Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Scott D. Winters - Former Vice President of Corporate Communications

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

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

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

Analysts

David W. Kistler - Simmons & Company International, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

Eric B. Anderson - Hartford Financial Management, Inc.

Plains Exploration & Production (PXP) Q3 2012 Earnings Call November 1, 2012 9:00 AM ET

Operator

Good morning. My name is Jessica, and I will be your conference operator today. At this time, I would like to welcome everyone to the PXP Third Quarter Earnings Results Conference Call. [Operator Instructions] I would now like to turn the conference over to Scott Winters, Vice President of Corporate Planning and Research. Mr. Winters, you may begin.

Scott D. Winters

Operator, thank you very much. 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. We have posted a slide presentation to supplement our comments this morning, and we may refer to the slides during the call. The webcast, slides, 10-Q and today's press release are all available on our website, pxp.com, in the Investor Information section.

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

In our press release 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 in the press release. Please take a minute to review the reconciliations.

Also, references to oil revenue and sales -- and oil sales volumes in the press release and in our prepared comments this morning include natural gas liquid volumes.

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

For the 3 months ended September 30, 2012, PXP reported a net loss attributable to common stockholders of $53.1 million or $0.41 per diluted share compared to a net loss of $88.3 million or $0.62 per diluted share for the 3 months ended September 30, 2011. The third quarter net loss includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, resulting in a net loss of $100.2 million due in large part to increased crude oil forward prices, a $43.1 million unrealized loss on investment in McMoRan Exploration Co.'s common stock and other items.

When considering these items, PXP reports net income attributable to common stockholders of $51.6 million or $0.39 per diluted share. This is a non-GAAP measure. Some quarterly highlights comparing third quarter 2012 to third quarter 2011 results include: oil revenue increased 43%; total daily sales volumes per diluted share increased 10% or 36% pro forma for the December 2011 asset sales; oil daily sales volumes per diluted share increased 36% or 56% pro forma for the December 2011 asset sales; operating cash flow increased 27%, this is a non-GAAP measure; cash margin per BOE increased 28%, this is also a non-GAAP measure.

Oil revenues increased $161.3 million to $540.4 million for 2012 from $379.1 million for 2011, reflecting greater sales volumes and higher average realized prices. Oil sales volumes increased 12.6 thousand barrels per day to 63.5 thousand barrels per day in 2012 from 50.9 thousand barrels per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestment, sales increased 19.4 thousand barrels per day in 2012. Our average realized price for oil increased $11.48 per barrel to $92.44 per barrel for 2012. The increase was primarily attributable to our new marketing contracts effective January 1, 2012 for our California and Eagle Ford crude oil production.

The average ICE Brent Index price for 2012 was $109.37 per barrel compared to the average NYMEX index price of $89.54 per barrel in 2011. Gas revenues decreased $58.4 million to $62.6 million in 2012 from $121 million in 2011, primarily reflecting lower average realized prices and sales volumes. Our average realized price for gas was $2.70 per Mcf in 2012 compared to $4.10 per Mcf in 2011. Gas sales volumes decreased 69.3 million cubic feet per day to 252 million cubic feet per day in 2012 from 321.3 million cubic feet per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in 2011, lower drilling activity in the Haynesville Shale, which was partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestment, sales increased 9.5 million cubic feet per day in 2012.

Lease operating expenses increased $18.1 million to $98.1 million in 2012 from $80 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, greater stock-based compensation expense resulting from an increase in the price of our common stock, increased diesel fuel cost at our Point Arguello platforms and increased well work-over expenses primarily at Inglewood property, partially offset by our Panhandle and South Texas properties, which were divested in December of 2011.

Steam gas costs decreased $4.9 million to $12.1 million in 2012, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.2 Bcf of natural gas at a cost of approximately $2.88 per MMBtu compared to 4.1 Bcf at a cost of approximately $4.18 per MMBtu in 2011.

Production and ad valorem taxes increased $10.5 million to $21.1 million in 2012, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, again, partially offset by our Panhandle and South Texas properties, which were divested in December of 2011.

Gathering and transportation expenses increased $4 million to $19.2 million in 2012, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Eagle Ford -- at our Haynesville Shale properties, partially offset by our Panhandle properties divested in December of 2011.

General and administrative expense increased $11 million to $39.2 million in 2012 primarily due to costs associated with the Gulf of Mexico acquisition and greater stock-based compensation expense resulting from an increase in the price of our common stock.

DD&A expense increased $102.7 million to $270.6 million in 2012. The increase is attributable to oil and gas depletion, which reflects a higher oil and gas unit of production rate. The oil and gas unit of production rate was $27.21 per BOE in 2012 compared to $16.86 per BOE in 2011.

Interest expense increased $15.7 million to $59.2 million in 2012 primarily due to a decrease in interest capitalized and greater average debt outstanding, partially offset by lower average interest rate. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $10.7 million and $27.9 million of interest in 2012 and 2011, respectively.

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 in mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements on the contracts result in making a payment to or receiving a payment from the counterparty. We recognized $100 million -- $100.2 million loss related to mark-to-market derivative contracts in the third quarter of 2012, which was primarily associated with the decrease in the fair value of our crude oil and natural gas derivative contracts due to increased forward pricing. In the third quarter of 2011, we recognized $125.6 million gain related to mark-to-market derivative contracts.

At September 30, 2012, we own 51 million shares of McMoRan common stock. We've elected to measure our equity investment in McMoRan at fair value, and the change in the fair value of our investment is recognized as a loss on investment measured at fair value in our income statement. We recognized a $43.1 million loss in the third quarter of 2012 related to our McMoRan investment, which was primarily associated with the decrease in McMoRan stock price. In the third quarter of 2011, we recognized the $395.5 million loss related to our McMoRan investment.

For the full year of 2012, PXP's total capital spending is expected to be approximately $2 billion, of which approximately $180 million is funded by Plains Offshore Operations Inc. The increase in PXP's capital spending over its base plan is attributed to oil and gas capital and seismic data acquisition capital for development and drilling activities of the Gulf of Mexico deepwater assets to be acquired and to accelerated development activity in the Eagle Ford Shale. Higher spending in the Eagle Ford Shale is leading to an approximate 78% increase in wells drilled and a 25% increase in the average daily sales volumes over the 2012 base plan. PXP's 2013 capital spending is expected to be approximately $2 billion, including capitalized interest and general and administrative costs.

We expect full year 2012 average sales volumes, excluding the sales volumes associated with the Gulf of Mexico acquisition, to be slightly above the revised guidance range of 95,000 to 97,000 BOE per day. We revised our sales volume guidance in August of 2012 from the original guidance of 92,000 to 96,000 BOE per day due to the anticipated sales volumes increases in the Eagle Ford Shale. Now including 1 month of sales volumes associated with the Gulf of Mexico acquisition, PXP now anticipates full year 2012 sales volumes to be approximately 103,000 BOEs per day.

PXP continues to implement its crude oil hedging program. We've reached our stated goal to protect up to 90% of expected crude oil sales volumes for 2013 and '14 estimated volumes and are well underway in achieving the 90% goal for 2015 volumes. And finally, we successfully secured $8 billion in total debt financing for the $6.11 billion Gulf of Mexico acquisition at a weighted average cost of debt of 4.8% as of October 29 this year. The company remains on track to close the acquisition by the end of November 2012.

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

James C. Flores

Thanks, Scott, and good morning, everyone. I'll go through some brief operational comments, and we'll turn over to Winston, since it's been a very active financing quarter and in connection with our Gulf of Mexico acquisition and all the bond offerings since then.

First, hitting the CapEx raise on the Eagle Ford and also the Gulf of Mexico. The Eagle Ford first. We've had a very consistent program out at Eagle Ford, and the efficiencies that we've gained in the Eagle Ford have caused us to continue to drill more wells. Our original plan that we announced at this time last year was to drill 83 wells in the Eagle Ford. We drilled 148 with a smaller rig fleet than what we'd planned. We had planned an 8-rig fleet. We've had a 7-rig fleet for most of the year, and we drilled 148 rigs. How do you do that? Drilling efficiencies. Our rig days have dropped 80% in 12 months. We've gone from 35 days down to 16 -- 16, 17 days per rig on the drilling to prove those efficiencies that have caused us to drill -- have the ability to drill more wells, become more efficient, frac-ing closer and quicker. And obviously, when you do that, you put more casing in the ground, you're performing more frac, and what you want to see is the response in the production ramp-up. Our production ramp-up has been tremendous this year. Well, it looks like, on average, somewhere around 27,000 barrels a day. That's above what we thought we'd exit at 25,000 barrels a day.

Our current exit rate forecast is between 34,000 and 36,000 barrels a day. We think we'll be comfortable hitting that, and we're looking for an average rate higher than -- somewhere between 36,000 and 40,000 barrels a day average rate next year over the increase of the 27,000 barrel a day average rate in 2012.

The interesting part about our CapEx is about 25% of our CapEx is fully loaded for facilities costs. And those facilities, we've built a tremendous amount of facilities here in 2012 as we've forecast. The facilities that we've built in 2012 are 13 total facilities. We call them our super facilities. Well, they'd pick up to 40 wells over a period of time. That brings -- that's 13 out of our 21 total, and presently, we are forecasting no additional facilities in 2013. I'm sure that will cause us to build at least one. So if you had a pro forma one facility, I'd do that because they have 0 facilities. With the amount of activity, we're always going to find some way to efficiently produce our barrels by adding more facilities.

So if you take the facilities costs out from the 2012 CapEx of about 1 point -- or $1.92 billion -- or $1.2 billion, that's how you look at our 2013 drilling cost or CapEx cost at $873 million, and you get 124 wells versus the 148 that we drilled this year when you pencil it out just on our well cost. But I expect more efficiencies and to have about the same number of wells for the $900 million we're going to drill in -- that we had used to drill in 2013 that we spent on the $1.2 billion in 2012, which include a tremendous amount of facility costs.

Frac costs are going down. Well costs are steady because we're using that cost savings as extra incentive to be innovative with our well designs, with our lateral lengths and also with our number of fracs and number of stages on a per well basis. And our guys have just done a fabulous job of being very efficient. We don't have a backlog for completion. Oil is $110 down there, and they are producing every barrel we can as fast as we can and drilling every well as fast as we can. The latest record drill time for us in the Eagle Ford was 11 days. That's 11 days to drill a well, and you could put a lot of steel in the ground when you work that efficiently. From our additional -- initial 45-day projections last year, it was 35, and you see our efficiency just accelerating. The guys have just done a fabulous job and done it very safely.

So moving from the Eagle Ford into the Gulf of Mexico, we had -- there's a planned purchase of seismic that we made in the Gulf of Mexico, plus we're accelerating some of the maintenance work while BP continues to operate the properties before we close the properties. We close on the acquisition, remember, on November 30 or December 1. So right now, all spending is on -- or prior to the effective date, October 1, the spending was on BP's nickel. And then in the -- and here in the fourth quarter, any spending will be offset by the revenues, and also, the revenue to the purchase price adjustment and the $90 million of CapEx, mainly seismic costs, will be attributable to that same revenue stream So from our standpoint, it would be a purchase price adjustment, and be not affected. But it is calculated as CapEx in our CapEx budget, and we want to get that seismic up and working and get our geoscience, so we can be prepared for all the opportunities and prepare for our drilling program going forward.

Those are the 2 major adjustments. Everything else is static in our business. California is doing great. Our realizations continue to be very strong with our Brent-linked pricing of -- we're seeing prices of $110. As long as we're seeing $110, we're going to continue to drill as many wells as we can and stay within our financial parameters to drive as much production as possible and hedge it accordingly, so we can drive as many -- as much cash flow and earnings to this business.

So with that, we'll answer questions after this, but I'll turn it over to Winston and let Winston go over the financing -- the financials activity this quarter, and then we'll get back for questions. Winston?

Winston M. Talbert

Yes, Jim, if everybody noticed, we went out and finished up our financing for the deepwater acquisition. If you look on the handouts we gave, we basically raised $8 billion. We're going to end up spending about $3.2 billion of secured financing for these properties and then $3 billion of unsecured. This is a little different than when we started. Because the bond market was so good and the rates were so low, we went ahead and secured about $1 billion more of unsecured debt. This will give us a lot more flexibility going forward. We have somewhere between $1.4 billion and $1.5 billion of liquidity at closing. Then we're going to have $1 billion of free cash flow plus the $1.5 billion of liquidity, so we'll have plenty of liquidity in 2013 and beyond.

And then we moved fairly rapidly to get our hedges in place. As you know, we finished the 2013 program. We finished 2014 program, and we're about halfway through with our 2015 program. We're just a little over halfway done. So we're very pleased with where we are. And then we're going to take those hedge revenues and pay down debt. We're also going to immediately launch into our asset divestment program to raise about $1.5 billion to $2 billion of cash. So we're going to utilize the free cash flow that's hedged and the asset sales to drive down long-term debt. We've got plenty of secured debt to pay down. And then starting next year, we're going to have a lot of our unsecured debt. It's going to become callable. So we've got plenty of flexibility in our call schedule and then our revolver and term notes to pay down, so we'll be able to pay those down very, very efficiently. So we're pleased to complete our program. All the money is ready to close the transaction, and we look forward to next year and paying down debt.

James C. Flores

Operator, open up for questions. Thank you, Winston.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, diving into that CapEx change a little bit more, if I exclude what's being paid by Plains Offshore Operations, it's about an uptick of approximately $200 million. Can you break that out specifically what's Eagle Ford, what's Gulf of Mexico? And then am I understanding it correctly that you're kind of saying that self-funding from the production uptick from both the Eagle Ford and the Gulf of Mexico, just round number, say, an additional 6,000 barrels of oil equivalent a day times your net backs on that effectively equates to about $200 million?

James C. Flores

Yes, if anything, your production number is a little low, Dave. We plan on making some money off of it. But you're talking about $90 million going to the Gulf of Mexico, which is seismic and some well maintenance, mostly seismic, $78 million of seismic and $12 million of well maintenance and the rest is Eagle Ford.

David W. Kistler - Simmons & Company International, Research Division

Okay. That's helpful. I appreciate that. And then on California, just noticing trending down a little bit more. Is that related to similar to last quarter, the natural production interruptions that take place as you continue to drill that out, and do you see that abating in the near future? How does that impact kind of our outlook into '13?

James C. Flores

Yes, I mean, it's just our seasonal slag, and you're looking at -- see all the drilling that we've done and all the heating and all the well stimulation that we've done in production going up here in the fourth quarter and first quarter and second quarter of next year. And as we put rigs in there, we will continue to see it do the wave, we call it. And so that's normal operations, but production in California is getting stronger and stronger at its own pace right now.

David W. Kistler - Simmons & Company International, Research Division

Okay. And then last thing in the Haynesville, I know you guys have no operated rigs working there, production kind of ticking up a little bit. Is that a result of maybe relieving any curtailments? Should we read anything into that in terms of how you guys are thinking about gas outlook, et cetera? And does that impact anything with respect to divestiture of that asset over time?

James C. Flores

You don't buy the fact that it's just magical? It happens when you don't put your money in production [indiscernible], okay? No, it's not magical. It's reversals of temporary curtailments. Most are on the marketing side, not directed curtailments, it's just marketing bottlenecks that got opened up. And that's what I'll say on the gas side, just the people who continue to find ways to produce gas cheaper. And that's part of big deals like the Eagle Ford and Barnett and so forth. They're not going to go away. So there's a lot of ways to de-bottleneck compression. There's a lot of ways to de-bottleneck some of the marketing stuff they had to do, get this gas flowing easier and better, reduce the well head pressure, [indiscernible] these wells continue to flow at longer and higher rates. So I mean, I think if anything, fundamentally, our change on gas -- gas doesn't change, but there's always the weather phenomenon, which everybody understand at the Northeast. The weather -- we're getting to a point where the weather may affect it, and you see a super winter, it can change the gas price. But it still doesn't change the outlook for oil prices giving us better returns than the gas business next year or any going forward for the next 5 years, so our plan stays intact.

David W. Kistler - Simmons & Company International, Research Division

Okay. Any comment on the divestiture thought on that?

James C. Flores

We've sent out a lot of CAs [ph]. I think it's premature. We have to be really solid on that, on our partner's commitment for confidentiality, but the process is ongoing. We're looking forward to a busy November and early December to get something announced.

Operator

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

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

I just wanted to dive into Eagle Ford a little bit more. You talked about drilling 148 wells this year, and you're going to lower that amount in 2013. Just I want to get a sense of kind of the rationale for somewhat slowing down the wells you're going to drill there.

James C. Flores

Well, history will tell you that we plan on drilling 83 wells in 2012 and we ended up drilling 148, okay? So when we say we're going to drill 124 wells, that's our current plan or current cost and current rig times and so forth. But if these guys continue to get more efficient, continue to drill faster, we start averaging 12, 13 days per well, you can see that rig -- that well number get up to 148. We've got to put some kind of budget governor on this thing because otherwise, we'd be drilling 200, 250 wells a year. So our aspect is control the capital and well and rig count, but just controlling the rig count is not slowing down the well count because these guys are doing a better and better job and they're going to be compensated for it. So don't read a lot into -- I would assume 124 to 148 wells as an average for next year, some more flat on the well count, and that's going to be representative of our production increases for '12 and '13. So we give you the best data we've got, but if these guys drill wells faster, we're not going to let the rigs go because they're doing a better and better job with oil prices at $110.

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

And it's helpful, for sure. In terms of your costs, can you just kind of give us some color where you're seeing the Eagle Ford well cost now? And I know you guys talked about an expectation of them sort of moving down into '13. Maybe just put some numbers around that. It'd be helpful.

James C. Flores

Sure, sure. We're about $8.5 million of well drilling complete, with another $800,000 for facilities, and that's the part that drops off next year, okay? So if you total up for drill complete and facilities, about $9.3 million, okay? We're saving $0.5 million on our frac cost going forward and other services as we get more efficient. So we hope to be around $8 million or less on drill complete going forward.

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

Okay, great. And I guess additionally, any sort of update on down-spacing tasks that you guys may have participated in or did yourself?

James C. Flores

I think everything you've heard has been consistent, has been very positive and so forth. You just got to do it right. The only tricky part, which is normal, is you got to stay away from the faulting, and our faults that we have in between -- really on the boundaries of our acreage since we have the center of the glob and just make sure you do a good job there. Our drillers have done a fantastic job of keeping that type of communication to a minimum and also on the standpoint of making sure we stay in the most porous zones. It's really the lenticular aspects of the Eagle Ford or really the fine-tuning. Our guys are realizing what zones are the best producers and the best porosity and so forth and have the best performance, and they don't need a frac near as big a wing but just need to have the wellbores in zone, and also a number stages will really be the big variables. But we just can't talk enough about how pleased we are with the operations down there and all the progress and how everybody's just done a great job.

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

Well, it's good to hear, for sure. I guess just switching gears to Gulf of Mexico, you talked about accelerating some seismic into 2012 to get a better handle on what you guys are seeing there. With that implied, that you guys might accelerate some of the drilling activity, I know you're not really planning on getting at the BP properties until kind of late '13. Could that imply sort of maybe a pickup in '14 or '15 on some of that, depending on how kind of pricing shakes out, if you like what you see?

James C. Flores

Well, yes, I think it relates more to lease sales and that type of thing versus initial drilling activity. We're moving very quickly. We really appreciate the vendor response and supplier response to our acquisition. They've all rolled out everything they could as far as helping us as far rig availability, understanding our needs and plans and being thoughtful and understand. We're going to be thoughtful as well, and the entire service community has really welcomed us open arms as far as an opportunity to get our business done. And so we're very pleased with that. You'll hear more about how the business is ramping up faster than what we planned. Obviously, we planned very conservatively. This is a big business. Just like we planned the Eagle Ford very conservatively. It's gotten much stronger, much better toward the high side of our cases. So we think we have it well planned not to disappoint, but well planned to make sure you're impressed by the ability of us to execute our business in the Gulf of Mexico. So that's kind of a vague answer to a very pointed question. Just trying to be vague. Just stay tuned.

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

Got you. And I guess lastly, any update on the Phobos' timing of spud?

James C. Flores

No specific update other than we're hearing whispers of November.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to follow up on Haynesville. It was asked earlier, but you've had production that's been kind of flat here, if not up, for the last couple of quarters. You are forecasting a decent decline here between now and year end, and I think that's something that people have theoretically been waiting for. But what gives you the confidence that, that decline is actually coming and you're not susceptible to some of the improvements in productivity that you think is happening across the chain?

James C. Flores

Well, Brian, I got to tell you not all of us agree on the declines, okay, in this room. But we are bound by engineering principles, and when you stop spending money in a gas field that has a decline rate like -- off of our low base in Haynesville, we have all have to -- we all have to abide by the gravitational pull of those decline deals. And I'm lecturing my reservoir engineer right now as we speak, Brian. I appreciate the question. However, it's hard to pro forma the abilities of the talented production hands of Chesapeake to keep our production flat to up, and they've done a spectacular job. And my money's betting on them as there's a tremendous amount of opportunity there on the surface and de-bottlenecking and compression issues and things like that, just like the Barnett didn't decline here as much as everybody thought. So stay tuned and we'll see. But we're bound by engineering in our forecast, and that's what gives us confidence. We can look at you and say these numbers are conservative and they're well thought out.

Brian Singer - Goldman Sachs Group Inc., Research Division

And so when you look at where you're at today then, where you say you are versus the third quarter average or you're expecting the decline to happen between now and the end of the year?

James C. Flores

Yes, it's going forward, Brian.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then on the Eagle Ford, you did talk to the backlog of wells in your release. I think it was about 35 or so. Can you talk to how that changes and whether you expect that to fall over the next 6 months, or just because of the drilling program and momentum, it's kind of stayed flat?

James C. Flores

I think it falls because of the efficiency, and the amount of frac equivalent, completion equivalent is pretty strong. Doss, do you want to make a comment?

Doss R. Bourgeois

It's kind of cyclic because with the number of rigs we have and as quick as they're moving. There's days where we're moving 4 rigs at a time, so you're having 4 wells that come offline, so you'll have a little ramp-up. Today, we're catch -- we said 35. We'll frac 8 or 9 in the month, so it drops back down. They're going pretty quickly, so it just -- it kind of bobbles right in there.

James C. Flores

It's hard to call it a backlog. It's more just like in the completion process.

Doss R. Bourgeois

When we have -- on these pads, we have multiple wells on the pads, so you have a pad that has 2 or 3 wells on it. You can't frac them until you move the rig off, so...

James C. Flores

How many wells did we bring on the other day? 12?

Doss R. Bourgeois

12 wells.

James C. Flores

Yes, and we topped that at 40,000 barrels a day as a 1-day rate. So it gets lumpy, like we told you. And so you're in a situation where the inventory really [indiscernible] 12 in 1 day or 10 in 1 day.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then lastly, you may have mentioned this in your opening remarks, but just maybe for my own clarification, what are the specific savings on capital cost next year from not having to construct the facilities that you constructed this year? I apologize if you mentioned that number already.

James C. Flores

It's about $300 million. If you took out the facility costs in 2012 of $1.2 billion, so on a per well basis, it's about $800,000 a well on the 148 well plan, which incorporates -- which is 13 facilities. So 13 facilities, 148 wells, that is $800,000 a well.

Operator

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

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

Just a couple. Most of my questions have been answered. On the original plan, the 83 wells and now the 148 in the Eagle Ford, were those gross or net numbers? And if it was gross, could you give us the net number?

James C. Flores

It's gross. On a percentage basis, right, how many wells at EOG? He's looking at it.

Scott D. Winters

70 out of 148 were 50%, whether they're EOG or operated.

James C. Flores

Yes, okay, so about half were -- 50% of wells and half are ours.

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

Okay. Do you have a number of net wells...

James C. Flores

80 were 100% and 70 were -- it's a little more than half.

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

Okay. On the number of wells completed, the net wells completed in the Eagle Ford in the third quarter, do you have that number?

James C. Flores

And you got to do just some heavy math. Why don't you give it to him, [indiscernible]?

Scott D. Winters

For annual, which would include even our projections in the fourth quarter, 118 net completed wells.

James C. Flores

Is that gross or net? I know the next question.

Scott D. Winters

That's net.

James C. Flores

Net 118 wells.

Operator

[Operator Instructions] Your next question comes from the line of Ron Mills with Johnson Rice.

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

Sounds like that spud may get moved up a little bit versus most recent expectations.

James C. Flores

Ron, we missed the first part of your question.

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

I'm sorry. On Phobos, I was -- it sounds like it could spud in November, maybe a few weeks early. What's the expected time frame in terms of -- to get that well drilled?

James C. Flores

We drill [indiscernible] rate of 30,000 per well, so it's a 120-day well. Standard, that's standard well. Obviously, the Pliocene is probably 45, 60 days from spud, and then Miocene as we go on down, so they'll be exciting things on the way down that we'll be thinking, still total is 120 days.

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

Great. And secondly, on the gas asset sales, it sounds like the process is ongoing, no real change in timing. But I don't know if you -- there was -- I think Bill Barrett sold some gas assets to an MLP today. I just want to reconfirm. The $1.5 billion to $2 billion in asset sales you talked about next year also include some potential monetization of McMoRan. Is that fair?

James C. Flores

Yes, Ron. Remember, our guidance is $1.4 billion to $1.6 billion. So we're saying, even including the McMoRan shares and the Haynesville and the Madden, $1.5 billion is our target. I know if you add them up on value, you get a higher number, closer to $2 billion. But $1.5 billion is our target.

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

Okay. I bring it up because I think today's transaction was priced somewhere between $6,000 and $7,000 per flowing M [ph]. And with your Paleogene holding up how it has and Madden holding steady, it seems like you can get a lion's share of that from a gas sales standpoint, at least, from my estimate.

James C. Flores

And obviously, with the development in the Haynesville and so forth and perpetuality of the Madden, we think it's worth a lot more than that. But we were willing to sell it at market plus a premium, so it works out fine. Not that we're trying -- not that you and I are trying to price this deal right now, okay?

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

I'll write the check. Just as it relates to California, the production rate, seems like it will be holding steady there. If you glance into 2013 relative to that 38,000 to 39,000 barrels a day range, is the expectation there still for kind of flattish production or growing a little bit, or do you have any incremental growth plans in California for next year?

James C. Flores

We have it growing 5%. Well, 38,000 to 40,000 barrels a day.

Operator

Your next question comes from the line of Curtis Trimble with Global Hunter Securities.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

I have a question. As you bring on the Gulf of Mexico acquired production, can you talk a little bit about changes in the expected operating expense profile?

James C. Flores

Yes, well, Curtis, it's a great question. The operating expense profile obviously go down because of the lower operating costs in the Gulf of Mexico versus, say, California and so forth. And the big thing about that is as we drive production volumes over time, we do everything on 5-year models here, and it will drive LOE costs down 50% in the next 5 years company-wide. And the big thing is like right now, the last 3 quarters, our margin, our gross margins have been somewhere around $35 a barrel where prices are today, which have been great. In the fourth quarter, we add the Gulf of Mexico production. Our gross margin jumps to $42 a barrel, and in '13, just at static prices, it's around $58 a barrel. So we're not only talking about reduction in LOE costs, you're talking about just the margin barrel. Our company gets tremendously more efficient and obviously becomes a big earnings generator next year because of our margin expansion in 2013.

Curtis Ryan Trimble - Global Hunter Securities, LLC, Research Division

I appreciate it. Then one other looking at the Eagle Ford. Have you participated to date in any of the Pearsall tests? I think you guys included a little bit a of a sort of hard circling amongst perspective acreage for the Pearsall.

James C. Flores

We're going to be involved to the extend our acreage is involved and so forth. I mean, the Pearsall's more of a chopped play, so it's going to have some highs and some lows standpoint. It's not a consistent matrix process. You don't play it like we have down at the Eagle Ford, I mean, some parts of it at this point in time. It's not something that's going to be a high priority for us to chase.

Operator

You have a follow-up question from the line of Marshall Carver with Capital One Southcoast.

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

Just one quick question. The 148 wells, that's the total wells for the year, right, not the number of wells spud year-to-date?

James C. Flores

Correct.

Operator

[Operator Instructions]

James C. Flores

Operator, I'd make a few comments. This is Jim here. We're excited about getting our Gulf of Mexico Project closed. It's going to be a tremendous driver of value for our company. Once we get it closed, then we'll spend a lot of time, starting early next year, showing everybody the hidden treasures that we believe are there, the detail, and the sell-side analysts are going to be busy coming to Houston, looking data that we can show. We feel like the opportunity for us to hedge these barrels, finance them efficiently at the cost of capital, we were able to do it. And just talking with the production personnel associated with the assets has been very enlightening from the standpoint of -- we think they'll mesh very well with our PXP culture. They're like-minded people that think about things in long-term value and also near-term efficiencies. And we just couldn't -- it's been a pleasure as far as the early parts of the transition has been really appreciated by all of us is how dedicated and how committed they are doing a good job and also the condition of facilities. So we're excited about this transition. We'll be talking a lot about it on the conference calls coming going forward. At the same point in time, we couldn't be prouder of all of the work everybody's doing in California and in the Eagle Ford and all of other areas from the standpoint of making sure that the company is doing a great job. So right now, we're hitting on all cylinders, a lot of excitement around here but a lot of transition. And we really appreciate support from everybody out there on the operations and also the finance side that kill themselves to get these transactions done. So, operator, any other questions, or we're going to cut it off?

Operator

You do have one other question from the line of Eric Anderson with Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

I jumped on the call a little bit late, so I apologize if you've covered this, but can you comment at all on just the permitting time from the regulators?

James C. Flores

In what...

Eric B. Anderson - Hartford Financial Management, Inc.

In the Gulf of Mexico.

James C. Flores

The permitting time, we're excited about the Gulf of Mexico from a permitting -- if you're doing thoughtful work that can be planned in engineering. It's more of are you going to get enough attention, and I think they probably -- they caught their breath over there, and I think our meetings with them showed that we're going to be very deliberate. We're going to give them plenty of time to digest and go back and forth and make sure we have thoughtful, consistent plans. And I think their commitment to work with us is heartfelt, and we know a lot of them over there. And I see it as good as any place in the country. I mean, our California permitting and so forth is going spectacular because of our ability to communicate and plan ahead, and we'll keep that same consistency there and make sure that there are no surprises. And we'll be able to work together if anything comes up.

With that, operator, thank you very much. Thank you all for joining. We'll see you at the year-end call.

Operator

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Plains Exploration & Production Management Discusses Q3 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts