WPX Energy's (WPX) CEO James Bender on Q1 2014 Results - Earnings Call Transcript

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WPX Energy (NYSE:WPX) Q1 2014 Earnings Call May 7, 2014 10:00 AM ET


David Sullivan -

James J. Bender - Former Chief Executive Officer, President and Inside Director

Bryan K. Guderian - Senior Vice President of Operations

J. Kevin Vann - Chief Financial Officer and Senior Vice President

Michael R. Fiser - Senior Vice President of Marketing


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

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

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.


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

I would now like to turn the call over to Mr. David Sullivan, Director of Investor Relations. Please proceed, sir. Thank you.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy First Quarter 2014 Operational Update. We appreciate your interest in WPX Energy. Jim Bender, our CEO; Bryan Guderian, our Senior Vice President of Operations; and Kevin Vann, our CFO, will review the prepared slide presentation this morning. Along with Jim, Bryan and Kevin; Mike Fiser, Senior VP of Marketing, will be available for questions after the presentation.

After the market closed yesterday, we announced our transaction with Legacy and our first quarter earnings results. Those releases and today's presentation are available on our website, wpxenergy.com. The 2014 first quarter Q will be filed later today, and that will be available on the website also.

Please review the cautionary language regarding 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, Jim, I'll turn it over to you.

James J. Bender

Thanks, David. As positive and exciting as our quarterly results were, we were also very pleased to be able to announce last week that Rick Muncrief will be joining WPX as President and CEO next Thursday and will then be replacing me in the board immediately following our Annual Shareholders Meeting on May 22.

What I'll do first here, and we're on Slide 4, is just hit some of the highlights. I know you can all read, but I -- this is an exciting quarter, and I'd like to just walk through those really quickly.

First of all, first bullet point, 58% growth in adjusted EBITDAX quarter-over-quarter, and that was as a result of both higher realized prices and growth in our oil production. We spud 68 wells in the Piceance in the first quarter. And of equal importance, I think, is that as a result of projected reductions in costs and some revised spacing, we believe that the Ryan Gulch area is now competitive with the Valley.

Third, despite a record cold winter, we were very proud to report that our Williston operations grew oil production 36% quarter-over-quarter. And Bryan Guderian will elaborate on our quarterly performance, as well as some of the results from recently drilled wells during his operations update shortly.

Development of San Juan Gallup continues to remain strong. Production grew to 1,700 barrels a day, and the team has transitioned to multi-well pad drilling ahead of schedule.

The first quarter was one of the best quarters WPX has had since spinning off in 2012. We exceeded our own production goals and are continuing to look at and find ways to improve our costs. And finally, yesterday afternoon, we announced a transaction with Legacy, which together with higher realized prices, will all but close our originally projected funding gap for 2014.

Moving to Slide 5. Slide 5 provides some details on our agreement with Legacy. At closing, we will sell to Legacy a graduating working interest in our existing Piceance Valley wells drilled prior to 2009. Importantly, more recently drilled well -- Valley wells, including wells targeting the Ryan Gulch, Kokopelli and Niobrara formations, are excluded from this transaction, leaving us with over 12,000 drillable locations in the Valley. Legacy's graduating working interest is detailed on the slide. This transaction does not affect the interest in undeveloped locations, and Legacy will be required to pay its share of operating expenses.

As additional consideration, Legacy will provide WPX an interest in a newly created class of incentive distribution rights, or IDR units, similar to those retained by the GP in many sponsored MLPs. In this case, our 10% ownership interest in the Legacy IDRs could grow to 30%, assuming further drop-downs. The impact of this transaction on production is outlined on the slide and is incorporated in our guidance that Kevin Vann will be discussing shortly.

Turning to Slide 6. Why do we like this transaction with Legacy? First, we feel that it's superior overall to creating our own MLP and also essentially solve the funding gap for our 2014 capital program.

Second, while both an MLP and an asset sale would be accretive to our shareholders at today's prices, we believe the asset sale to Legacy actually provides our shareholders with a greater uplift. In addition, we are monetizing a gas asset while maintaining control without undertaking administrative costs and growth pressures we would have with an MLP.

Third, the sales price reflects an attractive valuation of our company's most important and largest asset, our Piceance Basin position.

And finally, while there is no obligation for either WPX or Legacy to do future transactions, the IDRs create an incentive for us to do similar transactions in the future and also to potentially partner with Legacy on future third-party acquisitions. We believe the strategic relationship or strategic alliance we have formed with Legacy will be a win-win for both companies moving forward.

I would now turn it over to Bryan.

Bryan K. Guderian

Well, thanks, Jim, and good morning, everyone. Our confidence in our execution and operating results continues to grow, and I'm really pleased that we're continuing into 2014 the momentum that has been building over the past few quarters.

As Jim indicated, we remain solidly committed to our ongoing efforts to further improve our operating results to deliver consistent performance and reduce our cost structure as well. I expect to see more favorable progress in the coming quarters, beyond what I think are really strong first quarter achievements here.

So let's turn to the basin highlights, Slide 8, starting with our Piceance activity. In the Piceance, as Jim mentioned, we spud 68 wells in the first quarter, all of these were in our traditional Mesaverde development areas. Our budget for this year calls for an average of 9 rigs, and we're on track to drill the 285 wells as planned in our capital budget for 2014.

We brought in our eight rig in March, which is devoted to our Mesaverde activity. We have a ninth rig that has recently arrived and spud its first well just this past weekend. And of course, depending on spud counts and efficiencies that we achieve throughout the year, we think that this would get us to our 285 wells. Our plan, actually, calls for adding a 10th rig late in the year, as we segue into 2015.

Year-to-date, our spud count is on plan, even though we've had a little over a month of rig delays. It's evidence, again, of our ever-improving cycle times reflected in the graphics that you'd see here on the slide. This increased activity will drive a return to volume growth in Piceance over the second half of the year, which we're very excited to return to growing our production in this core asset.

As you can see, our efficiency gains continue to show up in well cost reductions. And coupling these improvements with a higher commodity price environment that we now enjoy certainly generates improved and very attractive returns, and this is our cornerstone asset.

We've added capacity to our infrastructure over the past year, particularly in the area of water management. This, along with higher water consumption due to our increasing activity, has really had a positive impact on our operating expense.

The ninth rig that I referred to will be dedicated for the balance of the year, the horizontal Niobrara delineation. And you may recall, on our last call, we informed you of our decision to procure a higher pressure-rated rig to continue horizontal delineation in the Niobrara. This was a function of the pressures that we encountered while drilling a horizontal in the middle Niobrara section, specifically.

And so we now have, in the basin, a newly built -- this is a Nabors X-PACE series rig. It is currently drilling about 4 miles east of the original Beast discovery. This will be a horizontal middle Niobrara well to help determine the geographic extent of the reservoir quality that we found in the Beast and, of course, also working to improve our drilling and completion practices in -- towards cost reduction as well.

And worth noting that while the new rig meets our design specs for our Niobrara delineation program, it also has a substructure that fits well for Mesaverde development, and so this gives us some versatility that we haven't had previously.

We're also getting ready to spud a vertical delineation well in the East Parachute, which would be another 3 miles or so further east of the previous well that I just mentioned. And in this well, we'll complete and test all prospective zones from bottom to top. So we'll start with the lower Niobrara and work our way up through the Niobrara section and then well into the main coast as well, again, to further delineate the geographic extent of the resource and help determine potential horizontal targets.

Let's turn to Slide 9. We averaged 15,600 -- obviously, now we're moving to the Bakken operation, and going to talk about the Williston here on this slide. And we averaged 15,600 barrels of oil and 17,700 barrels equivalent in the first quarter, exceeding the first quarter volume that is built into our guidance.

Our first quarter production represents 36% oil growth over year ago levels and 40% growth in total production. And certainly, this performance sets us up well to achieve our full year guidance. And as Jim mentioned, we did this in the face of adverse winter weather conditions. And while we performed very well in the hostile environment, I think results certainly could have been even better had we experienced normal weather. And this came, by the way, of -- we talked about this, I think, on the last call that winterization efforts that we undertook very aggressively last summer certainly paid dividends for us this past year.

On a current basis, we continue to run well ahead of our planned production rates. We brought in our fifth rig in March. This is another Nabors D-series efficiency rig, just like 3 that we already have in the fleet and that's performing well for us.

We are now designing all of our drilling and spacing units for development with 11 wells. Our actual well counts will vary based on optimal spacing in each of the areas that we develop. And our analysis in this regard will be ongoing. But at this point, I think our thinking is the same as we communicated in the previous quarter's call, which is a total of 7 laterals on the north side of the lake, where we have really outstanding reservoir quality. And there, we'll generally be a 4 -- I'm sorry, 4 Middle Bakken and 3 Three Forks wells or in some cases, that could be reversed, 3 Middle Bakken and 4 Three Forks wells.

And then on the south side of the lake, where we also have excellent reservoir characteristics but the rocks are a bit tighter, we're planning for 11 wells. And there, the composition will be generally 6 Middle Bakken and 5 Three Forks and again, in some cases, that could be reversed.

We just started completing on the tighter density patterns, and so we had limited production data thus far. And we won't have production from fully developed pads for some time to come later in 2014, but early results are quite good.

And we'd just draw your attention to the highlighted unit on the left side of the map there. At our Alfred Old Dog unit, we completed 3 wells on the tighter density pattern during first quarter, that had average 30-day IP rates of 1,356 barrels of oil, 2 of these were Middle Bakken and 1 at Three Forks, to go along with the previously drilled Three Forks well. And so these are on the tighter spacing, 880 feet apart within the same zone. And then the laterals are staggered and effectively 440 feet apart in the varying zones there.

Speaking of Three Forks, our performance remains very strong across the board. And as we've communicated previously, it's been a nice upside surprise for us. We put 4 wells on first sales in Q1, with 30-day average IP, so it's 1,234 barrels of oil. And we continue to gain operating efficiency from gaining experience with pad development in the Bakken. Cycle times continue to improve, particularly in drilling. And we've recently drilled a new best well for us at our Ruby pad in 19.4 days spud-to-rig release.

In addition to tighter spacing, we're also increasing the size of our stimulations by about 20%. This is based on pilot work that we've done over the last 9 months or so, and we also discussed this earlier in the year. And so we've got about 8 months of production history from both the Three Forks and Middle Bakken well. These are on the north side of the lake, and we feel it supports the change in our methodology at this point. It will add about $300,000 in completion costs, but gives us a nice boost to our return, our present value and also recoveries. So an excellent return on that incremental investment.

We're monitoring, of course, completion methods; a lot in the press lately, in particular, about slick water fracs. I can tell you that we're really happy with our results. And while we're reluctant to change significantly, if the results of these alternative methods prove out over time, we certainly will be open to that consideration. But for now, we're going to increase the size of our stimulation, but stay with our current method.

Let's go to Slide 11 and talk about the San Juan briefly, where the development of our Gallup Sandstone is in full swing. We're exceeding planned volumes year-to-date. Total production grew 29% quarter-over-quarter, taking into account our transition to pad drilling, which certainly had some inherent delays associated with it.

In Q1, we surpassed production of 0.5 million barrels in the first year of our operations, with only a single rig running for about 11 months. We deployed the second rig in February and completed our first multi-unit pad in March, both ahead of schedule. Production from our first 3-well pad completion averaged 420 barrels of oil per day and 620 barrels equivalent per day over 30 days. This is nicely ahead of our average for all of our 2013 wells, the 388 barrels oil per day and 475 equivalent barrels per day. Both of our rigs are now drilling on pads, and we continue to move up the learning curve quickly. We're capturing efficiencies that you would expect now that we transitioned to pad development.

In San Juan, we recently drilled a new best well for us, in just under 13 days spud-to-rig release. And we're confident that we're going to meet or exceed our drilling cost target for 2014, which is the $1.8 million. And just a reminder that our average cycle time last year was 20 days, so significant improvements there.

We've also made good progress on the completion side, with faster cycle times and lower costs. After averaging 5.7 hours per stage in our single-well operations, we averaged 4.3 hours per stage in our first zipper frac, which is about a 25% reduction, and we think we can move that lower as we manage our logistics better.

We still have work to do with facility. That's been our -- really, our biggest challenge has been timely construction of permanent facilities so that we can avoid the high cost of rental equipment and temporary flowback services, as we bring new wells online. And we're really getting out in front of this now and doing a better job with our longer-lead planning. We're permitting further in advance now that we're in the development phase of the play. And so we've reduced our start-to-finish construction time by about 50% to 6 to 7 weeks. And so we do feel like we'll have facilities there just in time. We're certainly very near the time that we bring new wells on from this point forward.

And in Gallup, we remain committed to our previously communicated $5.4 million total well cost and believe we can drive those costs lower over time. Importantly, we're now reaching 50,000 net acres in the play, with the addition of another 4,600 net acres in quarter 1. And we continue our efforts to add to the position and are confident that we will do so.

So we're well on our way to meeting our planned objectives, and with recent efficiency gains, could easily drill, I believe, more than the 29 wells that we modeled for our 2 rigs. And now that we've got our prerequisite activities, I think better planned permitting, infrastructure and so forth, I think we will be positioned to support a third rig later in the year if we choose to do so.

And now I'm going to transition to Kevin for the financial update.

J. Kevin Vann

Thanks, Bryan. I'd like to spend some time this morning briefly covering our first quarter 2014 results relative to those of the same period of 2013. Specifically, I will cover our production, adjusted EBITDAX, adjusted net income and capital expenditures. Then I will cover our second quarter and full year guidance on various metrics, including production, capital expenditures, price realizations and certain expenses. These items represent the same metrics that we began presenting during our last earnings call.

Overall, our production volumes were down when comparing the 2 quarters. However, our domestic natural gas production was nearly identical to the fourth quarter of 2013, and our domestic oil production climbed almost 40% versus the same period a year ago. On an equivalent basis, we are reporting 1.23 billion cubic feet of production per day compared to 1.268 cubic -- billion cubic feet during the same period of 2013.

Despite the decrease in quarter-over-quarter production, our adjusted EBITDAX increased from $203 million to $320 million during 2014. As Jim mentioned, the primary drivers of the improvement are: an increase in domestic realized natural gas prices of $4.40 this quarter compared to $2.90 in 2013; the increase in domestic oil production in Williston and the Gallup Sandstone in San Juan, together with improved margins in our gas management activities. This improvement in margins primarily reflect the benefit of an increase in the differentials associated with the utilization of contracted transportation capacity in the Northeast. We had planned for positive margins associated with this transport, however, our portfolio in this area allowed us to capture even higher values, given the market fundamentals that were presented during the winter.

Our adjusted net income for the first quarter was $44 million compared to a $51 million loss during the same period of 2013. Our adjusted net income excludes the impact of unrealized mark-to-market gains and losses included in net income, as well as the charge taken for a change in state tax legislation of $9 million.

Lastly, our capital expenditures were $352 million compared to $271 million quarter-over-quarter and consistent with our first quarter guidance.

Now I'd like to take -- now I would like to turn to our second quarter guidance slide and discuss briefly how our first quarter results compared to the guidance provided during our year-end earnings call, together with second quarter and full year guidance.

We exceeded our first quarter production guidance of 1.204 billion to 1.217 billion cubic feet per day, while our actual production, as I previously mentioned, was 1.23 billion. Despite the potential production setbacks in the Williston Basin, Bryan's team's efforts to prepare for such a bitterly cold winter were rewarded with very little production interruptions. As a result, our production was over 24,000 barrels, which is approximately 1,000 barrels over our first quarter guidance.

Also contributing to the favorable production volumes were strong performance in our natural gas business. Gas production was 975 million cubic feet per day compared to our goal of 952 million to 962 million per day.

On a full year basis, our guidance reflects the impact of our sales interest in properties in the Piceance Basin to Legacy, as previously discussed. As Jim mentioned, this transaction creates strategic value, as we direct the additional capital available to other areas, such as our continued oil drilling in the Williston, as well as the Gallup Sandstone in San Juan. It also reflects our commitment to executing on our 2014 goals relative to our strategy. Our natural gas drilling in 2014 continues to be focused in the Piceance Basin, given our scale and efficiency of our operations.

Our capital expenditures for the second quarter are projected to be between $355 million and $410 million, which is slightly higher than our first quarter expenditures of $352 million, but still consistent with our 2014 plan.

Our commodity price realizations for the first quarter were consistent with our guidance, with natural gas at the top end and oil slightly lower than the bottom of their respective ranges. We continue to actively manage these differentials through our physical sales agreements.

For expenses, our first quarter results were either better or within the range of guidance for the categories presented. Production taxes were at the higher end of first quarter guidance range, given the impact of the higher realized natural gas prices. For the full year, we have increased that range slightly, as forward prices for the balance of 2014 remain strong and doesn't increase the production tax to which we will be -- which will be paid.

The largest change to our full year guidance reflects the revisions that we have made to our margins related to our gas management activities. As I previously mentioned, our first quarter results were positively impacted by the higher margin surrounding utilization of transportation capacity in the Northeast. Our new full year projection reflects the increase -- this increase, together with the execution of additional arrangements on a portion of our Northeast transportation portfolio. These arrangements effectively capture $20 million of the increase in transportation value for the remainder of 2014.

We are continuing to proactively explore both long-term and short-term opportunities to lock in value from this capacity. Our previous full year guidance for gas management margins was a loss of $45 million to $55 million. We have revised that guidance to reflect the first quarter results embedded in the full year guidance, along with the additional $20 million for the balance of the year. That activity is now projected to be neutral to a negligible loss on a full year basis.

For the full year, we decreased our interest expense slightly, reflecting utilization of the cash received in our transaction announced yesterday to pay down the outstanding borrowings under our revolver.

In summary, our first quarter results reflect the quality of our growth basins, together with our ability to optimize that value in this pricing environment. I think 2014 is shaping up nicely to be a real turnaround year for the company financially, as we continue to strengthen our balance sheet and pursue opportunities to reinvest in our growth areas.

With that, I'd like to turn the call back to Jim for some closing remarks.

James J. Bender

Thanks, Kevin. To summarize, as a result of the hard work and continued dedication of our employees, for the first time since we have been a public company, we met or exceeded expectations for the quarter. This was very much a team effort. We know we must continue to meet or exceed expectations, both operationally and financially, and that one successful quarter is not enough, but it is a great start.

As we have previously indicated, assuming natural gas prices remain at the current strip, we expect 2014 adjusted EBITDAX to be in the $1.1 billion range. We executed a transaction with Legacy as an alternative to the MLP, which we have talked about for a long time, but there are many, many other opportunities for us to rationalize our portfolio that we know we must deliver on, and we will continue to pursue those opportunities.

One of those opportunities is the sale of our interest in Apco and unfortunately, I have nothing further to report at this time on Apco. While our overall business performed well during the quarter, we feel -- and we feel confident about the remainder of the year, as Kevin just indicated, we take nothing for granted. We must continue to deliver.

With Rick Muncrief joining the company next week, this is the last time you'll hear from me, so I wanted to finish by saying that it has been my honor to serve as the CEO of WPX for the past 4-plus months, and I thank you, all, for your continued interest in the company.

With that, I would like to turn it back over to the operator for any questions.

Question-and-Answer Session


[Operator Instructions] And the first question is from the line of Brian Gamble from Simmons & Company.

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

Jim, if this is the kind of performance we can expect, maybe you shouldn't be going anywhere. We appreciate all your hard work. A couple of things. I wanted to touch on the Bakken discussion. Bryan, would you walk through -- when you factor all of the spacing assumptions into account on the different areas, what are we looking like for total locations yet to be drilled?

Bryan K. Guderian

Brian, we are going through the tedious job right now of doing sort of a recasting, if you will, of our location count. Given the development activity and the orientation of some of the wells that were drilled early in the play, given the regulatory considerations that we have there, it's quite an undertaking. And so I think what we said on the last quarter call is that by mid-year, we would have a feel for incremental locations, as well as some preliminary information around reserves impact. So I can tell you that it's going to be significant, but we're reluctant to commit to absolute numbers until we get through the process, which I think will take us a couple of more months.

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

That's fair. And then one other on that side of things. From the Niobrara, the results of the well that you just spud just last week came with the higher pressure. And roll in the horizontal out, what are we expecting from a timing standpoint on that? Is that likely a Q2 earnings event or is that more likely kind of a Q3 ops update event?

Bryan K. Guderian

Yes. Well, I mean, we're certainly hoping to gain a lot of efficiency as we go forward and get these wells drilled more quickly. I think our feeling around both of the wells that we just spud, to be clear, we have both a horizontal as well as a vertical going on -- or we'll have a vertical spudding any day. And so we have 2 wells going at the same time. We possibly could have some early preliminary information by the next quarter call. But I would say, at that point, it would be pretty preliminary, so likely more of a next quarter event, where we would have some production history from these new wells.

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

And then one kind of follow-on, bigger-picture strategy on the asset sale, I think that's a great way to do that and keep things simple. When you think about future endeavors in that regard, you mentioned that your IDR doesn't obligate you to do anything, but obviously incentivizes you. I guess, how quickly or are there any other deals that you guys are already contemplating that could potentially be quick follow-on to this? I mean, it wasn't a ton of drop-down that you did, but it was on par with what you had originally kind of surmised would be your goal. Just how do we think about that going forward? And could there be something else this year or is this kind of a one-off for '14 and reevaluate next year?

James J. Bender

This is Jim. I mean, there is nothing else contemplated other than the fact that we've got the structure set up and we've got a mutual sort of incentive. Obviously, with Rick coming in next week, that'll be something that he will look at as a part of his overall review of the company strategy. So I think even if I had some thoughts on it, they would probably not be that meaningful. So it's something that Rick and the management team will look at going forward.


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

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

Quick question. I was hoping maybe you could expand a little bit your comments on what types of options you're exploring for both short-term and long-term monetization possibilities on that gas capacity in the Northeast.

Michael R. Fiser

Sure, Brian. This is Mike Fiser. We're looking at a variety of ways to capture that value, locking that cash flow. Currently, we have financial derivatives in place to hedge that position and to reduce our risk and lock in margins above our transportation cost. We also have some physical transactions that do the same thing. So all I can tell you is we know there's great value in these positions, and we're hoping and currently negotiating many different options to monetize that.

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

Okay. And then one other, and it might be a little bit too soon to tell, but the new completion methods in the Bakken increasing cost by $300,000 per well, do you have an associated recovery expectation to go with those costs?

Bryan K. Guderian

We do. Based on the pilot work that we've done, we think the incremental recoveries will be in the range of 10%, 8% to 10%.


[Operator Instructions] Another question from the line of Jeoffrey Lambujon from Tudor, Pickering, Holt & Co.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

You mentioned being excited to return to growth in the Piceance this year. You talked about your rig count adds in Q1. Can you elaborate a little bit more on your plans for growth there?

Bryan K. Guderian

Well, of course, we've been ramping up our activity there over the last couple of years. We hit a low, I think, of 5 rigs back in 2012 and have been sort of climbing up since then. Averaged 7 rigs this past year, 2013, and the plan calls for 9 this year. As we look forward, we certainly have the opportunity, given the right return environment, obviously driven by improving gas prices, but we have the opportunity to accelerate our activity there just by way of the infrastructure that we have, the franchise that we have in place. And so we'll address that, as we move through our planning process. Looking at the numbers, our expectation would be that we finish 2014 with 6% exit growth over 2013, and that will set us up well to grow even more in 2015, if we stay at the same rig count or decide to add to it.

While we have the white space here, I might just mention that typically, when we add rigs, you really get more impact from that capital investment in the second year of production than you do in the first year. So we certainly would expect our volumes to continue growing into 2015, even with the same rig count.


Our next question is from the line of Jeffrey Campbell from Tuohy Brothers Investment Research.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

I wanted to first ask you about the Gallup. You've mentioned the drilling time have dropped to 12.9 days. Could you tell me what's the current average time to complete a well in total to put it to sales?

Bryan K. Guderian

Well, let me think about that a little bit. We've actually -- we have transitioned to zipper fracs, and so we're now completing 2 to 3 wells sequentially. This all occurred at the end of last year. And so we only have one such job under our belt currently. But I believe that we got that done in about 4 days. So we did 2 wells in 4 days, I believe.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. And you also are talking about zipper fracs. It's obviously really early, but actually something to think about. In a number of other plays, Eagle Ford, Bakken, Niobrara, oil in Niobrara, operators are pretty resolute in saying that the zipper fracs not only save them cost, but they also enhance their production. I mean, did you see any enhanced production effect on the one zipper frac that you've done so far? Or do you really just think of this as a cost-saving mechanism?

Bryan K. Guderian

Well, actually, I would say we concur that we should get some additional benefit from all that energy going into the ground at the same time or certainly in a sequential way. And so the results that we communicated for the first pad completion in March were considerably better than what our average results were for 2013. And specifically, we averaged 420 barrels of oil per day versus 388 barrels of oil per day, with mostly single well completions back in 2013. Whether we can attribute that to sequential fracs or not, I think it's too early to tell. But we would concur that we would expect some performance improvement, in addition to the cost savings and efficiencies.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay, well, that's helpful. With regard to the Ryan Gulch, you mentioned that EURs have increased greater than 2 Bcfe. What was the former EUR prior to the revision? And is this more a matter of high-grading or is it better completions or everything? What's behind the revision?

Bryan K. Guderian

Yes. Well, I'd say it's a refinement really of our completion practices over time. We've been at it, up at Ryan now, for, gosh, 6 or 7 years, I believe that at one time, had a couple of rigs running up there. And so it's an evolution of technology and modifying our completion methods there. And so as the slide reflected, and I didn't really speak directly to this slide, but if you reference Slide 9, you'll note that we've seen really substantial improvement in our cycle times for drilling, as well as drilling and completion costs. And so we've seen those EURs move over time from, I think, about 1.8 Bcf, if you go back 3 to 4 years, up to the current estimate that we've talked about. And at the same time, obviously, drilling costs have come down dramatically. And up at Ryan, we've been building infrastructure over the last 2 or 3 years, and so we're enjoying now the benefits of that infrastructure, certainly, as a positive cost impact on our operating expense. And so -- and then, again, the better commodity environment that we have today. We as well averaged about 59 barrels per million of NGLs at Ryan, which is considerably more than what we had down in the Valley. And so you add all that together and we certainly feel that our current economics, the current gas prices, with the cost and EURs that we're articulating here, make this very competitive with the Valley operations. And we've got some 35,000 net acres in Ryan proper, and then we have other nearby acreage at other projects. So this could add some 4,000 or more locations. And as you see us moving into '15 and '16, assuming we still like the economics that we foresee and in particular, that we still have a good gas price environment, I think you'll see our rig count increase up at Ryan, and this would be sort of a transition to many more years of development, as the Valley matures. So it's a great segue for us, a little bit deeper, higher well cost, but we enjoy higher EURs and higher NGL yields.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

And just to quickly follow up on a point you just made, you referred to locations on that same slide that discusses the 10-acre successful density testing and then gives some 3P locations as a result. Has Ryan Gulch been fully characterized with regard to 10-acre spacing or is there still acreage left?

Bryan K. Guderian

From the pilot work that we've done, we certainly feel that 10 acres is going to work in a large part of Ryan and potentially throughout Ryan. We simply don't have it well delineated yet on 10 acres. But the early results from the pilots overall in the East side, where we have our -- we've been approved for year-round operations there, they look very encouraging. So we do feel pretty solid on the 10-acre for at least the majority of the project area.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

But based on what you just said, that 4,317 undrilled 3P locations could actually increase over time.

Bryan K. Guderian

Well, I think as it relates to the 35,000 acres that we have in Ryan proper, that would be the total count on 10-acre spacing. We do have other acreage nearby that is not reflected in these numbers.


[Operator Instructions] Your next question comes from the line of Jeoffrey Lambujon from TPH.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I just had another one, real quick on the Mancos position. You mentioned 2 -- the second rig deployed in February, movement to pad drilling and adding acreage. Can you talk about your acceleration potential across that asset? Apologies if I missed this.

Bryan K. Guderian

Yes. Well, really, all I said was that we're getting out in front on permitting and infrastructure. And the progress that we've made, I would say, over the last 6 months allows us to be really highly confident that we're good with our 2-rig program for the balance of 2014. And assuming things continue to progress the way that they have recently, I think we'll be in a position to accelerate to a third rig, either in late '14 or early '15, if we choose to do so.

Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And is there any update to your long-term plan with Marcellus?

Bryan K. Guderian

Well, probably not, but I'll reiterate it. We have been waiting for infrastructure resolution in Susquehanna County, in particular. And I think we have to say it's there now through work done by our service provider, expansion in particular at the Dunbar station and the Millennium has been completed. And so we see pretty stable operating conditions, have over the last 30, 45 days in the field. And so we are now slowing all of our production and have gotten wells back online. We've communicated previously, we just weren't going to spend any more capital there due to the volatility that we were experiencing in the gathering system. So our goal for the Northeast is to try a couple of larger fracs later in the year to see if we can improve performance there and then consider what capital activity we may want to undertake for 2015. And so we're going to stay the course on that. Then on Southwest PA, we've actually completed wells that had previously been drilled, and we really liked the results. There, again, we pumped significantly larger fracs, and early time results look really encouraging to us there. And so our volumes in the Marcellus are running right on plan for the year. And we're going to stay the course and reconsider our activity and what capital we might want to commit, as we move through the 2015 budget process in third quarter.


Our next question is from the line of Jeffrey Campbell from Tuohy Brothers Investment Research.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

I’d just want to ask a couple more. Appreciate the opportunity. Following up on what you just said about the Marcellus, I just want to make sure I'm clear. We're talking about the frac experimentation taking place in the Northeast. And could you single-out counties that you might consider Susquehanna? Or do you have any particular targets in mind at this point?

Bryan K. Guderian

Well, all of our acreage is in Susquehanna and the northwest corner of Susquehanna. And so we've got a couple of wells there that we drilled in the prior year that we're trying to get set up to try new completions on later this year and then, obviously, we want to monitor those results. We've communicated previously that we still believe that we are in decent territory here. We don't have the sort of position that Cabot has, as you move north and west away from their position. Pressure has declined pretty rapidly, and you've got some subsurface changes there that impact our position. Nonetheless, we feel if we can drill these wells for $6 million to $7 million and generate a 6 to 7 Bcf EUR, we still have an economic play. We've just had a lot of challenges associated with the infrastructure and got to a point where we didn't want to put more capital in until we were able to get our wells online and produce them in a stable operating environment. And so we have that now and really, it's a matter of monitoring our production results, trying these new completions and then, as I said earlier, considering how we might go forward through 2015 and beyond.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay, that was helpful. And I just wanted to ask another question about Legacy, and I appreciate the fact that we have regime change, so I'm not trying to ask that sort of question. What I'm interested in is, would it -- the Legacy vehicle that's been constructed, could that possibly accommodate a drop-down of midstream assets? Or is this always most likely to be a vehicle for monetizing production?

James J. Bender

This is Jim. I think it's more likely a vehicle to monetize production.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Okay. So if you were to ever try to do anything with midstream, it would have to be a different type of structure?

James J. Bender



Thank you. I would now like to turn the call over to CEO, Jim Bender, for closing remarks. Please proceed, sir. Thank you.

James J. Bender

Thank you. Thank you, all, for your questions. And just as a final comment, I think the management team here feels very, very good about our quarter, and that we can build on that and continue with the momentum that's been created. So thank you, all, once again for your interest in the company.


Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a very good day.

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