WPX Energy Management Discusses Q1 2013 Results - Earnings Call Transcript

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 |  About: WPX Energy, Inc. (WPX)
by: SA Transcripts

WPX Energy (NYSE:WPX)

Q1 2013 Earnings Call

May 02, 2013 10:00 am ET

Executives

David Sullivan

Ralph A. Hill - Chief Executive Officer, President and Director

Rodney J. Sailor - Chief Financial Officer, Senior Vice President and Treasurer

Bryan K. Guderian - Senior Vice President of Operations

Analysts

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Robert Bellinski - Morningstar Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the WPX Energy first quarter update. Today's call is being recorded. At this time, I would like to turn the conference over to Mr. David Sullivan, Manager of Investor Relations. Please proceed.

David Sullivan

Thank you. Good morning, everybody. Welcome to WPX Energy first quarter 2013 operational update. We appreciate your interest in WPX Energy. Ralph Hill, our CEO; and Rod Sailor, our CFO, will review a prepared slide presentation this morning. Along with Ralph Hill and Rod Sailor are members of the senior management team. Bryan Guderian, Senior VP of Operations; Neal Buck, Senior VP A&D and Land; and Mike Fiser, Senior VP of Marketing, will be available for questions after the presentation. This morning on our website, wpxenergy.com, you will find today's presentation and the press release that was issued earlier today. The first quarter 10-Q will be filed today and that will be available on the website as well.

Please review the cautionary language regarding forward-looking statements on Slide 2 and the disclaimer of oil and gas reserves on Slide #3. They're important and integral to our remarks, so please review them. Also included are various non-GAAP numbers that have been reconciled back to Generally Accepted Accounting Principles. Those schedules follow the presentation.

So with that, Ralph, I'll turn it over to you.

Ralph A. Hill

Thank you, David, and welcome to WPX Energy's first quarter 2013 earnings call, and thank you for your interest in WPX. Our quarter's highlights are, number one, the Piceance discovery, Niobrara discovery well exceeded 1 Bcf of production in a little over 100 days. Number two, our Williston oil production grew 50%. We had a 40% growth in the Appalachian natural gas production. Our balance sheet remains strong, particularly versus a number of our peers. We are reaffirming our 2013 production guidance, and we have cost improvements that are beginning, with more to come.

Let's move to Slide 4, please. We're encouraged by the stronger natural gas prices that began late in the first quarter. While not adding rigs at this time, WPX is ideally suited to capitalize on a sustained gas improvement and we believe, particularly in the Piceance, we can be the first and fastest to grow. We are growing -- total company oil production this year by 21%, with growth in the Bakken of 25% to 30%. We have continued cost improvements that are kicking in, contractual improvements that I'll talk about in a couple of slides, and we're also reducing our drilling and completion days, which I'll discuss when I talk about our major basin slides. And we continue to pursue new opportunities. Obviously, the organic opportunity in the Piceance Niobrara, which I also will talk about, we are pursuing. And our new oil exploration efforts are underway. We've completed 2 wells in one of our new plays and are drilling our third. The second play should spud our first well later this month, and we will update you on the first play at a minimum no later than our second quarter earnings call.

Slide 5, some of our recent highlights. 12 Bakken wells were put on first sale in the first quarter, very difficult weather challenge early in the quarter, but we were able to put the 12 wells on sale. The majority of those wells were put on sale later in the quarter because of the weather, so our average well ended up in March at 12,500 barrels a day. In the Niobrara, our Niobrara well continues to perform well above our expectations. It produced 1 Bcf in the first 107 days of production. And at this rate, the Niobrara well will produce in the first 4 months what a typical Piceance Basin Williams Fork well will do over its estimated life cycle of 25 to 30 years. Our contractual cost savings did kick in at Willow Creek and Piceance gathering. Saved us $11 million in the first quarter alone from the new Willow Creek and this Piceance gathering contract. These are the first of many contractual cost savings we will see in 2013 and 2014, which I'll discuss in a minute. On the Powder River Basin, as we evaluate our bid submitted by interested third parties, we are continuing the process of the potential monetization of these assets. And at Apco, after the market closed yesterday, WPX filed a 13D regarding its ownership stake in Apco. Apco's operations continue to perform very well, ending 2012 with its 10th consecutive year of production growth. This 13D is the first step in exploring possible disposition of our equity interest in Apco.

Slide 6. I do want to remind our investors we have a number of cost improvements that are kicking in or beginning to kick in. Our first, for 2013, we will have a run rate savings of $45 million to $65 million. As I mentioned, the Willow Creek improvement processing fee has dropped from $0.36 to $0.07. And our Piceance, we had a gathering rate change, those have already kicked in, and that will be the $45 million to $65 million of savings. Our Van Hook Gathering System, which will save us $2 to $4 a barrel of hauling, will kick in by the end of the second quarter of 2013. By the fourth quarter of 2014, we will have a total run rate savings of $125 million to $165 million. Included in that is our Laser contract, we will reach our gathering volume minimum, if you will, and that will decrease our rate substantially. And our sale for resale agreement on the Rockies Express expires in the fourth quarter 2014, which obviously causes a tremendous cost improvement for us. And we are aggressively negotiating to buyout of our unutilized transportation. This improvement is not included, it's not included in the $125 million to $165 million number above, but if we -- depending on how much we buyout of, and if we buyout of, it could save us $25 million to $46 million of the potential annual cost savings for us.

Slide 7, let's now look at our core basins. WPX has a very unique position in the Piceance and with over 230,000 net acres. Advantages we have is our infrastructure's in place, we have state-of-the-art water management systems, our midstream equipment is in place to cover many years of our forecasted gas rates. We are the preferred operator. We have the best quality of reservoir in the basin and highest economics in the basin. If you look at Bullet 2, our Rulison Field well costs were about 38% less than offset operators would look like, and our lifting costs are about 53% less. It's part of the scale advantage we have. Our water management system is up to approximately 50,000 barrels a day that we can handle. It's in place and ready for more. Our drilling efficiencies continue to do better and better in the Piceance. We spud 54 wells in the first quarter. We -- average well in the Ryan -- record well in the Valley of 3.7 days and 7.7 days in Ryan Gulch, and our average Valley drilling time is now 8 days.

And our drilling continues on new, emerging Niobrara play which is on the next slide, Slide 8. Let me remind you of the existing resource we control. We have about 180,000 net deep acres that we control and held by production. Other operators have drilled a number of wells in here, but let's look at what we've done. We spud our first horizontal well in August of 2012. We had 535 feet of coring and special logs we did. Our IP was at 16 million a day at 7,300 pounds. First 100-day average was 9.5 million. And as you know, we've done over 1 Bcf in the first 107 days. So as we work to delineate the field this year, we've already spud our second well in April, and it was within a 4-mile radius of the first well. It's an acreage delineation well. We have a brand new rig in the Piceance, and we think it's the first one in the Piceance -- definitely know it's the first one in the Piceance that's a 100% natural gas powered, obviously saving us quite a bit of money on that rig. We have 3 additional horizontal wells planned for 2013. Two of those wells will be an immediate offset to the first Niobrara well we drilled to the west and the north and another well will be another acreage delineation well, which will be within a 4-mile radius. Finally for 2014, as we get these results in, as we look at it, we are doing everything we need to do to get a more aggressive 2014 drilling plan developed and we'll give you those plans later this year.

Slide 9, this is a publication by IHS Herold. If you convert our Niobrara well to a Boe equivalent, we have the #1 well that's been drilled in the Niobrara in the Rockies, 45% higher than the next best well. And interesting, it's not on this chart, is you remember we have about a 2 Tcf discovery in the San Juan Basin, in the Mancos formation. If our 2 wells in the San Juan Basin were included on this, they would have been in the 5th place spot. We're obviously not drilling there yet, but it is a significant resource for us in the San Juan Basin also, as we have in the Piceance.

Next slide, please. On the Williston Basin, we had 9 spuds with 4 rigs operating, 5 Middle Bakken and 4 Three Forks. Our Bakken oil production increased 50% to 11,500 barrels of oil a day in the first quarter. We had severe weather affect some of our early planned completions and caused some freeze-offs, but this was corrected as the quarter progressed and team did a great job of getting 12 wells put on sale, majority of those were later in the quarter and our March production averaged 12,500 barrels of oil per day. Our wells continued to perform at or above expectation. And we have our IPs listed here, our long Middle Bakkens are doing very well, at about -- close to 1,400 barrels of oil per day. Our long Three Forks are about 1,350; in my vernacular, 1,400 barrels a day on -- rounded up. And our short Middle Bakken actually did very well, and we're basically done with any shorts that we need to do. Our cost improvements continue with that 10% to 20% that we've been talking about. Our drilling days continue to improve. We have our record days there at the lowest Middle Bakken of 27 days and lowest Three Forks of 25 days. We did zipper fracs, continue to be very successful for us. 6.5 days execution time and one of our first. The majority of our future completions will be done with this dual/triple zipper fracs, substantially improving our cost, and we have fully transitioned to pad drilling. So the team has done an excellent job of getting us in the right spot at the Williston and costs continue to improve, and the EURs continue to get better.

Slide 11, Appalachia. We had a very strong production growth, increasing our EURs. That came in spite ongoing infrastructure issues that we've all talked about numerous times. Our drilling and completion efficiencies have continued. Our average day to spud to rig release has reached an all-time low in the first quarter of 2013. Our new rig is obviously performing very, very well. It's an Orion rig. Our completion costs are down significantly for 2012. And as we wait for the infrastructure in the Susquehanna to improve, we have moved our rig down to Westmoreland for the time being. Talking the second bullet, the infrastructure improvements are progressing, finally. The field receipt compression was installed by Williams in March. They are having remedial work done at the Dunbar station, a major compression in New York, which is currently restricting production. We think a lot of the remedial work should be complete by the end of May per Williams, and the Dunbar major expansion should be completed by the fourth quarter. When it is all working, we have seen that 50% uplift that we've talked about, so when all the field receipt compressions are working, we've had production of 20 million to 25 million a day higher, when it's all working, and we expect at least the remedial work to be done by May, and then the major expansion done by the fourth quarter.

With that, I'll turn it over to Rod to talk about the financial results.

Rodney J. Sailor

Thank you, Ralph. This morning, we released our earnings for the first quarter of 2013. Earnings were in line with our expectations and previously released guidance. Overall, first quarter equivalent production was 1,286 (sic) [ 1,268] million cubic feet per day. As Ralph mentioned, oil production was up approximately 21% quarter-over-quarter and averaged a little over 19,000 barrels per day. First quarter oil production was impacted by colder weather in the Bakken, which really hampered our completions in January and February. As we've stated, we'll be disciplined in our natural gas development. Marcellus production was up 40% compared to first quarter 2012. It was up approximately 4% compared to fourth quarter 2012 as we continue to be hampered in the first quarter by infrastructure in Susquehanna County. Total natural gas production was 1,021 million cubic feet per day. While down versus quarter comparisons, it's slightly ahead of our expectations. Natural gas liquid volumes were 21,700 barrels per day, which is down quarter-over-quarter -- on quarter-over-quarter comparisons largely due to ethane rejection. We continue to believe ethane will hold at or near the natural gas BTU equivalent for the remainder of the year.

First quarter 2013 results were negatively impacted by mark-to-mark losses of $94 million. On our hedging, our natural gas derivatives not designated for hedge accounting treatment. These losses will be realized throughout the year at the current forward prices. Absent these losses, our adjusted net loss from continuing operations for the first quarter was $51 million versus a loss of $7 million in the first quarter of 2012. EBITDAX for the quarter totaled $203 million versus the $263 million in the first quarter of 2012. And our capital spending for the quarter was $271 million, which was down from $428 million in the first quarter of 2012.

If I could turn you to our hedging slide, really here we -- what's new is we have included a summary of our 2014 hedging activity. We executed swaps at a $4.35 price. The counterparty does have the onetime option to double the volume on these trades. It's a onetime election. As we saw prices strengthened in the forward curve, we executed some costless collars, averaging a $4 floor and $4.58 ceiling. And again, we've also hedged a small percentage of oil at $95.

And with that, I will turn it back over to Ralph to wrap up.

Ralph A. Hill

Thank you. Looking at our map of our portfolio, I like to close with this always. Let me just remind you a couple of things about WPX. We continue to operate from a position of strength. We have strength in our reserves portfolio with over 18 Tcf of 3P reserves. And this doesn't count any of our Piceance Niobrara discovery, which could easily double the size of those reserves. Strength in our balance sheet with approximately $1.5 billion of liquidity and ability to grow all 3 of our product lines: oil, gas and NGLs at a greater than 10% annually for the foreseeable future, with what we own today, just the 18 Tcf. That could effectively double the size of our company in about 5 years. And we are encouraged that gas prices are showing the signs that it's about time to get back into the drilling for gas. The vast majority of our capital continues to be invested in our 3 primary areas: the Piceance, which is, we believe -- and it's unique to us, it's a unique position, it's the best gas and NGL basin; the Bakken, which we believe is the best oil basin; and the Marcellus, which we believe is the best gas basin.

So with that, I thank you for your interest. I'll close, and we'll turn it over to the operator for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Velie, Capital One Southcoast.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

A couple of quick questions. The evaluating bids right now for the Powder River asset divestiture, is that -- do you think where you stand today, does it lessen the likelihood that you'll, I guess, be looking at MLP possibilities in San Juan or the Piceance?

Ralph A. Hill

I would say no, it doesn't at all. That's just the -- the Powder for us is not going to win, if you will, the allocation for capital. So those are completely separate decisions.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay. And then the 10% to 20% savings in the Bakken wells, is that -- what base well costs are you going from there?

Ralph A. Hill

That was in like -- the last year's range was at $12.5 million to $13 million, so it makes our well costs now down in the $11 million range. And keep in mind, we do use ceramics, so if you look at what's going on in that area, we've seen some other operators that are saying their well costs are about $11 million, but they don't use ceramics. We've done a lot of analysis on it. We think you should. So it puts us currently in about the $11 million range, which we think is very competitive for that area of the Williston.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay, great. And then finally, I think I heard you say that in the Susquehanna County, you're starting to see what looked like better EURs and that costs are coming down, can you quantify that at all? Or is it still too soon with the -- I guess, interruptions from takeaway?

Ralph A. Hill

Well, we still -- our type curves are still in the 7 Bcf to 9 Bcf range up there because of the lack of new data, so we don't have enough data yet. But we are seeing, when the field receipt compression comes on, enough data at least make us feel comfortable those are the right ranges. Will they go higher? We just don't know yet, unfortunately.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay. And then on the cost side, what are you thinking would be a good place to model those well costs there in Susquehanna going forward? I know you don't have a rig there right now, but in the future?

Ralph A. Hill

Well, I think the team would say about 6.5 and, of course, I'll say about 6, so I'd say somewhere between 6 and 6.5, because the team continues to do better and they really are. When we get back in the game there, I think they'll continue to do -- they've done a really, really good job based on sporadic drilling, if you will, because of the infrastructure problems.

Operator

Your next question comes from Robert Bellinski from Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was hoping you could give us some additional color on your San Juan Basin acreage and your take on the prospects for additional development, given the recent interest by others in the industry? Or alternatively, would you consider divestiture to accelerate the value of the acreage?

Ralph A. Hill

Well, I see -- I don't have the acreage -- it's on our map there, I think our acreage -- Bryan, could you get that for us? But we actually -- the San Juan Basin for us, with the 2 wells I talked about that we did were horizontal Mancos, if you will, similar to the Niobrara formation. We think that we have about 2 Tcf of reserves we're sitting on there on a 3P type basis. So the San Juan Basin, at this point, is not a candidate to be a divesture because of the opportunities we have -- significant opportunities we have based just on the Piceance gas discovery that we have -- or I'm sorry, the San Juan Basin Mancos discovery that we have. Bryan, can you give him the acreage?

Bryan K. Guderian

Sure. Just maybe a little additional color there. We still have, of course, undeveloped reserves both proved as well as probable and possible reserves related to our legacy development. In particular, our core asset, which is known as the Rosa Unit. And so we would see our traditional legacy development going forward there within Rosa. And then deeper, you've heard us mentioned before, we originated our study of the Mancos shale in the San Juan Basin. In fact, under the Rosa core asset position there. And that's where we drilled some 60 vertical wells that were completed in the Mancos originally going back 4 to 5 years. And then 3 years back, we drilled the 2 horizontal wells there that are on target to make between 5.5 Bcf and 6.5 Bcf each. And so we have a lot of future opportunity there in the basin that we can go to when the gas price environment is favorable.

Robert Bellinski - Morningstar Inc., Research Division

Okay, that's helpful. Also, in the Bakken, do you guys have any thoughts on downspacing at this point?

Ralph A. Hill

Well, we did do extensive core site study last year. And I think it might be a little early, but I'll turn that to Bryan to talk about that.

Bryan K. Guderian

Well, our study is underway certainly, and it's really -- what we're doing, we did coring, we've done a lot of petrophysical analysis there. We're trying to ensure that we get the optimum completion, design as well as spacing very early in the life cycle of this project. We're eager to watch industry. There are other pilots that are underway. I'm sure you guys are well aware of that. We have not drilled anything tighter than 3 to 4 Middle Bakken and 3 to 4 Three Forks wells per 1,280 acres at this point. I think we're encouraged by the industry activity that we see, and we would expect the results of our science -- scientific analysis to be coming out over the second half of the year and we'll make more definitive decisions around spacing at that point in time.

Operator

[Operator Instructions] Your next question comes from line of Mr. Hsulin Peng from Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

This is Hsulin from Robert Baird. So on the call, you had mentioned that you can ramp up Piceance if gas prices stay its current strength. And I was just kind of wondering if you can give us more color there in terms of what do you -- how long of a sustainable period do you need to see? And also, if you -- how many rigs would you -- could you potentially add? Would you want to go up to 7 from the current 5, to keep production flat? And how much CapEx that would take to get to that level, for example?

Ralph A. Hill

Well, I think the -- we're encouraged, as I mentioned, and we clearly would like to hold that production flat. So if we were at 7 rigs on an annual basis, that would essentially hold the production flat. Obviously, it's a little late to do that this year, but I would answer your question that I would like to see us go to the 7 rigs and stay at 7 rigs, and we'll probably make that decision in the next month or so. If we did that, since it's the next half of the year, these are rough numbers, and we'd have to get it back to you, that would probably be $50 million to $60 million. It wouldn't add a lot of production this year, but it would add a significant amount of production next year. And we can get all that for you once we decide to do that, if we decide to do that. But that would be my preference, but we're still just monitoring it and understanding. The team can easily do that. The rigs are available, so it's something that we're seriously considering.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So you'd give us an update within the next month or so?

Ralph A. Hill

I think so. I think by midyear, yes, which is -- yes, next month or so is midyear, yes, absolutely.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then second question, it's regarding the Marcellus infrastructure. So now that Dunbar station is in -- the remedial work will be completed by the end of May, I think, as you said. I was wondering, so would you consider just keeping the current 2 rigs? And how would you or would you potentially add more rigs to it? And do you still have, I think it was about 30 M that was constrained, is that all back on right now?

Ralph A. Hill

I would say the -- a lot of that is still constrained. We've had days when it's come up, 20 million to 25 million a day, and then we've had days when the Dunbar station goes down and kicks it all off. So I still think it's constrained. We actually have one running right now, and that's in Westmoreland. We'd like -- if the infrastructure is fixed, and I think that will take more like September, even though I think they'll remediate the early opportunities. It -- clearly, the Susquehanna is our best area to drill in. We have rigs available. And I would like to see us add something there, but that will probably be more like in September. And that's our best area to drill in, and we would clearly like to be -- it's too early to tell, but we were at 3 rigs in that area. We'd like to be back to that at some point. That won't happen this year, but I think in the near future if prices stay where they were, that would be -- and that would have significant impact to our potential growth.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, and that's not in your current guidance, correct?

Ralph A. Hill

No, what we have -- if you look on our guidance slide, we have like a low base and high, and I think that high adds...

David Sullivan

The $4 case has 2 rigs coming into the Marcellus.

Ralph A. Hill

It has 2 total?

David Sullivan

Yes, 2 total.

Ralph A. Hill

Yes. So that -- so you see that, that would be the impact and difference in capital on that -- on our guidance slide we've talked about it, if we had 2 rigs running on an annual basis. So it's not in the base guidance, no.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then last question is regarding your potential asset sales with Powder River and Apco, I was just wondering how you would consider investing the proceeds?

Ralph A. Hill

Well, I think, obviously, we -- your questions have led pretty much where I think we'd like to do that. We would like to get -- if prices stay where they are, we could easily invest the proceeds into developing what we have with the vast portfolio we have, is to do that first. We may also use some of it to continue to clean up some of our cost side. But if prices stay where they are, it will work very well to use that to jump start our growth.

Operator

[Operator Instructions] Your next question comes from the line of Matt Portillo from Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I was just hoping that you could give us a little bit of color, or I guess walk us through how you guys see your oil volumes reaching kind of the mid case or base case this year at almost 22,000 a day from kind of Q1? Just trying to get a little more color on how we get to that number for the full year average.

Ralph A. Hill

Yes, we can.

Rodney J. Sailor

So I would start with, again, we were hampered somewhat in January and February. We did end with, I think with 12 completions in the Bakken in the first quarter. Those largely came on in March. So that's where you saw the kind of the average March at 12.5. Again, the 21 -- my production number, the 21 point...

Ralph A. Hill

21.5 -- that's total company.

Rodney J. Sailor

Yes, thank you. It's total company. So that includes our condensate in the Piceance, which remains relatively constant. And it also includes our international assets from Apco. Apco was somewhat hammered -- hampered by rig availability, I think, in the first quarter, but we expect them to catch up later in the year. So again, we feel -- sitting here today, we're confident we're going to hit kind of midpoint of our guidance as we get past the weather issues in the Bakken and Apco catches up.

Ralph A. Hill

Yes, we're now ahead, if you will, from where we thought we would be at that 12.5, so that -- the Bakken will continue to grow at some point, but we do get about 6 million -- 6.5 million, 6.6 million from the international volumes, and then we have miscellaneous volumes coming in from the Piceance.

Rodney J. Sailor

I would also -- I'd also point out that if you look at our guidance, we've got about $40 million dedicated to oil development. Again, we would expect that, Ralph talked about we've drilled 2 and we're starting our third in kind of some of our exploration activities. If those results continue to be as expected, we would go into oil development in June around that acreage and that will also add some additional oil volumes in 2013.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so to follow-up there, it sounds like the first 2 wells you guys have drilled have been successful or at least in line with your kind of expectations on the new venture play. Is there any additional color you can give us there?

Rodney J. Sailor

Yes, you're correct. They're meeting our expectations. And again, I think we would look to get, as Ralph mentioned, get something out no later than the second quarter call. I think if we continue to be pleased with the results, we would likely look to maybe do an interim release prior to that. Again, the reason -- as we said, the reason that we've been a little silent on results around that is just that we are still trying to wrap up some acreage additions in that area.

Ralph A. Hill

I'd say, actually, so far they definitely are meeting and probably exceeding our expectations, so that's a good thing.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just on the timing on asset sales, I was just curious if you could give us any color on maybe when you'd expect to announce a winning bid for the CBM asset? And then on Apco, how long of a process could that be? So just a little bit more color on the timing of that.

Ralph A. Hill

I'd say on Powder, it'd be probably by next month, a deal would be announced. And on Apco, just the way the -- we just filed our 13D, there's a lot to do there. But I think for that, an optimistic case on that would be the early part of '14 just because of the complex -- not complexity, just the timing to get that done. So first quarter '14, I'd like to see that done by, but obviously we're just starting to process.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And have there -- I guess, have you had any encouragement from some of the other processes that have gone on in Argentina to bring this forward? Or what was kind of the genesis behind potentially selling Apco here?

Ralph A. Hill

Well, I think again it's strategic. We don't think that ultimately that value -- even though Apco has done, as I mentioned, I think it's the 10th or 12th straight year of production growth and net income growth and continues to do very well. We just don't think it's going to be reflected in WPX value ultimately for our shareholders. So we think the sale of that and the ability to bring that back and redeploy that into our domestic operations brings a lot more value. So really, it's a strategic decision.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a quick question on the Mancos. What do you need to see from here to get, I guess, more aggressive on the drilling? And as we roll into 2014, if you continue to see similar well results, how should we think about kind of the drilling cadence or the rig count potential for that Mancos formation for you?

Ralph A. Hill

That's -- we just don't quite know yet. It's -- we do have the 4 this year. Clearly, we're -- and we're only really delineating like the eastern third of what we own. So there's a lot more to do, but we could kind of have a combination probably where we're developing a little more rapidly in the area we're drilling now and still doing some science as we move to the east. And I'd love to give you a good answer, yes, but that is something we're really working hard with the team on. And we're just on our second well, so we'll give you more color at each call of what we think we're going to do. And by the end -- at least no later than the end of the year, what we think we'll do for '14. But I would like to see us do a -- maybe at least twice what we're doing this year next year or maybe slightly more. That's not a lot of wells, but these are big wells. If we got to that level, that's a great way to do it. Then in 2015, I think we have enough to know where we'd go into full development. But if we could do 8 to 10 wells next year, that would be very good, because there's still a lot to do and it's a big field and it's a vast resource.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And from a -- I guess from a derisking perspective, is this potentially an asset where you may look to bring in a partner to financially derisk the play? Or do you really want to hold on to this sole risk and delineate the play further?

Ralph A. Hill

Well, I think it's -- luckily for us, in the area we're in, there's been a number of others that -- their wells aren't good as ours, but they're to the south of us and maybe around to the west of us, but they're helping delineate part of the field too. So at this point, it's a great resource, and we like what we have and we're not in thoughts about partners for that, but it's still very early.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And my last question, I apologize for so many. Just as we think about your asset base today, you now have 2 established gas assets, the Piceance and the Marcellus, and potentially a third in the Mancos. Kind of given your capital constraints in a $4 to $4.50 gas environment, that's probably a lot to develop on your own. How do you think about those as they rank in terms of the resource potential? And is there potential for you guys to maybe sell down or monetize some part of that portfolio, if you are able to establish a third play in the Mancos?

Ralph A. Hill

Well, I think the -- obviously, the resource potential is the greatest in the Piceance by far than our Marcellus position. And we think we can develop it all, but it's -- we need to also understand what that resource is and if there's a way to bring value faster, we clearly would look at other avenues, but it's too early to tell right now as we continue to understand that resource.

Rodney J. Sailor

Yes. I would just add, we need to understand what the Niobrara potential is. Again, if we wanted to develop elsewhere, and we were capital constrained, that would then -- I think would lead us to discussions around JV partners. Again, I think we feel that we can add up, $4.25, $4.50 gas price, the Mancos return -- excuse me, the Marcellus returns are very, very strong. So again, I think we'd first look, is there alternative ways to raise some capital.

Operator

I would now like to turn the call over to David Sullivan for closing remarks.

David Sullivan

Thanks again for your interest in the company. As you have heard from Ralph and Rod and all those who participated in today's discussion, the management team of WPX is committed to creating long-term shareholder value through the execution of our plan. So thank you again for your interest in the company.

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