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WPX Energy (NYSE:WPX)

Q3 2013 Earnings Call

November 07, 2013 10:00 am ET

Executives

David Sullivan

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

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

Michael R. Fiser - Senior Vice President of Marketing

Bryan K. Guderian - Senior Vice President of Operations

Analysts

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

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

Brian D. Gamble - Simmons & Company International, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2013 WPX Energy Incorporated Operations Update Conference Call. My name is Crystal, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host, Mr. David Sullivan, Manager of Investor Relations. Please proceed, sir.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy Third 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 and Rod, 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 third quarter 10-Q will be filed later today, and you'll be able to access that on our 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 Energy's Third Quarter 2013 Earnings Call, and thank you for your interest in WPX. A reminder of our foundation for growth in the future, we have 18 Tcf of 3P reserves in our portfolio which does not include the recent Piceance, Niobrara discovery or the San Juan oil discovery that what we've announced last quarter. We also have a very strong balance sheet with approximately $1.3 billion in liquidity. From an operating viewpoint, we had a strong quarter, reflecting these strengths with major highlights.

First, our second Niobrara well produced at initial high rate of nearly 12 million cubic feet a day, which is the second-best Niobrara well drilled in the country. And speaking of the best Niobrara well drilled in the country, our Niobrara discovery well hit 2 billion cubic feet in cumulative production in the first 10 months of production. Our oil production was at an all-time high, with the Bakken oil production up 46% in the third quarter to nearly 14,000 barrels of oil a day, and our efficiencies continue in the Bakken to drive our -- too much lower Bakken F&D costs. Our first 9 Gallup -- San Juan Basin Gallup oil wells had an average initial flow of 728 barrels of oil equivalent per day. And as promised, we have stemmed our gas production decline this quarter with additional rigs we've put in the Piceance.

The vast majority of our capital will continue to be invested in 3 primary areas: the Piceance, which we believe is the best gas and NGL basin in the nation, a position unique to us; the Bakken, which is the best oil basin; and now our oil discovery in the San Juan Basin and in the Mancos/Gallup play.

Turning to Slide 4. Looking more at some of these recent highlights. As we announced last week, our Niobrara discovery well continues to perform above expectations. The second well came in at 11.8 million a day. This well is currently producing 8 million a day after being choked back. It will help delineate the southern boundary for us, and I have some additional words on this in just a few well -- in a few minutes. And our first well, as I mentioned, has now produced 2 Bcf in its first 10 months. And for 2014, we intend to more than double our activity in Niobrara.

Our oil production was up 46%, and our efficiency gains continue to drive down our well costs in our F&D. And our Three Fork wells are continuing to outperform plan, and we expect about a 16% -- a 16% increase in the Three Forks EUR reserve bookings at year-end 2013.

In the Mancos/Gallup, we now have drilled and completed 9 wells, and our most recent well was drilled in a record 14.6 days, better than -- twice as fast as the company's first Gallup well. And our well performance continues to be very strong, and our early production rates continue to show that we're going to have EURs greater than 500 Mboes. Initial production rates remain very robust and have averaged about 728 Boes per day. And we estimate again that the potential reserve adds for WPX in what we own today, only what we own today, should be about 66 million barrels of oil equivalent, about 70% of that is oil.

We did stem our gas production decline, and we saw sequential gas growth in volumes. And despite ongoing infrastructures, our Marcellus volumes grew 40% compared to last year.

And we sold our Powder River deep rights, just the deep rights, for $40 million.

Turning to Slide 5. I want to remind investors and continue to remind we have a number of cost improvements that have occurred, and we have a very important cost improvement that will come across in 2014.

First, as you can see from the checkmarks, we have run rate savings -- annual run rate savings of about $45 million to $70 million, with the Willow Creek improved processing fee which kicked in at the beginning of this year; the Piceance gathering rate change, which also kicked in at the beginning of this year; and we now have a checkmark by the Van Hook gathering system of $2 to $4 per barrel savings, which now have kicked in, in the fourth quarter of 2013.

Next year, we will have a total run rate savings of about $125 million to $165 million, as that sale-for-resale agreement on the Rockies Express that we have expires in November of 2014.

We also continue to evaluate our buyout of unutilized transport. This is not included in the $125 million to $165 million numbers. But if we would be able to buy out some of this transport, it could save us between $25 million and $46 million of potential annual savings.

And we did proactively renegotiate our Laser contract in the Marcellus, saving WPX $10 million this year and about $3 million in 2014.

Next slide, Piceance highlights. We increased our drilling plan, and we currently are operating 7 rigs, as we mentioned to you. Importantly, we've arrested and flattened the decline of production there. And one of these rigs is drilling, obviously, for the Piceance, Niobrara, which I'll talk about next.

Our water management is an example of our continued efficiencies we have in the basin and we think is best in the basin and best in the country. We now have about 50,000 barrels of water that we can treat every day. We recycle 100% of our water. An example of what that means is we eliminated 90,000 water truck trips annually through our water management programs.

Our efficiencies also continue to decrease our well costs. Our average valley drilling time is now 8 days and 11.5 days in our -- what's our highland tier of Ryan Gulch. We've also become more efficient. We've converted 2 more rigs to natural gas power and 2 more will be completed by year-end. Obviously, that saves us substantial amount of money per day on the cost of gas versus diesel. We continue to test our fracturing completion equipment with dual fuel, and we plan to have a full crew on that in 2014. And we've said before that we typically drill our well pads are up to 22 wells per pad. We now have a 36-well pad to show the efficiency we have there. And as we begin to develop the Niobrara, we believe we'll have sufficient takeaway capacity in place to support our future plans.

Turning to next slide, our Niobrara delineation. This is very important for WPX. Our initial discovery well continues to be very strong. It's produced the 2 Bcf, as I mentioned, and it's currently producing about 3.5 million a day, so it continues to produce very strongly.

Our second well, very excited about that, with 11.8 million initial flow that came out at a flowing pressure of 5,700 psi. Our original expectations were that the second well might have less pressure due to offset results from other operators to the south of this well and also due to the geology in area being about 1,500 feet shallower. However, the reservoir pressure gradient stayed constant at 0.94 psi per foot with our first Niobrara discovery well, which was 3 miles north of this. The key point to remember is this our shallowest area of our Valley acreage, and everything else, as we delineate north to east, will be deeper, higher pressure and should result in higher EURs and higher reserves. If this is going to be our worst well in the area, we'll take it. We're very proud of this well and very happy with the results.

On the second well, we now choked it back essentially, and it's producing about 8 million a day at 5,400 psi. We're very pleased with this well.

Our third well was drilled in August. On the drilling side, it was very successful in a sense of we reduced our drilling time by 43% compared to the second well, a major improvement and an example of our efficiencies already kicking in. We won't complete this well until late in the first quarter of next year, and we'll announce the results probably later in May of 2014. It will be sidetracked due to the casing failure, which occurred before the completion operations commenced.

We want to remain aggressive and prudent in delineating our Niobrara and our Valley acreage. We initially planned to drill the eastern part of the field next year and the -- what's called East Rulison. However, we decided to spud a vertical well already, and we've already spud that well this week. This week, it will test 12 miles to the northeast of our initial discovery well. It will help delineate the Rulison Field -- what we call the Rulison Field and aid our engineers in delineating the formations.

We also will spud our fourth horizontal well 3 miles to the north of the discovery well later this week. This again will help delineate the Niobrara resource to the north of where the initial discovery is.

Early in 2014, we expect to drill a horizontal well 3 miles to the east of the discovery well, and we continue to delineate the field. Obviously, our goal is to aggressively and prudently delineate the remainder of the Niobrara. We have 180,000 acres, as you know, that is held by production. This discovery well and our second well will continue to, we hope, confirm the transformative nature this play has as we begin to realize the potential of 20 to 30 Tcf we believe we have in this area.

Next slide. Basically, to summarize, we have a very good plan in place. And obviously, to the extend we can be more aggressive, we'll try to be. Again, we're trying to be aggressive and prudent. Obviously, moving to the Rulison Field 12 miles east of the discovery well is an aggressive move to try to delineate the field earlier. So the focused plan is, first, we are proving up acreage with our vertical and horizontal drilling; second, we're looking for repeatability and improvement; third, we're determining the appropriate well spacing and density; and fourth, we have other horizons we need to be testing. We are currently producing from the middle Niobrara. We also have an upper Niobrara horizon to test and Mancos intervals. So we have a tremendous resource here, just what we know already in the middle Niobrara, and we have a lot more coming up.

So delineation continues to grow. This year, we've delineated about 20% of the Valley field, and we'll have about 50% delineated by the end of the year. Next year's program should have at least 80% of the Valley delineated. We also have on the seismic side 83% of Ryan Gulch is covered by 3D and 34% currently covered in the Valley with about 70% covered by next year.

Let's look now to Williston Basin. We continue to improve our efficiencies and F&D, as I mentioned. As promised last call, due to these efficiencies, we're on track to drill 7 more wells and complete 10 more wells this year than our original plan for a total of 46 spuds and 52 completions. This quarter, we produced about 14,000 barrels of oil per day and 15,000 barrels of oil on equivalent basis, which is a 46% growth in production, represents a second quarter in a row of double-digit production growth consecutively and year-over-year.

Our Three Forks wells are performing very well. Year-to-date, we've put 13 Three Forks wells' first sales. All these wells continue to perform above expectations, and we feel the EURs of these wells will be 16% higher than our year-end reserve report from 2012.

We've put 13 wells on first sales in the first quarter -- in the third quarter, I'm sorry, 5 Middle Bakken and 8 Three Forks, and they continue to perform -- all those continue to perform at or above our expectations. And again, with the drilling of 7 more wells and completing 10 more wells, we're on target to meet our year-end production rate of 16,000 barrels of oil per day or oil equivalent and 15,000 barrels of oil just on an oil basis, represents an increase this year of about 25% to 30%, and also this helps the additional wells to increase our growth rate in 2014 to 30% to 35%.

Williston Basin ranked F&D, next slide. We think it's very important to look at the Williston Basin in a variety of areas, and this data was compiled by public investor materials provided by each of the companies listed here. WPX is #3 in F&D well cost per average in EUR. We're behind only the regional field of Sanish and Parshall, which were -- where most of the drilling has already been done, and a smaller area to our west called the Southern Antelope area.

Two big takeaways from this slide. Not ever is the Williston Basin the same. EURs vary across the plate quite a bit, and it's not proper to just look at well cost that what each producer is getting for these costs. And also I want to remind you that when WPX discusses well cost, ours are soup to nuts. We include drilling, completion, pads, facilities, artificial lift and reservation costs. Also keep in mind, we use 65% ceramic in our proppant mix, which adds about $1 million to our completion costs.

Looking now on our technical expertise in the basin. We believe it continues to drive these leading results you just saw. As you can see from the graphic on this page, on the right-hand side, this is based on North Dakota Industrial Commission data, WPX is #1 in the entire Williston in 180 and 365 days on accumulated oil production for the Middle Bakken long laterals. And this -- the study has been put on since January of 2011. Keep in mind, we closed on our deal in December 2010 and took over operations in about April or May of 2011. Based on our -- on this -- on our peers' analysis and analysis from the North Dakota Industrial Commission website, we are beating our peers on 180 days by 47% in cumulative oil production and on 365 days by 60%, respectively.

Down-spacing also, so you look at this, it's not a matter of if but rather of when. We are now permitting 6 Middle Bakken wells and 3 -- 5 Three Fork wells per location. Previously, we're permitting 4 Middle Bakken and 3 Three Forks. This is based on our ongoing well density projects. Early results have led us to increase in our premium infill locations, so we know down-spacing will occur, and this is what we're permitting for. We're not saying this will happen on every location, but we do believe there will be additional value created by a number of additional infill locations.

Looking at completion design technology, we started using cement liners in May of 2012, and we identified and implemented the plug and perf completion methodology as the right and the superior completion methodology. We made these changes well before other operators are now talking about making the same change.

Also, we use our zipper frac completion. It's been very successful. We've now completed 3 sets of triple zipper frac successfully, and we'll continue to use these dual and triple zipper fracs.

Other proactive cost-saving measures we've done now as we build all our winter pads this last summer, and we drilled at prime, which allowed us to drill several of our most recent wells another 20 days.

So you can see from this slide, we produce some of the best results in the basin. We're leading our peers by 47% in 180-day cumulative production and by 60% in 365-day cumulative production. We are leaders in completion technology and leaders in F&D cost. And now with the down-spacing we expect to occur, we had many infill -- premium infill locations and add more value to our shareholders.

Turning now to the San Juan Basin discovery. Again, we're very pleased that last quarter we announced the successful results of our first expanded exploration oil play. Our first oil project was in this Gallup Sandstone formation. It's a tight sandstone that sits in the middle of the Mancos Shale section, southern margin of the San Juan Basin in New Mexico. Now we've drilled and completed 9 wells in this formation. We have 2 wells which we expect to complete next week, one well is currently being drilled. Our average drill time on the development days is 17 days, with a record drill time on our last well of 14.6 days. Our drilling times are more than twice as fast as the company's first well. This allows us to drill 15 wells this year. And the performance of these wells have continued to be very strong, as you can see, and on the next slide, we'll talk more about that. We do expect to meet our exit rate of 3,400 barrels of oil equivalent in our first year development play. And we expect again the 66 million barrels of oil resource potential.

We have 31,000 acres in the play, with an average NRI of 83%. We expect to increase that acreage this year. And currently, we continue to target drilling and completion costs below $5 million, and our EURs are going to be greater than 500 MBoes.

Next slide. The San Juan Mancos is performing superbly for us. It's currently producing the 2,300 barrels of oil equivalent a day. Average production rates again -- or average reserve results, we think, are going to be greater than 500 MBoes. And as you can see from the graph on this page, we're the premier operator in the basin and excited about the potential this play brings to our company.

Our sentiments about this basin are now being confirmed by our results, obviously, and with the recent results of some of our peers in the basin. Our wells and some of the offset wells are confirming our EUR and return expectations. Now the production data that is available on the New Mexico oil website, we have drilled 4 out of the top 8 wells to date. We accelerated the implementing the efficiency in the San Juan Basin that we talked about last quarter we're going to put in, in 2014. Instead, we're going to start using zipper fracs by the end of this year, and we also expect to move to more cost-efficient pad drilling techniques also this year. And we expect to more than double this year's 15-well program to 37 wells next year and achieve more than double our exit rate this year of up to 3,400 barrels of oil equivalent to next year exit rate of about 8,400 barrels of oil equivalent.

And with that, I'll turn it over to Rod to talk about financial results before I finish off.

Rodney J. Sailor

Thank you, Ralph. As Ralph mentioned, we had good operational update this morning, but our third -- but we are disappointed in our third quarter financial results. And as I go through the slides this morning, I will point out some of the issues that negatively impacted the quarter.

On a quarter-over-quarter comparison, equivalent production volumes were down approximately 7% in the third quarter 2013 compared to the same period a year ago. Volumes were up over the second quarter of this year. Oil revenues increased about $65 million on 46% higher domestic crude volumes and 19% higher prices. Natural gas revenues were 79% lower, 3Q 2013 versus the third quarter 2012. While we experienced higher realized prices in the third quarter of 2013, these were offset by 6% lower production volumes and the absence of $107 million in gains associated with derivatives, designated hedges in the third quarter of 2012.

Natural gas liquid revenues were $8 million lower third quarter 2013 versus third quarter 2012, primarily related to a 31% decrease in domestic sales volumes. A part of this decrease is related to lower ethane recovery rates in the Piceance, partially offset by higher realized prices per barrel for natural gas liquids reflecting a change in the composite barrel due to lower ethane recovery rates.

Adjusted EBITDAX was $174 million in the third quarter compared with $230 million in that same period in 2012.

Capital expenditures for the quarter were $295 million versus $337 million in the third quarter of 2012.

As mentioned in this morning's release, items negatively impacting our third quarter financial results included a $19 million impairment to our Kokopelli probable reserves, a $7 million litigation accrual and a $6 million impact related to changes in Argentine tax law, which affected our investment in Apco Oil and Gas. After adjusting for these items, we reported adjusted net loss of $83 million or $0.41 per share.

In the quarter, we also recorded $9 million related to an increase in our valuation allowance related to Pennsylvania deferred taxes. In the third quarter, we identified the need to increase the valuation allowance associated with our Pennsylvania net operating loss carryover. The increase is due to a unique aspect in Pennsylvania law that caps the amount of the net operating loss in any given year. In July of 2013, Pennsylvania increased the amount of that NOL -- of the NOL that could be utilized in a particular year, which required us to go back and increase the valuation allowance associated with the deferred taxes in Pennsylvania.

On the Argentine tax matter, in September 2013, the Argentine government enacted a tax reform related to dividends and capital gains. The tax reform imposed a 10% tax on dividends made to Argentine individuals and foreign shareholders. This tax will apply to Apco on dividends received from its investment in Petrolera and out of it at any branch remittances. The dividend tax will be accrued when the dividends are paid in future periods. The tax reform also removes the income tax provision related to providing -- provided to non-Argentine residents since 1971 on income derived from the sale of securities. The sale of such securities are now subjected to a 13.5% tax on gross proceeds. U.S. GAAP requires the recognition of these deferred taxes on the excess book basis over tax basis of equity investments, such as Apco's Petrolera investment. Therefore, Apco recorded deferred tax liability for these capital gains associated with its equity investment in Petrolera. That adjustment flows through our consolidated financials. It is partially offset on WPX's book by a $4 million U.S. deferred tax benefit attributable to foreign tax.

Turning to the next slide. In an effort to try to identify some of these issues impacting the third quarter, we compare this reconciliation to our second quarter adjusted numbers. Adjusted EPS for the third quarter -- starting from our adjusted EPS of $0.22 in the second quarter, EPS for the third quarter was negatively impacted by $0.13 due to lower natural gas price realizations. NYMEX pricing was approximately 50% lower in the third quarter versus the second quarter. Additionally, we saw basis widen approximately $0.10 in the third quarter versus the second quarter. This was primarily driven by the widening of the Dominion basis in the Northeast, where we saw an average of about $0.40 in the third quarter. Just to remind you that approximately 24% of our natural gas is exposed to the northeast pricing on both our Appalachia production in the Marcellus and our obligation to sell gas to a shipper on wrecks. That obligation, as Ralph has mentioned, expires in November of 2014, and this will reduce our Northeast exposure to approximately 10%.

Moving on, we had a slight positive impact from increasing gas volumes in the second quarter -- third quarter over second quarter. The impact from oil revenues was up $0.08. $0.06 of this was due to production increases. Both oil and natural gas have been adjusted for the impacted of economic hedges realized in the quarter. Partially offsetting the increase from crude were the higher operating and transportation expenses associated with the production of higher-margin crude volumes.

Moving on, you can see we had higher marketing expenses -- higher marketing and international expenses of approximately $0.05. This was large -- the marketing expenses were largely seasonal in nature, and we still anticipate ending the year flat on marketing, with the exception of approximately $46 million in stranded transport expense, which we have previously disclosed in guidance. Also, we continue to see lower revenues from our investment in Apco Argentina -- excuse me, Apco Oil and Gas. That accounted for about $0.03 of that $0.05 variance. We had other expenses of approximately $0.03, including approximately $0.01 related to operating expenses. Finally, we had the $0.03 associated with the previously discussed increasing our valuation allowance in Pennsylvania.

As Ralph mentioned in the release, we expect to be at the bottom end of our guidance range for volumes, largely due to infrastructure issues in the Marcellus. We anticipate that capital spending will be at the upper end of our range at $1.2 billion.

With that, I'll turn it back over to Ralph to wrap up.

Ralph A. Hill

Thanks, Rod. Financial results, as Rod mentioned, weren't what we wanted. Obviously, we'll continue to work on that, but we did have a good quarter operationally, continue to build our foundation for 2014 growth and beyond.

Looking at our path to greater shareholder value we talked about earlier this year, we are maintaining disciplined natural gas development, and we've actually stopped our gas production decline after adding the rigs in the Piceance. We're ideally situated to capitalize on a gas price improvement in the Piceance basically with our traditional drilling and now with the Niobrara opportunities that are coming for us. We do believe that Piceance, at the right time, can be the first and fastest to grow, facilities are set up, takeaway capacity is set up, and, obviously, we've done this for many, many years in the Piceance.

Secondly, growing oil production. We've grown our Williston oil production by 46%. I feel that the 2013 efficiencies continue to drive not only growth for this year but also in 2014. We're leaders in completion design technology. We're poised to grow with some of the strongest wealth in the basin. We're drilling faster in the Williston, and we added additional 7 wells and 11 completions above plan without adding or exceeding our capital guidance. Our efficiencies continue to kick in, and we're the F&D leader in the Williston, and we've found many ways to cut costs throughout that portfolio.

Thirdly, continued cost improvements. Obviously, we've seen the Laser contract help us this year in a sense of the $10 million savings. The Willow Creek improvement is there. The Piceance gathering rate is there. The Van Hook's facility is kicking in. And in November of 2014, about $80 million to $100 million of costs go away, which should improve our revenues as that REX contract goes away.

Fourth, on pursuing new opportunities, including the Niobrara discovery. Obviously, we continue to rapidly delineate the Niobrara discovery on a very prudent way. Today, our discovery well, as we know, has produced 2 Bcf of gas. It's producing 3.5 million cubic feet a day. Our traditional Mesaverde well in the Valley that we've drilled produces about 1.2 Bcf over its entire lifetime to 1.3 Bcf. So obviously, in 10 months, to get 2 Bcf is significant. The second well came on at 11.8 million a day at very high pressures. And again, this is probably -- this drilling what would probably be our shallowest area and still very overpressured, so we're very pleased with the delineations going on.

We look to continue to move forward in the San Juan Basin, and we've got the 9 wells on this year. We're going to drill our -- double our program next year. So we continue to do very well in the whole oil exploration side of the world.

As far as strategic direction, we're consistent with our goal of optimizing and focusing our portfolio. We continue to evaluate the portfolio with intention of optimizing it by having more focus over time. In the past, we've determined certain assets that will be worth more to others than us, we've thought, but we're not going to sell assets at prices we feel will be value destructive or not add value. So we'll continue to be very prudent in that.

As we're moving into late 2013 and early '14, we continue to evaluate -- and we've talked about this with you before -- the viability of alternative financial structures, including the possibility of an MLP, joint ventures and joint ventures for some of our assets. And we're currently deep into the 2014 planning process, and we expect to issue guidance no later than early 2014.

With that, that wraps up our prepared remarks. We thank you for your time, and we look forward to taking your questions.

David Sullivan

Great. I open it up for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Brian Velie.

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

Just a couple quick questions. Ralph, you just started to touch on a little bit there in your closing remarks, but I wondered, in terms of maybe some bigger picture structural items, the talk recently around the possibility for MLP creation, is there anything maybe more definitive that's come about lately? Or is there any kind of a timeline for expectations you can give me -- give us around what you might do and whether it will be those older Piceance volumes?

Ralph A. Hill

Can't really comment on the timeline, but I can tell you that we continue to evaluate that opportunity, that MLP opportunity. And we do believe, as we've mentioned before, that our assets are uniquely situated for a potential MLP, particularly in the Piceance, the mature assets we have in the Piceance, and to a lesser extent, the San Juan Basin. In the Piceance, we've drilled 4,000 wells. We have another, ultimately, 10,000 wells to drill, and that's without the Niobrara opportunity. So we know what we're doing there. We have a lot of wells that are on the very mature decline stage of their life, so we feel we have a unique set of assets that we would be able to put into an MLP. And if we did that, we think it will fund our growth opportunities going forward and accelerate some capital into areas like the Niobrara, which we think can be very value-enhancing for us. So that's where we are. We continue to look at it, and we think we have a -- we are uniquely situated for that. And at this point, that's all I can comment on.

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

Okay. Is there maybe anything on the other side of that, that makes you hesitant or kind of weighs against all those positives that you mentioned that would make you shy away from maybe doing that?

Ralph A. Hill

Just -- no, not really. We're just -- we continue to evaluate it, and there's -- the MLP market has had -- E&P MLP markets had some ups and downs recently, but it looks like those problems have been fixed, and we just continue to -- ours would be unique in the sense of we would be able to fund ourself -- or drop down to ourselves for a number of years versus having to use this as an acquisition vehicle. We can actually use it to drop down our suite of assets over time and use that capital again drill areas like the Niobrara and the Gallup Sandstone type areas.

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

Okay. And then one more question, if I could. The -- some other recent comments that you guys have made and things that we've talked about around your desire to get to a point where you can grow within cash flow sometime in the future. With assets like the Marcellus, where, in a soft gas market, it's have to grow, and then even suffered to grow with the infrastructure concerns, is that -- when you think about monetizing potential assets, is that one that's, especially as of late, kind of comes to the top of the list?

Ralph A. Hill

Well, obviously, we would like to grow and -- within cash flow, and I think that MLP vehicle will actually help us do that going forward. Yes, the Marcellus, we're not disappointed at all with our well results. Our well cost or the efficiencies are the same. We're very disappointed in the infrastructure problems up there. We were pleased when Williams bought that system, the Laser system a year ago -- or so ago. They're working very hard to fix that. We've had some good conversations with them, but the bottom line is it's not fixed yet. So the best thing to say about the Marcellus right now is we've put limited investment in that asset, and we have the ability to hold the acreage we want to without putting a lot of money into it. So at this point, it's a wait-and-see on what happens with the infrastructure out there for us.

Operator

Our next question comes from the line of Mr. (sic) [Ms.] Peng.

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

This is Hsulin. So my question is regarding -- first of all, I want to get better understanding on the legacies sale agreement with the Appalachian pricing. Well, first of all, I would like to understand, is it -- can you just give us some more color on the pricing terms? Is it tied to a particular Appalachian hub? Or is it a fixed price?

Michael R. Fiser

Sure. This is Mike Fiser. That sales agreement was entered in 2006, and it's a -- it's not capacity that we own on REX pipeline, it is just the mechanism to arrive at the sales price. So the sales price is a Dominion-related Appalachia price. And then there is a deduction for the full pipeline and tariff fees associated with REX pipeline to get to the -- to get to a netback price in the Piceance. As we mentioned, that does roll off next year. And fortunately, we do not own the REX capacity ourselves, but it's a -- it is a deduction from the Dominion index price.

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

Okay. So that makes more sense, given that the impact this quarter was more pronounced. From previous quarters, it was mainly because we saw the decline in Dominion gas price hub. Is that fair?

Michael R. Fiser

That's correct.

Ralph A. Hill

Yes, very fair with that basis blowing up there. It's obviously gotten worse and -- for us, and that contract, as Mike said, was a 2006 contract. The actual 5-year contract didn't kick in till 2009, as it always takes several years for pipelines to be built. But it does expire automatically in November of 2014.

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

Right. Okay. Understood. And then second question is regarding the Bakken. In terms of -- just kind of wanted to get a better understanding on your -- well, maybe just your initial thoughts on your drilling plan in 2014 because, if I understand, the same rig count, it should lead to more wells, given that you're gaining efficiency. And what is your current well costs and target with the efficiency you're gaining, please?

Ralph A. Hill

I would say that the -- yes, if we kept the same rig count, that we would probably drill more. We -- and we've mentioned this, we have not given 2014 guidance yet, but we expect to probably be -- instead of 4 rigs, probably be at least at 5 rigs next year over there. Our well cost target will remain to get to the $10 million to $10.5 million range. Again, obviously, we use ceramic, and we also have a very high EUR area, as you see from the F&D side, and so that would be our target. Our current costs are in the probably $10.5 million to $11 million range, so we look to improve that. With the ability the team has done to drill some wells in less than 20 days and some of the other things, we might improve in that area. But we're also looking at, is there areas we should use a little more proppants and more stages or less stages. So it's a lot of completion design technology that we think and we feel we're leaders in. That could affect that cost one way or the other, but it's too early to tell you that. But we're -- obviously, we're very encouraged that the reserves that we bought and what we thought at the time we think are going to be substantially more than that, and particularly one which is the better performance we've had in our reserves than we thought, and now with the potential with all the down-spacing that will in the future.

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

Okay, great. And then so in terms of your -- based on your existing portfolio, I know you mentioned that Bakken and Gallup are the highest-returning assets in the portfolio. So I wanted to kind of understand, what is the -- what are some limiting factors for you to allocate as much capital as you can there versus the lower-returning areas?

Ralph A. Hill

Well, we're doing about 90% -- 85%, 90% of our capital will go to the Bakken, the San Juan and the Piceance, which we think, even in a depressed liquids market, we still get about a $0.55 uptick in our liquids -- $0.50 to $0.55 uptick in our liquids. And we believe it's smart to delineate our Niobrara field there. So about 85%, 90% of our capital goes to that area. The other capital is some exploration capital and land capital we have as we continue to advance some of the new plays we're in, and very minimal capital on our other basins. So we're very focused on those 3 areas. Did that answer your question, I'm sorry?

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

Yes, I mean, that does. So -- and then my last question, and I'll go back in the queue is regarding...

Ralph A. Hill

Let me say one more thing. On the San Juan, what we're doing is we have one rig running there right now. We're picking a second rig up in the end of the first quarter next year. Now we will do more if possible, but it's -- the San Juan needs to catch up, and they do very good there, but not our team, but we're just...

Rodney J. Sailor

Permitting.

Ralph A. Hill

Permitting side of the world, the pace of play at permitting, which we don't want to act as if it's a problem, but it's new, and we're going to be drilling more, and we have some competitors drilling more down there. So that's our best estimate of what we think we can do now based on the price at play at permitting. To the extent that accelerates, then you would see us do more in the San Juan, for example.

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

That makes sense. And then last question, and I'll go back in the queue is just regarding the San Juan Gallup. I know you have 31,000 acres currently. What are you seeing in terms of opportunities for acquiring more and the current market rate for the leases?

Ralph A. Hill

Well, we've been negotiating and looking for leases for quite a while down there, so I don't feel like there's been real inflation in the cost of leases down there. So I guess what I've told everybody publicly, we'd like to see our position double there, if we could, and that's within this year, early next year. And some of the deals we're looking at are outright leases and costs, and some are more like drill to earn, which we're very good at. And we've had a long-term relationship with many of the landowners down there for over 35 years, so we might also have some where we don't actually purchase the leases but we actually do drill to earn. So we're optimistic we can increase that portfolio down there.

Operator

[Operator Instructions] Our your next question comes from the line of Brian Gamble.

Brian D. Gamble - Simmons & Company International, Research Division

I wanted to touch on a couple things. One, the down-spacing in the Bakken, you mentioned 11 from a permitting standpoint, obviously, not testing that yet. Can you walk us through potential timeline for that? And as a part of that, are you going to be targeting multiple zones in the Three Forks when you go to that down-spacing or is there certain zones that you are looking to hit first and then go past that once the down-spacing to one zone is complete?

Bryan K. Guderian

Good morning. This is Bryan Guderian. Initially, we'll be focusing on the Middle Bakken. The science work that we've done around our increased density, really, we have, by far, the most data around our Middle Bakken development. You may recall that we really just got into significant Three Forks drilling at the beginning of this year, and so we're hoping to validate our early conclusions and findings around the Three Forks as we glean more production information in the coming months. So initially, it will be Middle Bakken. From a permitting standpoint and pad design, we are making those decisions now. So that's really our next step. One of the big issues at this point is sort of redesigning your well layout and your pad configurations. And as Ralph mentioned earlier, we're now setting up for 11 wells. What we see here early on in the area north of the lake, which we call Van Hook, those are some of the most prolific wells in the basin, we think we can add at least 1 Middle Bakken lateral to our current 3-well Middle Bakken plan. South of the Lake in the area that we call Mandaree, our conclusion suggests that we can add an additional 2 Middle Bakken wells there, which would take our existing plan for 4 up to 6. And more to come a little bit later in the year, early in 2014 on the Three Forks.

Ralph A. Hill

I would say, on the Three Forks, so we are feeling good about where we are. Half of our wells drilled this year are going to be Three Forks wells. And as I mentioned, the performance has been better and better, really, with every well that we're drilling there. So Brian is correct, the initial -- the most analysis we have is on the Middle Bakken, but we're feeling very good about where we're headed with the Three Forks also.

Brian D. Gamble - Simmons & Company International, Research Division

And, Bryan, when is Ralph going to let you start drilling those extra horizontals, both north and south of the lake, is that later this year or you're not starting to drill those until early next year?

Bryan K. Guderian

Probably be in early '14. We have our schedule pretty well mapped out between now and the end of this year. But as soon as we get this new design in place, we'll get some of those wells underway.

Brian D. Gamble - Simmons & Company International, Research Division

And then one more on the Bakken. Just kind of doing some math from your quarterly performance, including those transport numbers to your exit rate for the year, it doesn't look like there's a big deal of growth expected in Q4. Is that due to completion timings? Or is there something else that we should be thinking about there as to the movement during the quarter?

Bryan K. Guderian

It's really about timing. We had the sort of a surge of production come on at the end of Q3, and we're just kind of tiding that early time significant decline. But we've got a dedicated frac crew that'll continue working on our account through the balance of the year. So really, it's about timing and accounting for moving into winter operations.

Brian D. Gamble - Simmons & Company International, Research Division

Great. And then one more on the San Juan. I think you had some -- I know we've seen some offset operators down there give new expectations for spending, and I was, frankly, quite impressed. What, if anything, does that impact from your standpoint? Does that help to delineate? And therefore, as you mentioned the permitting, it might become easier as more people start to drill in that area? Or does the expectation of adding acres become more challenging because maybe some of the acres that you thought were available for sale are going to be developed by someone else now. How do -- how should we think about that?

Ralph A. Hill

Well, I think we'll get the acres that we've been working on for quite a while, so I think we still can get our position, hopefully, doubled where -- from where we are. And I think we had a specific target in mind of what we wanted to go after. And I think you see that the sand that we went after is the sand that's working. And I think some of our competitors did more of a blanket buy down there. And it's fair to say that, I think, that they are now targeting the same sand we are, with their more successful wells. So we feel that our concentrated effort and our technical team did a good job of putting us in the right area and get at the right spots. So I think the permitting side -- and so turning to the permitting side, we might -- it's not a problem right now, it's just that we're getting the permits in place and getting them done and getting them improved. That's just what we think our pace of play can be right now, but, obviously, we're not complaining about where it is. But if it gets better or, clearly, if we -- if they -- if we can turn it quicker, we would add more rigs. And I think the offset operators, the ones that have been successful, that does help validate the resource. And I also think that, again, we're starting to run into already the soup-to-nuts type well cost that we put out, which we know that we said our -- we're drilling slightly above $6 million now, and we target less than $5 million. Some have put out that they're drilling less than that, than we are, but as we've analyzed our numbers, they're not including facilities and other things that we include. So we always run into that, but you can always be assured that when WPX talks about its well costs, it's everything.

Operator

[Operator Instructions] Our your next question comes from the line of Brian Corales.

Brian M. Corales - Howard Weil Incorporated, Research Division

I have a couple questions on this Gallup play. I mean, one, is there more acreage to be had in -- or is this pretty locked up?

Ralph A. Hill

Well, the San Juan Basin, as you know, has been around forever, and there are a tremendous amount of operators in 50, 60, 70 years. So it's not like there's new acreage per se, but there's a lot of people that we know and that we've dealt with in the past that we feel we can work agreements out and acquire additional acreage, either through actually acquiring it or through, like I mentioned before, some drill-to-earn opportunities. So everything at the San Juan Basin from day 1 -- not from day 1, for many, many years is, if you will, held by production, but there's good opportunities there, and we've been operating for over 30 years, as I mentioned, and we feel we can expand our position.

Brian M. Corales - Howard Weil Incorporated, Research Division

I thought this acreage maybe was a little bit further south of the gas development. Is that accurate or not at all?

Ralph A. Hill

Yes, it is. It is definitely South.

Bryan K. Guderian

This is effectively the oil leg in the basin, and so it does lie geographically about 20 miles or so south of the primary dry gas development.

Ralph A. Hill

Yes, the map on our slide -- our San Juan map on there, the orange and the yellow at the top is our traditional gas area. And then down at the bottom is the green area, that's really where the oil window is, we feel.

Bryan K. Guderian

But, Brian, the situation with the acreage down here is that you've had operators developing various Gallup, Mesaverde, Mancos sands vertically for many, many years.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And is there a reason that, I guess, you're doing 5,000-foot laterals? Is that something you want to try to extend over time? Or is it possible to do that?

Bryan K. Guderian

Oh, I would say early on, that's sort of the model that we're most comfortable with from an operating standpoint. It is also driven by units and lease configuration. We will develop the ideal -- the well design based on present value rate of return as we go forward.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then can you maybe talk about how the wells look 6 months down the road or whatever you have the most production history on, as far as year 1, I guess.

Bryan K. Guderian

Well, we've only got a couple....

Ralph A. Hill

Yes, we had -- the good news about this is, well, and I said some, the impressive discovery is we had no production in January this year, so we're impressed with where we're headed. But, Bryan, I...

Bryan K. Guderian

Well, we just have a couple of wells with 6 months of production history at this point, so we're monitoring them very closely. But we've developed a type well curve that we've talked about, 500 MMboe, and 6 of our 8 wells are well north of that curve and outperforming it. We've got a couple slightly under. But on average, as Ralph indicated earlier, in this early time, we are beating that type well curve.

Operator

With no further questions in the queue, I would like to turn the call back over to Mr. Ralph Hill for closing remarks.

Ralph A. Hill

Thank you very much for your interest. Again, we feel we had a very good operational quarter. You can see we're setting the foundation up for a tremendous amount of growth in our existing areas that we're putting capital into and our new areas that we're developing in the Niobrara and the Gallup Sandstone. Obviously, we will work to improve our financial results. A lot of that was the price differential, as Rod mentioned. We will continue on that side, but the -- on the foundation for growth, the foundation for 2014 and beyond, we feel that the strength of this asset and the strength of the team we have working, we will be able to deliver greater shareholder value as we move forward. So we appreciate your questions today and your interest in the company, and we look forward to talking to you again soon.

Operator

Ladies and gentlemen, that ends our presentation. You may now disconnect. Have a great day.

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