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Plains Exploration & Production (NYSE:PXP)

Q4 2010 Earnings Call

February 24, 2011 9:00 am ET

Executives

John Wombwell - Executive Vice President, Secretary and General Counsel

Scott Winters -

James Flores - Chairman, Chief Executive Officer and President

Doss Bourgeois - Executive Vice President of Exploration & Production

Winston Talbert - Chief Financial Officer and Executive Vice President

Analysts

Pearce Hammond - Simmons

Brian Singer - Goldman Sachs Group Inc.

Leo Mariani - RBC Capital Markets, LLC

David Heikkinen - Tudor, Pickering, Holt

Duane Grubert - Susquehanna Financial Group, LLLP

Operator

Good morning. My name is Brandy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Plains Exploration 2010 Fourth Quarter and Year-End Results Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. Scott Winters, Vice President of Corporate Communications. Please go ahead, sir.

Scott Winters

Brandy, thank you. Good morning, everybody, and welcome to our conference call. Earlier this morning, we issued our fourth quarter and full year earnings release and filed our 10-K. 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 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-K and today's press release are all 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 of Investor Relations.

Starting with financial results. For the fourth quarter of 2010, PXP reported a net loss of $19.5 million or $0.14 per diluted share compared to net income of $48.1 million or $0.34 per diluted share for the fourth quarter of 2009. The net loss includes the impact of realized and unrealized gains and losses on our mark-to-market derivative contracts and other items, which affect the comparability of operating results. When considering these items, PXP reported net income for the fourth quarter of 2010 of $28.3 million or $0.20 per diluted share compared to net income of $86.6 million or $0.61 per diluted share for the same period in 2009.

Fourth quarter net cash provided by operating activities was $235.3 million and operating cash flow was $253.6 million. 2010 fourth quarter daily sales volumes averaged approximately 93,000 barrels of oil equivalent per day, an 8% increase over fourth quarter of 2009 average daily sales volumes.

For the fourth quarter of 2010, oil and gas revenues increased 11% to $407.8 million from $367.1 million in the fourth quarter of 2009. Oil revenues increased $36.7 million due to higher oil prices and stronger oil sales price realizations. Natural gas revenues increased approximately $4 million, as higher natural gas sales volumes just offset lower natural gas prices and lower sales price realizations.

Oil sales price realizations before derivative transactions were 86% in the fourth quarter of 2010, compared to 84% in the fourth quarter of 2009. In the fourth quarter of 2010, posted crude oil prices in California strengthened in relation to NYMEX. PXP's average realized oil price increased $8.89 to $73.17 per barrel in 2010 from $64.28 per barrel in 2009.

Natural gas sales price realizations before derivative transactions were 96% in the fourth quarter of 2010 versus 99% in the fourth quarter of 2009. PXP's average realized natural gas price decreased to $0.46 to $3.66 per Mcf in 2010 compared to $4.12 per Mcf in 2009.

Total production costs were $14.24 per BOE for the fourth quarter of 2010 compared to $12.89 per BOE in the fourth quarter of 2009. Lower steam gas costs and production ad valorem taxes per BOE were offset by higher lease operating expenses and gathering and transportation costs per BOE.

For the fiscal year 2010, total production costs per BOE were $14, flat to fiscal year 2009 costs. A quick review of the components of total production costs for the fourth quarter of 2010 compared to fourth quarter of 2009 is as follows: Steam gas costs decreased $2.1 million to $14.3 million in 2010, primarily reflecting the lower cost of gas used in steam generation.

In 2010, we burned approximately four Bcf of natural gas at a cost of $3.56 per MMBtu compared to 3.8 Bcf at a cost of approximately $4.33 per MMBtu in 2009. Production and ad valorem taxes were down slightly to $8.1 million in 2010 from $8.7 million in 2009, primarily reflecting production tax abatements.

Lease operating expenses increased about $18.4 million to $74.8 million in 2010 from $56.4 million in 2009, primarily reflecting higher repair and maintenance and well workover expenditures. Gathering and transportation expenses increased approximately $2 million to $13 million in 2010, primarily reflecting an increase in production from our Haynesville Shale properties, partially offset by a decrease in production from the Gulf of Mexico properties prior to the December 2010 sale.

Other items include general and administrative expenses, which increased approximately $1 million in the fourth quarter of 2010 compared to the same period in 2009. But on a per unit basis, G&A expense was approximately 5% lower than the fourth quarter of 2009.

Interest expense increased $11.6 million to $31.1 million in 2010, primarily due to greater average debt outstanding in 2010 attributed to a senior notes issuance in March of 2010 and increased borrowings under our senior revolving credit facility related to the purchase of the Eagle Ford Shale properties. Interest expense is net of interest capitalized on oil and natural gas properties not selling to amortization, but in the process of development. Capitalized interest was $30.5 million and $35.5 million in the fourth quarter of 2010 and 2009, respectively.

The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are mark-to-market each quarter with fair value gains and losses both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized an $83.9 million loss in mark-to-market derivative contracts in the fourth quarter of 2010, which was primarily associated with a decrease in the fair value of our 2011 and 2012 crude oil and natural gas contracts. In the fourth quarter of 2009, we recognized a $20.2 million loss related to mark-to-market derivative contracts.

Since our last quarterly report, we've added natural gas three-way collars that have a floor price of $4 with a limit of $3 and a weighted average ceiling price of $4.92 on 200 million Btus per day for 2011. Additionally, we acquired put option spread contracts on 160 million Btus per day for 2012 with a floor price of $4.30 and a limit of $3 per MMBtu. A summary of PXP's derivative positions is included with the financial tables in the press release.

In December of 2010, we completed the divestment of our Gulf of Mexico shallow water shale properties to McMoRan, in a cash and stock transaction. We've elected to measure our equity investment in McMoRan at fair value. As a result, unrealized gains and losses on the investment will be recorded quarterly in our consolidated statement of income, which could result in volatility in our earnings. In the fourth quarter of 2010, PXP reported a $1.6 million loss on the investment.

The effective tax rate in the fourth quarter was approximately 13% and resulted primarily from a fourth quarter loss on mark-to-market derivative contracts and its impact on the tax rate true up recorded in the fourth quarter. The annual effective tax rate for 2010 was 49% and the estimated annual effective tax rate range for 2011 is 42% to 44%.

For the full year of 2010, PXP reported revenues of $1.5 billion and net income of $103.3 million or $0.73 per diluted share. Net income includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses in our mark-to-market derivative contracts, an impairment of our Vietnam properties, a legal recovery and other items. When considering these items, PXP reports net income for 2010 of $150.2 million or $1.06 per diluted share.

Other full year statistical highlights include: Net cash provided by operating activities of $912.5 million, an 83% increase year-over-year; operating cash flow of $976.7 million, which represents a 4% increase year-over-year; average daily sales volumes of 88,500 barrels of oil equivalent, which represents a 7% increase year-over-year; proved reserves of 416.1 million BOEs, which represents a 16% increase year-over-year; all-in finding development costs is $17.69 per BOE and finding and development costs excluding acquisition costs of $11.15 per BOE; proved reserve extensions and discoveries of 77 million BOE including 54 million BOE in the Haynesville Shale, resulting from successful drilling during 2010 that extended and developed the proved acreage; and 17 million BOE in the Panhandle, resulting from successful horizontal development of the Granite/Atoka Wash area. Positive revisions of 20 million BOE were primarily related to higher realized oil and gas prices and proved reserve additions related to the interest acquired in the Eagle Ford Shale were approximately 1 million BOE. Reserve replacement ratio for the year was 302%.

Turning now to operations. PXP began 2011 well positioned to continue growing production and reserves with contribution from multiple asset areas and the full year 2010 operational results highlight our sound execution of the strategic plan. Our drilling program remains active in our key growth asset areas. And here's a quick update as we move into 2011.

In our core California asset area, Platform Irene is shut-in for planned maintenance. The work began mid-January and is expected to be completed by the end of the first quarter of 2011. PXP continues its active development program in the Los Angeles and San Joaquin Basin. California is PXP's largest asset area, with approximately 211 million barrels of oil equivalent of proved reserves at year-end 2010, of which over 95% is oil. PXP maintained average daily sales volumes of approximately 40,000 barrels of oil equivalent per day throughout 2010 and expects a 3% to 5% sales volume increase during 2011.

In the Eagle Ford Shale asset area, PXP has four drilling rigs operating and expect to have four to six rigs drilling on its acreage during 2011. There are 10 wells waiting on completion or connection to pipelines. Sales volume exit rates for the first quarter 2010 are expected to be in excess of 2,500 barrels of oil equivalent per day net to PXP and 5,000 barrels of oil equivalent per day net by year-end 2011.

In the Texas Panhandle asset area, PXP has five drilling rigs operating in the Granite Wash trend and expects to continue this level of activity through 2011. There are seven wells waiting on completion or connection to pipelines. Fourth quarter average daily sales volumes were approximately 8,000 barrels of oil equivalent per day net to PXP. Average daily sales volumes are expected to increase to approximately 17,000 barrels of oil equivalent net per day by the end of 2011.

In the Haynesville Shale asset area, PXP's primary operator is currently operating 31 rigs and expects to operate an average of 25 rigs in 2011, plus PXP expects 15 or more rigs by other operators on its acreage. Fourth quarter average daily sales volumes were approximately 146 million cubic feet equivalent net to PXP. A record daily sales volume of 155.6 million cubic feet equivalent net to PXP was raised in February and average daily sales volumes for the year are expected to increase to approximately 160 million cubic feet equivalent net per day by year-end 2011.

Despite the turbulence in the commodity markets and an increasingly complex regulatory environment during 2010, our teams executed and produced solid operational and financial results. As we move into 2011, our balanced, low-risk portfolio of assets, our increased exposure to onshore oil liquids development, in which PXP will primarily operate, and our ongoing hedge program, will serve us well in the volatile commodity price environment and allow future potential upside. These attributes combined with our financial position, flexible capital program and skilled and dedicated workforce are the catalyst positioning our multiyear double-digit production and reserve growth program. With that, I'll turn the call over to Jim.

James Flores

Thank you very much, Scott. Good morning, everyone. These are volatile times on the markets, but it's a very consistent and predictable and disciplined year at PXP. We had a great year 2010 reflective of our results. At the same point in time, the underlying assets and operational and business performing well on the top line, but also on the expense side with G&A lower and so forth.

The activities last year also included all of our asset rotations that we're in the process of completing this year. Our deepwater sale is on track and imminent and we fully expect that to be resolved here and -- as announced and previously forecasted in March. We'll have that data for you guys later this spring. With that, that will be the last final asset rotation that we need to do as a company that's going to be -- put us on the track for consistent, positive results.

A couple of areas that we're going to focus on today is going to be the Eagle Ford and the Granite Wash. The California assets and Haynesville assets are consistent strong, continue to grow and perform as normal. But as we want to give everybody a little color on our Eagle Ford assets because it's obviously a new asset that we've only had for about 75 days, we're going to try to be as forthcoming as possible. However, we have limited data because of, obviously, the 75 days. Takes a little while to get through all these wells and so forth, and we're going to -- in depth in that as well as our Granite Wash has continued to be a very consistent performer. We see nothing but good, solid results out there as it continues to drill with the five rigs.

At this point in time, I'm going to turn it over to questions and we have everyone here that needs to be to answer all your questions and take care of your needs. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Leo Mariani of RBC.

Leo Mariani - RBC Capital Markets, LLC

Quick question on the Granite Wash, looks like your production growth there has been pretty robust. Just trying to get a sense of how many wells you guys have producing currently?

John Wombwell

Yes, we got six to seven wells producing right now. One well is shut in temporarily for a workover but six are producing consistently.

Leo Mariani - RBC Capital Markets, LLC

And I guess a similar question on the Eagle Ford, how many wells do you guys have producing there?

James Flores

We have the 50% interest with EOG, so give a net, net well aspect -- we're focused on getting operations drilled and so forth right now, Leo. So that's a number we got to dig for. We have about a dozen net right now. Eagle Ford has really continued to surprise us to the upside. The wells that we announced in the press release that we completed, those were drilled by the former owner and so forth and we were, frankly, a little surprised at the floor rates of those wells because the way they were drilled and so forth. We have not yet completed or announced a well that we have drilled, completed and taken all the way through the tanks and we've seen some things on the drilling side, staying in zone and stay in -- and we think it's a more permeable and porous areas, that the Eagle Ford is going to be a good asset around here for PXP on driving crude oil production higher.

Leo Mariani - RBC Capital Markets, LLC

Just jumping over to Haynesville, and looks like you guys have pretty solid production and I think you announced sort of a February rate there, but I guess you're only talking about trying to get up to about 160 million a day average in 2011, can you kind of give us some color there? I know it sounds like Chesapeake's dropping some rigs, so those coming off in the next quarter or so. Maybe just kind of talk us through the trajectory on the production there, if it's going to ramp into midyear and then start to decline in the second half, or what are you expecting there?

James Flores

Again, we are kind of reacting to a lot of different operators there because we -- about 60% of our businesses is Chesapeake and 40% is other operators, Petro Hawk and everyone else. So what we're seeing there, we're seeing a lot of talk and rhetoric, of people dropping rigs. We haven't seen a whole lot of 18-wheelers hauling rigs out of the field. Now we're in February, we're late February, by midyear, we're supposed to start seeing the drop. So I think what you'll see is those rigs starting to move out this summer as gas prices continue to wane but we have not seen people reducing their activity wholesale like you would expect with sub-$4 gas. So consequently Leo, our production may be low, it may be right on, it's going to be just dependent on rig activity and also frac activity as well. The shut-in, the drill but not turn to sales well count has continued to rise in Louisiana, and obviously it would be a big component of that as well.

Leo Mariani - RBC Capital Markets, LLC

Just quickly on California here. In terms of your oil price realization, what are you guys seeing so far in the first quarter? Obviously, we've seen a huge move up in oil. Have you guys started to tighten your differential versus WTI so far this year?

Winston Talbert

Yes. Out in California, we have a Conoco contract where we sell on a percent of a NYMEX basis but we also sell at California posted prices, about a third of the production and those prices have gotten much, much better and it's tightened up our differentials and we're seeing 3%, 3% to 4% uplift in realizations out in California from what we expected.

James Flores

And then also, Leo, on that, we are focused, in the Eagle Ford getting our -- or trying to compete with LLS posting as well. Getting it down in the intercoastal canal and try to get our product moving in that market as well.

Leo Mariani - RBC Capital Markets, LLC

Are you guys trucking it, in the Eagle Ford into the Gulf Coast Louisiana market there?

James Flores

We're putting it in buckets, everything, anything we can. But the key is get it on the water, get it in the barges, trucking it, working on some pipeline solutions, everything to get it down there. It's too big a gap not to try to capture.

Operator

Your next question comes from David Heikkinen of Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt

Jim, just wanted to talk about the operations plan. Let's talk Eagle Ford first where you're ramping capital spending in 2011 and then into 2012 and 2013. As you think about just kind of core competencies inside the company and any hurdles or thoughts around how you ramp that, both from a personal standpoint, and then you just hit infrastructure was the second thought?

James Flores

Well, as far as core competencies on the corporate side, as far as geologic engineering, drilling and so forth, we have been coming off the Haynesville and then the Granite Wash, the Eagle Ford, we're geared all the way to go. What's been a blessing from a personnel standpoint is gearing up a big oil field in South Texas is getting field personnel, production technicians, those types of things. And I have to tell you, our Gulf of Mexico contacts are really paying off here. We're big on putting our field staff on salary as staff instead of consultants. And it pays off dealing with oil and production volumes and operational efficiencies. We're reacquainting ourselves with a bunch of old friends in the Gulf Coast that we've been able to hire a bunch of excellent people at that lease level and production office level that they're jumping in, know how to do things. And they do it in offshore Gulf of Mexico time, which is 24/7. And it's not pickup truck time so we're very pleased with our staff that were building to operate the Eagle Ford at the lease level. Doss, do you want to add anything to that?

Doss Bourgeois

Along with that, we're dealing with a lot of our contractors and contacts in the Gulf Coast and they're able to supplement where we were short in the areas we are operating. The Panhandle is kind of sparse. You got to go a long ways to get contracts from where we get our equipment and facilities and stuff built on the Gulf Coast and get them shipped up. So they're reacting very well to that. So timing wise, we're not missing a beat there. It's working out well.

David Heikkinen - Tudor, Pickering, Holt

And then just the Eagle Ford well results, higher volumes, can you talk about cost of transport, and then any thoughts around what type of recovery you'd expect from these two most recent wells?

Company Speaker

Our type curve, and it's too early to deviate from it -- these wells are probably a little above it in their initial testing, but it's 258,000 barrels EUR per well, and we would expect that to be that or higher given these initial rates.

James Flores

That was our type curve that we bought in on the play so we expect to keep pushing that north as we get better production rates, but we're going to need some time on the curve.

David Heikkinen - Tudor, Pickering, Holt

And then cost of transport and kind of how that is actually working?

James Flores

We're going to give you some numbers, but that's a variable depending on whether we truck it or put it in buckets and get it to the intercoastal canal where our realizations are versus, say, put it in the EPD system.

Operator

Your next question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Following up on the Granite Wash question, can you just kind of take us through the six wells that have been drilled? Where within the play they have been drilled and the spacing assumptions that you're using as you go forward?

James Flores

We're in the 320 range on our assumptions, Brian. Remember, we have three rigs running up at Marvin Lake up to the north and two rigs running at Wheeler. These Granite Wash plays, just to bring you back, everybody back in history a little bit, you're drilling former vertical fields, vertically drilled fields and they're porosity pods. So you're going to have areas that have better drainage from the vertical wells. You're going to have areas that are going to be better drainage from horizontal wells. So you just have to be careful about layering in wells side-by-side each other. We've taken a very conservative approach. We have everybody ask us, how many locations you have and so forth. We have seven different Granite Wash reservoirs, five different Atoka Wash reservoirs. So you're looking at, they have 12 opportunities. I'm being very simple in this. This is a max of 12 opportunities in each wellbore. We're still establishing commercial production in the different layers. We haven't gone into the geographic type of delineation of one single layer because of the prolific nature of Wheeler. And then once we started drilling Marvin Lake, we were very conservative in that last year, remember. And we've been very pleased and surprised at a couple things at Marvin Lake. The permeability has been better at Marvin Lake, therefore the production rates were higher than we forecast, more correlative to Wheeler. And the yield is much higher on the condensate side. So we're executing our plan at Granite Wash and I think we have four wells at Wheeler and two at Marvin Lake. Is that the breakdown of the six wells, Wright [ph], of where they are?

Company Speaker

Yes, well, actually producing you're talking about? We actually have four.

James Flores

So about 50% in both areas. And from our standpoint by the end of 2011, we will have -- we think all the reservoirs identified as commercial, and that's what we're striving to do. And then we'll lay out a further infield development plan based on drainage and well history and that type of thing that they'll have some science behind it versus just geographics.

Brian Singer - Goldman Sachs Group Inc.

And then can you just give us the latest update on the deepwater sale and potentially with some potential movement here with regards to permitting and the move-up we've seen in futures prices, is that having an impact on how you or others think about valuation?

James Flores

One more thing on the Granite Wash, Brian, that we just tested a well here at Marvin Lake, at 20 million a day and 800 barrels of condensate. That was a new well we just tested, earlier this year.

Company Speaker

It hasn't gone to sales yet. That was an eighth well, it's not on sales yet.

James Flores

On the deepwater, from a standpoint. Ask your question again, I'm sorry.

Brian Singer - Goldman Sachs Group Inc.

One is timing and two whether you kind of feel on your end or on those you're talking to that there is an impact to evaluation from the rise in oil futures that we've seen and some potential movements here and then the permitting process in the Gulf?

James Flores

Well if you look at the PV10 of our assets, it's around $4 billion at $100 oil in the deepwater. At $115 oil it's obviously, maybe $4.5 billion. We're going to sell it at a significant discount to that. We've got some additional geologic information that makes it even look better on some of our exploratory stuff. So strategically, if we didn't have a situation where we could reinvest the capital and get a higher PV like reinvesting, accelerate our Eagle Ford and so forth, it'd be a more difficult sale than it already is from an emotional standpoint for us. A couple of things have improved in the deepwater, which is the well containment company has passed the initial tests with the caps and so forth, that is really going to dislodge a lot of thinking that we can control a blowout if it happened again within days and weeks versus months and years like what we were faced with before as an industry. A lot of things are settling in along those lines. That has not changed the buyer universe from a standpoint of being some concentrated buyers within the Gulf of Mexico because strategically, the money is still flowing out of the Gulf of Mexico into things like the shale plays and so forth. So selling a deepwater project in the Gulf of Mexico right now would be a little bit like selling the Fayetteville if they suspended hydrofrac-ing. So it's a little different market right now. So I think we've managed expectations correctly with everyone. The transaction, we believe, is imminent and in the next days we'll track and have some news for everybody in March and we'll be onshore at that point in time.

Brian Singer - Goldman Sachs Group Inc.

When you look at the Eagle Ford, what is the maximum recount you think you could run on your existing assets?

James Flores

Right now, and you've got to promise to ask me that question in about two years, okay? But right now let's say 12.

Operator

Your next question comes from Pearce Hammond of Simmons & Company.

Pearce Hammond - Simmons

Jim, I just wanted to ask about the status of the BP production handling agreement with Friesian, and how that impacts the deepwater Gulf of Mexico sale?

James Flores

Two things, we're under confidentiality with them to discuss as much about it from a standpoint. We're in discussions with BP and their partner Shell all the time and Boehmer [ph], as far as that situation. Since it's involved in the sale, Pearce, I've got to table that one because we got ongoing discussions with people looking at that issue differently. And so we've got to pass on that.

Pearce Hammond - Simmons

Are there any unitization agreements with other counterparties around those deepwater assets and how could that impact the sales price as well?

James Flores

Actually, we completed a preliminary unitization agreement on Lucius, between our Lucius partners led by Anadarko and the north hedging [ph] partners they call it, led by Exxon. That's helped put some clarity to our plans and also to sharing in costs and so forth. It actually helped the process even though it delayed it for three months from last -- we were expecting a sale in fourth quarter last year to the first quarter this year.

Pearce Hammond - Simmons

And then finally on the Mowry shale, what would you need to see to allocate additional capital to that play?

James Flores

A year's worth of production. We're a ways away, that's a science project at this point in time.

Operator

Your next question comes from Duane Grubert of Susquehanna.

Duane Grubert - Susquehanna Financial Group, LLLP

Jim, in your release you talk about being active in California but I didn't a see a reference or rig count, so could you just tell me if you're running rigs both in Los Angeles and in San Joaquin right now?

James Flores

We try not to quote rig counts because we have to -- in California, Duane, you understand it, that we have the answer to the crazy community out there. But we're actually running four rigs right now in California, how's that?

Duane Grubert - Susquehanna Financial Group, LLLP

Now with the changes in the diatomite permitting out there, which is an old issue, did the sector and did you specifically learn anything or change anything in how you're going to pursue your cash cow diatomite development going forward?

Doss Bourgeois

No, it slowed down just a little bit. We're working through the permitting process with DOGGR [Division of Oil, Gas and Geothermal Resources]. But as far as that goes, not really. It's just slowed the process down just a little bit, but they've been very receptive working with all the operators out there. They had to come in and understand the process, and we showed them how we monitor, how we are injecting steam to make sure that you don't have surface breaches and those types of things. But they've been educated, there was a change out of people there and they just needed to be brought up to speed and they seem to be working with us.

James Flores

With that said, Duane, it has take -- we're always learning out there. There's always new processes and there's new ways of doing things. So anytime we paused out there -- when we paused in 2008 on capital, it sure helped everybody kind of think about some things that we were doing and we changed some processes and so each pause, we do make a technological or at least an intellectual leap forward besides just getting the work done.

Duane Grubert - Susquehanna Financial Group, LLLP

Your land strategy the last year has been focused outside of California, but plausibly, there are some farm-ins from maybe some of the majors and plausibly there are some private company's out there still to mop up. Is that of interest to you guys at all?

James Flores

Well, it's always a price deal. Imagine what people want for their properties out there right now. California -- all real estate is probably some of the most valuable because it's endless. We'd love to get more California properties out there, but we don't have anything. We're focused on debt paydown around here with the deepwater sale. And on top of that is redeploying as much capital as you can in the lighter crudes in the Eagle Ford.

Operator

[Operator Instructions]

James Flores

Thanks everybody for participating. We look forward to give everybody some big results in the Eagle Ford and the rest of our assets after the first quarter. Thank you, operator.

Operator

Thank you, that concludes today's conference call. You may now disconnect.

Operator

Thank you. That concludes today's conference call. You may now disconnect.

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