Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)

WPX Energy (NYSE:WPX)

Q2 2013 Earnings Call

August 01, 2013 11:00 am ET

Executives

David Sullivan

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

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

Bryan K. Guderian - Senior Vice President of Operations

Michael R. Fiser - Senior Vice President of Marketing

Analysts

Phillip Jungwirth - BMO Capital Markets U.S.

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

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

Nicholas Pope

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter WPX Energy Operations Update Call. My name is Matthew, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes.

And now, I'd like to turn the call over to Mr. David Sullivan, Manager of Investor Relations of WPX. Please proceed, sir.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy Second Quarter 2013 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, members of our senior management team, Bryan Guderian, Senior VP of Operations; Neal Buck, Senior VP of Business Development and Land; and Mike Fiser, Senior VP of Marketing, will be available for questions after the presentation.

This morning, on our website, wpxenergy.com, you will find today's presentation and the press release that was issued earlier today. The second quarter Q will be filed later today, and you'll be able to access that on the website as well.

Please review the forward-looking statements on Slide 2 and the disclaimer on oil and gas reserves on Slide #3. They are important and integral to our remarks, so please review them.

Also included are various non-GAAP numbers that have been reconciled back to Generally Accepted Accounting Principles. Those schedules follow the presentation.

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

Ralph A. Hill

Thank you, David. Welcome to WPX's second quarter call. Thank you for your interest in WPX. I've talked about this before, but we continue to operate from a position of strength: strength in our reserves portfolio of the 18 TCF of 3P reserves, and that does not include any numbers for the Piceance, Niobrara discovery or our newly announced San Juan oil discovery this morning; strength of our balance sheet, with $1.4 billion in liquidity; and the ability we can grow all 3 of our products, oil, gas and liquids, at a double-digit production growth for many years, effectively doubling the size of our company in 5 years.

I think this quarter is a reflection of that strength kicking in. Let me give you 4 examples of that kicking in. First, our oil discovery in the New Mexico San Juan Basin, which I'll talk about. Second, our Niobrara discovery well, which now has produced 1.4 Bcf in its first 180 days. We added rigs in the Piceance, which will arrest our overall gas decline this year and position us for growth in the future. We also increased our Marcellus production by 33%. And our Williston oil production increased 30% and on an equivalent basis, 35%. Our operational efficiencies are driving a greater number of wells drilled this year and completed without any additional rigs in 2013. All 4 of those things are a reflection of our strengths.

Let me turn to Slide 4. The recent highlights, as I mentioned, the oil discovery in New Mexico's Mancos/Gallup play exceeds our expectations. This is our first expanded oil play. The first 3 wells posted IP rates between 500 to over 1,000 barrels of oil equivalent per day. The fourth well just recently went online and IP'd at 800 barrels of oil equivalent a day. We estimate that our potential reserve additions to this will be over 66 million barrels of equivalent, with a 2013 exit rate of 3,400 barrels of oil equivalent per day. We've already moved to efficiently drilling and just beginning with our drilling program, our last wells have been drilling more in 15 days versus the original plan of 28 days.

Niobrara well is 1.4 Bcf, as I mentioned, in the first 180 days. I've got a slide to talk about how we plan to delineate this impressive discovery this year and next.

Bakken oil production is up 30%, equivalent is up 35%. We're doing simultaneous operations like we do in the Piceance. Things in the Bakken continue to get better and better.

In the Piceance, we added the 2 rigs I mentioned, brings our total rig count to the -- for the rest of the year to 7. It should add 2 Bcf of equivalent production by end of this year and increase the basin's exit rate to about -- from 700 million a day to 730 million a day at year-end. This also increase our -- will stop the production decline, as I mentioned, for the entire company and will add 15 Bcf of production in 2014.

And compliments to our Marcellus team and facilities team to successfully renegotiating the Laser contract in the Marcellus early, results in $10 million of savings for 2013 and has many benefits, which I'll talk about later for our contract and our go-forward operations.

Slide 5. I want to remind our investors, we have a number of cost improvements that have occurred and will continue to kick in. First, for 2013, we have a run rate savings of $47 million to $68 million, primarily due to our new Willow Creek contract rate and our Piceance gathering rate changes. By the fourth quarter of 2014, that run rate will move to the $120 million to $150 million range, and that's when we get rid of the sale for resale agreement contracts to the Rockies Express, which does expire in the fourth quarter of '14.

We continue to negotiate the buyout of our unutilized transportation. This improvement is not included, and I stress, is not included in the $120 million to $150 million of improvement. And if we would do that and could get out of those contracts, that could add additional $25 million to $46 million of potential annual savings.

And we did proactively renegotiate the Laser contract with Williams, saving the $10 million, as I mentioned. It eliminated minimum volume commitments. It has new flow assurances, capacity allocations, pressure requirements, release clauses for us. It is a very favorable contract for us in the Marcellus.

Slide 6. I am very pleased to announce the successful result of our first expanded exploration oil play, which we start -- we talked about on this call last year. Our first oil project that was very successful is in the Gallup Sandstone formation. It's a tight sandstone that sits in the middle of Mancos shale section of the southern margin area of the San Juan Basin.

We began this year with exploratory efforts in Mancos, and we ended up drilling 4 horizontal wells, with laterals about 4,500 feet in length. All 4 wells are now on production, and you can see their impressive rates on the right-hand part of this slide. Due to this strong results, we've commenced our horizontal development program this year, and we're planning to drill additional 8 to 10 wells for a total of 12 to 14 wells drilled by year end.

Our exit rate, as I mentioned is 3,400 barrels of oil equivalent expected this year, and we do estimate this already hones about 66 million barrels of resource potential for us, with 70% of that being oil.

We have 31,000 net acres in the play, with an average net revenue interest of approximately 83% to 84%. And we're targeting D&C cost below $5 million and EURs greater than 500,000 barrels oil equivalent. Each of these wells should be very high returns, in the 50% plus type return basis on -- based on a $90 to $95 oil price.

Slide 7. We do have a long history in San Juan, and several things are very beneficial about finding this new discovery in the San Juan. We have 31 years of continuous operations. We've drilled and operated over 880 wells ourselves. We hold joint interest in another 2,400 wells.

WPX San Juan team was the first one to drill the 2 Mancos horizontal gas wells, which we announced in 2010 discoveries. This discovery is a direct result of our basin expertise and has also helped us out on the Piceance, Niobrara development.

Very importantly, we do not have to add a new asset team for this discovery, but we utilize our existing people and resources within our San Juan Basin office. And due to the basin maturity, infrastructure is in place. We have a proven permitting process in place, long-term relationships with our service company and vendors. All this would be -- help us -- help WPX rapidly develop these exciting opportunities.

We took extensive quarry and signs in the first 4 wells. Those wells did take longer to drill, but, as I mentioned, our most recent well required only 15 days. Development well costs are already below $6 million, and we're headed for $5 million or less as soon as we get to multi-well padding -- pad drilling. And we should see future efficiency gains by employing zipper fracs and multi-well pads, which will start sometime in the second quarter of 2014.

Slide 8. Quickly on our core Piceance operations. We have the preeminent Piceance position, with a superior acreage position you've seen before. We increased our drilling plan for the year, with an addition of 2 rigs. We've arrested our production decline. We will spud 51 -- we did spud 51 wells in the second quarter, with the 7 rigs. And it would continue to get better and better, with our Valley drilling time that's reduced to 8 days and our Ryan Gulch average drilling time, 11.5. And as you know, our record drilling times are substantially below those too.

We are the low-cost operator, and our facilities are in place, from water management to gathering processing, and a takeaway capacity to be able to make this the first and fastest basin to grow on gas production, which we are getting close to being able to do.

Slide 9. Let's talk about the Niobrara. We are going to aggressively delineate Niobrara. We're carefully trying to balance our desire to rapidly develop this wonderful discovery with the right systemic and technical approach to make sure we delineate the field properly, and we also understand the proper ways to drill and complete these wells. We have a very focused plan now on proving up our acreage, looking for repeatability and improvement in our operations, understanding the well spacing and density, and also looking if there are some other horizontal -- horizons in there that we can evaluate there.

Our delineation schedule is on track. So far, we've delineated about 18% of the Valley acreage, but the key number is, by the end of this year, we will have delineated about 50% of our Valley acreage. Next year's program, which we anticipate to be 10 to 12 wells drilled, will be about -- would have about 80% of the Valley acreage delineated. So again, it's a balance between rapidly developing this and also making sure we do it the right way.

3D seismic. 83% of the Ryan Gulch acreage is already covered by a 3D seismic. 34% of the Valley is currently covered, with about 68% of that will be done, with our current shoot, that will be done by -- 3D shoot, will be done by midyear 2014. Overall, we'll have over 100,000 acres with 3D seismic coverage by the middle of 2014.

Slide 10. Turning now to the Bakken. We continue to drill some of the best wells in the play. We put out 9 wells on first sales in the first -- in the second quarter, 7 Middle Bakken and 2 Three Forks. We spud 11 wells with the 4 rigs. Our wells continued to perform at or above our expectations.

And again, I do believe, particularly in Dunn County, we're drilling some of the best wells. We have a study that shows that we're #1 in cumulative Middle Bakken production for spuds since 2011, which we took off for over operations in about April of 2011, I believe it was. So since we've taken over operations, we continue to have some of the best producing wells out in the play.

I do want to talk on Slide 11 about our efficiencies. We have lowered our well costs throughout the basins. We have now fully transitioned to pad drilling. And we have implemented simultaneous operations, which allows us to drill, produce and complete at the same time on the same pad.

Over last year, we've reduced our drilling times by 35%. Our last 2 wells have averaged 22 and 24 days, respectively, in drilling. In addition to faster drilling times, we're now drilling all our wells with brine water, and 2 of our wells TD'd at drilling rates exceeding 1,000-foot per day or less than 20 days drilling.

Our zipper frac completions have been very successful. We've recently completed our first triple zipper frac successfully. On a go-forward basis, we intend to use these dual and triple zipper fracs.

Infrastructure is improving. The Arrow expansion improved throughput and reliability, and we expect the Van Hook project to be completed in the third quarter. We have electrified 51 of the 55 Van Hook wells, by the end of year we will have, and that will look to lower our lifting cost.

In addition, we're doing many things, such as building all of our winter pads this summer, which should save us some substantial amount of money.

So as you can see, this page continues to show, not only the previous page, we're drilling some of the best wells in the play, we now are continuing to get better and better on our efficiencies.

And speaking of efficiencies, Slide 12. In addition to and as a result of all the continuous cost improvements and efficiencies, our oil production rate had gone up impressively, with 30% in the second quarter compared with a year -- just a year ago. So it's -- the efficiencies have kicked in, the production is going up. And because of this, you see that we've been able to announce today that we should facilitate the drilling of 7 more wells and 11 additional completions this year for a new total of 36 -- 46 spuds, not -- versus 39 previously and 52 completions. This will increase our year-end exit rate for our Williston oil production by more than 2,000 barrels a day, or 15%, to a new total exit rate of 15,000 barrels of oil per day.

For 2014, this additional activity -- and I want to stress this because our press release was a little confusing to some, this additional activity will incrementally, and I stress, incrementally increase our Williston production by 8%. We'll have a very substantial -- pardon me, for 2014. Did I say '13? '14. For 2014, this will incrementally increase our Williston production by 8%. We haven't given out guidance for '14, but obviously, we expect very impressive growth rates for the Williston Basin for 2014.

On Slide 13, the Marcellus. We continue to grow our production volumes. They were up by 33%. And we hit a record production day of 100 million a day at the end of June. We did this in spite of infrastructure constraints, but I do want to stress that the remedial work at Williams' Dunbar station was completed in June. The field compression is becoming more reliable, resulting in an uplift in production that you've seen. Production pressure were constrained -- our production -- the pressure out there constrained our production by about 20 million a day on average for the second quarter, but by the end of the second quarter, that had dropped to about 10 million a day. And I had mentioned several times how good the team did on renegotiating the Laser contract early.

On Slide 14, just a reminder that we've started a process on Apco, includes hiring a representative. Any possible action around this, and I would stress this, any possible action around this would be a 2014 event. We have a value target in mind. We will reach that value target or exceed that value target or we will not transact on that. But we are encouraged by the recently announced Chevron and YPF joint venture, where Chevron will invest more than $1 billion just west of our 249,000 Vaca Muerta acres, which are in the Neuquen Basin.

With that, let me turn this over to Rod.

Rodney J. Sailor

Thank you, Ralph. Turning to our second quarter results slide. Overall, the second quarter equivalent production was 1.26 Bcf per day. Overall oil production was up approximately 14% versus the same period a year ago and averaged 21,100 barrels per day. Oil production in the Williston, as Ralph mentioned, was up 30% and averaged 12,300 barrels for the quarter. Natural gas production was slightly over 1 Bcf a day. While down versus our second quarter 2012 comparisons, as mentioned, we expect the addition of the 2 rigs -- or excuse me, maintaining the 7-rig program in the Piceance to arrest our production declines as we move forward.

And although we did see improvements late in the second quarter, overall, Marcellus second quarter gas production continued to be hampered by the infrastructure constraints for much of the quarter, and we continued -- again, for much of the quarter, to have about 20 million a day constraint.

Natural gas liquid volumes were 21,300 barrels per day, which is down quarter-over-quarter, largely due to ethane rejection. Our ethane recovery in the second quarter was 37% versus 74% a year ago.

For the second quarter 2013, WPX reported unaudited net income from continuing operations attributable for the company of $18 million. Our results were positively impacted by unrealized mark-to-market gains of $99 million on derivatives not designated for hedge accounting treatment. And $94 million of these were related to natural gas derivatives. Offsetting this was $21 million of realized losses, $20 million of which were related to natural gas.

Absent these gains, we showed an adjusted net loss from continuing operations for the second quarter of $44 million versus $30 million for the second quarter of 2012. EBITDAX for the quarter totaled $210 million versus $251 million in the second quarter of 2012. Our capital spending for the quarter was $277 million, which was down from the $400 million we spent in the second quarter of 2012.

Turning to our next slide, as we mentioned in the press release, we are anticipating capital spending to remain within our guidance range but to be near the upper end, at approximately $1.2 billion for 2013. This includes the impact of running the 7-rig program in the Piceance, the 7 new spuds and the 11 additional completions in the Bakken and also moving to commercial operations in the recent -- the new Mancos/Gallup discovery.

I would point out that on our capital guidance, we have done some reallocation between categories. The other change on our guidance slide relates to our GP&T expense line item. We did enter into a rail contract in the second quarter, and transportation charges associated with that contract flowed through our gathering, processing and transport line item.

As we have indicated, the rail agreement allows us to not only get less pricing, but also move product east and west. The benefit of this pricing will be included in our revenue line item, but it will be offset by slightly higher GP&T expense.

Overall, we expect our basin differential in the Bakken to average $6 to $8, a range we are currently seeing.

Production is still within our guidance range. The Piceance and Bakken production will exceed our base expectations in the back half of 2013. This is primarily due to the previously discussed efficiency gains in the Bakken and the additional drilling and completion -- from the additional drilling and completions and also the 7-rig program in the Piceance. These increased activities will help drive 2013 growth, but will mainly benefit 2014 production in both of these areas.

Marcellus year-over-year production is still being hampered by infrastructure constraints in Susquehanna County. We do expect to be close to our expected Marcellus exit rate, but year-over-year production will probably be closer to 40%.

Also, we expect international production to slightly decline in the second half of 2013 due to drilling delays as we wait for final Rio Negro province concession extension.

In our release, we also announced that after a rigorous undertaking, we have concluded our process to sell the Powder River Basin assets and will be retaining those properties. We did not need to sell these assets for any funding purposes and would only sell -- consistently said we would only sell for a fair value. We will utilize our ample $1.5 billion revolver to satisfy any funding requirements. The company remains open to a full or partial monetization of these assets in the future.

Turning to our -- my last slide, I'll talk a little bit about our hedging activity. New activity includes -- for the quarter, included 2,000 barrels per day on a September through December LLS swaps for a little over $106, raising our average price for oil hedges in 2013 to $101.84. For 2014, we did add $50 million a day in costless collars, with a floor of $4 and a ceiling of $4.82, raising our average for 2014 collars to a $4 floor and a $4.58 ceiling. We also executed on 8,000 barrels of crude swaps for a little over $93, raising our average price for 2014 to $93.81.

With that, I'd like to turn it back over to Ralph for the wrap-up.

Ralph A. Hill

Thank you, Rod. We did have an exciting quarter and are executing on the 2013 path that we outlined for you at the beginning of this year for greater shareholder value. First, on the disciplined natural gas development, we have stopped our natural gas production decline by adding the 2 rigs at the Piceance. I do remind you that I believe WPX is ideally suited to be the first and fastest to grow gas production.

Second, we have grown our Williston oil production by 30%, and we find that the 2013 efficiencies are going to drive even greater 2014 production growth. We're doing more with less, as we said we would.

Third, our cost improvements, you can see the checkmarks here. We have the Laser contract renegotiated early. The Willow Creek contract has kicked in the beginning of the year. The Piceance gathering rate has changed. And our Williston efficiency has kicked in, so it will -- much more efficient, drilling 7 more wells, 11 more completions this year.

Finally, we're very excited about the new discovery in the Niobrara, obviously, and the Piceance, and we're going to delineate that as fast as possible but also very prudently. But as you can see, a majority of that will be delineated by -- with next year's program. We're also very excited about the new discovery in San Juan Basin oil window, with a resource potential of approximately 66 million barrels of oil equivalent.

So before I go to Q&A, let me just sum this up. We're obviously excited about stopping our production gas decline. We've arrested that decline. We've added 2 rigs in the Piceance. We're poised for growth.

We're very excited to delineate the Niobrara discovery. We're doing that as we speak.

We should add more wells on this year. We have 10 to 12 planned for next year, but we're doing it also very prudently, but I think also as rapidly as possible.

The San Juan Basin, our first step-out is going to be a great success, we believe. And we're excited about that resource potential of 66 million barrels of oil equivalent. And then our Bakken results continue to get better as we drill some of the best wells in the basin, continue to drive efficiencies, get more efficient, move to pad drilling.

All the things we said we're going to do are kicking in, and as a direct result of additional production this year with an exit rate of over 2,000 barrels a day equivalent -- or 2,000 barrels of oil a day higher than we thought it would be.

So we feel those things have -- really start to be a reflection of the strength of WPX, and we look forward to continue to execute for you.

And with that, we'll turn to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Phillip Jungwirth of BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

On the San Juan oil discovery, based on the declines that you've seen from the 4 wells announced today, would any of those wells, and if so, which ones would meet the targeted EURs of 500 Mboe?

Ralph A. Hill

They all would exceed that at this point. The actual -- our original target EUR I believe was 3...

Rodney J. Sailor

350.

Ralph A. Hill

350. So our original assumption was 350, and all those will be exceeding that.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then on the Powder, do you own the -- or control the deep right on that acreage? And if so, is there any planned activity later this year? And can you talk to any offsetting activity?

Ralph A. Hill

We do have 140,000 acres of deep rights associated with the package that we had the rigorous process on. There are a number of third-party proposals that we are evaluating. We have some of our own prospects that we've identified. At this point, we are not planning to drill those this year and don't need to, but that is part of the value proposition of the overall package of why at this point we have not transacted.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then last question, I think you talked about a second oil -- oily stealth play. Are you still active there? And if so, when do you think you could be able to talk about results like you have today with San Juan?

Ralph A. Hill

We are active. And I think -- I'll turn to Bryan. Would that be early next year, we'd talk about that, or...

Bryan K. Guderian

Potentially fourth quarter.

Ralph A. Hill

Potentially fourth quarter call, yes. So end of this year, early next year.

Operator

Your next question comes from the line of Hsulin Peng of Robert Baird.

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

So just first question on your '13 guidance. I understand that you guys keep your guidance the same for '13. But I -- and with the increased oil production from Bakken and also with -- from San Juan, Gallup and most likely that's not until the end of the year and the offset in Marcellus. So I was wondering, can you talk about the production mix that you anticipate by year end?

Rodney J. Sailor

Well, I guess -- that's a far-longer [ph] question. But as it relates to the San Juan, we did have -- in our guidance, we did have some barrels associated with the $40 million in capital associated with the San Juan drilling program. Our results to date have been much, much higher than we expected. So we do anticipate, again, seeing higher production from the San Juan. Again, as Ralph mentioned, Piceance production will be slightly up from our expectations. Unfortunately, it will also be offset by the fact that we've been hampered for the first 6 months of the year by Marcellus. So again, we expect gas to probably be somewhat in line with our guidance. Oil will be somewhat up due to the Charco and the efficiencies in the Bakken. And right now, probably liquids will be up slightly from our midpoint due to the increased activity in the Piceance. So -- but net-net, again, we're in the -- between the mid and the high point of our guidance range.

Ralph A. Hill

And I think for the mix, at the end of the year, I don't think we'll see a substantial change in the mix. I think we said early this year about 78% gas. I would guess that mix will be about the same just because a lot of the Bakken production out there will be coming on at the end of the year, but not enough to change the overall percentage for the year yet.

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

Okay. Got it. And then second question regarding Marcellus. I just was wondering, given that it's still infrastructure hampered, what would you need to see before you can add another rig? And when do you expect the constraint to be cleared up completely?

Bryan K. Guderian

Yes. This is Bryan Guderian. What we're looking to do now that the Williams infrastructure is more or less stabilized, it continues to improve, we're likely to add additional compression in the field to lower the operating conditions near the wellbore so that we can improve the deliverability into the system there. And so it's as simple as adding -- potentially adding a second stage of compression across our field gathering systems.

Ralph A. Hill

I mean, ideally, what I've said is I'd like to see us next year in the Marcellus go back to at least 3 rigs, primarily -- probably all those in Susquehanna County, but it's just too early to say that yet. But we are encouraged that the amount that's currently being constrained is much less than it was. And as Bryan said, some of the fields where we see compression is becoming more reliable. So as we -- we continue to see better signs, and I would say that you could see us next year with a plan to be more on 3 rigs or so in the Marcellus versus to 1.

Bryan K. Guderian

And just -- I'm sorry, I would just add to that, that based on the 3 rigs that Ralph just mentioned, we feel we have ample capacity to move that production to the mainline through the end of 2014. So we will not have any downstream constraints, assuming we go back to a growth program of 3 rigs.

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

[indiscernible] would you go from 1 to 3 or would you go from 1 to 2 to 3? And when could that addition -- I mean, I guess, are we thinking early -- potentially early '14 for those 3 rigs, or just later in '14?

Ralph A. Hill

Well, don't take this as guidance yet, but ideally, we have the rigs available. We can put those all to work in early 2014 at the same time. We have the personnel in place and we have the ability to -- we have the rigs in place if we need them. But we still need to sort that out in the next several months.

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

Okay. And then in terms of, I guess, '14 guidance, I know it's still early, but just kind of thinking about with the San Juan Gallup and also the increased efficiency in the Bakken. I know before, you guys had talked about oil growth rate sort of in the 25% to 30% CAGR rate. I mean, I was -- I would hope that the -- that with the addition from San Juan Gallup and Bakken that it could be higher than that, you think? I don't want to put words in your mouth, but how should we think about your total CAGR going forward?

Ralph A. Hill

Yes, that intuitively makes sense to me also.

Rodney J. Sailor

But again, I would just caution, we haven't been through our capital allocation plan for 2014, nor have we given any definitive guidance about the product mixes for 2014.

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

Okay. When do you think you'll give '14 guidance?

Rodney J. Sailor

We would give it probably either very late in 2013, but most likely early 2014.

Ralph A. Hill

Similar to last year. Probably late '14, early '13 -- I'm sorry, late '13, early '14.

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

Okay. So like on the fourth quarter call, maybe?

Rodney J. Sailor

Or before.

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

Okay. And the last question, then I'll jump off. So with the San Juan Gallup, can you just talk about -- because I think you said you are currently trucking to some pipeline injection point. Do you foresee -- as you develop this area, do you foresee putting in a pipeline such that you can save some, I guess, trucking costs? And where is that pipeline injection point, and also the quality of the oil, please?

Michael R. Fiser

Yes, this is Mike Fiser. We currently have a deal in place to a refiner in the area. And we truck to that location to get into the pipe to serve that facility. We'll continue to look at options to move it further downstream, but at this point, that agreement is an agreement that we like.

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

Okay. And what's the quality of the oil, and so we can think about the differential for that oil, please?

Ralph A. Hill

It's sweet oil. It's light sweet oil. And I think the differential right now is around, what, $10, $11?

Michael R. Fiser

About $11 basis differential, and it's sweet-quality crude.

Operator

Your next question comes from the line of Brian Corales of Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Just more on the Gallup. One, is there a lot of other acreage to be had there, or is it pretty much all held?

Ralph A. Hill

Well, we're aggressively looking to add, and there is ability to add to it. So I would say I think we will add to our positions.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And based on early results, I mean, would you drop rigs in the Piceance or Marcellus and reallocate capital here or potentially to the Bakken if things have improved quite a bit?

Ralph A. Hill

It's probably too early to tell yet, Brian. But we do like this play. We like the returns. We do think that -- we do have plans to do more next year. So it's too early to tell the capital allocation side of the world, but we do like this. And I think the Bakken continues to be better and better for us. I don't think it would come from the Bakken. We do like the Piceance. And also, we need to delineate the Piceance side. So and I would say currently right now, and that's -- part of this is because of infrastructure constraints, the one that's kind of out there is the Marcellus side of this versus the other 3 plays.

Brian M. Corales - Howard Weil Incorporated, Research Division

And then maybe one bigger picture question. I mean, would you look to divest any of these assets, I mean, whether it's the Marcellus or the Bakken to kind of refocus your activity into certain areas that you get the best returns? One that maybe -- Marcellus has been kind of a struggle over the past year, maybe let someone else do that and you focus on the Bakken, Gallup and the Piceance or Niobrara?

Ralph A. Hill

Well, we obviously want to make -- well, first of all, most of our capital goes to the 3 previously, and the additional San Juan development was part of the budget this year. We assumed an additional, I think it was -- we said $40 million or something if we were successful. So that was all baked into this year's program, so -- but, obviously, we want to make sure we're putting our dollars in our highest return areas. So we will look at all of our areas. But I would say the oil plays in the Piceance are doing very well, and we know the Marcellus could do well with the infrastructure doing better. So we believe we have adequate assets and teams in place to develop all of these. And I mentioned on the San Juan Basin, that team has been in place, there's no incremental cost to that except going out and drilling very good wells. So I guess the answer is yes, but we don't see any reason to do that at this point. But we always will look to look for value enhancing opportunities for our shareholders.

Operator

Your next question comes from the line of Brian Velie of Capital One Southcoast.

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

Just a couple of quick questions. Brian had covered a couple of them a moment ago about your thoughts on portfolio migrating and refocusing, but I also wanted to ask on San Juan wells, it seems it's pretty early to put up the EUR expectation of 500,000 barrels. And I just wondered if there are any special causes for your confidence there that we can better understand -- with just 4 wells on it, it's certainly encouraging. But just wondered what made you so confident in those wells at this stage.

Ralph A. Hill

Well, they are all 4 well exceeding our curves, which is great, our expected curves. Also, there is other industry activity that we've monitored and seen, and we've seen what they have done right and wrong, and that gave us a lot more data points. So that's the reason why, is we just feel we have good data for -- are and we are seeing resource potential and targets, but we feel we're above those targets at this point. So we just have enough data to make us speak confidently about that.

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

Okay. And, Ralph, I just wanted to clarify, you mentioned that you're above the -- outperforming the 350,000-barrel curve or the 500,000-barrel curve?

Rodney J. Sailor

350,000.

Ralph A. Hill

Yes, we're definitely above the 350,000. And we're in the 500,000 range on the other -- all 4 wells.

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

Got you. And then just kind of -- the 4 wells that are in the release, what kind of production histories or the length of that production do you have, is it kind of a mix, or how far back do those go?

Ralph A. Hill

I think the first one was flowing in April.

Bryan K. Guderian

April.

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

And then one other question, on the deep rights in the Powder River Basin, you mentioned that offset operators have detailed some pretty impressive wells up there. Do you have any idea if there's overlap with some of that recent activity for that 140,000-acre deep piece that you have?

Ralph A. Hill

There's a little bit. Now, our acreage -- our gross acreage in the Powder is about 485,000 acres, I think, Neal, approximately. So that's 140,000. So we have some areas where we have some good working interest and some where we have very small working interest. A lot of the activity I've seen recently is a little to the south of us still. So we're not in the game necessarily on the -- some the wells you've seen announced recently, but that doesn't mean it can't get there, but they are to the South of us, some of the wells you're probably talking about.

Operator

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

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

Just a few quick questions for me. In terms of the Marcellus, you guys, I think, are in a pretty favorable position from a takeaway perspective. I was wondering if you could give us an update on your transportation capacity out of the basin, and how that effectively works with your agreements today.

Michael R. Fiser

Sure, this is Mike. We have spoken about it before, but we have a very flexible transportation agreement that we like on Millennium. We negotiated that agreement early as an anchor shipper, which gave us some favorable terms and some flexibility that we think is very valuable. We can ramp up the capacity to sort of mirror our production forecast and development activities or ramp it down through annual and biennial elections. So out of our time, we have a range of firm capacity that we can move on that pipeline. Further, it diversifies our price risk and gets us away from some of the basis points that are getting hammered recently and gets us to points further downstream that are exposed to a Boston price or maybe a Washington D.C., New Jersey market area type pricing. The team has done a great job in signing longer-term deals that we entered really a couple of years ago to give us that price diversity. And you saw a lot of that in our Q1 results in terms of the uplift to our pricing.

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

Great. And then just sticking with the marketing side of the business, could you remind us how your REX contract works today in terms of the pricing dynamics and where you specifically deliver that contract into?

Michael R. Fiser

Yes, the delivery point is Clarington, Ohio. The pricing is an Appalachian basket index and then it -- there's a deduction for the pipeline tariff on REX. So that gives you the netback as -- you can think of it is an Appalachia price minus the REX tariff cost to get to the netback to the Rockies.

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

And so for me, a pricing perspective, if we see these basis differentials for those volumes on REX, should we think about that as having exposure to that basis risk?

Michael R. Fiser

Correct.

Ralph A. Hill

And last year, that cost -- that contract cost is, I think we say in our slide, about $88 million, so -- and if you looked at our production -- this is last year, not this year -- I think that was a detriment to our overall pricing for the entire portfolio, even though it doesn't flow with the entire portfolio, about $0.17.

Michael R. Fiser

Correct.

Ralph A. Hill

On all of the 1.1 Bcf a day, we produced last year. I assume the cost is still about the same [indiscernible].

Rodney J. Sailor

Yes, correct. It's around $0.20 per MMBtu in terms of the overall impact to our price for our portfolio.

Ralph A. Hill

And contractually, that automatically goes away in the fourth quarter of '14.

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

Great. And then just last question on the marketing side quickly here. In terms of your Bakken oil volumes, with the change in the Brent-TI spread, how does that, if at all, affect your desire to move crude on rail? And what's the flexibility to deliver it either into Clearbrook or into WTI-linked price markets?

Michael R. Fiser

Well, we began this -- a rail deal in the second quarter. It's for approximately 9,000 barrels a day out of the Berthold rail facility. The agreement gives us the option to go to the Gulf Coast but also to the East and West Coast as -- if Brent becomes more favorable to LLS and so forth. We also have some pipeline capacity to Clearbrook that we use. And I think in the appendix, we show sort of the breakdown of our sales areas between pipe, rail and just basin-related sales. So we think that, that gives us some price diversity to get out of the basin and then access some of these markets on the coast.

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

Perfect. And my last question, just in regards to the San Juan. I just wanted to clarify in terms of the location count, so if I just use your 500,000 EUR, is that roughly kind of 120-plus locations from a drilling perspective, or was that on the lower EUR that you guys were initially thinking about?

Ralph A. Hill

I think it's -- the locations are more -- 150-plus locations is what we know today.

Operator

[Operator Instructions] And your next question comes from the line of Nicholas Pope of Cowen and Company.

Nicholas Pope

Just curious, you talk a lot about kind of the efficiencies in the Bakken. I was trying to understand how that's kind of manifesting itself in well costs. I mean, I guess, I'm trying to get where you guys at right now in the Bakken, and if the cost is not in line with, I guess, how efficient you've gotten, where -- what are you doing to kind of like -- is it bigger wells, more efficient, what are you trying to do there?

Ralph A. Hill

Well, pad drilling's just kicked in, in the second quarter, as we mentioned. I think the -- we have an appendix, Slide 36, that kind of talks about our F&D versus the other areas out there. So we try to boil that down to -- our well costs are still in the $11 million range, so that's soup to nuts, that includes everything. Our targeted well costs are more like the $10 million, and we expect to be headed that way in the third and fourth quarter. We -- obviously, in the first quarter we had a winter, a severe winter. We had severe flooding in the second quarter. You can see we're still getting a number of spuds off and completions done, so we did very well there. So our targeted well cost would still be to head towards the $10 million range. One thing we try to stress is you'll hear lower numbers in other areas, but we -- that's why we put our slide in the appendix, it depends on how much -- what the EURs are also in there. So I'd say, currently $10 million -- $11 million going to $10 million. We get to $10 million, I'm sure you're going to hear me say something different then. But those are the kind of things we're doing. You can see many of the things are kicking in, the drilling efficiencies, the completion efficiencies, the zipper fracs, all those things that are out there and just continuing to upgrade our equipment, and our people are there in place and the team is starting to roll.

Nicholas Pope

That's great. And just kind of looking at the expectation that you're going to be drilling a lot more, I guess, wells in Bakken than what was originally expected. I mean, is this to stay within the CapEx budget as you have it right now, are you looking -- is stuff being reallocated, or is there just room, I guess, to -- with kind of the budget that you all had in place at the end of the year to keep that within you-all's range?

Ralph A. Hill

It's a little of both. There was some relocation, definitely, some areas we're not spending as much and some areas we had -- our range is 1 to 1.2, I think, so we're, I think Rod mentioned, we're headed towards the upper end of that range, but we were able to stay within the range. And the reallocation, as Rod [indiscernible]

Rodney J. Sailor

Yes -- no, the upper part of our capital range assumed we had more rigs running in the Marcellus, and so we've reallocated that capital due to the infrastructure issues to the Bakken.

Ralph A. Hill

We already had the San Juan development basically in there. We've also picked up some additional land in some areas, so that's been reallocated somewhat, and so -- but still maintained to stay within the guidance.

Operator

Thank you for your questions, ladies and gentlemen. I would now like to turn the call over to Ralph Hill, CEO, for the closing remarks.

Ralph A. Hill

All right. Thank you very much for your interest. Just real quick, key takeaways. Very excited about stopping our gas production decline with the 2 additional rigs in the Piceance. Sticking with the Piceance prudently, but very efficiently and as fast as possible, delineating that discovery. We're excited to continue to be able to tell you more plans with that, what we continue to find out with the Niobrara. We think we have a significant discovery in the San Juan Basin, and we're going to be after -- all after that, like you can tell. And our exit rates should be very impressive by the end of the year. And the Bakken results, both the well results and the costs have kicked in better and better each quarter, and we're excited about that. So key takeaways for the quarter are operationally, we feel we're starting to show you that strength that WPX has, and we're anxious to continue to show that to you. So I appreciate your interest and your time today, and look forward to talking to you all soon, as soon as possible.

Operator

Thank you for joining in today's conference, ladies and gentlemen. This concludes the presentation. You may now disconnect. Thank you, and have a good day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

This Transcript
All Transcripts