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Plains Exploration & Production (NYSE:PXP)

Q1 2012 Earnings Call

May 03, 2012 9:00 am ET

Executives

Scott D. Winters - Former Vice President of Corporate Communications

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

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

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

Hance Myers - Vice President of Investor Relations

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Anne Cameron - BNP Paribas, Research Division

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

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

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

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Rehan Rashid - FBR Capital Markets & Co., Research Division

Operator

Good morning. My name is Cassandra, and I will be your conference operator today. At this time, I would like to welcome everyone to the PXP First Quarter 2012 Results. [Operator Instructions] And now, I would like to turn the call over to Scott Winters, Vice President of Corporate Planning. You may begin.

Scott D. Winters

Cassandra, 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 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 available on our website in the Investor Information section.

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

In our press release and our prepared comments this morning, we present non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release.

On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Doss Bourgeois, our 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 March 31, 2012, PXP reported a net loss attributable to common stockholders of $82.3 million or $0.64 per diluted share to -- compared to net income of $71 million or $0.49 per diluted share for the 3 months ended March 31, 2011. The first 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 $109.1 million due in large part to increased crude oil forward prices. It also included a $135.9 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 $77 million or $0.58 per diluted share, a 47% increase compared to the first quarter of 2011.

Significant transactions that affect comparisons between the periods include the divestment of our Texas Panhandle and South Texas properties in the fourth quarter of 2011. The following comments compare results from first quarter 2012 to first quarter 2011: oil/liquids and gas revenues increased $92.4 million to $521 million for 2012; oil/liquids revenues increased $135.6 million to $467.5 million for 2012, reflecting higher average realized prices and higher sales volumes; the oil/liquids average realized price per barrel before derivative transactions, which includes 1,842 barrels per day of natural gas liquids was approximately $103.45, up $19.78 or 24% over first quarter 2011; the crude oil-only average realized price per barrel before derivative transactions and other adjustments was approximately $106.95 or 90% of Brent, a 23% increase over the approximate $86.72 average realized price per barrel before derivative transactions and other adjustments in 2011. The stronger pricing was primarily attributable to our new marketing contracts in California and the Eagle Ford Shale.

Oil/liquids sales volumes increased 5,600 barrels per day to 49,700 barrels per day in 2012 from 44,100 barrels per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Texas Panhandle properties in 2011.

Gas revenues decreased $43.3 million to $53.5 million in 2012, primarily reflecting lower average realized prices and lower sales volumes. Our average realized price for gas was $2.56 per Mcf in 2012 compared to $4.08 per Mcf in 2011. Gas sales volumes decreased 34.1 million cubic feet per day to 229.3 million cubic feet per day in 2012 from 263.4 million cubic feet per day in 2011, primarily reflecting the impact of our South Texas and Texas Panhandle property divestment in 2011.

Lease operating expenses increased $10.7 million to $83 million in 2012, reflecting increased production, primarily our Eagle Ford Shale and Haynesville Shale properties and higher well workovers, primarily at our California properties, partially offset by our Texas Panhandle and South Texas property divestment in 2011.

Steam gas costs decreased $4.7 million to $11.1 million in 2012, primarily reflecting the lower cost of gas used in steam generation. In 2012, we burned approximately 4 Bcf of natural gas at a cost of approximately $2.77 per MMBtu compared to 4.1 Bcf at a cost of approximately $3.88 per MMBtu in 2011.

Gathering and transportation expenses increased $3.6 million to $16.3 million in 2012, primarily reflecting increased rates and production at our Haynesville Shale properties and an increase in production from our Eagle Ford Shale properties.

Interest expense increased $12.9 million to $45.3 million in 2012 from $32.4 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding, partially offset by lower average interest rates. PXP capitalized $17.1 million in the first quarter of 2012.

The loss related to mark-to-market derivative contracts in the first quarter was primarily associated with a decrease in the fair value of our crude oil derivative contracts due to increased forward prices, partially offset by an increase in the fair value of our natural gas derivative contracts due to decreased forward prices.

In April 2012, PXP acquired additional 2014 Brent crude oil put option spread contracts, bringing total volumes covered to 50,000 barrels of oil per day, up from 20,000 barrels of oil per day, with a floor price of $90 per barrel and a limit of $70 per barrel. Currently, PXP has approximately 70% of its 2012, 90% of its 2013 and 60% of its 2014 estimated oil/liquids sales volumes hedged. The company has approximately 70% of its 2012 and 60% of its 2013 and '14 estimated natural gas sales volumes hedged. Given the characteristics of today's commodity markets and PXP's outlook, the company will continue to aggressively hedge to protect against downside commodity price risk and ensure ample cash flow. PXP also plans to continue its strategy of offsetting deferred premiums by selling call options in the future.

At March 31, 2012, PXP owned 51 million shares in McMoRan common stock. We have elected to measure our equity investment in McMoRan at fair value, and a change in fair value of our investment is recognized as the loss or a gain on investment measured at fair value in our income statement. The unrealized loss for the 3 months ended March 31, 2012, was primarily associated with the decrease in McMoRan's stock price.

For the first quarter of 2012, PXP had cash expenditures of $401.3 million for additions to oil and gas properties and $16.6 million for leasehold acquisition. Of the $417.9 million total, approximately $371.3 million was funded by PXP and $46.6 million was funded by Plains Offshore Operations Inc., PXP's consolidated subsidiary.

In the first quarter of 2012, PXP completed the purchase of 2.4 million common shares at an average cost of $37.02 per share, totaling $88.5 million, as previously disclosed in our February 2012 year-end earnings report. PXP reiterates its full year 2012 average sales volume range of 92,000 to 96,000 BOE per day. Company estimates oil volume growth to more than offset declines in the natural gas volumes, particularly in the second half of the year.

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

James C. Flores

Thank you, Scott, and good morning, everyone. First quarter is a very solid quarter. We focused on our cash flow and our margin expansion. The new contracts obviously helped. Strong oil prices continue to be our wind at our back here, and we'll continue to do the things right, executing in the field operationally. Driving oil volumes is what PXP is going to be all about going forward with, obviously, California having some marketing issues with the oil. We had to stock in tanks during the first quarter that will be sold in the second quarter. So it's not a net effect on the year, it's just the timing effect of those barrels sold in the first quarter. Obviously, it's going to make the second quarter look strong as well.

Then the Eagle Ford growth is tremendous. We going to get a sneak peak of -- at April at what we're seeing and plus you got to love -- the Love wells and Jendrusch well are now our top producer in the field, and we continue to set records every month there with our drilling accomplishments and our production accomplishments there.

Lucius is on track. We had an investor meeting this week, and Hance Myers corrected me when I said it's 24 months away before the platform is going to be there. It's 12 months away when the Lucius platform's going to be on location. And then there'll be additional 10 to 12 months before it's on production. So getting closer and closer to that 25,000 barrels a day and large cash flow coming out of our Gulf of Mexico and we can't wait. And in the meantime, we're on schedule to drill both wells in the fourth quarter. We feel very good about everything. We did our bond offering, terming out some of our debt in the -- on our revolver, as well as there's going to be, I'll call, some of our high-priced notes. Winston can take you through that, which is very successful. We appreciate all the support there. And PXP is in a perfect position with our gas hedges and continue to maintain gas volumes is the way we look at it.

Our operator in Chesapeake and in Haynesville has reduced gas volumes to just right at pipeline takeaway requirements. It's probably on an overall basis. It's going to reduce our flow somewhere between 6,000 and 8,000 BOE a day for the year. We've already got that baked into our production guidance. That's why we're reaffirming 92,000 to 96,000 versus raising that guidance like we would have if we were producing that gas.

The molecule, of course, is not going anywhere. We still own them, and hopefully, we'll sell them at higher prices in the future. But with that steady gas flow, we have our gas -- total gas business model around $200 million a day for the next several years, and we think we can maintain that with a $150 million of CapEx, which will allow us to make the profit of our $4 hedges about $100 million a year of net free cash flow out of our gas business, which makes us probably the best gas business in the world right now in North America.

So with that, I'll open it up for questions and go through any of the detail you guys need. So operator, we'd like you to bring forth the questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you touch on the Eagle Ford wells, the 3 wells and a little bit more color? Were there anything different that you were doing there in terms of lateral length? And where do you attribute the strong performance to? And can you also talk to the oil mix in those wells as well?

James C. Flores

The lateral length there, I'll let Doss handle that one.

Doss R. Bourgeois

The lateral lengths are approaching 6,000 feet. We've kind of gone to a little closer broken up to more stages and these wells are in what we think a little bit thicker part of the lower Eagle Ford.

Brian Singer - Goldman Sachs Group Inc., Research Division

And I guess, it's fairly early at least for these peak rates [indiscernible] that you've put out here, but do you have a sense of what EURs are? Or maybe more broadly, do you see EURs raising and where do you think they get to in the Eagle Ford?

James C. Flores

I think they -- we'll going to be staying about where we modeled. They could come up little bit, but we just -- we need a little bit more production out of these particular wells to see if that's is going to change the EURs in this area.

Doss R. Bourgeois

Brian, we're not going to be getting ahead of EOG. It was our partner out there on some of our leases, but also has larger acreage spread. We'll wait from them to continually -- they'll be pressing the EURs based on well performance and we support where we are right now.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then lastly, there's been a little bit more talk among some others on various exploration opportunities in the Rockies, including the Mowry, and I wondered whether that was an area that's regaining focus for you and if you could broadly talk about new venture opportunities.

James C. Flores

Well, there's a couple of things on that. Let me back up just a little bit and kind of branch out. We're so concentrated in California, at Eagle Ford and the Gulf of Mexico right now and that's going to drive our business. Ancillary, we have our Mowry lease walk out there. We drilled 2 wells, and we have 2 additional locations we think are much better spots now. We're starting to understand the geology there. We have a large lease block in Nevada. We have worked on some other things that all that stuff will be rolled into a joint venture for 2013 and drilled by third parties and not using our capital. So Mowry's going to be a candidate to do that as well. We're hoping the rest of the industry helps define the play, but that's going to be something that will be an upside opportunity for our company post the Phobos drilling late this year.

Operator

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

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

Just curious as to where those last 3 Eagle Ford came out wells in terms of well cost? It sounds like it really has slightly longer laterals. Just trying to get a sense of what those costs you.

James C. Flores

It probably costs another $750 million. Instead of $8.5 million, we're probably $9.5 million on those wells.

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

Okay. Any updated plans for your McMoRan acquisition?

James C. Flores

No updated plans at this point in time. Drill drill-bit keeps turning to McMoRan and its completion work continues, so we're glad to be in the ownership position.

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

Okay. I guess, I thought that you guys did pick up a little bit of additional leasehold in the first quarter, not a big number, but just curious as to where you're leasing? Is that just fill-ins in Eagle Ford?

James C. Flores

No, it's not in Eagle Ford. It's other places that we haven't disclosed at this point.

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

Okay. So that's kind of part of your new venture program that you just talked about there?

James C. Flores

Yes, it's real cheap leases in kind of areas that are exploratory that we'll wrap up in our 2013 business.

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

Okay. I imagine, given your stance on gas, you guys are looking for oil and liquids?

James C. Flores

You can be confident of that, Leo. You're exactly right. No, we're trying to avoid as much gas as possible.

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

Okay. And I guess in the Haynesville, just to make sure I understood you correctly, Jim, did you guys say that your overall gas volumes should trend downwards around 200 million a day and just stay flat for the next couple of years? Just want to make sure I understood that.

James C. Flores

Yes. Let me back up, I mentioned this in passing. We did spend $12 million on leases from the deepwater, picking up 2 more Phobos-type prospects out of that leasehold. That's what you picked up.

Winston M. Talbert

And those were paid by POI.

James C. Flores

Right. Those were reimbursed by our joint venture partners. Is that clear?

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

Yes, absolutely.

James C. Flores

Okay, great. Back to the gas deal. Basically, Haynesville, we expected about 150 million a day. We get about 40 million a day out of our Madden Field in Wyoming and then additional gas production out of the Eagle Ford's 10 million to 15 million somewhere because it's almost all oil at the Eagle Ford. It's just associated gas. So you kind of model 200 million a day flat. And remember, in the Haynesville, we're producing wells when we come up so we can -- we keep it pretty flat for a long period of time, plus we still have a completion backlog, plus we still are spending some money in the gas business in maintaining these fields at all the 11,000 locations we have in the Haynesville and the Bossier. So what we're trying -- we're looking at Mowry's almost from a cash flow model including the hedges that will generate $250 million of cash flow out of the gas business, with $150 million worth of expenditures, net in a corporation $100 million worth of free cash flow. So pay down debt or buy back stock. Until fundamentals return. And Leo, on that, remember we're also hedged to 2014 above $4.

Operator

The next question comes from the line of Anne Cameron from BNP.

Anne Cameron - BNP Paribas, Research Division

Just a question about your crude pricing, which was just a few dollars below where we expected. Can you tell me what your average realized price for the quarter in California was?

James C. Flores

Yes, we'll get into that. Let me do a commentary first, Anne, on that because, one thing, we give everybody guidance to what we thought were yearly average differentials. Of course, everybody knows that the differentials on a weekly, daily, quarterly basis are going to be moving around like they're $3 tighter here already in the second quarter than they were in the first quarter. It all depends on refinery, [indiscernible] gas and everything else. One thing I want to tell you and all the other analysts covering, we going to be more vocal about what differentials are during the quarter or at the quarters so you guys can really zone in on that so it won't be such a surprise one way or the other, positive or negative. But we have put number slides that -- Number 6 in our presentation. We have a detailed slide showing the differentials, the store for differentials and you can get kind of a trend on when they're tight and when they're long. So Winston, you want answer a question specifically?

Winston M. Talbert

Yes. If you -- at the beginning of the quarter, the spreads widen up pretty much, especially in California, a little bit more than we had thought, and then towards the end of the quarter. And as you're seeing right now, they're starting to tighten up. So we're turning about where they're at in California about where our average is, is about 90% of Brent.

Anne Cameron - BNP Paribas, Research Division

Okay, that's been helpful. And then in the Eagle Ford, when you sell barrels to Shell, do they treat the condensate the same as your Light Sweet? I mean, are they agnostic, you get one price for both of them? Or do they make some kind of distinction?

James C. Flores

Kind of an interesting question because we don't ask them. But we sell them the condensate and oil, they pay is the same price for each one. We don't know if they treat them the same or not. But we get the same price.

Anne Cameron - BNP Paribas, Research Division

What percent of your barrels in -- roughly in the Eagle Ford are condensate versus crude?

James C. Flores

Very small, right, because of it's crude.

Winston M. Talbert

In general, it's about 70%, 75% crude and then about 10% to 15% condensate.

James C. Flores

And the tough part about that is there's a lot of people calling condensate crude because it's less than 60 API. If you take all of the less than 60 API, you're talking about 90% of our stuff's all crude. So we consider 45 to 60, somewhere in there, mostly condensate. So it all depends on everybody's definition of what condensate is. But your answer, we're selling at the same price, so it's irrelevant to us.

Operator

Your next question comes from the line of Dave Kistler from Simmons & Company.

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

Real quickly in the California stuff where volumes were a little lower as a result of maintenance turnarounds. Can you just talk about what that the volume change was so we have a sense for what to be looking for in Q2?

James C. Flores

We're hoping you wouldn't ask that question.

Hance Myers

Dave, we are thinking it's going to be in the 20 to 21.

James C. Flores

Hundred barrel a day range.

Doss R. Bourgeois

Right.

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

Okay, that's helpful. And then just a clarification in the Haynesville. At this point, are you guys still going nonconsent on some of the wells there? Or has the rig count come down enough and you have kind enough cash flow flowing through that you're going to continue to complete some -- or drill some additional wells there?

James C. Flores

Dave, Hance is still talking to me about the deal. To answer the question on the -- how many -- what was the production at the end of second quarter attributable to the shut-in?

Hance Myers

To the shut-ins in California? David, it's about 700 barrels -- 700 to 800 barrels a day in California.

James C. Flores

So that's oil production in the second quarter?

Hance Myers

That's correct.

James C. Flores

I got to get the words out to everybody. Now repeat your other question.

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

In the Haynesville, are you guys still looking at going nonconsent on various wells there or is there no cash flow coming through?

James C. Flores

Sure, we're going to be -- we're budget limited there. That means that we're only drilling the wells -- or participating the wells in the best area if we have cash. The big thing that we're stating [ph] the cash for is completing wells we've already drilled and everything else is non consent. We'll not consent anything that CapEx is $150 million. It's not an engineering decision, it's an economic decision. Until this fundamental is back in the gas business, if we lose 100 locations out of our 11,000, so be it. I mean -- and the key about it is when we look at it by hedging our gas -- having our gas all hedged at $4, let's say, gas doesn't recover in 2014, it's higher than $4, we'll go back to drilling in the Haynesville and we'll have so much -- so many volumes we'll swap where we are any way with volumes and enjoy the $6. So we don't feel at risk at all. I feel very comfortable with our hedge position. Until we see some fundamentals return to our gas business, we're going to keep it curtailed.

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

Okay. Appreciate that clarification. And then you guys articulated that there were both shut-ins and curtailments. Can you kind of distinguish between the 2 of those? Were the shut-ins related to pipeline capacity or to some inability to deliver versus curtailments that would be voluntary, I would guess?

James C. Flores

I appreciate -- no, it's strictly voluntary -- we call shut-in and curtailments the same. It's where they reduce the flow rates of certain wells, or they actually shut them and then flow them incrementally. That's 2 different things. Now the pipeline is just the opposite. The pipelines are requiring gas because a lot of the way these infrastructure were all built, they were built with volume commitments for financing and those volume commitments increase basically every year. And so it becomes a really -- it's almost like a drilling commitment. All these big fields to where -- and we're not a party to it, number 1. We're not a part of it, but what it's going to require is continued activity in these fields to meet the pipeline requirements of more volumes because everybody sold these things for and got all the money out based on those higher volumes and higher revenues. So with that situation, you're either going to have to renegotiate these contracts or you're going to be in situation of continuing to drill wells, not economic wells versus pay penalties and make those type decisions. Again, PXP is not involved or not a party to any of these contracts. So our aspect is the way we control our budget is not considering the wells and we keep our flow costs out there and make really -- make money off our hedges.

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

Okay. I appreciate that clarification. One last one, it's probably real easy. It's just, what is that drilled out completed backlog right now in the Haynesville for you?

James C. Flores

It's somewhere -- it's about half of where it was. Somewhere around 80 to 100 wells. It fluctuates depending on frac [ph] crews and expenditures. And that's the best way to control expenses out there as we work through completion. So the backlog may not get worked off in a straight line. We may have the same backlog at the end of this year as we have right now. But it really won't mean anything. It just means that -- what type of expenditures the operators spent out there as they're all challenged for money.

Operator

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

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

I was curious. In the presentation, you talked about 3 exploration wells in California and I know at the Analyst Day you talked about a 3D shoot out there with Eric. Can you give us some guidelines on how that's going in timing?

James C. Flores

3D sheet is complete and we actually have our first well that will draw off that 3D sheet coming up here shortly.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Great. And I hear some rumblings that Exxon was able to get some permits offshore, be able to do more drilling, converting some of their processing facilities for -- in using natural gas and getting more AQMD permits. Is that kind of happening? Is there any potential for T-Ridge to see some CapEx at some point?

James C. Flores

Well, the difference -- the answer is no on that because we received drilling permits also a lot on Point Ped, but it's the drill from our federal lease platform on federal acreage. Remember, T-Ridge involves the State of California, which is currency different situation than what Exxon's dealing with and what we're dealing with, with the rest of our production out there. So I don't think T-Ridge is available to us [indiscernible] it's $500 a barrel.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

All right. And on the Eagle Ford, do you think this kind of 8 to 10 rig -- or 8 or 9 rigs is kind of where you stay out? Or do you see any appetite to increase your rig count out there?

James C. Flores

We certainly had plenty of offers to increase our rig count from other operators shutting rigs down. Right now, we're pretty happy. We're just going to be opportunistic. We've got a great rig fleet out there doing really great and we've got good balance between our rig contractors. They're all competing for the top slot of most efficient. And so we had great tension there on performance. And from that standpoint, Doss, anything you want to add to that as far as rig outlook?

Doss R. Bourgeois

I think the rigs, as Jim said, are becoming more and more available. We're getting calls all the time. So contract durations are demand, that they want are getting shorter. And usually, when that happens, then you'll probably start seeing some day rates start coming down too. So we want to be able to be opportunistic and take advantage of those kinds of things when they come our way. We've already seen that, of course, the frac-ing side were prices have started to come down.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Great. And just one last one. It might be in the Q -- the 10-Q but I haven't had a chance to look at it. On the call options that you're selling in 2013 and 2014, what's the cap on them?

Winston M. Talbert

In 2014, I don't have the numbers right. It's about 125. In 2013...

James C. Flores

And we haven't sold anything yet. We just said if we sold them today...

Winston M. Talbert

If we sold them today, it'll be about 124 out in 2013. The ones we sold which is about 30,000 barrels a day are around 125.

Philip J. McPherson - Global Hunter Securities, LLC, Research Division

Okay. And in the presentation, it has $109 million in call option sales, those are sold or to be sold?

James C. Flores

I think it says to be sold.

Winston M. Talbert

To be sold.

James C. Flores

In the presentation. You got to read it closely.

Winston M. Talbert

Yes, we still have about $71 million worth of premium in 2013, which is about 30,000 barrels a day of premiums that we probably want to offset with calls. If we did it today, it'd be around 124 just kind of watching the market. And 2014, we have 50,000 barrels a day, of 70 by 90 puts that cost us an average of, I think, about 599.

James C. Flores

Yes, you're right. It said sell the brand. Said should -- to be sold. And what we're trying to illustrate is what our strategy is and it's just more of a timing factor, because if all blows out, 150 or whatever, we'll the calls a lot higher. And we're not in a big rush. As long as our downside's protected, we have time to figure out how to offset the cost.

Operator

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

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

Just a couple of quick questions. On the Eagle Ford, that's a nice production ramp-up there. Do you have the number of wells you put online in the first quarter?

James C. Flores

We can get that to you, Marshall. You got another question while I'm digging through the papers?.

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

Yes. The production mix for the Eagle Ford, you give it BOEs per day, do you have the breakdown between oil, NGLs and gas?

Doss R. Bourgeois

Yes. It's 75% oil, 9% NGL and 16% gas.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

I'll stick with the Eagle Ford. Are you all pad drilling yet? Or are you still trying to save leases?

James C. Flores

No, we're not concentrated at least for this. We're batch -- we call it batch drilling because it's more than 2 wells that support a 6 wells a pad, that's why it's lumpy. We're doing that in timing into our central facilities. It's the concert between the central facilities and the pipelines and the wells drilled. But the efficiency of multi-well pads, I mean, between the zipper-fracs and everything else and just logistics and wear and tear on our land owners has been really, really beneficial. Doss, you have a question on that?

Doss R. Bourgeois

We put on approximately 20 wells, about 20 wells in the first quarter.

Brian M. Corales - Howard Weil Incorporated, Research Division

And then in the Eagle Ford, I mean, you said you're up 8 net rigs today. Is your go-forward plan to keep that relatively flat or is that likely going to be ramped up?

James C. Flores

We'll probably add -- the question before, we'll be optimistic add a rig. You see, the volatility in that is that we have some acreage 50:50 with EOG, and they were planning on one rig this year, now they have 3 in their drilling. So -- and we're obviously participating in everything in the Eagle Ford. So that's why it moves around a little bit, and we just -- we've got a great working relationship with them. We just said, "Look, do what you want to do. We'll do what we do. We got plenty of capital to respond and we'll be a good partner." So we kind of give it total flexibility they give us flexibility, just keep making good decisions and it's worked out to be a great relationship. That's your productivity's responded.

Brian M. Corales - Howard Weil Incorporated, Research Division

So -- but kind of the go forward, I guess, in your slide deck, and in terms of production and CapEx.

James C. Flores

You're modeling [indiscernible] define rigs. Yes, you probably have to [indiscernible]. We didn't talk about that.

Operator

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

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

Just 2 real quick ones on the Eagle Ford again. On the lateral lengths, the 6,000 feet, is that going to be part of your go-forward plan? Are you going to continue to drill these longer laterals as long as lease -- the units allow? Or when you think about your lateral length, do you think that you can even continue to push that a little bit?

James C. Flores

Yes, I think innovation is going to be a big part of it and so forth. I mean, we have the oil window, we have the gas condensate window, we have the graben area, we have -- some areas are faulted. It really is going to be dependent on the well. But wherever we can maximize our recovery rates, we're going to take advantage of it. And I'm just real proud of our operating guys, the innovation they're using. And the methodical approach, we got a good, strong baseline with our 5,000 foot laterals now moving to 6,000 foot laterals. I mean, we're given a free reign to be creative as far as -- and thoughtful. And they're being very conservative right now as far as the opportunity used. But everything they seem to do as far as more stages per foot of lateral, length of lateral, different profit mix and so forth in sand and so forth, everything they're doing has really seemed to show production good results. I think there's more to come, it remains to be seen. Is that fair, Doss?

Doss R. Bourgeois

Correct.

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

Great. And then on the spacing in the Eagle Ford, I know EOG has talked about 65 to 80 acres testing and strong results. Are any of the wells that you've been drilling or any of the 3 that you highlighted, are those still being drilled on your 100 acres? Or are you starting to also, on your operating program, drill tighter spacing?

James C. Flores

We're not needing to drill tighter spacing. I think we're participating with some of those EOG wells so we're involved in those and so forth and we're highly supportive of that view. But we haven't gotten to that point yet. We're still just covering the acreage and staying with the larger spacing.

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

Great. And in the deepwater, you added a couple wells to your 13 to 14 exploratory projects from the recent lease sale, added 250 million barrels to your resource potential. Can you just -- how do those prospects shape up? Or what are the targets relative to what you've been doing and -- or seeing in Lucius and what you're planning at Phobos?

James C. Flores

Sure. There are 2 very large extensions to our whole Pliocene from a play out there. They're very Phobos-like. They're just not in the same neighborhood of Hadrian and Lucius. So that didn't get the de-risking at Phobos. Phobos did -- I mean, they're still very large prospects. We've risked those significantly harder. They're in adjacent many basins that don't have Pliocene production as of yet because no Pliocene wells have been drilled. But they have the same either 4-way or 3-way characteristics and sand signatures that we see on the seismic. So we're very happy about those. We bought them 100% so we can control who we want to be partners with and we're in that process right now of identifying partners and who has rigs. We want drill those as soon as possible. As you noted, they moved up the drilling chart so there are new freshman, faster, bigger, stronger athletes that we want to drill as soon as possible after Phobos.

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

Great. And then 2 real quick ones for a modeling standpoint. On -- when some on capitalized interest, you talked about it going down quite a bit to $17 million. Is that a pretty good run rate going forward? Or is there something going on here in the first quarter that caused that impact?

Winston M. Talbert

Well, part of it is we're moving a lot of the Haynesville unevaluated dollars over to evaluated as the gas price is going down. We're having to move that over. So that's kind of causing us to not capitalize quite as much. So if you see gas prices this low for longer, you may see even a little bit more interest going less capitalized. So right now, I think it's a pretty good run rate. But if gas prices stay pretty low, you could probably get it up to a little bit higher, maybe 20% higher than that.

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

Okay. And from a lumpiness of production, you obviously have a big jump here in April versus the fourth quarter and it has to do with the batch drilling. As we look out second, third and fourth quarters, should we plan on lumpiness and maybe growth here in the second, a little bit less in the third and more again in the fourth? Or how do you have your completions scheduled?

James C. Flores

Ron, I think the lumpiness that we've been forecast for the past year, we've experienced some of it here in the past. I think going forward, we're getting enough infrastructure in place on a quarterly basis. You could see some readable, just ramp-ups toward our 26,000 barrels a day exit. I don't want to say it -- a curse [ph] -- of saying it will be smoother, but we're doing everything we can for it not to be lumpy. And the forecast is not probably right now. So I think you can deal with hands [ph] and discuss some volume trends over [indiscernible] of the infrastructure that's in place and the scale of the operations now.

Operator

Your next question comes from the line of Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I know Anadarko is the operator of Phobos, but has your thoughts on the technical risk of Phobos evolved as you've been able to just get more data and actually integrate some of the Lucius information?

James C. Flores

Yes, they evolved. I mean, I guess the best -- we got so -- we're so enthusiastic on -- I think we've continued to substantiate our enthusiasm, I guess is the right way to think about that. We've done a lot of geophysical work, a lot of reprocess, a lot of modeling. We've had a lot offers from third-party industry players to participate in the project and so forth. And we just don't see any other project out there that competes with that with Phobos. So that doesn't mean it's going to be successful. It's just that it's the best advantage project for PXP. And I think from a standpoint of our opportunity set and what we're doing in the final Pliocene and to be out in front of the industry, it's just a very unique position for a company the size of PXP. We're not -- that's why we had a great response on our Zephir and Kanzi prospects, a partner with us, we just got a lot of momentum. And to think that we're replacing -- 5 years ago, we thought we haven't had a gas business to grow this business and replacing it with this high-volume $5 cost of oil that's selling at Brent from Lucius and potentially Phobos, Zephir, Kanzi. Things are pretty exciting around here. So we're just going to -- we'll continue to manage the risk, continue to manage the expectations, but with the Lucius bar being out on location next summer, things are starting to happen and starting to feel pretty good.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes. No doubt. It seems like things just kind of keep going around and around on that front. The question, though, like, more specifically, so if you look at the Lucius well, you look at Hadrian, have you guys been actually able to tie the well control there with the 3D seismic that you have in Phobos?

James C. Flores

We've tied it. We've done all the details, lenticular work to -- in all of the seismic signatures to the -- we see the sands is continuous across, or at least a section, continuous across there. We see it actually terminate to the South when it gets well off of the Phobos structure. We see it correlate to the Hadrian 2 well and a 450-foot updip position as the top of the section in our Phobos location. We see the spill point being 24,500 acres from a prospect standpoint. I dream about it every night. So I tell you exactly everything you want to know about it.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Well, in that case, what are you guys estimating again from a geologic chance of success right now?

James C. Flores

Well, in all exploratory wells you start off with the highest rating you get us 50% because it's either the black or white or good or bad. So you start at 50%. And being in its close proximity updip to production, the size, structure and so forth, the seismic coverage we have, the information we have around it, we give it the highest rating of 50%.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's great. And then just the last question from me, and I apologize if I didn't hear this correctly, but what is the updated plans for -- if any, for spudding Phobos?

James C. Flores

We're zeroing in on the fourth quarter, and we'll let Anadarko, our operator, give you more details because, obviously, they're managing that book for us. But we're -- that looks like it's most likely. Talk about Phobos all day long.

Operator

Your next question comes from the line of Brian Kuzma from Weiss Multi-Strategy.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

You talked about some -- like the different geologic settings across your Eagle Ford acreage. I'm curious, these wells that you guys have had this quarter and prior quarter that are kind of a 2,000 barrels a day. Are they all in, like one of those specific settings and...

James C. Flores

No, they're across. We're just talking about well types and what will it take to maximize production across because there are some areas with faulty, there are areas with different pressure regimes, there's different thickness, the graben's obviously special and what we're doing, that why it's really interesting. But our report, it's really we're reporting different areas every time because we're moving rigs to certain areas and getting acreage HGP [ph] and so forth. So it's not as necessarily been the geographic variabilities of our acreage, it's been more the engineering techniques. It's some of the geologic, specifics of the reservoir and thickness and reservoir characteristics.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

And I wanted you guys to clarify California again for me. The impact from marketing on Q1 was what? How much are you going to get back in Q2? And how does it grow from -- you talked about low growth...

James C. Flores

It's about 800 barrels a day in the first quarter and 800 barrels a day of negative in the first quarter, 800 barrels a day positive in the second quarter. It's just we're putting it in the tank and we're selling it -- sell it in the second quarter versus first quarter on the marketing impact. And the other thing is we modeled a little more aggressive some of our impact from steaming at Simrac [ph] and in a way Sunset [ph]. I mean, we've had to adjust our models a little bit to do the well performance and so forth of timing of when that steam or reservoir. It's one of those things that our engineers are the best guessers in the world, but they're still having to guess what the reservoir is going to do for them. So we may be a quarter -- may have had better steam response in the second quarter than we did in the first quarter.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Okay. And so in the press release, you guys talked about like slow growth from Q1, that slow growth from Q1 going -- or growth going forward from Q1 plus the additional barrels from storage or was that assuming the growth included the barrels from storage?

James C. Flores

I don't think we get that fine-tuned about it. I mean, we're more talking about the growth of the assets. I can't remember us using the word slow ever.

Operator

Your next question comes from the line of Rehan Rashid from FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Eagle Ford real quick again. Where are you guys landing the wells? Is it all on lower Eagle Ford? Have you tried something on the upper Eagle Ford, please?

James C. Flores

All of the above. We're not -- we don't want to disclose that information to our competitors.

Operator

There are no further questions. Do you have any closing remarks.

James C. Flores

Sure, operator. Thank you -- thanks everyone. Just keep the oil prices up and we'll deal with the gas issue and [indiscernible] for your stakeholders. Everyone have a good day, and we'll talk to you by the end of the second quarter. Thank you.

Operator

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

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