Your next question is from the line Jeff Classic [ph] of ThinkEquity Advisor[ph].

Unknown Analyst -

Any plans to monetize any of the other Deepwater assets besides Lucius?

James Flores

Jeff, all of our Deepwater business will go into south. All of the leases, everything. So they'll be done all at the same time.

Operator

Your next question is from the line of Anne Cameron of BNP.

Anne Cameron - JP Morgan

Want to ask about the $350 million of capital to bring the Lucius online? Does that include drilling completion and infrastructure?

James Flores

Yes, and a 23% interest in the unit.

Anne Cameron - JP Morgan

Okay. So theoretically, if let's just say Lucius were a $500 million a barrel field growth, that's pretty low. I mean, that's less than $3 a barrel?

James Flores

Yes, we have the high side case right now, Anne. But yes, you're doing the math correctly. And that's the reason why that I think putting the Lucius into sub and financing at this point in time will get a rousing response from a lot of people who actually see the data. And the data is actually -- we've been able to expand of their new seismic coverage and some things we're seeing out there that. Not beyond Lucius, we're very excited about drilling Phobos, which could be twice as big as Lucius. We're very excited about going Capri and other things. So we think we have a nice production complex that we -- that can be -- just need some capital, need some drilling and a little time to see if it's really come to fruition. So I couldn't be more excited about the project, and especially and when we think of, if oil kind of stays in the $90 to $100 a barrel day range in the next couple of years and think about 2015, we'll have quite a project at the right time.

Operator

Your final question comes from the line Gary Stromberg of Barclays Capital.

Gary Stromberg - Barclays Capital

But maybe this is one more for Winston. The Deepwater ring fence -- would that be an unrestricted subsidiary and therefore, restricted payment?

Winston Talbert

Right now, we're just -- we're working through all that and we'll be ready -- we'll be able to answer those questions for you later in the summer.

Gary Stromberg - Barclays Capital

And what kind of securities or financing are you expecting? Is that going to be a secured term loan? Or is that also on the comp...

James Flores

Gary, we got our lawyers looking at us. I do want to clear one thing up. We've executed a contract with Shell to sell all of our Eagle Ford volumes for $6.50 off of LOS. The effective date on that is November 1. So $6.50 to $7. So we've got -- and that's a 5-year term on that contract. So we think we've got a great marketing contract where they can take barrels down on the Gulf Coast and the Inter-costal Canal and we can realize prices. So between our pricing in the Eagle Ford and our price in California, we're well placed on our oil. We're very excited about the upside there. We're very excited about strengthen our balance sheet, due to monetization of some of our goals assets either McMoRan over time, next year or our Deepwater, what happens there, so we can lower some interest cost. So there's a lot of things we need to do around here and really improve cash flow beyond just the strong oil prices that we're enjoying and redeploying on the Eagle Ford. So that's give you kind of the wrap-up. But that was your question, right, Gary, with the Eagle Ford marketing, right?

Operator

And there are no further questions at this time. Presenters, do you have any closing remarks?

James Flores

Thank you, operator. We're very excited about this year, 2011. We're well positioned, and look forward to executing on a continued basis and having more of these good calls. Thank you very much.

Operator

This concludes today's conference call. You may now disconnect.

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