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WPX Energy (NYSE:WPX)

Q2 2012 Earnings Call

August 02, 2012 9:00 am ET

Executives

David Sullivan

Ralph A. Hill - Chief Executive Officer 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

Michael R. Fiser - Senior Vice President of Marketing

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Anne Cameron - BNP Paribas, Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

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

Robert Bellinski - Morningstar Inc., Research Division

Operator

Good day, and welcome to the WPX Energy quarterly conference call. As a reminder, today's conference is being recorded. At this time, I'd like to turn the conference over to David Sullivan. Please go ahead, sir.

David Sullivan

Thank you. Good morning, everybody. Welcome to WPX Energy Second Quarter 2012 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. [Technical Difficulty] Rod Sailor, 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, will be available for questions after the presentation.

This morning on our website, wpxenergy.com, you'll find today's presentation and the press release that was issued earlier today. The second quarter Q will be filed later this week, and you'll be able to access that on the website as well. Please review the forward-looking statement on Slide 2 and the disclaimer on oil and gas reserves on Slide #3. They are important and intrical 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. Slide 1. First, welcome to our second quarter 2012 earnings call. Thank you for your interest in WPX. A few reminders about WPX. We do have a premiere portfolio and have strong -- and we've had very strong production growth in all 3 product lines, with our oil production up 57% versus last year, our liquids production up 10% and our gas production also grew up 8 -- grew 8%. And when the commodity environment's right, we can increase that gas volume production growth quite a bit and go back in the double-digit gas production growth.

Our existing portfolio of 18.5 3 Tcf (sic) [18.5 Tcfe 3P] of reserves disability to grow all 3 product lines without any new investments for many years in the future. We're choosing not to go gas as much as we could right now due to low commodity environment.

We continue to have tremendous flexibility in our capital spending up or down without losing our leases. As you've seen earlier this year, we significantly decreased our capital budget.

We are a technical and low-cost leader. Our balance sheet remains very strong, particularly compared to our peers with about $1.9 billion in liquidity. This gives us a position of strength to grow and -- in our core areas and also new areas as we see some compelling opportunity. And we're very excited to say we've entered some new areas. We don't have a lot of detail we can give you on that, but we increased our capital, primarily because of our opportunities we see through our exploration team to grow in horizontal oil plays, new plays. It's part of our natural progression as an E&P company, a stand-alone company, to enter new oil plays much earlier, and we're excited about that.

By choice and design, we think we are in the best oil basin in the nation in the Bakken; the best gas and liquid basin in the Piceance, it's really exclusively to WPX, but we are exclusively the best in the Piceance; and we're in the best gas basin in the nation in the Marcellus.

Let's flip to Slide 3 -- or 4, please. Second quarter highlights. Our employees are focused on what they control, and so are we, which is our production growth and our cost. And on our items that we can't control, such as the commodity prices currently or weak international and domestic economies. Thus, we're focusing on executing our plan, which is our production side and our cost side. And I'm very pleased to report, we're executing on that plan with our combined year-to-date oil and gas -- oil and liquids production up 24%. As I mentioned, domestic gas is up 8%. And the Piceance is still receiving in what is a weak NGL margin of $0.66 per Mcf NGL uplift. So even in a very weak NGL market, we're getting quite a bit of uplift in the Piceance.

Looking solely at the Bakken, our production in oil was up 83%, quite an achievement, and our costs were trending lower. Our LOE is down 6%. And on a combined basis, our gathering, processing and transportation costs were down 10%.

Our EBITDAX was over $500 million for the 6 months -- first 6 months. And as mentioned, as Rod will talk about, we continue to have superior liquidity compared to our peers with over $1.9 billion in liquidity side. And we're now deploying additional capital in new oil-focused plays, which we are very excited to do as a team.

Slide 5. Just very quickly. Reminder, the Bakken, we think, is a world-class oil basin, and our results continued to show, as we expected through our exploration team, which is also the team that's leading us into these new plays, that we're located in the best remaining undeveloped reservoir in the Bakken play.

Slide 6. We're pleased with this reservoir and our performance so far, with early time well results well above our acquisition thesis and confirming again that we're in the best part of the play.

For July -- for June 12, our net barrels of oil production a day was 11,300 barrels a day approximately, which is a 74% increase over June of 2011. Our performance is improving. 4 of our 6 drilling rigs have been converted to new efficiency rigs and 2 more are in the transit. We have our dedicated frac crews in place and are reducing time and costs. But as you've heard from other operators, and you've seen in our capital increase today, there's a substantial upward pressure on costs to the first quarter of this year, which continued in the second quarter, but we feel they have peaked in the second quarter. But based on our experience today, part of our capital increase, $75 million, is for additional drilling completion and facility costs in the Bakken.

There's some unique issues driving our performance and strategy that we feel will go away, but as a new operator, just taken over operations slightly over a year ago, it takes a while to become an established operator in this basin. So for the first 3 quarters, what we've been facing is basically a lease saving mode. Since we've assumed operations a year ago, we've been transitioning to a much -- we will transition to a much more efficient pad drilling, but initially, we've been bouncing around from lease to lease to make sure we hold our leases. The good news is, we only have 10 more wells to drill to have all the leases held by production, and all those wells -- or majority of those wells will be completed by the end of third quarter and definitely this year.

For 2013, thus the majority of our drilling will be from pads and we'll be done with the long rig moves, we'll be done with building the initial roads, infrastructures, pads, well connects, production facilities, et cetera. All that will go away. And we've built our suite of preferred vendors, contracts and equipment to where we like for a Piceance-type efficiency model.

We believe we're now at the front of the queue or near the front of the queue for services from our vendors. We can optimize our service equipment, and I've mentioned 4 of our 6 rigs are now the fit-for-purpose rigs, but 2 of those just recently came on. So we have not experienced the benefit of those yet. We've high-graded our directional drilling services. We've got our completions and operation efficiencies underway, and we've optimized our completion design.

We also have put in field infrastructure, the one I talked about last time, the Van Hook Fields construction, will be done in the fourth quarter, and that will eliminate flaring, trucking of our oil, water among other things, and thus, save more money. So we expect as we get done with the one-and-gone lease saving development phase later this year, we will be able to lower our well cost by about $2 million.

Also, you should see that we do via operate on the reservation, just generally for some associated fees and other items; there's about a $500,000 per well additional cost by operating the reservation. The good news is, the reservoirs are far superior. And we use and believe in 65% ceramic and 35% profit mix. That adds about $1 million to our wells, but as the slide I'll show you in a few minutes, we believe that results in superior wells and superior production, superior reserves and eliminates any problems down the road when the sand could get crushed if using 100% sand.

Slide 7. 4 of the 6 planned rigs have been converted to new fit-for-purpose. And as I mentioned, just a couple of those have been delivered. So we really have not began the efficiency-type drilling. As I mentioned, that will happen later in the third quarter, beginning in the fourth quarter. But our reserves in production continued to outperform our expectations.

This slide's a busy slide, but let me walk you through a couple of things. 11 wells -- we spud 11 wells in the second quarter, and you can see in the light green and the orange, the colors there, we put 6 wells on first sales. We're drilling from our first multi-well pad infill density project has begun, but we're doing 4 Middle Bakken and Three Forks eventually, and that's in the red hash marks on the map.

Our best well result from -- during pad drilling has gone down to 25 days, averaging 30 days right now, but we already started to achieve 25 days, gives me confidence we will drive our well cost.

We delineated our field -- or we continue to delineate our field, and we proved up some assets in the south. Our first completion was much higher than we expected. Our peak month was 1,039 barrels of oil a day versus our plan of 700 barrels or less [ph] so we're very encouraged about the 7 part.

Currently, we're stepping out to the West and East to delineate the acreage there, and we'll have good -- we should have results on those in the third quarter report. And we're proving up our Three Forks formation. 4 wells are waiting on completion, but we do have 2 that are on and are flowing better than we thought with higher EURs than we expected. So we continue to see good opportunities or good results from our drilling here. And really, we've been drilling with older equipment, with not the frac crews we wanted and many other services. So as we move to what we call the Piceance efficiency model, we think we'll do much better.

Slide 8. We believe that our acreage and our use of 65% ceramic and 35% sand as our profit provide superior results, and peers -- only to some of our peers use. This does add about $1 million to our cost, as I mentioned. But if you look at the performance here, our performance for the wells easily offsets the additional cost. You can see on a 180-day rate that WPX is superior to all the other operators out there. And this is a substantial mix, about 85% of the activity on the reservation.

You can also see that our EUR comparison is higher, and that is on a NBO basis to 640, and if you equate that to an NBOE basis, it's 706, which is the -- in our type curve, you see in previous-type curves. That also is -- includes in our piece some delineation wells to the South, some Three Forks wells and some delineation we're beginning to the West and the East. So as we stay more in the sweet spot, that we believe really that will trend up. These are all wells that are completed on the Indian reservation. They're all Middle Bakken and long laterals, and we believe in 180-day rate and this is calculated by a third-party IHS data, it's public data. So this is all public that you can go out there and see that our wells are doing better than our peers. Also, we believe the 180-day rate is a much superior rate to look at versus just the 24-hour IP.

Slide 8 -- Slide 9. In the first quarter, our WTI discount was about 16%, off the WTI. Second quarter, that's decreased to about 12% to 14%. And also on absolute basis, our differential improved by $4 per barrel. We expect this will improve as the year goes on by $2 for the balance of the year for a basis of 10% to $11.

As we see our Van Hook Gathering System completed, we think on the Van Hook barrels, that will save us additional $4, and that should be completed by the fourth quarter.

And we also continue to make progress on our future rail sales agreements. As we talked about last time, it's still on the slide where we think for the 2013 to 2015 period, we'll be up to 20,000 barrels of oil, we can move on the rail.

Turning to the Piceance, Slide 10. It is a world-class gas and oil, an NGL play, and it is for us. Some others don't have the position we have. Our geologic position is unique relative to the other operators, and we're the only operator scaled to be efficient. We drill over 4,000 wells. We have 10,000 remaining locations. We have the lowest cost structure, it's driven by our technology and our operational efficiencies, coupled with our enhanced liquids processing.

We have superior liquid contract sales, as you'll see in our barrels -- our net realized barrels, and we're just in unique -- and I do believe as the gas prices turn that WPX is in a unique position to reach our gas production, particularly in the Piceance.

Slide 11. Update on the second quarter. We did spud 53 wells, 123 wells to the second quarter for year-to-date. We've had a record gross operating production of almost 950 million a day. Our higher volumes and strong NGL uplift was $0.66 per Mcf in the second quarter, and that was despite the very weak price that we saw out there.

We continue to gain efficiencies, which the next slide will show you, even in the Highlands, and we're not drilling much in the Highlands, but the Ryan Gulch area was developed simultaneous operations, which you know we've done in the Valley where we drill, complete, produce, stimulate on the same pad at the same time. We've gone in the Highlands for the first time, leveraged the valley efficiencies that we have. And we actually have done a Ryan Gulch well in a record day, drilling of 8.5 days, and the average Ryan Gulch wells are now taking 11 to 12 days, that was about 25 days 3 years ago. So it's a significant improvement there in the Ryan Gulch area, and a good opportunity for us as we -- when we begin to drill there in a much larger scale.

We also have new value recognition projects in the Mancos and Niobrara. Third-party results are very encouraging. I have another slide on this and our new opportunities later. But there've been about 27 horizontal wells drilled by other operators so far. Our first horizontal wells will spud this month or next month and have hopefully a completion by the end of the year. So we're excited about that as we move forward, and I'll talk about this again in a few minutes.

Slide 12. The efficiencies continue year after year after year. In the Piceance, we continue to set drilling records. It's a relentless drive this team has for efficiency. And our Valley well costs have actually been flat the last couple of years, when, as you know, there's been considerable upside pressure in all basins. We've been -- managed through efficiencies to keep our costs flat or slightly down. It's done by our performance in optimization and from active vendor negotiations, and also the great vendors that we have.

We're forecasting our Ryan Gulch wells are now going to move less than $3 million. And I mentioned how the -- how much the drilling time has come down there, so it should be substantially below that.

We have a continuous reduction in spud-to-spud times and every time you save a day up in the Piceance, you're saving $40,000 to $60,000.

Our lowering rig count has actually had a side benefit of allowing us to lower our average day rate for our fleet and prepare us for efficient ramp-up, and we've done many other things to optimize as the team always does.

Slide 13. If you look at our weighted average barrel, it's $36.27 in the second quarter. Even with historically low ethane and propane prices in the same quarter, I mentioned the $0.66 per Mcf uplift. If the new Willow Creek deal -- or if the Willow Creek new contract, which kicks in automatically in 2013, was in place in the second quarter, that uplift would have been $0.72. So even in one of the worst environments that's been out there for ethane in quite a while, if you annualize that on a 4 quarter basis, that would have been about $16 million improvement to EBITDAX for the year. And we believe, going forward, as we mentioned before, that we think that's going to be more like $25 million to $35 million improvement in the future.

We feel we're in a good position to continue to realize significant value from our NGLs based on our advantage long-term T&F rates and all of our products, more importantly, our price off Mount Belvieu and not subject to Conway.

Slide 14. Since our last call on May 3, gas prices have come up somewhat, about 7%. On calendar '13, it's $3.73. And I believe and our team believes that we are one of the best positioned companies to respond to the coming opportunity to rapidly deploy rigs, and increase production when gas prices recover. We believe that the Piceance size rigs will be available versus rigs that are going to be needed for the longer drilling horizontal gas shale plays.

You can see on this graph, we've done it before, we had about a 30% -- 31% CAGR growth rate in the Piceance from 2004 to 2008. And you can see we increased our Bcf production by about 157 Bcf from '04 to '08.

With us so much more efficient now, we can drill -- do the same kind of growth with only 17 rigs versus 26 rigs the last time we did it, and we give an example here, if we start off with 8 rigs in year 1 and to move up to ultimately 17 rigs. That would be a 12% CAGR for the Piceance we could do, and the total production growth about 155 Bcf, grow the same amount of production growth. We believe that we have that in place and can take advantage of that. We believe we can get the rigs. We have well over 200 permits in hand and ready to drill. Our infrastructure, as you know, is in place. The capacity to move the gas North, South, West and East is in place. Our staff has done up to 27 rigs before, so they can easily handle 17 rigs. The support structure is there. We have the lowest drilling completion and operating costs in the basin, and we can ramp up sooner we think than anybody else can in any other basin. We can utilize available rigs. As I mentioned, I believe, the Piceance size rigs would be available, and we can build up to smart knowledge from a prior ramp up. So due to our people, our knowledge, our experience, our low cost of operations, our low final and development costs and our infrastructure already built out, we are one of the best gas stories just waiting to explode when the prices are right.

Our final basin is the Marcellus, it's Slide 15. As I mentioned before, our technical team, which is leading us to the new areas that we increased our capital for, also purposely got this in the primarily Susquehanna County part of the Marcellus. We like what we've seen in the Marcellus. We continue to have great results. We also believe the team has cracked the code on lower drilling completion costs and the Piceance model efficiencies, is starting to kick in, it's actually kicking in there.

We do remain frustrated with the operations at the Laser pipeline in terms of reliability and pressure. We believe our former sister company, WPZ, which acquired the system in February, will bring the system up to par hopefully, by the end of this year, early next year.

Slide 16. As I mentioned, the Piceance model is taking hold in Marcellus. We have transitioned to new rigs built specifically for Pennsylvania, on track to average 3 rigs this year. Our first Orion rig came in as planned at the end of May. 2 others are scheduled to come in later this year, the end of this month and the 1st of November.

We've reduced our completion cost. It's been a major focus for us, and they're down 30% from last year, a significant progress made. Our net production increased 19% from the first quarter to the second quarter, actually right ending at June.

We believe that production continues to be impacted by the very high lying pressures and erratic operational performance by Laser, which under pressures have been running between 600 pounds to 800 pounds. But we do estimate our current net production of $70 million a day could have been about $30 million a day higher and absent any infrastructure constraints. We can see the problems we continue to have there. And we are poised to ramp up quickly when the gas price rebound. Not as quickly as the Piceance, but the Marcellus would be in pretty good shape also.

Slide 17. Looking at the efficiency model, how you see this, this is almost a mirror of what we saw starting out with the Piceance and the Piceance continues to do. Our spud to rig release time has continued to drop, on average an all-time low about 16 days in the second quarter. Early in the play, this was closer to 30 days, so great improvement by the team. The 60% improvement from where we started just 2 years ago.

As I mentioned, the completion costs have been reduced through operational changes, better frac designs and working with our vendors and getting more partnerships them. We're down about 20% on average since the beginning of the year. And the Marcellus just looks like an absolute great example of WPX transporting the Piceance model to the Marcellus, and we believe this will start to occur and begin to occur in the Bakken as they crack the code also.

Slide 18, let's look internationally briefly. As you know, we own 600% interest in Apco. I do want to stress and continue to stress that Apco represents less than 5% of our total production reserves and we're self-funding. No domestic capital spend on Apco. Also on the upside, we do have about 250,000 net acres exposed to the Vaca Muerta Shale.

There was a government decree issued this week now requiring an annual approval of oil and gas companies' investment plans. Here's our thoughts on that, early thoughts: we've invested consistently and significantly developed our holdings over the years. We've basically redeployed our cash down there into reinvestment. We need to see the detailed requirements from process yet to be published by the government. It appears the decree is to formalize rules that the government's already imposing on the industries, which some of those are like price controls. It seems this is a move by the government for tighter controls and involvement in development of the country's energy resources, but as I've mentioned, we've always redeployed our capital down there, internally, not the domestic capital. We have investment programs built into our concession agreements already, so we have that already set up. Some of them which have been earned [ph] and few of these are still being approved as the concessions remain extended. So we hope that we -- that what we have in place already is very satisfactory to the new government rules, and we'll just -- time will tell on that.

Looking at our operational update, in the Neuquen Basin for all of 2012, we're going to drill 33 development wells and 5 exploration wells, and these are in the traditional targets at Tordillo and Contuco [ph] Formations. Productions from results in this area have been in line with expectations. As you know, we have 2 wells on production, the Vaca Muerta and the vertical side. Current plans are to call for a multistage fracs of the CAS x-4 before the end of the year. So we continue to prosecute and understand what we have in the Vaca Muerta between what we're doing and what the industry is doing.

In Colombia, we announced our first discovery in Llanos 32 block, where we currently have a 20% working in it, interest on the Maniceno #1 well. That is on production, it's average about 2,400 barrels of oil a day since July. Our second well has been -- has found prospective pay in 3 formations, and the casing has been set. Completion rig is in location, and it will commence testing of these formations. And Llanos 40, we've also completed our seismic inspection and drilling there in 2013. So we continue to do good in the operational side on the Apco.

Slide 20. We are excited to discuss a couple of existing future opportunities in our early entry into promising new plays. As we mentioned, as pure play and peak are coming, we are diversifying our strategy to use exploration in land earlier and get into plays earlier. And for more economically, we think this will be a nice balance to the traditional A&D work we have done. If all our new opportunities that ultimately come through this year, it will represent about 60% to 65% of the $200 million capital increase.

Slide 21. But first, let me remind you of an existing resource we control in the Piceance basin and we made it -- we have significant upside in what's called the Mancos/Niobrara gas formation. We own 250,000 gross, about 150,000 net acres. If you look at the opposite operators and the number of things going on out there, that could represent 20 to 30 Tcf of unbooked resource potential based on results of other operators of 67 Bcf a well. Our current activity is we had an initial vertical test done last year and we frac-ed 1 zone and half-loaded 1.5 million per day. We have 5 to 7 additional intervals remaining to be tested in that. And as I mentioned, our first horizontal well is planned for the third quarter of this year, and it's going to be the offset to that vertical study -- to that vertical well.

Other operators have drilled or spud 27 wells in this area, all horizontal type wells, with additional 65 locations permitted. And again, the wells are being reported in the 6 to 7 Bcf range. None of this is in our resource potential, our current resource potential, 18.5 Tcf of 3P reserves or of what I mentioned is that what we currently have in the Piceance of 10,000 remaining locations. So this represents significant gas upside to us when the time would be right, and we hold it by production, we can develop when we want to.

Slide 22. We also made a Mancos gas discovery in the San Juan Basin, where we led the charge and made the discovery. We did a number of vertical tests in the Mancos, extensive reservoir and geological assessments. Basically, the bottom line is, we drilled 2 grassroot horizontal Mancos wells, the first one looks like it's going to be between 4.5 to 5.5 Bcf; the second one, between 5 to 6 Bcf. We control a substantial amount of Mancos rights held by production of 61,000 acres, have a number of -- 700 gross 3P locations. On a gross basis, it looks like we have about 3 Tcf of gross exposure, which should be about 1.8 Tcf to us. Again, none of these numbers are in our resource potential. We look to prosecute this at the right time, and the San Juan Basin team has been drilling there for a number of years. So at the right time, it's going to be a good upside for us.

Finally, we did enter -- we are entering or have entered new oil plays. There are 3 to 4 primary areas of interest to us. All of these are oil focused horizontal plays. We're feeling very good about our positions; we like what we've done. We increased our capital budget by a $100 million, and that could go up even a little bit more, but not much, it wouldn't change guidance. We will begin testing this year. Most of those will be vertical test. Initial well results are expected no later than mid-2013. Obviously, we have increased capital today, and we did not increase production guidance, but it's not prudent to increase production guidance on exploration time, but we're very excited where we are and where we're headed with these prospects, and I think it's to going to see part of WPX you haven't seen before as our exploration and land team have done this in the right plays that are more mature, these are earlier entries in the plays that aren't mature, but we think they're going to do pretty well.

With that, I'll turn it over to Rod.

Rodney J. Sailor

Thank you, Ralph. Slide 25. Earlier this morning, we released our second quarter results. These results reflected weak gas prices. And even with the impact from our hedge position, we realized approximately $3 per Mcf. As well, we continue to see weakening in the price of our composite NGL barrel, further impacting results worldwide basin differentials in the Bakken in the month of April. And while the differential somewhat normalized by June, the price accrued also retreated, so net, not much changed in the realized price over the quarter. We are still on plan to meet our volume projections and currently looking very favorable in our outlook for oil and NGLs. Results were also impacted by noncash impairments to probables in the Powder River Basin, totaling approximately $65 million for the quarter, and total impairments year-to-date of $117 million. Adjusting out these and unrealized mark-to-market gains that tripled to our hedging program, we experienced an adjusted net loss from operations for the quarter of $30 million and $37 million year-to-date.

Even in this challenging commodity environment, we had just over $0.25 billion in adjusted EBITDAX and $514 million year-to-date adjusted EBITDAX.

Ralph previously mentioned, and while it is -- mentioned capital increases, and while it is running ahead of previous estimates, we believe we are turning the corner on our cost in the Bakken and have made and will continue to make additional land purchases.

Turning to Slide 26. That kind of brings us to our outlook for the year. While we did see significant pressure on prices in the second quarter, we are seeing gas strengthening, ethane and propane prices are stronger -- are looking stronger and should benefit us in the third quarter.

As I indicated, we continue to feel good about our full-year production estimates. Our EBITDAX estimates are within our rule of thumb sensitivities and based on kind of 7/31 script prices, with what we realized to date, we would anticipate that our adjusted EBITDAX would probably be $85 million to $100 million lower than the original $1,175,000,000.

As previously mentioned, we are increasing our capital expenditures estimate by approximately $200 million, and this is related to the costs in the Bakken and some target acreage acquisition that Ralph had mentioned.

Turning to Slide 27. Second quarter liquidity remained strong. While we are seeing higher spending and some pressure on cash flow for the low commodity prices, these were more than offset by the $300 million we received from the sale of our Barnett and Arkoma properties in the second quarter. Liquidity at the end of the quarter stood at approximately $1.9 billion. And again, as Ralph mentioned, we think we're positioned very well from a liquidity and a balance sheet standpoint as we ended the second quarter.

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

Ralph A. Hill

Thank you, Rod. Slide 28. So remaining priorities for 2012 in our value creation. We've already continued to do this but continue to grow our domestic oil production, 50% to 60%. As I mentioned, first 6 months is up 57%. We are uniquely situated to ramp up gas production at the right price. We're already one of the most efficient producers, and we're seeing our gas cost basins trend lower.

The Piceance efficiency is continuing to be best-in-class and the Marcellus team has cracked the efficiency code. And as I discussed, I really can't stress enough, when the time is right, I believe and we believe that, particularly in the Piceance, we can significantly grow our gas production as that one slide showed you how much we can do with less equipment than we did in the past.

We are going to maintain our top-tier balance sheet in this depressed environment, but the environment is getting a little bit better. As we continue to execute financial discipline in the Bakken, we expect several things to happen. All of our acreage will be held by production. That is a great thing. We will have all fit-for-purpose rigs designed for the Bakken in operation. 4 in now, 2 that just recently came on, 2 more coming, there are all 6 will be there. We should begin pad drilling in the third quarter, which should lower well cost ultimately by $2 million as efficiencies kick in.

We will complete our final gathering system for all of our oil, water and gas, and none of that will have to be trucked. And in the future, we could probably, and I believe, we will be able to drill the same number of wells with one less rig. In other words with 6 rigs could be drilled -- the same amount of wells could be drilled with 5 rigs in the future as these efficiencies begin to kick in, and that will make us -- when we do have rigs, be able to drill that many more wells.

And our new opportunities there is in the Piceance, we're going to spud our Mancos horizontal just for the gas to continue evaluate this potential large gas resource. We're also continuing to maximize the liquids recovery. I did mention the Powder River, but we are evaluating numerous oil prospects where we own 140,000 acres of deep rights. We'll begin to participate in some of these prospects, continue to test the Vaca Muerta in Argentina where we have 250,000 acres as I mentioned. And we'll begin testing the new exploration oil areas where we've invested approximately $100 million in. We believe those things will -- as we do some vertical tests and have some results early next year, hopefully, you'll be pleased with those results. And finally, we'll continue to tell the WPX story that we have, of our disciplined management team, our great balance sheet, our tremendous opportunities that we hold in-house today and our new oil horizontal exploration opportunities.

Thank you for your interest in WPX, and with that, I'll turn it to David.

David Sullivan

I think we're ready for the Q&A portion.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Brian Corales with Howard Weil Investment Firm.

Brian M. Corales - Howard Weil Incorporated, Research Division

Just a couple on the Bakken, costs have come up a little bit. Can you talk about where costs are? And Ralph, I think you said you try to cut $2 million from the cost. What would a well cost if you can cut $2 million out of, and what -- where is the majority of that savings coming from?

Ralph A. Hill

Well I'll start now, and let Bryan in. If we get -- if we cut $2 million out and instead of -- we basically are drilling 45 wells here in the Bakken this year, so if you look at the $60 million, we wanted about $10.5 million well cost this year, and with $75 million increase, the way that translates out to on networking interest, that's about a $12.5 million well instead of $10.5 million. So we believe we can get down to $10.5 million, that's with the pad drilling and with better completions, and I'll let Bryan take over there for the -- well, I'll let you answer the last part of that. But we should be able to drive it down to $10.5 million.

Bryan K. Guderian

Yes, certainly, we're not happy where costs are at this point in time either, and I think you've seen some color around this, perhaps from the other companies that have already released. We have drilled since we bought into the project about 45 wells. We have what we would consider to be, I guess, near final cost on about 30. Looking at the drivers of those actual costs versus what we've been targeting, as Ralph said, $10.5 million. I guess there's one area that we haven't really talked about that I would add a little color to. We feel like there's -- Ralph has mentioned $2 million savings when we transitioned to pad drilling. Frankly, we feel like there's a couple of million dollars worth of savings associated with improving our contractor and vendor service quality. Of the wells that we've drilled thus far, there's still a lot of problems associated with executing on those wells, and I think it's generally driven by the demand for services in the Bakken. The services and the experience of those folks just have been running hard to catch up to the operator demand that exists in the basin. We've seen pretty significant improvement on all fronts with respect to our rigs, our dedicated frac crew. And so again, we still believe that over time, as we get to pad drilling, as we take the problem wells out, which are fairly common early in an aggressive growth basin like this, that we can take $2 million to $2.5 million off of our current run rate. Ralph mentioned we're looking at $12.5 million as our estimate for well cost over the balance of this year, and we hope to drive that considerably lower as we get into pad drilling, which will be the prevailing mode of operation for us in 2013.

Ralph A. Hill

The good news is we've only drilled about 7% of our locations, and I do believe that we're already seeing better well cost and better time. On the one pad we're doing, we've had one well drilled in 25 days. So we're eliminating move days. As Brian mentioned, our crews are getting better. We finally feel that there's just some design things we had to get through and just better crews. And as you know, we like to go to efficiency-type rigs that are built for this area. They are just now coming on. We like the dedicated frac crew. Those things just take time, and we inherited what we would say was poor equipment, and we're just fixing that code. And if you look at the Marcellus, well, I think, we'll just change the code and crack the code just like we did in the Marcellus like we did in the Piceance.

Brian M. Corales - Howard Weil Incorporated, Research Division

That was helpful. And one other question, with the new leasehold -- or should we assume that's in a new play, not to bolt-on to what -- bolt-on to the Bakken or one of your existing Rockies assets?

Neal A. Buck

Well, this is Neal Buck. I mean, clearly, we don't want to miss out on in any plays going on in our backyards, so we stay current on all plays. And if you can find one in one of our areas, that's great. But our main criteria is that we're looking for oil, that we're looking for great risk reward on our investment. And then, we want large continuous positions where we can apply our efficiency model like we used in the other basins, so in some cases that may be near our existing production; in other cases, it won't be.

Operator

And next we'll go to Matt Portillo with Tudor, Pickering, Holt.

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

Just a couple of quick questions for me. In terms of the -- I have a couple of quick questions on NGL and gas realizations. For the quarter, it did look like you guys had a pretty significant drop on your gas realizations. Could you give us any color as to what -- what may have led to that drop in realizations? And then, on the Piceance in particular, could you talk about where you think breakeven economic rates of return or at the moment, if you kind of use current NGL pricing and current oil pricing?

Rodney J. Sailor

Yes. On the gas realizations, yes, we did see a significant drop. We had -- we also had I think some prior period adjustments that impacted the second quarter over the first quarter on gas. Mike, did you have anything?

Michael R. Fiser

Well, I would just add that our outlook on gas is still supportive overall, even though we were down quarter-over-quarter. As we look forward to the second half of the year, we continue to feel like prices will be supportive due to the drop in rig count, the inventory is getting worked off. And all the fundamentals point to a more balanced market as we go to the second half of the year.

Ralph A. Hill

And then on the gas realization, I guess it was prior period roughly. And on the returns, we still believe that in the Piceance, the reason we're not drilling as much as we did -- as we could is really we try to manage our balance sheet. A 285 gas environment in the Piceance still would return a 15% return to us. So we've done it 4,000 times. We know we can do that. But we're choosing not to do that at this point. So we haven't change our view on sub -- around the $3 gas price, and 15% is not our target necessarily, but we think that would still bring a 15%-type return.

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

Great and then just on the CapEx for the quarter. You guys spent around $400 million. Could you give us the breakout on what was spent on acquisitions?

Rodney J. Sailor

I think that our exploration number was about $30 million in the quarter.

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

Okay. And then, as we think about your full year guidance at $1.4 billion, that implies a pretty significant drop-off on a run rate basis for Q3 and Q4, but I believe you guys are talking about bringing an additional rig back into the Marcellus, so you're running 2, going to 3. And I think you had planned on an additional rig in Q4 in the Bakken. Can you help us understand a little bit where those changes and where those savings will come outside of kind of the acquisition cost?

Ralph A. Hill

We actually -- in the first quarter of the year, we were really 4.5 or 5 rigs in the Marcellus. I don't recall, and then it has dropped down to -- it actually dropped down to 1 as we've been switching around, so that's just starting to kick in. And then, we'll be adding the second and the third. So it'll be in the second and third quarter there. We also had some -- first quarter, we said by Carrefour, if you will, from the previous year. So that's really what's happening primarily. Rod, or --?

Rodney J. Sailor

I'll add a couple of comments if Bryan wants to weigh in, and Ralph, get on it. We've probably seen a little higher cost in the Marcellus, but we expect to catch up in the third and fourth quarter on that. The Bakken, we've discussed at length. But again, as Ralph mentioned and Bryan also mentioned, we have some cost coming in from last year and that -- again, that's part of those cost increases. And then finally, we had -- as we said, we had some land purchases.

Bryan K. Guderian

Yes, and -- I'm sorry, this is Bryan. In Marcellus, it's really a timing issue. We were coming off more rigs throughout 2011, and as Ralph mentioned, we ultimately got down to 1. And so, we should really gain on that run rate here in the third quarter. And then also in Piceance, we were coming off a much higher rig count in Piceance last year as well, and some of those costs carried into the first quarter end as well. You've seen us now stable at 5 rigs for the last, probably, 4 months. And so, we should gain on that run rate over the balance of the year, too.

Rodney J. Sailor

And I would just add, I think Bryan is starting to see efficiencies, and we talked briefly to it -- or Ralph spoke briefly to it. We're starting to see the efficiencies in the Marcellus, and that should help us out in the third and fourth quarter. And again, we think we've turned the quarter in the Bakken, which should also help us out in the third or fourth quarter. But it -- we will be challenged for the rest of the year, but our intent is to stay on plan.

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

Great. And then, just 2 quick final questions for me. On the Marcellus, you mentioned I think in the press release that in July, there was $30 million a day of curtailment. Is that incremental to your production? So essentially, was that what you're talking about with the upside to your production? Or is that actual production that you've had to curtail on the Laser pipeline, so you're actually going to see a decline in July's production number?

Ralph A. Hill

It's incremental. If it's gas, we would have on if the pressures were -- if the system operated reliably and pressures were lower.

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

Great. And then final question for me. In terms of asset monetizations, have you guys at all looked at or explored the potential to high-grade your portfolio further and potentially looking at monetizing some of your CBM assets where I would assume, given the 3 core place for you at the moment, really won't see much capital allocated to them over time?

Ralph A. Hill

We will. You saw we did that earlier with the Barnett and we will be always looking at all of our assets and understanding if they fit better with us or with somebody else. So there's nothing on the front burner or anything at this time, but we really believe in making sure whatever stays in our portfolio is driving our value. So we'll continue to operate that way.

Operator

And next we'll go to Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

On your EBITDAX guidance for 2012, it looks like it's based on $51 a barrel for your NGLs, which is a good bunch higher than 1Q and 2Q and the strip. I'm asking what's driving that assumption partly because it has a really big effect on cash flow, but partly because I'm wondering if you're guiding us to that because you're expecting ethane rejection and so you'll see lower NGL volumes and higher prices.

Rodney J. Sailor

Well, I would add -- I'll take the first crack at it. That $1.175 has been the number we put out in February. And we put out the rule of thumb, but again, that -- the $1.175 billion was based on the prices that we've -- I think we've disclosed in February and then first and second quarter earnings release. If you use our sensitivities also included in the press releases. And as I spoke to in the slide deck, based on current strip price that we're seeing now, you would probably end up $85 million to $100 million lower than the $1.175 billion, and that would assume kind of a go-forward run rate on NGLs of about $31 a barrel is what we're seeing. The $51 when we put out that guidance, that was what we were realizing in -- we realized in the fourth quarter of last year and in January of this year, and in fact, the -- I think, we're currently talking about 14% hedge this year in NGLs, that is the price that we were able to hedge early in the year.

Ralph A. Hill

So what we're try to do, Anne, is basically, the $1.175 billion is out there for the year, but the rule of thumb is below there. So depending on what your model is and what you're prices are, you can adjust that accordingly, and so can others. So we try to make it to -- $1.175 billion is based on these 3 factors: oil, gas and the liquid barrel. And to the extent that changes, as Rod mentioned, currently what we see, that could be down $85 million to $100 million, it depends on what your model says, and you can adjust it accordingly that way.

Anne Cameron - BNP Paribas, Research Division

Okay, got it. And then kind of a related question. I mean, clearly they're rejecting ethane at Conway, and I know that you are -- your marketing contracts are indexed in Belvieu even though, you sell at Conway. So if you're making a decision at the processing plant level to whether or not to mix the ethane back into the gas game, how does that work where your actual end market isn't taking the ethane?

Michael R. Fiser

Anne, this is Mike Fiser. We -- as you said, the physical barrel does end up at Conway, but our pricing is based on a Mont Belvieu price. So the economics that would be run on that would be a Mont Belvieu price, not a Conway price. The other point on ethane rejection you had brought up is that we've been hovering around rejection economics for a while throughout the quarter. And so, the net realized barrel that you're looking at in our presentation includes a very, very low ethane price. And we do think that as gas price recover, as propane recovers due to increased export capacity and the inventory being reduced, we think ethane also will be, maybe not robust, but certainly higher priced in this -- in the current spot market.

Rodney J. Sailor

I was just going to add, you mentioned the decision on ethane rejection, and that's really made at the processor level. We don't control that. But one of the reasons that we realigned our Willow Creek contract was to put us and WBZ more closely aligned with the revenue -- excuse me, with the margin sharing mechanism.

Anne Cameron - BNP Paribas, Research Division

Okay, got it. And how much in your transportation costs for barrel of NGL to get down to Conway?

Ralph A. Hill

It runs about -- per barrel, it's about $10 a barrel of transportation and fractionation.

Rodney J. Sailor

That's -- well, but transportation is -- and transportation is less than, obviously, less than $0.10, it's a piece of that. But again, it's probably in the -- just the transportation component, I'd say is in the $0.06 to $0.07 per gallon range.

Operator

And next we'll go to Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So on your rig count, could you just go around the horn and just go area by area, what's the rig count now per area? What's the plan at year end 2012?

Ralph A. Hill

The rig count in the Piceance is 5. We have -- and we are at 6 -- we have 6 in the Bakken, and we have 2 in the Marcellus currently. The Marcellus was 1, the Marcellus is 2. We'll have a third Marcellus come on in November, is that correct?

Rodney J. Sailor

Yes, we're doing some change-outs around new rig contracts that we executed 18 months or so ago for newbuilds, and so, we'll have some transition periods. In Marcellus, we've got 2 more new rigs coming. We'll be dropping 1 of the existing 2 that we currently have working. And then in Bakken, we're actually going to have a short period here where we're probably at 7 rigs, again during transition. And then as our remaining 2 neighbor -- I'm sorry remaining neighbor's rig comes on board, and then we also have a pioneer rig that's scheduled to come in on August, we'll be dropping 1 of the existing -- or 2 of the existing rigs to get us back down to the 6 average for the year.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. Then Piceance will stay at 5 through the rest of the year?

Ralph A. Hill

Yes.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, great. Any rigs running out anywhere else?

Ralph A. Hill

No.

Rodney J. Sailor

No, no operated rigs running anywhere else.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. Okay. And then, on -- in the Bakken in particular, with $12.5 million drilling complete cost, what kind of return do you get on that cost?

Ralph A. Hill

If you look in the appendix, let me -- let's find it. There's a sensitivity slide in there, Dave, do you have it?

David Sullivan

31. Yes.

Ralph A. Hill

Slide 31. Basically -- I'm sorry, I have to get there for a second. You can see it's kind of -- it depends on the EURs, but it -- just take the lower line, just if you want, but I'll take the higher line, but $12.5 million would be about a 20% return. The -- that is based on a $90 oil, and a -- but we really, our reserves are actually trending more towards the green line. So it's between the 20% to 25% range. And you see what would happen if we move back with the pad drill and other stuff, it goes back to the $10.5 million.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. That's helpful. And then, the plan to drop the $2 million in costs, what's the timetable on getting down to $2.5 million do you think?

Ralph A. Hill

Well, I think that will be our goal for next year. But I -- we're going to have to shake through that. I'm not saying that's the exact 2013 plan. That would be my goal, it may not be the team's goal yet. We have to get through the pad drilling or get everything held by production. As mentioned, we have 10 wells left to do. That will happen in third quarter. Those will be completed. We'll get more -- we'll get our system completed and gathering system and some other things happening, so we believe we're doing better on the completion crews and we really are impressed with our new rigs that are coming on, we've got to get those other 2 on, I understand that. So that would be a goal, but that number could easily be more like $11 million next year. So we just -- we'll have to give you more guidance on that as we move towards -- and remember, for apples-to-apples comparison, we do use ceramic, some other operators don't. We firmly believe in it. We've tracked over, I think it's 4,000 wells, and there are some areas I understand why sand was used, one, ceramic wasn't available when they first developed. But they -- well, we are -- we've strongly believed in that ceramic and that adds $1 million to costs to our well, but we believe it gets superior performance. So I would say next year, you'd see us in a target range between around $11 million, hopefully, lower. I'll push the team lower, the team will push me higher. We'll see where we end up.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And what's the long-term target for cost in the Bakken?

Ralph A. Hill

I've always loved $9.5 million. I might be the only one who loves it. But I believe -- I've seen us do it in the Piceance, I've seen the Marcellus team crack the nut, and I know the Bakken team is going to crack the nut. So that would be a long-term goal.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. And then, I might have missed this, but what are the current costs in the Marcellus? And what's your target and the timetable to get to that target?

Ralph A. Hill

I think current costs are -- they were -- or certainly above $7 million, they moved to $6.5 million, and our target's $6 million. And I think we're headed towards $6 million as we move into these lower drilling costs of 16 days or -- so, I would say the current target will be -- and actual results are between $6 million and $6.5 million. And you would ask what my long-term goal would be, and that would be $5.5 million. Again, that would be a discussion between the team and I, but once again, I'll point out that we've done it before, and I know we can do it again.

Rodney J. Sailor

Current call is probably $6.5 million to $7 million right now.

Ralph A. Hill

Earlier in the year, yes.

Operator

And next we'll go to Brian Velie with Capital One Southcoast.

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

A couple of quick questions. Going back to the Piceance, I think I heard you mentioned that at 285 gas, there's a 15% rate of return. But on the sensitivity slide, it looks like 285 gas gives you more like a 10% or 12% return, but aside from that, I just wondered what NGL price you're using in that sensitivity slide also?

Ralph A. Hill

The NGL price would've been -- I think it's the second quarter NGL price. Yes, it was. It would be the...

Rodney J. Sailor

$28

Ralph A. Hill

So yes, I was going off more like a first quarter NGL price. So I guess at that point, you would need to give you a 15%, we would need to be more in the $325 million range or so for that to be a 15% type return. $285 million would have been using more of the first -- end of the year higher NGL price. So that would have been based off of more of a $0.90 -- I think it was close to a $0.90 uplift on what I was using. And this Q2 is more of a $0.66 uplift.

Rodney J. Sailor

That's a good point.

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

Okay. I just wanted to make sure I was looking at it correctly.

Ralph A. Hill

Yes, I know you are. Yes, I'd -- absolutely.

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

All right. And then on the Mancos and Niobrara, I just wonder if you could remind me for the well that you're going to plan to drill there in 3Q '12, what kind of a production mix do you expect?

Ralph A. Hill

Well, this -- in Mancos, if you're asking like gas, it's mostly gas. It's that -- the Mancos, that -- part of the Mancos and the Piceance, underneath our existing drilling is gas, it's dry gas. It looks probably similar to what the Valley has. We're not sure of that yet, but the Valley gas, it's pretty lame, but obviously, we have the trial capacity and then the Valley gas is 10.40% to 10.80% gas, and we don't know enough about to say if the Mancos is going to be the same, but I would hope it'd be something in that range.

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

Okay. And then, how much do you plan to spend there for the rest of the year?

Ralph A. Hill

In the -- on just that one -- that one well?

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

On that -- on the deeper Mancos/Niobrara project that you allude to in the slide deck.

Ralph A. Hill

It's included in our guidance. I would guess that well will have a ton of science on that and everything else, so that could have $8 million into it or something, $9 million, I don't know. We would guess -- but what we would see going forward, if you move to where we think we'd be, we'd think those wells across between around $5.5 million and hopefully you're getting the $6 million to $7 million piece. That's where we think we'd get to long-term. But we haven't done that yet. But we just know what that team can do. But the first well will be cored, it will be extensively tested. Everything you can throw at it, we'll throw at it.

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

Okay. But that $8 million will be the total goal out of that $1.4 billion 2012 CapEx, only some of that $8 million will be spent there?

Ralph A. Hill

$8 million to $10 million. Yes, I think it might be up to $10 million. But yes, that's all included in the $1.4 billion.

Operator

And we'll take our final question from Robert Bellinski with MorningStar.

Robert Bellinski - Morningstar Inc., Research Division

I was just wondering if you could give a quick update on permitting in the Bakken and what you're seeing in terms of permit inventory.

Bryan K. Guderian

Yes, this is Bryan. I'll take the question. My answer is probably the same as it was last quarter. It remains tenuous. We'd like to see things move at a much faster clip. But at least, up to this point, it's been manageable. We haven't had any rig idle time as a result of waiting on permits. Last -- I think it was early in the year and into maybe even the second quarter, the BLM formed a kind of a permitting task force that was assisted, and I think even partially funded, by industry. And so, they cleared a pretty significant backlog. As a part of that process, we got some 25 or 30 in essentially a very short timeframe, which gave us a nice inventory to stay in front of the rigs. But I think you've probably heard from some of the other operators since the task force went away, things seemed to have slowed down again. On our side, we created a back office to attack this issue when we first bought into the basin. And so, the good news for us is the very vast majority of our prerequisite work has already been completed, and so our permits are truly sitting in the pipeline, either at the BLM or at the NDIC. And so, the short answer is it remains tenuous. We feel it's manageable. We've done our part. Our work is largely completed. And at least up to this point in time, when things get tight, we've been able to push things through the system there. And currently, we've got a couple of permits out in front of each of our rigs. So we'd like to see it improve, but it's been manageable up to this point.

Ralph A. Hill

Yes, this is Ralph. I think the good news is, it's not like we've seen in other areas like the Piceance, I mentioned we had 200 permits in hand and we have a 2-year permitting timeframe on the expiration of those permits, and we have more every day. We're not going to get that in North Dakota, but we're at least 2 to 3 permits per well -- per rig ahead. What we're saying is we'd like that to be 6. That may never happen, but the good news is, we're ahead of each rig, we expect to stay ahead of each rig, and our teams have done a very good job of doing that. And we think we've become, for the tribe and for others, the operator of choice up there. So we'll get them, but we'd love to have a longer inventory, but we've got a good inventory.

Is that it? Okay. Well, thank you very much for your interest, we appreciate it. We're excited about our new -- we're excited about the team doing what they do, and that's execute well. Our productions are really ahead of where we thought we would be. Our costs are coming down, that's what we can control. And also, we're excited about what our exploration land team are putting together in these new areas and look forward to doing some drilling, doing some testing and telling you about that in the future. So thank you for your interest and we look forward to talking to you soon.

Operator

And that does conclude today's conference, and we thank you for participating.

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