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Plains Exploration & Production (NYSE:PXP)

Q2 2011 Earnings Call

August 04, 2011 9:00 am ET

Executives

Hance Myers - Vice President of Investor Relations

Scott Winters -

James Flores - Chairman, Chief Executive Officer and President

Winston Talbert - Chief Financial Officer and Executive Vice President

Analysts

Brian Singer - Goldman Sachs Group Inc.

Philip McPherson - Global Hunter Securities, LLC

David Kistler - Simmons & Company International

Leo Mariani - RBC Capital Markets, LLC

Brian Corales - Howard Weil Incorporated

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Marshall Carver - Capital One Southcoast, Inc.

Nicholas Pope - JP Morgan

Unknown Analyst -

Operator

Good morning. My name is a Theresa, and I will be your conference operator today. At this time, I would like to welcome everyone to the 2011 Second Quarter Earnings Results Conference Call. [Operator Instructions] I would now like to turn the call over to Scott Winters, Vice President of Corporate Planning and Research. Mr. Winters, please go ahead, sir.

Scott Winters

Operator, thank you. Good morning, everyone, 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 the slides during the call. The webcast, the slides, 10-Q and today's press release are available on the website, in the Investor Information section.

Before we begin today's comments, I'd like to remind everybody that during this call, there will be forward-looking statements as defined by the SEC. These statements are based on 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 discussion of these risks.

In our press release, the slide presentation and our prepared comments this morning, we present non-GAAP measures. A reconciliation of all the 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; Winston Talbert, our Executive Vice President and Chief Financial Officer; John Wombwell, our Executive Vice President and General Counsel; and Hance Myers, Vice President Corporate Information Director.

For the second quarter of 2011, PXP reported net income of $125 million or $0.87 per diluted share, compared to net income of $45 million or $0.32 per diluted share for the second 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 may affect the comparability of operating results. When considering these items, PXP reported net income of $77 million or $0.54 per diluted share compared to net income of $37 million or $0.26 per diluted share for the same period in 2010.

2011 second quarter daily sales volumes averaged approximately 97,700 barrels oil equivalent per day, a 15% increase compared to the second quarter 2010 or a 27% increase pro forma for the 2010 asset sale. Average daily liquids sales volumes increased 7% compared to the second quarter of 2010 or 12% pro forma for the 2010 asset sales, and are expected to increase ratably throughout the rest of the year.

During the second quarter of 2011, gross margin per BOE was $25.31 and cash margin per BOE was $39.92, up 35% and a 20% increase over second quarter of 2010, respectively. Higher production and higher realized prices are the primary drivers for this increase.

For the second quarter of 2011, oil and gas revenues increased 41% compared to second quarter of 2010. Oil revenues increased approximately $123 million reflecting higher average realized prices, benefited by California crude postings, which remain strong relative to NYMEX, and higher sales volumes. Gas revenues increased approximately $26 million, reflecting higher sales volumes and higher average realized prices.

Lease operating expenses increased approximately $25 million to $82 million in 2011, reflecting an increased number of producing wells at our Eagle Ford Shale and Panhandle properties, and higher scheduled repair and maintenance and well workovers, primarily at our California properties. Steam gas cost increased approximately $1.5 million, primarily reflecting higher cost of gas and higher volumes used in steam generation. In the second quarter of 2011, we burned approximately 4.1 Bcf of natural gas at a cost of approximately $4.13 per MMBtu, compared to 3.9 Bcf at a cost of approximately $3.90 per MMBtu in 2010.

Production and ad valorem taxes increased $13 million to approximately $17 million in 2011, reflecting higher ad valorem taxes at our California and Haynesville Shale properties. The increase in production taxes in 2011 compared to 2010 reflect the impact of the production tax abatements recorded in 2010, and increased production, primarily from our Panhandle property in 2011. Gathering and transportation expenses increased approximately $4 million to $17 million in 2011, primarily reflecting an increase in production from our Haynesville Shale properties.

Income from operations was approximately $186 million during the second quarter of 2011 compared to approximately $50 million for the same period in 2010. The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked to market each quarter, with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to, or receiving a payment from, the counter-party. We recognized a $19 million gain on mark-to-market derivative contracts in the second quarter of 2011, which was primarily associated with an increase in the fair value of our 2011 crude oil and natural gas collars due to lower forward prices. In the second quarter 2010, we recognized a $58 million gain related to 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 derivatives is included with the financial tables in the press release.

At June 30, 2011, PXP owned 51 million shares of McMoRan common stock. We've elected to measure our equity investment in McMoRan at fair value. As a result, unrealized gains and losses on investment will be reported quarterly in our income statement, which could result in volatility in our earnings. In the second quarter of 2011, we recognized a $43 million gain on investment. A complete discussion can be found in the 10-Q.

In August, PXP executed a new marketing contract for its California crude production with ConocoPhillips. Currently, PXP sells approximately 65% of its crude oil to ConocoPhillips. The new contract covers approximately 90% of PXP's California production, extends the dedication from January 1, 2015 to January 1, 2023, and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach beginning in 2012.

Separately, PXP executed an agreement with a third-party purchaser to sell a large portion of the Eagle Ford crude oil using a Light Louisiana Sweet-based price mechanism. In 2012, using the current market price outlook and the new marketing contract, PXP currently expects full year oil price realization to be between 101% and 103% of NYMEX. PXP expects 2012 total company liquids price realization, which includes crude oil and natural gas liquids, to be between 93% and 95% of NYMEX, compared to the full year 2011 total company liquids price realization guidance range of 84% to 86%.

With respect to 2011 full year guidance, we have the following updates: Due primarily to our accelerated drilling activity in the Eagle Ford and a higher-than-originally planned rig count in the Haynesville, PXP's Board of Directors approved an increase in 2011 capital spending, which is estimated to be approximately $1.5 billion, excluding deepwater spending, up from $1.2 billion. For the first 6 months, average daily sales volumes were 92,900 BOE, with higher drilling activity year-to-date than originally planned in the Haynesville and in the Eagle Ford, full year 2011 average daily sales volumes are now expected to be near the upper end of a new guidance range of 97,000 to 100,000 BOEs per day. The range was 95,000 to 100,000 BOE per day.

PXP expects its oil price realization for the full year 2011 to be above the guidance range due to continued strength of California crude oil pricing relative to NYMEX West Texas Intermediate. And finally, PXP expects lease operating expenses per BOE, a component of total production cost per BOE, to be at the high end of the $7.90 to $8.30 per BOE full year 2011 guidance range due to the increased activity in the Eagle Ford.

A quick comment on our operations. In the Texas Panhandle asset area, PXP has 5 drilling rigs operating in the Granite Wash tran and expect to continue this level of activity through 2011. Second quarter daily sales volumes averaged approximately 13,620 BOEs per day net to PXP, or 52% higher than the first quarter 2011 and 139% higher than the second quarter of 2010. Average daily sales volumes are expected to increase to approximately 17,000 BOE net per day by year-end 2011.

During 2010 and early 2011, PXP built 15 production handling facilities and related infrastructure in order to support the rapid growth in sales volume that PXP is now reporting. In the Eagle Ford asset area, PXP has 5.5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. Second quarter daily sales volumes averaged approximately 2,330 BOE per, day net for PXP, an increase of approximately 4% to first quarter 2011 average daily sales volume. For the month of July, daily sales volumes averaged approximately 4,400 BOE per day net to PXP, and PXP expects to exit the year above 10,000 BOEs net per day for this asset area.

The 2 most recent initial production tests are as follows, the Comedy Trust 1H achieved an initial production rate of 1,745 gross and 1,396 net BOE per day and a Comedy Trust 2H achieved an initial production rate of approximately 1,904 gross and 1,523 net BOEs per day. During the first half of the year, PXP built 4 production handling facilities and related infrastructure, out of the 12 facilities currently planned through 2012 to support future sales volume growth. Each facility has the capability of supporting multiple wells, and construction continues on future production facilities. Timing of right-of-way approvals temporarily slowed construction during the second quarter, which slowed the process of connecting completed wells to pipelines. With many of the initial logistics resolved, PXP anticipates a ramp-up in sales volumes during the second half of 2011.

In California, PXP has 3 drilling rigs operating onshore, where PXP continues its active development program in the Los Angeles and San Joaquin Basin. Daily sales volumes onshore and offshore averaged 40,500 BOEs per day net to PXP or 7% higher than the first quarter of 2011 and slightly higher than the second quarter of 2010. Average daily sales volumes are expected to be above 41,000 BOEs per day net by the end of year end 2011.

In the Haynesville Shale, PXP's primary operator is currently operating 31 rigs and expects to reduce the rig count during the quarter. In addition, PXP expects 15 or more rigs run by other operators on its acreage. Second quarter daily sales volumes averaged approximately 181.7 million cubic feet equivalent per day net to PXP or 12% higher than the first quarter of 2011, and 71% higher than the second quarter of 2010. The rate of increase in sales volumes is anticipated to slow as the rig count decreases later this year.

In Wyoming, Mowry Shale, PXP drilled and completed its first well in June of 2011 and produced high-quality oil in small quantities. PXP drilled its second well and is in the process of completing this well. We'll study the results of these initial wells and drill 2 additional wells in 2012 to further evaluate the project.

In the Gulf of Mexico, the operator of the Lucius Discovery, Anadarko Petroleum Corporation, recently announced the finalization of a unitization agreement with Exxon Mobil Corporation, and co-owners to develop the Lucius field. Following the unitization agreement, the Lucius interest owners entered into agreement with the Hadrian South co-ventures whereby natural gas produced in the Hadrian South field will be processed through the Lucius facility in return for a production handling fee and reimbursement for any required facility upgrades.

So our 2011 growth objectives are on track. Drilling results in each of our project areas have been strong, and we look forward to providing an update on our progress at our third quarter earnings call. With that, I'll turn the call over to Jim.

James Flores

Thank you, Scott. Good morning, everyone. This is Jim Flores. You can tell by Scott's report on our results, we're really moving the ball forward in Eagle Ford and our liquids production. And also, with redetermination of oil prices in California, we accomplished one of our key corporate goals this year is to get as much of our crude oil production, not only in California but also in Eagle Ford, reflective of world oil prices and not subject to the WTI discount. The market reflection of our coastal barrels is more of a seaborne price, and as we obviously have quality discounts to some of those barrels. But when you net the quality discounts out, we're still trading above NYMEX and WTI, which is a very significant upgrade and should bring forth between $140 million to $160 million of additional income to the company starting January 2012 and should, like with the California contract, that's an 11-year contract on the Candino [ph] we have a 5-year contract. So should provide many years of additional income. And since I've been with the company almost 9 years or 10 years, this is one of the key goals we had when we started to make sure that the valuable California barrels were going to be priced at world market prices versus some type of arbritrarial or location discount, which they had suffered since the '70s when the Alaskan North Slope Crude came on. So kudos to our entire organization and also our refiners and also the California gasoline market for letting us achieve that goal.

We have obviously, besides our operating results they're so consistent and growing production between 12% and 15%. As you can see in our press release and my comments, our operating margin continues to increase because we're oil focused. We are suffering service cost inflation like everyone else. But as service cost inflation's going up 8%, 9%, 10%, oil price is going up 25%, we're still continuing to expand our operating margin. If oil prices stay here, then we'll have some service cost inflation going forward. But it'll start to mute as capacity is being added rapidly by all the service providers. If oil goes up another $25, service costs are going to go higher. We're planning on that next year for service cost to go higher under that scenario. If oil prices drop $10 to $15 on liquid, we won't have much service cost inflation, because it's going to be very impactful to the marginal barrel and development plans of a lot of these projects. So I think we're very much linked at the hip. And I think when you look at a company like PXP that has an excellent operating margin under this, I would call it severe inflationary environment, it gives us a definite opportunity to manage our way through it and provide consistent value our stakeholders.

With that, there's 2 other corporate goals that we have to tick off, which is the financing of our Plains Offshore. The lawyers are telling us that since we're in the throes of negotiating that financing, that we cannot comment further as to that and hope to have that done later this year. Along with that, some key milestones is the eventual sanctioning of our Lucius project, which obviously significant to PXP and also be significant to Plains Offshore as far as closing the transaction of the financing. And we'll discuss more of that, as people are curious about it. Then the third area is to work on or continue to work on our balance sheet, look at assets that we can monetize. We have some financial assets, primarily that we're looking hopefully be in a position to refinance some our several high-cost debt and drive some more income into next year. So we've got, from a corporate strategic perspective, we've ticked off 1 of the 3 with our oil price realization accomplishments, and our crude oil contracts in California. We have 2 more to go between now and the next 6 to 9 months to knock out, and we're highly focused on that going forward, so stay tuned.

So with that, I will open up to questions, and we can get into the details of our second quarter. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Your first question is from Leo Mariani with RBC Capital Markets.

Leo Mariani - RBC Capital Markets, LLC

You obviously talked about 2 new oil contracts, 1 for the Eagle Ford, 1 for California. Just wanted to confirm that those both are going into effect on January 1, 2012. And you talked about sort of market-based pricing for those. Could give us a little bit more sort of color on that? Are you guys going to be getting some kind of a discount to Midway out in California? And how is it getting priced off of LLS and now the Eagle Ford?

James Flores

Well, I'll give you some detail on that. For example, Midway sunset right now, we're just pricing it off of NYMEX is the key thing. It's trading about 103% of NYMEX, and that includes all of our discounts. That's net-net to PXP, and that's up from say 88% of NYMEX where it is right now, which is up from our guidance, which is 84% to 86% of NYMEX. It's the best way to think about that. Obviously we're trading on a retail price, closer to Brent. And when you do the quality discounts and transportation, we get down to 103% of NYMEX or WTI. Same thing, we have Buena Vista, then we have Oriente, we trade off of that. For offshore, when you go all through it, it's about 103% as an average for our California crude above NYMEX. On our crude oil contracts in Eagle Ford, we're about $7 a barrel off of LLS. That starts mid-fourth quarter this year, so call it Jan 1 for planning purposes, as well as the California contract. And it'll be taking all of our barrels on to the near coast canal and putting them through the Shell refining network. So we're in good shape. Now that covers about 90% of our crude oil as a company. We have 10% of our crude oil that's either -- we hold it out, we market that ourselves, outside of those contracts more as a price check mechanism to continue to keep our hand on the prices. And then we have about 1,500 barrels a day at Montebello we sell directly to a refinery through the infrastructure there at Paramount in the LA Basin, and we get excellent spot pricing on that as well. So we're, at this point in time, we have -- our WTI and NYMEX exposures really are in the Granite Wash, where we have significant volumes in liquids there but also the NGLs. But the key thing about those contracts, they have very good volume takes, and we're able to make excellent rates of return because of the high flow rates of those wells versus the investment capital.

Leo Mariani - RBC Capital Markets, LLC

Great. And I guess with respect to the Granite Wash, you guys obviously posted a huge increase in production from the first quarter to the second quarter. trying to get a sense of how many new wells you guys brought online, if you can kind of comment a little bit more detail some of the recent well performance.

James Flores

Well, the well performance has been pretty consistent, Leo, as what we've had. It's just more logistics when Scott talked about the production facilities and so forth. It's more of a timing of quantity as those things go. And as you know as we get more facilities out there, and more central facilities, it's much easier and faster to put on wells. So I think what you'll see in the Granite Wash is an accelerated rate of wells going into production versus wells waiting on facilities and those types of things. It's kind of like it's a year ahead of where we are in the Eagle Ford. Eagle Ford, we have 4 central facilities in and they'll take multiple wells. Some of them will take 6, 8, 10, some of them will take 30 wells, it just depends on where they're located. And so we're at 4 central facilities in Eagle Ford, we'll be at 12 by next year, by the end of next year, which is a key feature because right now in the Eagle Ford, for us to continue to develop it rapidly with the accelerated amount of rigs, and we're talking about -- we're at 5 we're talking about adding 2 more is late this year or early next year, as far as continue to ramp up our production there. We're to keep up with that schedule on a production basis, we're required to get a lot of rental equipment. We're required to get a lot of contract labor. Well that flows through in our LOEs. it's not an LOE bump in cost, other than it's more of an LOE bump in activity. So as we get the central facilities built in the Panhandle and also in the Eagle Ford, I can see the second half of 2012 and '13 and '14 having a lot lower LOEs just on an absolute basis because we'll be using less and less of that contract and rental equipment and more of our own, not to mention on a per barrel basis because we have a lot higher volumes and so forth. So we're very much in the construction phase of these 2 projects that obviously responded greatly with the production. But that's kind of the backdrop. It's just a matter of how many facilities we're going to be able to put in and the rapid rate we're able to put them in is how we're going to drive production on a more accelerated basis.

Leo Mariani - RBC Capital Markets, LLC

Great. I guess, just quick question here on the Mowry, you guys talked about producing some small amounts of high-quality oil. Was that a vertical well or horizontal well? And just want to get a sense of what you guys are thinking? Are you encouraged by the early results? Obviously you're drilling several more wells here.

James Flores

Well, we had several times the press release went around internally. We struck the word encouraged out, how's that? Because we get encouraged by commercial results. I mean, geologically, the positives are we found some high-quality oil and we think we found a kitchen, but we need to drill some wells in some different locations to find out if we have some commerciality to this play. We're being very judicious about it. It was a horizontal well. We did test it and so forth. We probably didn't put as big a frac as we would have if we had a lot of confidence. Initial we're just trying to explore and scratch and understand. We have a large acreage block out there for us, over 100,000 acres. And that's a steep, dipping basin, and we're hoping to get a little hotter area, a little more energy to get that a lot more of that high-quality oil out of the ground. So just we're just telling everybody stay tuned, it's exploratory project we're going to -- we're in the process, when we start completing our second well here little bit later in August. And we'll keep blowing it back this fall, where we've already planned 2 new locations in different spots of our lease block that we think are more prospective, and we just don't have any results yet on the commercial side to talk about yet.

Operator

Your next question comes from Dave Kistler of Simmons & Co.

David Kistler - Simmons & Company International

Real quickly focusing on California for a bit here and specifically kind of the cyclic steam side of things, where you have a pretty significant development effort in place to grow production. Can you give us an update on what that's looking like right now, because it's such a big driver of the cash flow going forward?

James Flores

It's all on schedule from our standpoint. We continue to -- most of our program each year is front-end loader, so really getting towards the end of our drilling program at San Joaquin Valley and LA Basin and we finish pretty much by third quarter. So you'll see CapEx drop-off and then pick back up in the first quarter next year. We're not seeing any issues. Things like kind of typical maintenance issues where we're seeing requirements to go back and P&A wells and do things like that. And as people are -- as regulatories tightening up around the place, we're addressing those issues in a timely fashion. And at this point in time, we see all that in place. Where we're seeing some good progress is on our construction in the Arroyo Grande of our reverse osmosis plant so we can handle the water when we go in to steam that field and subsequent dewater it. So everything on track in California and as we accelerate the Eagle Ford, we do have 450 employees in California focused on making sure that oil production shows up. So we have plenty of eyes focused on it.

David Kistler - Simmons & Company International

Great. And then just thinking about production growth out of California with the new contract in place, does that have any scale mechanisms as far as delivering additional production to ConocoPhillips and take advantage of the better pricing situation you have?

James Flores

There's no limitations to the amount of production we send to ConocoPhillips. We're displacing Long Beach barrels, so we can send all the production their way and they'd be happy to take that and displace the Long Beach barrels with our production.

David Kistler - Simmons & Company International

Outstanding. And then last one here, kind of a cleanup item. The McMoRan shares that you currently hold, I believe the unlock comes around the first of the year here. Any kind of thoughts you can give us with respect to monetization of those, holding those? Anything like that?

James Flores

Yes, first you have -- as part of our opportunity to refinance our balance sheet, we've focused on maybe a few -- as much as $400 million or $500 million of it, doing some type of convert, locked up for 3 or 4 years and in the McMoRan shares and try to monetize some of it, which will allow us to refinance the deal. The last thing we want to do is get rid of those shares from the standpoint of the upside and just put those shares, hit the deck. So we have a lot of ways to monetize them and be able to achieve our goals of strengthening our balance sheet. So we'll be looking at doing that at the 1st of the year and going forward, so maybe halve our position. But right now, we had a McMoRan board meeting early this week and things look pretty bright. We've got plenty of capital and we're excited about the upcoming drilling schedule and all -- we're right on top of a lot of the major targets. So we're excited about the next 3 to 6 months, see what happens in McMoRan.

David Kistler - Simmons & Company International

Great. If I could just sneak one more in. Switching topics. Looking at the impressive results out of the Eagle Ford, can you talk just a little bit to what the latest costs were to those wells and the cost trend you see going forward on those?

James Flores

I'll give you kind of some general stuff. The interesting part about these 2 wells, I mean, that's -- these are the first 2 wells we used the infamous highway frac on. All right? And if you extrapolate the results -- and these are early results, okay? Let's quantify that. I mean we don't have a long-term trend, but if the trend continues on these wells and so forth, they're about double, Dave, on productive basis than what we thought on our initial buy-in. So that's just a significant improvement on the reservoir aspect and a recovery aspect of these wells. If they continue like this and if the rest of our areas seem to be significant. So that means it echoes some of the comments that Mark Papa, at EOG, our partner and obviously surrounds us and Clarence Cazalot at Marathon, the purchase, stuff like that. There is a lot of oil in place here in this Corns trough and the Grobin [ph] area, that with the right technology and so forth, it seems to be responding quite well. Is the highway frac 20% more expensive? It's not free, that's for sure. And dealing with a behemoth like Schlumberger and getting them coordinated is probably -- can be a little bit more work for PXP than someone else. But the resource potential of the technology breakthroughs in the frac-ing is being applied to our Eagle Ford is quite extraordinary this early on, 6 months in to owning this asset. So we are most excited about these 2 wells.

Operator

Your next question comes from Phil McPherson of Global Hunter Securities.

Philip McPherson - Global Hunter Securities, LLC

I was wondering if you could break down CapEx in California from a drilling standpoint and infrastructure standpoint. It looks like in 2012, it's going to increase by about $100 million. And is that kind of indicative of more rigs running and maybe you can give us a little more color there?

James Flores

Think about this way in a macro base, because that's a very detailed answer you're going to have to get on a spreadsheet versus verbally, because there's so many moving parts to it. But the first $200 million we spend every year is maintenance CapEx up there. That's drilling, completion, rope, soap and dope. $200 million. Anything above $200 million is expansion CapEx. And the reason why I break it down that way, the expansion CapEx is timed to what we're doing. Like for instance Rio Grande, is mostly construction right now. And next year, it'll be mostly drilling and so forth, so it's a sequential process of developing the 2 greenfield areas like 19Z and Arroyo Grande. So I'm not trying to give you more of a general answer to get you direction then you can circle back with Hance and get some detail there from a standpoint. But it's a combination on the expansion CapEx above $200 million. 75% of the $200 million is basically drilling and completion.

Philip McPherson - Global Hunter Securities, LLC

Okay, great. And would that 75% stay consistent into 2012 then?

James Flores

That's consistent for the next 7 years. And now standpoint, it will trend higher toward the end of the 7 years, maybe 50% or 75%. Maybe $225 million, $250 million, $275 million going up as far as maintenance as these fields mature.

Philip McPherson - Global Hunter Securities, LLC

Got you. You have maintenance increases as production increases?

James Flores

Yes, exactly.

Philip McPherson - Global Hunter Securities, LLC

Got you, great. And then just a quick question on the Haynesville. At what point do you think you hit -- that you've got all the acreage in HBP and how much of the 92,000 acres is currently HBP?

James Flores

That's a good question. Here's some detail on that right now. Let's kind of talk year-end 2011. Year-end 2011 we'll have 1,000 units that will be HBP or in the process or drilling or to be hooked up. That would give PXP interest in 7,000 development wells. There'll probably be another 200 units that will be HBP till -- to the second quarter of 2012, about 1/3 to 40% of those will be with Chesapeake. The other 60% will be with non-Chesapeake operators like Petrohawk, BHP, EXCO Encana, Shell and the like, so as our acreage spread. By the end of the second quarter, our plan that we see, is we'll have about 1,200 units, about 8,400 development wells. And at that point in time, then we'll make a decision whether we want to continue drilling any development wells or go forth from there. There are going to be some interesting projects, we think, of people trying to figure out the best way to develop these 6 40s, there'll be some experiment to how low they can get cost in the Eagle Ford now that the infrastructure is in place and how fewer services we can use to drill the wells and how cheap we well next year. So there'll be some of that early in the year and it's all being reflective of gas prices. But we're not talking about $50 million to $75 million worth of changes in CapEx either way. So it's very minute compared to the ramp-up that we're having in the Eagle Ford and those things enforce liquid drilling. In the Haynesville, Haynesville is going to be one of those legacy assets. It's going to be like our California oil production. it'll be a gas asset forever inside this company that can hopefully yield results as prices recover. But the biggest thing that's a challenge to the dry gas business, as all of you all know is the inflation in our industry is being driven by oil prices. And for 30 years, it was driven by gas prices and that's no longer the case. So as long as we're -- we expect next year to spend over 90% of our capital on oil. And so you can see how minute the effects variability of Haynesville may or may not be. So we're spending 90% of our capital at driving revenues and so forth higher, actually going to continue to drive the oil revenues as a percentage of revenues higher even in spite of gas production staying up with our oil revenues strictly because of the leverage we have on the price. So from that standpoint, our gas business, we have our floors in place at $4. We generate nice cash flow at $4. We spend, we're spending all of that cash flow this year on the gas business. Next year, we'll probably spend 60% to 65% of our gas cash flow on the gas business and be diverting more that to our oil production in the Eagle Ford and the Granite Wash.

Philip McPherson - Global Hunter Securities, LLC

Great, I appreciate the color. I think you meant that you said end of 2012, but I think you said in the second quarter. I just want to clarify.

James Flores

Yes. Second quarter the HBP program will be pretty much done. But one more comment on that too is that we're already seeing rigs drop by operators like Chesapeake, I think going to drop 4 to 5 or 6 rigs here by the end of the month. And there's already rigs dropping here in the third quarter, which we are forecasting that earlier in the year, and now and then we changed our forecast to maybe late fourth quarter or year end. I think with their success in other fields and so forth that they're able to pull those rigs out sooner. So we're actually kind of going to accelerate the decline of rigs in the Haynesville here this year and still meet all those objectives of HBP.

Philip McPherson - Global Hunter Securities, LLC

Great and I think in the slide presentation, you're still using $7.5 million for an AFE at the Haynesville. I think if other people have been saying it's obviously higher. Is there -- have you guys locked in something there? Or is that just kind of your original assumptions?

James Flores

No, no. That's an overall project cost of Haynesville. This your -- our current cost are $8.3 million to $8.5 million, but we drilled some wells in there less than $5 million early on when we just tried to drill the development well and see how cheap we could do it. So until we get into drilling development wells and finding how cheap we can really do it, we think the $7.5 million is probably a pretty good number. Because you know what's happening, inflation and if prices stay low and oil prices go back to $60, then these well costs will come down a lot. So it's more of a projected life of the fuel cost. And again these -- our projections on our presentation. I mean we're going to update these this fall with our budget and everything. But right now, these are pretty low prices, with $85 oil and $4.55 gas. So you're going to have true them up with your own commodity price assumptions.

Operator

Your next question is from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Going back to the Eagle Ford with those 2 wells with the highway fracs. Can you talk to the oil, gas and NGL mix of those wells? And whether you think what kind of EURs using those will deliver?

James Flores

EUR, if they continue to produce, yes, the EURs that are significantly higher than what we planned on our acquisition economics. However, let's see some more well history before we start quoting some numbers. But we start talking about doubles, everything is on the positive side from there. This is, remember, we're in the oil, to a bottle of oil to oil condensate window, the real juicy part of it. So in terms of flow rates, we're talking about 1,500 barrels of oil a day and 2 million cubic feet of gas, 2 to 5 million cubic feet of gas situation. So we're a lot more liquid than we are gas in these areas and NGLs and so forth are minimal since we're talking about mostly oil versus condensate.

Brian Singer - Goldman Sachs Group Inc.

Got it. And I guess as we look forward to future Eagle Ford drilling, what percent of that should we expect that you're going to try the highway frac versus what you've been doing in the past?

James Flores

I don't know. We got to talk to Schlumberger before we make that comment. The answer is -- the exciting part about this technology is going to be spread thru the industry as more technology comes across there. Where it's really going to pay off is when we get all our facilities up, when we do some more dedicated focus on using this on a production basis. So we look across at our 500 to 800 well locations, I mean because we are planning on having 1,200 -- put spacing between the laterals. And now with several of the operators going to 600 feet between laterals and being very successful, we see our well count going up from what it -- presentation in the Eagle Ford, and now with our productivity really having an opportunity to take a technological leap. Obviously, we're going to scramble and kind of redo some plans and do as many of these as we possibly can.

Brian Singer - Goldman Sachs Group Inc.

Okay, thanks. Shifting to the Granite Wash, I think you responded earlier in focusing people's attention on some of the facilities that allowed production to increase quarter-on-quarter. Can you talk a little bit about that well performance there and whether that was a contributing factor or not to the sharp increase?

James Flores

It really hasn't been, Brian. We've been very consistent at Granite Wash as far as going through our 7 Granite Wash zones, the 7 to 12 really, that we have identified. We figured about 5 of them would be really, really spectacular. It's about where we came out, as far as identifying which ones would be good reservoirs. And we've got 2 or 3 Atoka washes. We're talking about good, big economic reservoirs at competitive rates of return with the best zones in the Eagle Ford, in the Granite Wash at these prices. And so our inventory is still deep 2 or 3 years there to get that done. We are seeing some additional liquids reservoir possibility in the Panhandle, not necessarily in the Granite Wash. We'll probably talk about in the third quarter, and some of that contribution may be helping here in the third quarter. So we could actually be getting more liquids-rich going forward in the start of third and fourth quarter, as our drilling kind of unfolds up there in the Panhandle, as we're finding additional zones beyond just the Granite Wash. So with the facilities and the leverage we have on the facilities side, we can handle a lot more production. And really the key about it is the Granite Wash as far as development is about a year ahead of the Eagle Ford. So you can see as we accelerate the Granite Wash because of our facility leverage and the number of wells and the way things are working out there, I fully expect to see the same type of results out of the Eagle Ford in the second quarter next year, as we get the most of our facilities built. And that's really the correlation that draws -- is where each one starts hitting the operational sweet spot. It's about a year away for the Eagle Ford. As good as those results are starting to come about, and as much iron as we're moving down there, we're still got a long way to go before we hit peak performance.

Brian Singer - Goldman Sachs Group Inc.

And lastly, you mentioned in your comments the significance of when Lucius gets sanctioned. Is that significant enough where one needs to wait for that to happen before closing the financing? The deepwater financing? Or should we expect that the deepwater financing could close prior to sanctioning of Lucius?

James Flores

I think you'll hear about announcing the transaction way before we actually close it. And closing, obviously, the Lucius sanction will be a condition to closing, which is just we have a timetable, it's going to be sometime in the fourth quarter before that happens, the closing. But you'll hear way before then as far as what the transaction is all about.

Operator

Our next question is from Nick Pope of Dahlman Rose.

Nicholas Pope - JP Morgan

I was curious on the Eagle Ford, like you give those July rates. How many wells do you currently have producing the Eagle Ford at this point?

James Flores

Hance, you want to help them out on that a little bit?

Hance Myers

Nick, we have...

James Flores

EOG wells, we got oil wells, net-net-net...

Hance Myers

Big combination. Most of these wells are EOG wells. They started before we drilled a well. So I would say it's probably about -- we have about a dozen wells and the EOG probably 20 gross, 10 net to us.

James Flores

Yes, so 20, 22 wells, so...

Nicholas Pope - JP Morgan

And just when you look forward to like the Lucius development, that reservoir, how many wells you think ultimately are going to needed to exploit the reservoir kind of as you see it at this point?

James Flores

Well we got tons of engineering horsepower in this thing, Nick. So I don't have to make that call, but I'm hearing 5 to 7 to only the Pliocene reservoirs. Our Miocene reservoirs that Exxon talked about, they found additional pay in their well correlate to the additional Miocene penetrations we have on our acreage. The Miocene reservoir may take another 5 to 7 as well. So and they obviously -- they're on top of each other, it just depends on the completion. So I would say initial development 5 to 7, but probably there's a redevelopment phase, we drill 4 or 5 more over time depending on the reservoirs. And if the Miocene continues to draw up, then we start pushing the upper end of the range from our perspective on the 300 to 500 range. The additional 200 million barrels over the 300 million was basically Miocene focus. So from what we see, we see that's very realistic at this point in time, and that's going to require some more take points from the Miocene or we may be able to do it all with the same well combinations, it just depends on how the engineers figure it out.

Nicholas Pope - JP Morgan

Okay. And when you look at like this, the whole unitization agreement that you have in kind of nearby fields with Exxon, like which fields do you have the direct ownership in versus the partnership, I guess that's going to be bringing gas into the facilities?

James Flores

You got to think about it this way. We're in Lucius, okay? We are in Lucius. Now, Lucius facility will process other people's gas. So when you hear about it processing gas like Hadrian North, Hadrian South. And whatever else it does, I mean, all that's going to do is drive down our LOEs at Lucius. So if you're using a traditional $10-barrel LOE at Lucius, you may want to cut that in half. And so you're talking about one of the most economic projects in the world with 4, 5 to 7 wells and LOEs that are supported and sponsored by third-party processing and royalty relief. It just doesn't get much better with this kind of project.

Operator

Your next question is from David Hakkinen of Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Just a couple of quick follow-ups. On the Mowry, your first well was drilled at what vertical depth? And your second well is obviously a deeper depth I'd assume?

James Flores

We're in a middle of an exploration program. We're not going to build them.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

So you're expecting to gas or some energy in the second well there?

James Flores

We're hoping. We need more energy than we had in the first well, how's that?

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Fair enough. And then the Haynesville, still expecting production to grow in the second quarter and -- or from the second quarter to the third quarter, and then third quarter to fourth quarter, with this current activity level?

James Flores

Yes. The key thing you said was current activity level. I mean obviously if completion activity or frac crews drop off, then that will change. But right now, we're seeing an increase.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Basically your guidance still is flattish in '12 and then growth again in '13.

James Flores

Well, it's not guidance. It's just more projections. haven't given any guidance for '12, because we don't -- we got to get our plans together with our operators and figure out exactly what it's going to be so we can get you some intelligent guidance. But that is the latest that we know at this point.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And then the Lucius development. Just want to make sure I'm understanding this. So the Miocene zones that were found at Hadrian North correlating those to Lucius, if they keep being found, could take you to the 500 million-barrel potential for just Lucius?

James Flores

In both the Pliocene and Miocene, that's combined.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

You add a couple of hundred million...

James Flores

We didn't include the Miocene in our earlier thought process, as far as reserve potential other than the gap between 300 and 500.

Operator

Your nest question is from Brian Corales of Howard Weil.

Brian Corales - Howard Weil Incorporated

Just back to the Eagle Ford, I mean is there any hindrance out there that outside the commodity price that you can't get to 10,000 barrels a day at year end?

James Flores

No, the way to answer the question if I stay out of the it and don't get too involved, yes Brian, I know what you mean. If I leave it up to Dawson and the boys, yes, it's going to be fine. There's no fiscal impediment as far as marketing of the type of thing of rigs, no...

Brian Corales - Howard Weil Incorporated

Okay. So completion delays, I mean you all have the contracts, you're not seeing any major delays.

James Flores

Let's put it this way. That should be a well-engineered number. Short of a South Texas ice storm, I think we're in good shape.

Brian Corales - Howard Weil Incorporated

And then finally, is all your oil going through Shell to get LLS prices or just...

James Flores

That will be by year end at this point in time. Right now, we're splitting it up between 2 or 3 of the Corpus Christi refineries and getting those same type prices. But it's all short term. That's why we haven't [indiscernible]. But that'll start in the first quarter next year for 5 years under that scenario.

Brian Corales - Howard Weil Incorporated

Okay. And then you mentioned earlier improving the balance sheet and obviously there's some financial things you can do in terms of selling assets. But have you all looked at selling any operating assets?

James Flores

No, we're fine there. Those assets, we have plenty of financial assets and the way our bonds are trading and so forth. We've got plenty of opportunity and people. Our bondholders are seeing the strength of our revenues from the oil side and the credit facilities and so forth. As our credit improves, I mean that's traditional finance, right? Winston, you want to cover that?

Winston Talbert

Basically, where we are and what we've talked about is reducing our debt, around $500 million. And that's kind of where we're focused on and we've got a couple of assets that can do that. And if you look at the strength of the interest rate and the yield curve, there's quite a bit of money that we could pick up refinancing the debt probably later this year. We are looking at a lot of different scenarios and trying to figure out when the best time is, we've got our bond that we can call. We've got another bond that is callable early next year. So we've got all opportunities to drive a lot of interesting things around here.

Operator

The next question is from Marshall Carver of Capital One.

Marshall Carver - Capital One Southcoast, Inc.

Just a couple of questions. Most of my questions were answered. But on the, you've had the CapEx increase from 1.2 to 1.5 and certainly rates are looking stronger heading into year end. You kept your long-term targets, the 3-year plan at still 10% to 15% growth. With the higher activity, how should we think about long-term goal? Will you now be towards the high end of that? You were at the low end before. Or was it more of an oily mix? Or how do you think about that?

James Flores

That question, I would think about it this way, Marshall. You'll have definitive answers midway in the fourth quarter this year, when we announce our 2012 budget with redone production. So you would think about that comment reflecting kind of our stale $85 forecast you see in our presentation. So what I'm basically saying is you're going directionally the right direction. Adding this kind of capital, which is direct drilling and production capital, where you should see responses that we should see the appropriate production responses that would be north of those numbers. But it's a matter of whether it is talking about a 3-year outlook, we haven't fully engineered that yet. We're 60 to 90 days away from having that all internal. With our budget process, that puts it at 120 to 140 days away from explaining to you guys. But directionally, the math would point higher.

Operator

Your next question is from Joe Magner of Macquarie Capital.

Unknown Analyst -

Any results that you're aware of on the deeper drilling at that Lucius appraisal well Exxon was working on?

James Flores

Yes, we get drill reports and so forth. So we're very pleased with that, of how that well is drilled out and so forth. And Exxon's the operator. We always yield to those guys as far as -- we'll go to the operators for well results. But you heard some of their comments talking about the Miocene plays and the additional base on the Pliocene and so forth. So it's a spectacular reservoir, spectacular field. We're very happy to have 23.3% of it.

Unknown Analyst -

Okay. And I might missed this. The initial results in the Mowry, can you provide any additional information on that and just kind of what the go forward plan is?

James Flores

No, we did in the strip is that we test the first well, we've tested some high-quality oil out of it but small amounts. We're drilling, we're completing the second well here and testing it. And then we plan on 2 more wells the first quarter next year to try to evaluate our lease block and so forth. We have some geologically encouraging results. We don't have any commercially encouraging results yet.

Operator

And there are no further questions at this time.

James Flores

Thank you, operator. Thank you, everyone. We will continue to do good work year and more news to come in the third quarter. We'll see you October. Goodbye.

Operator

Thank you for participating in today's conference call. You may now disconnect.

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