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WPX Energy (NYSE:WPX)

Q4 2012 Earnings Call

February 28, 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

Neal A. Buck - Senior Vice President of Business Development and Land

Analysts

Stephen Richardson - Deutsche Bank AG, Research Division

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

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Trevor Menke - Robert W. Baird & Co. Incorporated, Research Division

Operator

Good day, and welcome to the WPX Energy operations update. Today's call is being recorded. At this time, I'd like to turn the conference over to David Sullivan, Manager of Investor Relations. Please go ahead.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy 2012 Year End Operational Update. We appreciate your interest in WPX Energy. Ralph Hill, our CEO; and Rod Sailor, our CFO, will review the prepared slide presentation this morning. Along with Ralph Hill and Rod Sailor, our members of the senior management team, Bryan Guderian, Senior VP of Operations; Neal Buck, Senior VP of A&D and Land; and Mike Fisher, Senior VP of Marketing; and all will be available for questions after the presentation.

Since the market closed yesterday, we have released our 2012 earnings results, 2013 guidance and 2012 year end reserves and also today's presentation, all of which are available on our website, wpxenergy.com.

The 2012 10-K will be filed later today, and you'll be able to access that on our website as well. Please review the cautionary language regarding the forward-looking statements on Slide 2 and the disclaimer on the oil and gas reserves on Slide #3. They are 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. Welcome to our 2013 Operational Outlook and Fourth Quarter 2012 Earnings Call, and thank you for your interest in WPX. A couple of key reminders before I move in to the body of the slides. With over 18 Tcf of 3P reserves in the appropriate commodity environment, we can grow all 3 of our product lines to the double-digit rate for many years. In other words, we can double the size of our company within 5 years by developing what we own today, and that is before our recent Niobrara discovery that I'll discuss today.

Our balance sheet remains very strong, with about $1.7 billion liquidity that keeps us in a position of strength to grow at the appropriate time. And we continue to believe and by choice we're in the best basins in the nation and sits in the best oil basin in the Bakken, the best gas in the NGL basin in the Piceance and the best gas basin -- pure gas basin in the Marcellus.

Please turn to Slide 4, please. Our 2013 path to greater shareholder value. We intend to grow our oil production as a total company by 21%. Our Bakken oil production will grow between 25% and 30%, and we're going to maintain a very disciplined natural gas development. We're not growing our gas volumes at this current environment, but we're poised to -- for growth when prices recover, and I continue to believe we can be the first and the fastest and the best returned when prices recover to grow our gas.

We will continue our cost improvements and discuss in a few minutes our drilling and completion cost decreases in our major and operating areas. We've had significant improvements in costs. And we have contractual improvements, such as our oil precontracts that have already kicked in with also improving several other costs. And we had new opportunities we're going to pursue this year. The organic opportunities and the Niobrara discovery, we'll talk about that in a few minutes. And we have oil explorations underway in 2 new basins. We've already spread one of our first wells in early January. I can talk more about the Niobrara here in just a few minutes, but as for the 2 new oil plays, that will be more of a mid-year update.

Slide 4, strategy to drive our shareholder value. First, if you look at the Bakken, we have transitioned to multi-well pads that's driving our production growth and a much lower well cost. I mentioned the production growth we expect about 25% to 30% for 2013. We've had some very good recent successes with our long laterals in the Bakken, 10% to 20% lower cost. Many things are happening there, the multi-well pad drilling, zipper frac completion. Our best well so far on a spread to rig release day was 25 days. We expect to continue to improve that, and our actual drilling time on that well was about 21 days. We continue to do more with less, so you'll notice that we have 4 rigs operating in the Bakken this year. We should drill about the same amount of wells with 4 versus about 6 that we averaged last year. So obviously, we're doing much more efficiency gains in our ability to drill wells.

We focused on infrastructure supporting development up there in the Bakken. The Van Hook system is up and operating and should improve our net base by $2 to $4 a barrel. We also have new rail agreements coming on in the second quarter of 2013, which should also improve our netbacks.

If you look at the Piceance, it continues to be, for us, a unique and world-class position, delivers attractive returns in any gas environment, and it has the ability to continue to grow for many, many years. Our existing 3P locations are about 10,000. That doesn't account with the Niobrara, which I'll talk about in a minute. We have a favorable long-term liquids processing contracts with the new Willow Creek contract. That contract alone gives us treating savings of about -- as an expense savings of $48 million under the new contract, and that has kicked in for this year.

If you look at even with the low liquids prices are out there, it still gives us a minimum of about $15 million or so of EBITDA gain in that contract, but the expense side continues to go down. Obviously, the Piceance continues to set records in the operational efficiencies.

In the Marcellus, in spite of infrastructure problems, we continue to have pretty good results there and actually, very good results. Production growth was up 75% to 80%. Our completion costs are down almost 50% in one year. Our spud to rig release days are down significantly, as you can see there, 60%. And we're going to have capital flexibility in that play. We'll be actually moving a rig to Westmoreland as we wait to catch up on the completions in the northern part of the play.

Slide 6. In the Piceance, we did have a major discovery, and the Niobrara shale well, the first one that we've drilled, continues to produce very strongly. We have about 180,000 acres held by production. The infrastructure is already in place. We believe this can be a 20 Tcf to 30 Tcf of resource potential. We plan for 4 horizontal wells in 2013, up from the original 2. We know that, as we continue to delineate that field and understand more about it, that we should be able to move in a fairly quick manner to develop mode at the right time.

In the Powder River Basin, a significant news. We're opening our data room to explore monetization opportunities with that, and that data room will open up -- will open really any day now.

Let's look at the 3 major basins, slide 7. On the Piceance, it is a superior acreage position. And this slide is very important because you see other people talk about the Piceance basin or don't talk about the Piceance basin because they don't have our position. And you see on the slide here, we're looking to offset operators that we have data from. We have 38% less drilling and completion costs. We have 53% less operating lifting cost. Those things cannot be duplicated. We're the only ones who can have that, and you can see why the Piceance basin is good for us.

We have a state-of-the-art water system -- management systems in place for, literally, thousands and thousands of barrels that we manage ourselves. The infrastructure and takeaway capacity is in place, and in fact, there is a new cryo being developed that we should be on -- is already, I think, will be ready by next year for another 300 million a day of cryo capacity. We're in the cryo capacity, in the Piceance, of up to about 1.2 Bcf a day. Now we have the new emerging play in the Niobrara. We've mentioned to you, we've sent a press release out, the initial IP was 16 million a day. Our 60-day average was almost 11 million a day. We've choked that back significantly as we understand this well. It is a prolific resource for us. We have 4 new horizontal wells planned this year. And again, I mentioned the 20 Tcf to 30 Tcf resource potential. So what's important on this slide is not only do we have a superior value position. We have 10,000 locations just left in our traditional Piceance, and now we have the new Niobrara. Then you see how much better we are than other operators out there, and I think it's important to notice that for WPX.

Slide 8, Bakken. Doing what we told you we're going to do. We're improving our well performance, we're lowering our costs and then we have a strong reserves growth. So you can see out of 31 wells put on first sales in 2012, 28 of them were at or surpassed our well performance expectations. We have many wells that are coming in significantly higher than our type curves, which are about 800,000 barrels for -- of oil equivalent for the Middle Bakken and about 600,000 for the Three Forks.

So this -- as you look on the slide, you can see that many of these wells are averaging even higher than that. Most recently, you can see in Middle Bakken, the Independence well was 9% higher than the type well. That would mean closer to about 900,000 barrels of oil equivalent. And the Three Forks's Kate Soldier well is more like 700,000 barrels of oil versus -- equivalent -- versus about 600,000 [ph] type curve.

Our drilling costs are coming down significantly. They're around to 10% to 20% on the recent long laterals. Our improvements are coming in there with lower drilling days. You can see our average there, early part of last year -- our early average this year, and now we're down to more like 25 days. And as I mentioned, the actual drilling time in that well was 21 days. We know we have a ways to go there, but the team has done the right things. We have the right things happening for the Bakken, and we're proud that our costs are coming down.

And I would say our costs in this $10.5 million to $11 million range are exactly where others are in, in the area, that on the reservation or around the reservation, and a lot of those do not use ceramics. And you need to remember, we use ceramics. We believe it's the right thing to do in our area. We've done significant studies on that. And that does add a significant amount of cost to our wells, but we think it's a better performer. So we believe we're outperforming a number of people out there, so we've had significant improvements since our third quarter call.

Turning to Slide 9, on the Marcellus. Again, in spite of infrastructure problems that we had in the Susquehanna, we have had strong performance there. You can see over 1000% reserves growth since 2010. The 2 compression pilots that we did in Susquehanna doubled our production in those areas, and we will have more of those coming on.

Our production did increase nicely last year. Not as much as we wanted to, but we, in the space of the field receipt compression, it wasn't put in yet, which is the next bullet, which is scheduled first quarter of '13.

You can see we've -- continuedly, we have at least 30 million a day of net production constrain. That should come on in March of 2013, the field receipt compression. And shortly thereafter that, we ought to be able to get those volumes on, so it should have a good growth in there in the Marcellus and Susquehanna.

Our Westmoreland wells continue to perform better than expected. Our curve is basically flattened out. Our reserves are up, so it shows some flexibility in the Marcellus this year. As we work off our backlog at compression -- or completions in the Susquehanna, we will actually mill a rig to Westmoreland, and we believe our returns would be very strong in Westmoreland.

And completion costs are down. Quarter after quarter after quarter, they continue to do better.

So if you look at the Marcellus, despite infrastructure issues, the Marcellus is delivering for us. We know we have the opportunity to be -- we're in the best area in the Susquehanna County. Some of ours may not be as good as some of the others. I mentioned up there, we might be not quite -- we think ours are probably a little less thick, our columns and possibly a little less pressure. But still, we're going to have very prolific wells up there. In the meantime, our Westmoreland continues to better than we thought, so we look to be able to grow the Marcellus. Really just the one rig out there in finishing our completions in 2013. And as the infrastructure problems are finally solved, which we think a lot will happen this quarter, we'll have a continued growth in Marcellus.

Look at the reserves report last year. We did have a very good reserves showing, and particularly in reserve adds, especially when you think that we probably had the lowest annual gas prices in, I think, in 13 years. Just for the effect of the severe lower gas and NGL prices, it is an amazing reserve replacement year for us.

This graphic reconciles what we had. We began the year with 2011 reserves of about 4.8 Tcf after we adjusted out the Barnett and Arkoma gas properties we sold for $300 million approximately last year. We produced 496 Bcf, which reduces that. We have reserve additions, again, of 634 Bcf, which is fairly amazing in that price environment, and it turned out to be an F&D -- drillbit F&D cost of about $1.74.

We had a small amount of net purchase reserves of about 6 Bcf that was associated with land trades that support our drilling programs. And then we used the SEC prescribed average 2012 price of $2.39 caused a downward revision of 498 Bcf.

These revisions were 572 Bcf associated price. We actually had 74 Bcf of nonprice-related revisions being positive for the net 498 Bcf. That gave us the new SEC price case up to 4.5 Tcf. But we like to also show what happens with the prices that were not much higher, but the 2011 average price. If we remove all the changes we made in price, we're over 5.3 Tcf of proved reserves. This case would add back 848 Bcf of proved reserves to the SEC case and a 400 -- 248 Bcf of tail reserves and the rest, 600 Bcf approximately of proved and developed of our reserves in our 5-year drilling plans.

So if you look at -- before 2012 price changes, we replaced 200% of our production and grew proved reserves by 10%. And that is with a $3.68 natural gas price, which we also believe is very conservative long-term price assumption.

With that, I'll turn it over to Rod to go through the earnings results and guidance.

Rodney J. Sailor

Thank you, Ralph. Turning to Slide 12. Earlier today, we released our fourth quarter and 2012 full year results. As noted, our fourth quarter production averaged 1,348 million cubic feet per day on an equivalent basis. Full year production was 1,386 million cubic feet per day on an equivalent basis.

Overall, a 4% increase in production, driven by a 40% increase in our oil production. Bakken oil was up 98%, a 3% increase in NGL production and a 2% increase in our natural gas production.

NGLs were hampered by ethane rejection late in the fourth quarter. For 2012, we experienced $225 million in noncash impairments, a $108 million of those in the fourth quarter. After adjusting for these and unrealized mark-to-market gains on our hedging program, our adjusted loss for continuing ops for the year was $123 million, compared with $80 million in adjusted income for 2012.

2012 year-to-date results were negatively impacted, as Ralph mentioned, by lower realized commodity prices in natural gas, where we experienced over a decade low in prices, and also lower realized natural gas liquids prices. These lower realized commodity prices were somewhat -- were partially offset, excuse me, by increased volumes. And we finished the year with $1 billion in EBITDAX versus $1.3 billion in 2011.

If now I could turn to the next slide, I'd talk a little bit about guidance. Again, last night, we released our guidance for 2013. We based that on a $3.20 to $4 natural gas price, really focusing on an expected case of about $3.50, oil ranging between $85 per barrel to $95 per barrel, again, expecting $92.50 per barrel, and targeting NGLs at $41 per barrel, based on our expected product mix.

For 2013, we are expecting ethane rejection to approximate 50% and have noted our top composite barrel on the slide. I'd like to also point out, we've hedged about 50% of our natural gas at $3.63 and 59% of our oil at slightly over $100 a barrel.

As Ralph discussed, we're going to be disciplined in our gas development at current commodity prices and expect gas production to decline to approximately 1,028 million cubic feet per day in 2013. We are expecting oil production of 21,700 barrels per day and NGL production of 20,800 barrels per day at our expected 53% rejection rate.

Capital expenditures are anticipated to range from $1 billion to $1.2 billion. [indiscernible] point approximately 7% to 8% of our capital expenditures will be in the Piceance, Bakken and the Marcellus. As the base case, we anticipate running a fiber [ph] program with the Piceance targeting -- drilling 4 wells in the Niobrara, a 4-rig program in the Bakken and running 1 rig in the Marcellus.

As Ralph mentioned, we will be targeting the Westmoreland area for part of the year. About 7% of our capital budget will be focused on oil exploration. There's also a $40 million to $50 million targeted for development of these opportunities. This is also some dollars that we could put into the Bakken should these opportunities not meet our targeted returns.

Next slide is our -- excuse me, our hedging summary. And I've previously discussed that, so I might turn you to Slide 15. We wanted to put this slide in here really just to show the impact of ethane rejection on our reported production stream. Our base plan assumes approximately 50% recoveries, due to ethane being on the margin, and we believe processing margins would need to improve $0.03 to $0.06 to significantly change this. We should note that we're still being paid for the BTUs. It's just instead of as a separate product, it's left in the stream we're being paid for the natural gas. Overall production for 2013 would be down 4.5%, where we're recovering ethane at our maximal volumes.

Our planned recovery rate, as you can tell from this slide, our production equivalency would be down an additional 2.9%. And then we've also put on there what a minimum ethane recovery would look like.

With that, I'd now like to turn it over to Ralph to wrap up.

Ralph A. Hill

Thank you, Rod. As you look at Slide 16, the strengths that we have and what we think about WPX is. When we get into an area, we capture operational efficiencies. Obviously, the first place we've done that is in the Piceance. And we continue to be a very low-cost operator there and do better and better and better. We like to be in areas where there's large and repeatable drilling programs so we can be cost effective. And if you look at that, we apply that expertise in the Piceance. The Bakken, now that the field has been delineated, the acreage is basically all held by production. We've got some of our initial infrastructure completed in the north. We have the new rigs on. We have the new way we're drilling the new zipper fracs, the efficiencies are just now starting to kick in there, we're feeling very good of where we're headed there. Marcellus has already had a tremendous amount of efficiencies happen for us as you can see by our drilling times. We're excited that the field receipt compression will be on there soon. We're excited to be able to not only develop the Susquehanna area, but also develop the Westmoreland area. And particularly, the Susquehanna area will be great for us to develop as soon as all the field receipt compression and that happens for us.

We like to be very disciplined in our capital allocation. We could easily grow gas in this environment. We're not going to, but we maintain in the right environments, which is more of a $4 environment ability to do that, particularly in the Piceance. We have a lot of upside from our 3P and our resource potential, particularly with our new Niobrara discovery. We also hope to be able to tell you good news in our new oil plays that we're looking at. So we're very excited about that. We also, as you look at the way we do our numbers, we're not assuming that the Powder River sales -- sells, but we are definitely going to start the process. So that will be additional capital that comes in the door to us if that sells and we're, obviously, looking forward to put that to good use for us. So a lot of upside there. So with that, I appreciate your calling in today and your interest in the company. And I'll turn it back over for questions.

Rodney J. Sailor

Yes. We're ready for the Q&A portion.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Stephen Richardson of Deutsche Bank.

Stephen Richardson - Deutsche Bank AG, Research Division

Ralph, I was wondering if you could address some of the questions about cost structure. You've been very, very active negotiating some of your midstream and getting additional efficiencies in your cost structure on midstream and gathering. Could you address the G&A of the corporation and how you look at that relative to some of the your peers and some of the efforts that could be made to kind of address that or not?

Ralph A. Hill

Yes. I think we're guiding to about 60-some cents this year in G&A for our per unit base. Part of the uptick is -- an excess down a little bit from the fourth quarter is obviously our volumes are down, but I think when you look at G&A, what we've looked at is 17 of our peers. I think you've got to be very careful between success efforts and full-cost companies. We look at it and we think we're about in the 7th position right now. They're a tremendous amount producers. So if you look at it, they look like they're much cheaper than us. So you got to dive in, and it's hard to do this. You got dive in into the details and see what they are. So having said that, I think we should do -- we want to be in the first quartile in our costs and our G&A. We're not quite there right now, but our numbers show that we're about in the 7th position. And we do it on an apples-to-apples comparison. And so I think with our volumes increasing at the right time and our relentless drive for efficiencies, you'll see us get into that first quartile.

Stephen Richardson - Deutsche Bank AG, Research Division

So is it really, to understand better, it's a function of growing volumes that will address the cost structure there, there's nothing additional to be done on the absolute level of costs? It's just a question of volume growth?

Ralph A. Hill

Well, I think it's a combination. We've -- since 2010, we entered 2 new basins on a prolific basis, meaning the Bakken and the Marcellus. Neither one of them -- and we've staffed those areas up. Neither one of those have taken off initially as we expected they can. Now they're doing much better now. The Bakken volumes have -- actually, the Bakken volumes and the Bakken reserves have been fine. The Marcellus volumes have been behind because of infrastructure constraints that a lot of people also faced. So that -- we have 2 teams poised and ready for growth that we haven't been be able to really take off. So that did add to our cost structure that time. But I do believe that the constraints and the problems we had there are going to be fixed, and we'll be able to grow that. So yes, in that case, I think it is -- we added people, we added resources to develop those 2 plays. The Marcellus, in particular, is a little slower than we wanted to because of infrastructure and not because of us, but we'll get there. And we -- I think that will help quite a bit. But we also always look at our cost. We were significantly below our cost structure we had at Williams. We inherited a lot of things that we've been able to work through last year and will continue to have a drive on. At each one of our areas, we have a drive to make sure that we do it our way versus what most -- the way it was done at a much bigger company.

Stephen Richardson - Deutsche Bank AG, Research Division

Great. If I could ask one more on the Bakken. The -- considering a 4-rig program, the growth -- the guidance growth looks very achievable to us. And that's probably a good place to start the year. Could you talk a little bit about what the push points on that program are for this year and what we would look for to either see either an acceleration, a pickup of completions, other things that we might not be seeing in terms of the absolute Bakken growth and what could see that number move higher during the year?

Ralph A. Hill

Yes. I think the -- if we continue to improve our cost and continue to improve our drilling times on that, I think that's when you'd see us pick that back up. I do believe, similar to what we did in the Piceance, that we can do more with less. So I think we -- this 4-rig program continues to let us have the right equipment, the right people working what we have to extend our costs, continue to improve, and our well results are already good. Then I think you could see it pick something up there during the year, particularly in the area because of the higher returns there, we'd like to look at for -- if something happens with the Powder, that could be a use of some of those proceeds.

Operator

Your next question comes from the line of Matt Portillo of Tudor, Pickering, Holt.

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

Just a quick question on the oil guidance. Would it be possible to give us a breakdown of the actual numbers that you guys are expecting for oil volumes in the Bakken, the Piceance and then internationally, averaging for 2013? Just trying to get a little more color there.

Ralph A. Hill

Yes. David here...

David Sullivan

I don't have that map. We can get that for you.

Ralph A. Hill

Yes. That won't be a problem.

Rodney J. Sailor

That won't be a problem.

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

Perfect. And then just on the Bakken, I was wondering if you could potentially provide us with an update of where well costs are at the moment, and kind of a guide path or a glide path to getting down to your targeted well costs over the next few quarters?

Ralph A. Hill

Well, I think the well costs are now more in the $11 million range in here. Last year, they were $12.5 million to $13 million. That, obviously, like any company, we would like to see that be lower at the right time. I think $11 million is a pretty good number for this year. I think we can maybe do a little better, but it's -- we -- my number still would be, hopefully, ultimately between $10 million, $10.5 million at some point. I know there are other areas in some parts of the Bakken where you hear numbers are a little different than that. But I'm telling you, where we are, we study it closely in what we do. $11 million is a good number. The ceramics that we use also add to us, but we think it's the right thing. But we're -- I would say still, ultimately, the goal would be more like $10 million-type wells. And that probably won't happen in 2013, but we'd clearly to strive for that.

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

So of the initiatives that you talked about in the past, have you executed on most of those at this point to get to $11 million? Or are there still things that you're looking at doing to move costs down lower?

Ralph A. Hill

Obviously, there are things we're looking at doing better. We are, like we mentioned, we're in pad drilling, but that's just starting. So there's a lot of efficiency we can gain with pad drilling. Bryan can talk about the zipper fracs we're just now doing. They're drilling under balance with brine [ph], those kind of things. If you want add some color to that Bryan...

Bryan K. Guderian

Yes. Well, yes. Sure, Matt, just a couple of things. My answer would be, yes, we have. We've completed the improvement efforts that we've put underway during the middle of last year with respect to the, really, the full well cycle. We've done a number of things on the drilling side, as well as the completion side. I'd say chief among them has been eliminating or greatly reducing trouble time. We have our new rigs in place. We have changed out a number of critical vendors, predominantly with respect to geosteering, which has helped us to keep our well boards in zone, eliminate shale strikes, which is often the sort of leading issue around problem wells. And so the drilling side really looks very good now. As Rod mentioned, we've transitioned 3 of our 4 rigs to brine [ph] drilling, which allows us to penetrate the well boards more quickly. On the completion side, the big change for us middle of last year was going back to plug-in-per [ph] more traditional type operations off the sliding sleeves. I think industry, as a whole, and we were no exceptions, had a number of problems with the sleeves and some operators continued to use them. But now that we've transition to pad drilling, we feel like plug-in-per [ph] can be done almost as efficiently as the sliding sleeves and certainly without the risk associated with them. And then of course, we've had the benefit of renegotiating a number of our service contracts. And so we've been able to drive both service, as well as more recently we're benefiting from lower costs per gore [ph] and ceramics. And so those things are all getting traction at this point.

Ralph A. Hill

And I would just point out that the ceramics do cost up to $1 million more per well. We do believe that's the right thing to do. We've only drilled 10% of our locations, so we'll continue to monitor that. But based on the pressures in the depth, we think it's the right formula, but as someone [ph] -- I know there are some people that are right next to us that you sand. And their well costs, from what I see here, are about the same as our well costs, so I think we're doing a good job there. But again, the number will be more like trend towards $10 million if we can and obviously, once we get the $10 million, we'll want to stay lower than that, much to Bryan's chagrin.

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

Great. And last question for me. Just on the Marcellus. I was wondering could you provide an estimate of what your booked reserves per well on an EUR basis were for Susquehanna and Westmoreland? Just trying to get an understanding of kind of the rig shift and then kind of the relative economics of those plays.

Ralph A. Hill

Yes. The booked reserves are obviously a little less because of some of the pressures. But Neal -- you can ask -- Neal Buck will answer that.

Neal A. Buck

This is Neal. Our reserves bookings in the Marcellus are actually still fairly conservative. We're more in the 5.5 Bcf range. Now we believe that those wells will probably perform at a higher level than that, maybe 7 to 9 Bcf. But we're working with our auditors, and we have to get additional production data once we get the line pressure fixed on the gathering systems. So I would say we definitely have upside in what we've been booking in our Susquehanna well.

Ralph A. Hill

That is just a function really of getting more data because we -- the wells that we have been able to put on with -- our own well had compression of that. We have seen the kind of response that we'd want to see. Again, a flattening of the curves in this area, which means a lot more to us. So we feel that we'll get there. It's just -- with the data we have bucking those high pressures 900 pounds or more, we just haven't had the data yet to fully confirm with our auditors yet, the 7 to 9 Bcf, so it does give us quite a bit of upside.

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

And with the shifting of the rig to Westmoreland, could you give us an update on kind of the infrastructure constraints and how we should think about kind of the Westmoreland economics? And that's it for me.

Ralph A. Hill

On the Westmoreland side, I believe the well is right there. We've moved our type curve up more to the 5 Bcf type wells. Is that correct, Bryan and Neal, in that area? We continue and we initially thought those when we first got into it, were 3.5 to 4 Bcf, and they continued to do better. Again, it is a flattening of the curve. As far as the infrastructure constraints, none in that -- the area we're going to be drilling in, which is more -- is it the northern Westmoreland? Is that correct?

Neal A. Buck

We have adequate capacity, both in the field and take away to support all of the activity here in 2013.

Ralph A. Hill

And we've just gotten more and more data in it, and it is exciting to see the data that the curves are starting to, as I mentioned, flattening. I think those will go up. It just allows us right now with the ongoing Williams problems up there, which I think are going to be fixed in the first quarter, is it's more prudent for us to focus on our completions in Susquehanna, move that rig down to Westmoreland and then obviously, let's assume that the infrastructure constraints get fixed. Then we can go back and have a program 2-prong drilling program there in both areas. Now our guidance didn't show that. Again, we'd have do have that capital, if you will battle it out versus the other areas on returns. But we have the ability we think with the field receipt compression coming on and getting some things fixed there to actually, hopefully, drill in both areas.

Operator

Your next question comes from the line of Duane Grubert of Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes. Guys, as you think about going into new oil plays, I know you've talked about some of the elements of your strengths in your existing developments, but I'm not trying to have you reveal where you're going. But when you have those internal discussions about here's the things were good at, what are the sort of elements on the geologic and engineering side that guide you to a particular new play?

Ralph A. Hill

Well, I guess on the geologic side, it's clearly through our exploration team and our technical people just the opportunity and the potential resource there. And it's really just a matter of what's in place, what we could -- what could we hope to recover. I hope that's what you're looking for there. In operational side, we clearly think and we've seen -- we traditionally have always been in an area where we actually control it, particularly, early on in the sense of the infrastructure and all that. Now we inherited our opportunity in the Marcellus, and we've been disappointed with that. But as you can see in the Bakken, we've been able to build our own and take off. So we also need to be in an area that we're operating on already or near that so we can bring those operational efficiencies to it, or an area that we believe either one, we can at least get the initial infrastructure working or work very closely with an infrastructure provider. Now we don't want to go out and build a big massive midstream infrastructure, but we do like to control early in a play so we won’t have the conversations we've had, for example, in Susquehanna this year. So technically, it really -- it's absolutely a technically driven strategy, where our geologists and geophysicists and technical people believe that the resources are going to be there. And more importantly, can you get it out? And then on the infrastructure side, we like to at least be able to control as much of that as early on as possible so we can get quicker results and understand the play better.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And then separately, on your hedging strategy, you put on some nice hedges, it looks like in 2013. Did you think about hedging in 2014 as well? And can you talk to us about how the decision-making process about hedging works at WPX?

Rodney J. Sailor

Yes. Sure this is Rod. To answer your first question, yes. We did think about 2014, both on the gas side and the oil side, that was really what -- it was sort of a price target, we set a price target or if we see a price target that we like. And we would extend our hedging program out beyond 2013. Then again, we just -- we look at what our expected returns are, we look at our plan, we look at our cash flow at risk and really we try to make a hedging decision around some certainty around cash flows, some certainty around our growing program, sort of around targeted prices. And clearly, we spoke late last year, 2012, that we had a bit higher handle on hedges that we would like to do for this year. We guided the year, we just didn't see those prices. And again, just to be prudent, to give us some certainty around cash flow with our drilling program, we've made a decision to hedge at the level we did. And given the timing we made that decision, we're very happy with both the level and the price that we got on those hedges.

Ralph A. Hill

But traditionally, if we could, we'd like to be about 50% hedged in both of our products. And our -- the liquids are a little harder, obviously, but we don't -- we're much more of a gas than an oil producer, but we'd like to be traditionally going into any given year about 50% hedged in oil and gas.

Operator

[Operator Instructions] And your next question comes from the line of Trevor Menke from Robert W. Baird.

Trevor Menke - Robert W. Baird & Co. Incorporated, Research Division

I had a question about this -- the Powder River Basin sale you're looking at. I think there were about 14% -- 15% of 4Q production. I'm just wondering what sort of cash costs you have there.

Ralph A. Hill

The cash costs or the LOE and because they're always down to about -- it's one of our higher, whereas the Piceance is in the $0.20 range. A good cash cost seems more like the $0.70 because of water. So it's about $0.70 I think in the Powder and it's really because of the prolific amount of water you have to handle. .

Trevor Menke - Robert W. Baird & Co. Incorporated, Research Division

All right. And then what was -- do you -- can you give us any insight into what the impact on 2012 EBITDA was from those assets?

Rodney J. Sailor

It was...

Ralph A. Hill

Minimal.

Rodney J. Sailor

Very, very small. Yes.

Ralph A. Hill

Very minimal because of the higher operating costs and the $2.68 gas price, so very minimal.

Trevor Menke - Robert W. Baird & Co. Incorporated, Research Division

All right. And then in this Piceance, Niobrara, I think you've previously said that you're looking at sort of 5 to 7 Bcf EUR and drilling completion costs of $5 million to $6 million. Is there any update to that?

Ralph A. Hill

Well, it's too early to say. But clearly, this first well, if it stays on target, and let me put a couple of ifs in there, stays on target, this first well is far superior to those numbers. That's probably a 7 to 10 Bcf type well. Now we have to -- we're now 90 days into production or 100 days or so. So we have a lot to learn there. But I think those wells are -- what we're seeing right now has the ability to be bigger than we thought, and we haven't even moved. As we move farther east in the basin, the pressures go up and the depths go up a little bit. We won't be far -- the farthest east this year, which is more of what we call our rules and sales [ph], but we'll get to that next year. So that could obviously -- typically, depth and pressure are better for you. It all -- that depends on can you get it out, the brittleness of the rock and the what's in the rock. But I believe those numbers will trend higher. As for well cost, I mean, right now, obviously we're doing a tremendous amount of science on that. But you'd want to be able to drill this about 10,000-foot vertical and approximately 5,000-foot horizontal lateral. You'd want to be in the $6 million to $7 million at the time. Now that's not here or there right now, but that's where we'd like to get to. But obviously, if the reserves are right, you could actually do a little better than that on well costs. Or spend a little more on that. So it's still early to play, but we -- what we like about it obviously is one, the first well is great. There are surrounding wells around us. They're not as good, but they're also very good from other operators. We like that we hold 800,000 acres by production. We like that we have 2.5 Bcf a day of excess transport capacity out of the basin, so we like the -- we want to delineate this resource and understand what it means because it could be very prolific. And there's no infrastructure problems out there, and that's a great thing to hear.

Trevor Menke - Robert W. Baird & Co. Incorporated, Research Division

All right and then one more. Just with this Powder River Basin sale. Does that -- if that -- assuming that successfully closes with that, would that go towards filling your funding gap, accelerating the Bakken or maybe looking at smaller acquisitions with the proceeds or sort of what are you looking to do with that cash?

Ralph A. Hill

I think it would go towards primarily, go more towards the -- probably filling the funding gap and also maybe opportunities to do more at Bakken and other things. I think it's really -- it's kind of a combination there. But I would guess it's -- I would think it's -- I think initially, that's where we look for that because we do say about a $200 million approximate funding gap. We're not giving the price of what we think for the Powder, but we hope we can fill that gap, and also allow us to do additional drilling in areas that make the right returns.

Operator

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

David Sullivan

Well, thank you for -- if there's no more questions, then thank you for participating in the call and thank you very much.

Ralph A. Hill

Yes. We appreciate your time. Thank you.

Operator

Thank you for joining today's conversation. This does conclude the presentation. You may now disconnect. Good day.

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