Operator: Good day, and welcome to the WPX Energy Operations Update. Today's call is being recorded. At this time, I would like to turn the conference over to David Sullivan, Manager of Investor Relations. Please go ahead.
David Sullivan - IR: 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 are members of the senior management team; Bryan Guderian, Senior VP of Operations; Neal Buck, Senior VP of A&D and Land; and Mike Fiser, 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 yearend 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 Number 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 - President and CEO: 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 into the body of the slides. With over 18 Tcf of 3P reserves, in the appropriate commodity environment we can grow all three of our product lines at double-digit rate for many years. In other words, we can double the size of our Company within five 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 of 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 since have the best oil basin in Bakken, the best gas and NGL basin in the Piceance and the best pure gas basin in the Marcellus.
Let's turn to Slide 4 please, our 2013 path to greater shareholder value, we intend to grow our oil production as a total Company about 21%. Our Bakken oil production will grow between 25% and 30%. 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 for growth when prices recover and I continue to believe we can be the first and the fastest and the best returns when prices recover to grow our gas.
We are continuing our cost improvements and discuss in a few minutes our drilling and completion cost decreases in our major and operating areas. We had significant improvements in cost and we have contractual improvements such as our Willow Creek contract that have already kicked in that would also improving some of our other costs. And we have new opportunities we're going to pursue this year. The organic opportunities in the Niobrara discovery, we'll talk about that in a few minutes and we have oil explorations underway in two new basins. We've already spud 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 two 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 to 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 in multi-well pad drillings, zipper frac completion, best well so far on the spud 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. You will notice that we have four rigs operating in the Bakken this year. We should drill about the same amount of wells with four versus about six that we averaged last year. So, obviously we are 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 netbacks by $2 to $4 a barrel. We also have 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. It delivers attractive returns in any gas environment and it has ability to continue to grow for many, many years. Our existing 3P locations are about 10,000. That doesn't count with the Niobrara which I will 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 expense savings of $48 million under the new contract and that is kicked in for this year. If you look at even with the lower liquids prices that 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 on the operational efficiencies. And then, Marcellus, in spite of infrastructure problems, we continue to have some 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 they are 60% and we are going to have capital flexibility in that play. We'll be actually moving a rig to Westmoreland and 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 in this Niobrara shale well. First one that we've drilled continues to produce very strongly. We have about 180,000 acres held by production. Infrastructure is already in place. We believe this can be a 20 Tcf to 30 Tcf of resource potential. We plan for four horizontal wells in 2013, up from the original two. We know that to continue delineate that field and understand more about it, 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, and that data room will open really any day now.
Let's look at the three major basins on Slide 7. On the Piceance, it is a superior acreage position, and this slide is very important, as you see other people talk about the Piceance Basin or don't talk about the Piceance Basin because they don't have our position. You can 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 and lifting costs. Those things cannot be duplicated. We are 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 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 should be on – is already – I think will be ready by next year for another 300 million a day of cryo capacity, bringing the cryo capacity in the Piceance up to about 1.2 Bcf a day.
Now we have the new emerging play in the Niobrara. We mentioned to you and we've sent a press release out. The initial IP was 60 million a day. Our 60 day average was almost 11 million a day. We've chocked that back significantly as we understand this well. It is a prolific resources for us. We have a four new horizontal wells planned this year and again I mentioned 20 to 30 Tcf resource potential. So, but important on this slide is not only do we have a superior valid position we have 10,000 locations just left and they are traditional Piceance and now we have the new in 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 are going to do. We are improving our well performance, we’re lowering our cost and we have a strong reserve growth. You can see we have 31 wells put on first sales in 2012, 28 of them were add or surpassed our well performance expectations. We have many wells that are coming in significantly higher than our type curves, which were about 800,000 barrels of oil equivalent for the Middle Bakken about 600,000 for the Three Forks.
So, just 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 a Middle Bakken the independence well was 9% higher than a type well that remain more closer to about 900,000 barrels of oil equivalent and Three Forks Kate Soldier well is more like 700,000 barrels of oil equivalent versus about 600 type curve.
Our drilling cost were coming down significantly around 10% to 20% on a recent long laterals, our improvements are coming in with much lower drilling days. You can see our average there early part of last year, our early average this year and now we are down to more like 25 days. And as I mentioned the actual drilling time in that well was 21 days. We know we have ways to go there, but the team is done the right things. We have the right sense having for the Bakken and we are proud that our costs are coming down.
And I would say our cost in this $10.5 million to $11 million range are exactly where others are in the area, that are on the reservation or around the reservation and a lot of those do not use ceramics and you need to remember, we used ceramics we believe it's a right thing to do in our area. We've done significant studies on that and that does have significant amount of cost to our wells, but we think it's a better performer. So we believe we are outperforming a number of people out there so we had significant improvements since our third quarter call.
Turning Slide 9 on the Marcellus again, in spite of infrastructure problems we had in the Susquehanna, we have had strong performance there and you can over 1000% reserves growth since 2010. The two 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 much as we wanted to, but (in space) of the field receipt compression that wasn’t put in yet, which is the next bullet, which is scheduled first quarter of '13. You can see we continue to believe we have at least 30 million a day of net production constraint. 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 we should have good growth in there in Marcellus and Susquehanna.
Our Westmoreland wells continue to perform better than expected. Our curve has basically flattened out. Our reserves are up, so this shows some flexibility in the Marcellus this year as we work off our backlog of compression – our completions in the Susquehanna, we will actually move a rig to Westmoreland and we believe our returns will 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. As mentioned up there, we might be not quite – we think ours are probably a little less thick, our columns and possible a little less pressure, but we're going to have very prolific wells up there.
In the meantime, our Westmoreland continues better than we thought, so we look to be able to grow the Marcellus. Really off just the one rig up there and finishing our completions in 2013 and as the infrastructure problems are finally solved, which we think that that will happen this quarter, we will be able to continue grow our Marcellus.
If you look at the reserves report last year, we did have a very good reserves showing and particularly in reserve adds. Especially if you think that we probably had the lowest annual gas prices I think in 13 years. Just for the effect of severe lower gas and NGL prices, it is 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 turned out to be an F&D, drill-bit F&D cost of about $1.74.
We had small amount of net purchase reserves of about 6 Bcf that was associated with land trades and supportive drilling programs. And then we used the SEC prescribed average 2012 price of $2.39, caused the downward revision of 498 Bcf. These revisions were 572 Bcf associated with price. We actually had 74 Bcf of non-price related revisions being positive for the net 498. That gave us the year-end SEC price case up to 4.5 Tcf. But we like to also show what happens with the prices were – and not much higher, but the 2011 average price remove all the changes relating to price were over 5.3 Tcf of proved reserves. This case would add back 848 Bcf of proved reserves to the SEC case and 248 Bcf of tail reserves and the rest 600 Bcf approximately of proved end of our reserves in our five year drilling plans.
So, if you look before 2012 price changes, we replaced 200% of our production and grew proved reserves by 10%, and that was with $3.68 natural gas price which we also believe is very conservative in long-term price assumption.
With that, I'll turn over to Rod to go through the earnings results and guidance.
Rodney J. Sailor - SVP and CFO: 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 non-cash 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 from 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 partially offset by increased volumes, and we finished the year with $1 billion in EBITDAX versus $1.3 billion in 2011.
If now I can turn to the next slide to 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 from $85 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 composite barrel on this 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 are going to be disciplined in our gas development at current commodity prices and expect that gas production declined to approximately 1,028 million cubic feet per day in 2013. We are expecting oil production of 21,700 barrels per day in NGL production of 20,800 barrels per day and expected 53% rejection rate.
Capital expenditures are anticipated to range from $1 billion to $1.2 billion; at our midpoint approximately 7% to 8% of our capital expenditures will be in the Piceance, Bakken and the Marcellus. As a base case, we anticipated running a (hybrid) program in the Piceance targeting –we are drilling four wells in the Niobrara a four rig program in the Bakken and running one 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 and there is also $40 million to $50 million targeted for development of these opportunities. This is also some dollars that we could put into the Bakken so these are opportunities not meet our targeted returns.
Next Slide is our hedging summary and I have previously discussed that, so like to turn you to Slide 15, we want 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 are still being paid for the BTUs it just instead of as a separate product it's left in the stream we are being paid for the natural gas. Overall production for 2013 would be down 4.5%, where we are recovering ethane at our maximum volumes. Our plan recovery rate as you can tell from this slide, our production equivalency would be down an additional 2.9% and that we have also put on there what a minimum ethane recovery would look like.
And with that I'd now like to turn it over to Ralph to wrap up.
Ralph A. Hill - President and CEO: Thank you, Rod. As you look at Slide 16, strengths we have and what we think about WPX's, 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 very low-cost operator there and do better and better and better. We like to be in areas where it's large and repeatable drilling programs so we can be cost-effective, and if you look at that we've applied that expertise in the Piceance. The Bakken now that the field has been delineated, acreage is basically all held by production. We got some of our initial infrastructure completed in the north and we have the new rigs on, we have the new way we're drilling, the new zipper fracs, the efficiencies they are just now starting to kick in there. So 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. 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 will maintain the right – in the right environments, which is more of a $4 environment the ability to do that, particular in the Piceance. We have a lot of upside from our 3P and our resource potential, particularly with the 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, but we are definitely going to start the process, so that will be additional capital comes in the door to us if that sells and we'll be very – obviously looking forward to put that to good use for us. So there's a lot of upside there.
So with that appreciate your calling in today and your interest in the company. And I'll turn it back over for questions.
David Sullivan - IR: We're ready for the Q&A portion.
Operator: Stephen Richardson, Deutsche Bank.
Stephen Richardson - Deutsche Bank: Ralph, I wonder if you could address some of the questions about cost structure, you have been 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 or the corporation and how you look at that relative to some of your peers, and some of the efforts that could be made to kind of address that or not?
Ralph A. Hill - President and CEO: I think we are guiding to about some $0.60 this year in G&A for per unit base. Part of the uptick is and actually that’s down a little bit from fourth quarter, is obviously our volumes were down but I think when you look at G&A, what we have looked at 17 of our peers. I think you got to be very careful between successful efforts in full cost company. We look at we think we are about in the 7th position right now. There are tremendous amount of producers if you look at they look they are much cheaper than us, you got to dive in and it's hard to do this. You got dive in to their detail and see where they are. So, having said that, I think we should do, we want to be in the first quartile in our cost and our G&A. We are not quite there right now but our numbers show that we are about in 7th position and we do it on an apples-to-apples comparison. So, I think with our volumes increasing at the right time and our relentless drive for efficiencies, you will see us get into that first quartile.
Stephen Richardson - Deutsche Bank: So, is it to understand better it's a function of growing volumes that will address the cost structure there is nothing additional to be done on the absolute level of cost; it's just a question of volume growth?
Ralph A. Hill - President and CEO: Well, I think it's a combination and we – since 2010 we entered two 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 two teams poised and ready for growth that we haven't been 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 have there are going to be fixed and we'll be able to grow that. So yeah, on that case, I think it is – we added people; we added resources to develop those two 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 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 each one of our areas; we'll have a drive to make sure that we do it our way versus the way it was done in a much bigger company.
Stephen Richardson - Deutsche Bank: If I could ask one more on the Bakken, considering a four rig program, 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 whether see either an acceleration, a pick-up 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 - President and CEO: Yeah, I think if we continue to improve our costs and continue to improve our drilling times, I think that's when you'd see us pick that back up. I do believe similar we did in the Piceance, so we can do more with less. So I think this four rig program continues to let us have the right equipment, the right people, working what we have, but to extend our cost, continue to improve and our well results are already good then I think you could see us pick something up there during the year. Particularly, it would be an area because of the higher returns there; we'd like to look at if something happens with the Powder that could be a use of some of those proceeds.
Operator: Matt Portillo, Tudor, Pickering, Holt.
Matt Portillo - Tudor, Pickering, Holt: 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 - President and CEO: David, you have that?
David Sullivan - IR: I don’t have that Matt. We can get that for you.
Ralph A. Hill - President and CEO: That won't be a problem.
Matt Portillo - Tudor, Pickering, Holt: 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 guide path or glide path to getting down to your targeted well cost over the next few quarters?
Ralph A. Hill - President and CEO: Well, I think the well costs are now more in the $11 million range, and 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 my number still would be hopefully ultimately between $10 million and $10.5 million at some point. I know there are other areas and some are parts of the Bakken where you here numbers that are a little different than that, but I am telling you where we are we study it closely and what we do. $11 million is a good number. The ceramics that we use also add to this, but we think it's a right thing. But 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'll clearly try to strive for that.
Matt Portillo - Tudor, Pickering, Holt: Of the initiatives that you've talked about in the past, have you executed on most of those at this point to get to 11 or are there still things that you're looking at doing to move costs down lower?
Ralph A. Hill - President and CEO: Obviously things we are 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 you can gain with pad drilling. Bryan can talk about the zipper fracs. We're just now doing the drilling underbalanced with brine, those kind of things. If you want to add some color to that Bryan.
Bryan K. Guderian - SVP, Operations: Well, yeah sure Matt. Just a couple of things. My answer would be yes we have. We've completed the improvement efforts that we put underway during the middle of last year with respect to really the full well cycle. We've done a number of things on the drilling side as well as the completion side. Id's 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 (dual) steering which has helped us to keep our wellbores 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 Ralph mentioned, we've transitioned three of four rigs to brine drilling, which allows to penetrate the wellbores more quickly. On the completion side the big change for us middle of last year was going back to plug-and-perf, more traditional type operations off the sliding sleeves. I think industry as a whole, and we were no exception, had a number of problems with the sleeved and some operators continue to use them. But now that we've transitioned to pad drilling, we feel like plug-and-perf 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 services as well as more recently we're benefiting from lower cost for guar and ceramics, and so those things are all getting traction at this point.
Ralph A. Hill - President and CEO: And I’d just point out that, the ceramics do cost up to a $1 million more per well. We do believe that’s the right thing to do. We have only drilled 10% of our locations, so we'll continue to monitor that. The basin, the pressures and the depth, we think it's the right formula, but that does so when – I know there are some people that are right next to us that use sand, and their well cost from what I see are about the same as our well cost. So, I think we are doing a good job there, but again, the number would be more like trend towards 10 million if we can and obviously once we get to 10, we want to stay lower than that, much to (indiscernible).
Matt Portillo - Tudor, Pickering, Holt: And last question from 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 - President and CEO: Yes, the booked reserves are obviously little less because of some of the pressure, but Neal Buck will answer that.
Neal A. Buck - SVP, Business Development & Land: Our reserves bookings in the Marcellus are actually still fairly conservative or 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 are 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’d say we definitely have upside in what we have been booking in our Susquehanna well.
Ralph A. Hill - President and CEO: That’s just the function of really getting more data, because the wells that we have been able to put on with our own wellhead compression of that, we have seen the kind of response we'd want to see. Again, a flattening of the curves in these area which means a lot more to us. So, we feel that we'll get there. It's just really data we have bucking those high pressures, 900 pounds or more, we just don't have the data yet to fully confirm with our auditors to get to 7 to 9, so it does give us quite a bit of upside.
Matt Portillo - Tudor, Pickering, Holt: 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 - President and CEO: On the Westmoreland side, I believe the wells are right there. We've moved our type curve out more to the 5 Bcf type wells. Is that correct, Bryan and Neal, in that area? And we initially thought those when we first got into them, we were 3.5 to 4 and they continue to do better, again, at the flattening of the curve. As far as infrastructure constraints, none in that – the area we are going to be drilling in, which is more – is it the northern Westmoreland, is that correct?
Bryan K. Guderian - SVP, Operations: We have adequate capacity both in the field and takeaway to support all of the activity here in 2013.
Ralph A. Hill - President and CEO: And we've just gotten more and more data and it is exciting to see the data that the curves are starting to, as I mentioned, flatten, and I think those will go up. It's just allows us right now with the ongoing Williams problems up there, which I think are going to be fixed in the first quarter, so it's just 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 two-pronged drilling program there in both areas. Our guidance didn't show that. Again, we'd have to have that capital, if you will, battle out versus the other areas on returns, but we have the ability we think with field receipt compression coming on and getting some things fixed here to actually hopefully drilling both areas.
Operator: Duane Grubert, Susquehanna Financial.
Duane Grubert - Susquehanna Financial: As you think about going into new oil plays, I know you've talked about some of the elements of your strength 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 we are 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 - President and CEO: Well, I guess on the geologic side, 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 hope to recover. I hope that's what you're looking for there. In operational side, we clearly think and we traditionally have always been in an area where we actually control it, particularly early on and since have 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 have been able to build our own and takeoff there. So, we also want to either need to be in an area that we are operating in already or near that so we can bring those operational efficiencies to 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's absolutely technically driven strategy where our geologist and geophysicist and technical people believe the resource is 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 you quicker results and understand the play better.
Duane Grubert - Susquehanna Financial: 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 - SVP and CFO: This is Rod. To answer your first question, yeah, we did. We did think about 2014 both on the gas side and the oil side. That was really what sort of a price target – we set a price target or if we see a price target that we like then we would extend our hedging program out beyond 2013. Duane, again, 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 flow, some certainty around our drilling 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 got into the year we just didn't see those prices and again just to be prudent to give us some certainty around cash flow and our drilling program, we 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 - President and CEO: But traditionally, if we could, we'd like to be about 50% hedged in most of our products and liquids are a little harder obviously. 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: (Trevor Menke, Robert W. Baird).
Trevor Menke - Robert W. Baird: I had a question about the Powder River Basin sale you were looking at. I think there were about 14% to 15% of 4Q production. I'm just wondering what sort of cash cost you have there?
Ralph A. Hill - President and CEO: The cash cost, the LOE because it waters down to about – it's one of our higher – whereas the Piceance is in the $0.20 range, I believe the cash cost there is more like the $0.70 range because of water. So it's about $0.70 I think in the Powder and it's really just because of prolific amount of water you have to handle.
Trevor Menke - Robert W. Baird: And can you give us any insight into what the impact on 2012 EBITDA was from those assets?
Rodney J. Sailor - SVP and CFO: It was very small.
Ralph A. Hill - President and CEO: Very minimal because of the higher operating cost and you know $2.68 gas price, so very minimal.
Trevor Menke - Robert W. Baird: And then in this Piceance Niobrara, I think you previous said that you are looking at sort of 5 to 7 Bcfe EUR and drilling completion cost of $5 million to $6 million. Is there any update to that?
Ralph A. Hill - President and CEO: Well, it's too early to say but clearly this first well if it stays on target, let me put a couple ifs in there, stays on target. This well is far superior to those numbers, that’s probably 7 to 10 Bcf type well. Now we have to – we are 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 are seeing right now have 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 depth grow up a little bit. We won’t be far, the farthest to east this year which is more what we call, rulers in field but we will get to that next year. So, that could obviously typically depth and pressure a better for you. It does depends on can you get it out, the brittleness of the rock and what’s in the rock, but I believe those numbers will trend higher. As for well cost, I mean right obviously we are doing a tremendous amount of science on that, but want to be to drill this about 10,000 foot vertical and approximately 5,000 foot horizontal lateral. You want to be in the $6 million to $7 million range at the time. Now that’s not here or there right now, but that what we would like to get to. But obviously the reserves are, you can actually do little better than that on well cost or spend a little more on that. So, it's still early in the play, but what we like about it obviously is one and the first well is great, they are surrounding wells around it, so it's not as good but they are also very good from other operators. We like that we hold 180,000 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: One more, just with this Powder River basin sale, assuming that successfully closes, 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 - President and CEO: I think it would go towards – primarily go more towards probably filling the funding gap and also maybe opportunities to do more Bakken and other things. I think it's kind of a combination there. But I would guess it's – I think initially that's what we would look for that because we do say about $200 million approximate funding gap. We're not giving the pricing of what we think for the Powder but we can fill that gap and also allow us to do additional drilling in areas that make the right return sense.
Operator: Thank you for your questions. I would now like to turn the call over to David Sullivan for closing remarks.
David Sullivan - IR: If there's no more questions, then thank you for participating in the call and thank you very much.
Ralph A. Hill - President and CEO: Yeah, we appreciate your time. Thank you.
Operator: Thank you for joining today's conference. Ladies and gentlemen, this concludes the presentation. You may now disconnect. Good day.