WPX Energy Management Discusses Q4 2013 Results - Earnings Call Transcript

| About: WPX Energy, (WPX)


Q4 2013 Earnings Call

February 27, 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

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


Good day, ladies and gentlemen. Welcome to the Fourth Quarter 2013 WPX Energy Earnings Conference Call. My name is Cecilia, 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 for today, Mr. David Sullivan, Manager of Investor Relations. Please proceed, sir.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy 2013 year end operational update. We appreciate your interest in WPX Energy. Jim Bender, our CEO; Bryan Guderian, our Senior Vice President of Operations; and Rod Sailor, our CFO, will review the prepared slide presentation this morning. Along with Jim, Bryan and Rod, other members of the senior management team: Neal Buck, Senior Vice President, A&D and Land; and Mike Fiser, Senior Vice President of Marketing, will be available for questions after the presentation.

After the market closed yesterday, we released our 2013 reserves, and this morning, we released our 2013 earnings results and today's presentation. Those releases and the presentation are available on our website, wpxenergy.com. The 2013 10-K will be filed later today and you'll be able to access that on our website as well.

Please review the cautionary language regarding the forward-looking statements on Slide 2 and the disclaimer on 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

Thank you, David, and welcome to our 2013 operations update. I'll touch briefly on a few 2013 highlights, speak to our year end reserves and then turn it over to Bryan Guderian.

As noted on Slide 4, we had excellent results in the Williston Basin in 2013 with oil production up 39% year-over-year. The early development of our oil discovery in the San Juan Gallup Sandstone is also very encouraging as is the initial delineation drilling of our Niobrara natural gas discovery in the Piceance.

Also in the Piceance, we were able to begin to arrest the gas production decline associated with reduced activity by adding 2 rigs for a total of 7 rigs running in 2013, one of which was dedicated to delineating our Niobrara discovery.

Regarding the Niobrara, we spud 2 wells in the fourth quarter, a vertical test in our East Rulison field and a horizontal well 3 miles north of the discovery well. As a result of high reservoir pressures encountered in the Niobrara, we are bringing in a high-pressure rated rig which should arrive in the second quarter. Bryan will provide additional details on our Niobrara activity.

Our operations in the Williston Basin continue to perform very well. In fact, as depicted on a later slide, over recent 1- and 2-year periods, WPX has been the #1 cumulative Middle Bakken long lateral producer in the basin. Also in the fourth quarter, we began our infield density drilling program and expect to be able to announce production results in our second quarter call.

Finally, our Van Hook gathering system, with current throughput of 7,500 barrels a day, is providing better netback pricing and improved gas sales. Importantly, in December alone, the Van Hook system reduced over 1,000 truckloads of oil.

Turning to the San Juan Basin. In 2013, we announced the successful discovery of an oil window in the San Juan Gallup Sandstone. This position lies just south of our legacy gas assets, and our asset team has quickly moved the project to the development phase.

WPX has drilled 5 of the 7 best wells in the basin with a 30-day average oil production of 388 barrels a day. Finally, we recently increased our acreage position to 44,000 net acres, which is a 42% increase over the third quarter.

Moving to Slide 5. The chart needs little explanation. Our domestic reserves grew 6% last year, replacing 162% of production with new reserves from our drilling program. The graphic on the slide shows the reserves reconciliation from year end 2012 when we had about 4.5 Tcfe of proved reserves.

During 2013, we produced 439 Bcfe and added 534 Bcfe of extensions and discoveries from our exploratory and development programs. We had no material acquisitions or divestitures of proved reserves; hence, all of our growth was organic. Finally, we had 177 Bcfe of upward revisions, which were predominantly related to higher gas prices in the Piceance and some improved well performance in our Williston Basin, offset by 30% lower ethane prices, leading to 23% downward NGL revisions on ethane rejection.

Before I turn it over to Bryan, I know many of you are interested in the status of the search for our permanent CEO. I'm not personally involved in the search, but I can tell you that the 5-person search committee of the board is actively engaged in the search, and it is progressing well. No specific deadline has been established by our Chairman, Bill Lowrie, but he reiterated to me that the primary objective of the committee is to hire the best person for the job. That is all the information I have at this time, and I'm not in any position to comment further.

So with that, I will turn it over to Bryan.

Bryan K. Guderian

Well, thanks, Jim, and good morning, everybody. I'm certainly pleased to share our progress executing in our operating activities. As we enter the new year, we certainly expect to continue gaining efficiencies. We're working aggressively to improve our operating results, deliver consistent performance and as well, exercising efforts to reduce our cost structure. And I want to share highlights of our 2013 activities in a little more detail and then also talk briefly about our plans for 2014.

So let's turn to Slide 7, looking at the Piceance Basin. And our team there continues with a lot of ingenuity represented by the first bullet that you read. You've heard us talk many times about drilling 18 to 22 wells per pad. Our folks continue to stretch the efficiency envelope now. We are drilling a 36-well pad as we speak, a new record for WPX.

In fourth quarter of '13, we drilled 45 wells and a total of 210 wells for the full year. We're currently operating 7 rigs as we did throughout '14. Jim referenced our increased -- I'm sorry, as we did throughout '13, Jim referenced our increase in the early part of '13 to stem our production decline. We have an additional rig contracted for arrival in March and yet another rig expected in May. That's the high-pressure rig that Jim referenced. The increase in activity to 9 rigs will grow our 2014 exit rate by 6% over the prior year.

And I do want to remind everyone that while many of our processing facilities are in ethane rejection currently, even in a lower recovery environment, WPX is still producing over 17,000 barrels of NGLs per day from the Piceance.

So let's look a little more specifically at our Niobrara activity. Jim mentioned the wells at our vertical test over in Rulison Field. We drilled to a total depth of just under 14,000 feet and encountered initial reservoir pressure of 13,800 psi. We ran pipe.

We are in the process of testing multiple horizons within the Niobrara and Mancos sections. We started with the lowermost member of the Niobrara and have now moved up to our primary target, the middle Niobrara that is productive in our discovery wells over in the West Valley area. Operations have gone according to our plan thus far, and we'll have information on this well in the second quarter -- I'm sorry, in the first quarter call.

Also in the fourth quarter, Jim mentioned the horizontal well that we drilled to the north, about 3 miles from the initial deep discovery. And we actually planned for this to be about a 6,000-foot lateral, and the well drilled out nicely. As we got into the horizontal section of the well, we encountered very high reservoir pressures again, exceeding 10,000 psi. We started to exceed the rig's operating capabilities with our pumping system. We had up to 18.5-, 19-pound mud. For safety reasons, we decided to stop drilling the well and run pipe. We have done so. We've got about 1,000 foot of lateral behind pipe. We initiated a 4-stage completion of that well and had early production rates of 6.5 million cubic feet a day.

The well continues to perform well, and we think it's an impressive result for a short lateral, and obviously, we can't wait to get back up there and drill a 5,000-foot lateral as we plan to do in the play to determine what the productivity of a full extended reach wellbore is capable of doing.

We'll continue our Niobrara program in 2014 with up to 10 wells planned. Our delineation will focus primarily in the West Valley area, where our producing wells are located, and then we also plan to drill a vertical test up in the highlands at our Ryan Gulch property, and I'll speak more to Ryan Gulch here in a minute. We had a sizable acreage position there, and so opportunity for lots of reserve additions in the future.

Our emphasis will be on repeatability, cost reduction and certainly, the mechanics of drilling these wells. These are challenging wells, but we are confident in our ability to get them down and work towards pretty significant cost reductions over time. And so the focus will be to transition this exploratory play to commercial development quickly and prudently, and the potential remains very exciting for us.

Turning to Slide 8. I want to speak a little bit more about our conventional Mesaverde development. Of course, we're continually driving for efficiencies in what has been our long-term gas development in the basin, and it's pretty amazing to me that we're still able to reduce our cycle times, well costs, things like the 36-well pad. These creative ideas continue to be played out by the team. And as we've shared many times, we have extensive infrastructure in place in the area that gives us a cost advantage over everybody else, coupled with the fact that we truly are in the sweet spot of the basin.

It really allows us, with our HBP acreage position, to allocate capital very prudently into the highest performing areas of the field. And we're constantly trying new things, albeit in a controlled environment to improve our well results and reduce costs. And the graphics here, certainly, are supportive of the success that we're having.

So I do want to speak about Ryan Gulch a little bit. This is probably some of the bigger news, I feel, in my operating update today. We've made really remarkable strides over the last 5 years. We've reduced well costs, improved EURs and our F&D costs now are not quite as good as the Valley, but we're certainly approaching a place where Ryan Gulch development is very nearly competitive with our results in the Valley. And you see from the graphics the progress that we've made.

We've also recently completed 10-acre density pilots in a number of areas up at Ryan. They appear to be the optimum spacing, and so we believe 10 acres is going to work in most, if not all, of the area. As I mentioned earlier, we've got 35,000 net acres and the 10-acre spacing, that yields some 4,300 3P locations. So opportunity for pretty massive growth up at Ryan.

And then finally and importantly, our overall cost structure in the Piceance allows us to generate higher returns than neighboring operators. As you can see from the some of the information that we have in the slide here, we have a significant competitive advantage that allows us to develop even in lower-priced environments.

Let's turn to Slide 9 and talk about the Williston and our Bakken and Three Forks activity. We've been discussing over the past year or so what we called a science project. A lot of deep analysis underway to help us confirm well density across our acreage position, through evaluating cores, logs and various pressure information along with actual well performance. We've come to some initial conclusions, and we've begun the process, as Jim mentioned, of setting up our pads for tighter well spacing and infill development.

North of the lake at our Van Hook area, we're adding one additional Middle Bakken lateral. So we'll be going from 3 to 4 total laterals in this area. You may recall that there were not a lot of Three Forks wells drilled on the reservation a couple of years ago when we first got started. We are still evaluating Three Forks data north of the lake. Everything is looking very favorable, but we're just not ready to make a conclusion on the increased density of the Three Forks on the north side of the lake. I would expect that to come, perhaps, in Q2.

South of the Lake in Mandaree though, we've had a little longer production history from Three Forks, and our Middle Bakken are also performing very well there. And so we're increasing Middle Bakken laterals from 4 to 6 and Three Forks laterals from 3 to 5. This makes the total lateral count at 11 versus our prior plan of 7.

And drilling on these new density patterns, I believe Jim mentioned, started in the fourth quarter, and so we're starting to complete wells. We'll be completing some of these wells late first quarter and should have some results in the second quarter.

Back in 2013, we spud 49 total wells with 4 rigs and very pleased that we made some great strides in our cycle times and costs as well. 15 wells were turned to first sales in the fourth quarter, and you see our production and the impressive growth rates that are listed here.

And I'm really pleased. I know that a number of operators have talked about the impact of winter weather to their production. Certainly, I think we probably could have done even better if the weather had been mild. However, due to winterization efforts that we've undertaken over the last couple of years and great focus by our field operations personnel, we kept our wells on stream and made our year, our quarter and our exit targets.

And then looking at this year, we're adding another rig. We've got a fifth rig coming in. We'll be there in the next couple of weeks, and we expect to drill 62 total wells in 2014, and that activity should generate 30% to 35% production growth for the year.

So let's go to Slide 10. And Jim mentioned this, I'll just hit a couple of things. We do look really good in this analysis versus the peer group. I think it's indicative of the quality of the reservoir that we have, the quality of our well construction and in particular, the effectiveness of our completion design.

You may recall that we were an early mover to cemented liners and more traditional plug-and-perf completion designs, and we took a lot of criticism for the cost, frankly, at that point in time. But this has proved to be a best practice in the basin, and our well results reflect the quality of how we're drilling and completing these wells.

And I mentioned efficiencies. We've had some 17 pads in 2013 that were either dual or triple fracs, and of course, that greatly cuts down on your cycle times, your mob and demob, and that, certainly, is reflected in our performance. We've been somewhat reluctant to change our completion design because of the strong performance of our wells. But as a part of our density project, we've done a lot of well reservoir characterization work, and it does suggest that we could pump about 20% more volume and achieve a more optimal completion. This adds cost, but it also has a big return associated with it. We have pumped 2 such jobs on the Van Hook Peninsula, 1 Middle Bakken and 1 Three Forks, and we're monitoring the results of those completions.

I do want to mention that we had a strong reserve booking at the end of the year. Our Middle Bakken well performance, both Middle Bakken and Three Forks well performance have really been outstanding. We increased our average Middle Bakken reserves by about 6% and also increased our average well reserves for Three Forks by some 17%. So what we see in our reservoir is continued strong performance and, at least, during 2013, performance that exceeded our expectations.

Turning to Slide 11 and looking at San Juan at our newest play, the Gallup Sandstone. We remain excited, as Jim indicated, about the results of this program. We achieved our projected oil exit rate. I will say that gas facilities have been a little slower to materialize than what we had planned. But we've had good recent progress, and we now have 11 of 13 producing wells connected for gas sales. And the initial footprint of the gathering system is in place but still needs to be expanded out to the well level, as you can appreciate.

Based on our well results to date, we have revised the composition of our production stream. We originally felt from our early data that we'd have a composition of 70% oil and 30% gas. Now that we have our measurement in place, we have gas plant statements giving us actual results. That composition looks more like 70% oil. We have not changed our oil numbers, our oil EURs, 15% gas and 15% NGLs.

And we do have a processing arrangement in place with 2 separate service providers to capture the value of those NGLs. So while our gas volume is down slightly and that reduces the overall volume slightly, we actually benefit economically from the value of the NGLs in the stream.

So we're very satisfied, as we've said a couple of times, with our early time results. And as Jim mentioned, we've already added a second rig. It spud its first well February 6. We'll drill 29 wells, at least 29 wells, I would say, in 2014, which will generate extraordinary production growth off of the low base. We've transitioned the pad drilling 4 months ahead of schedule, and so both of our rigs are now drilling on multi-well pads, and they'll continue that throughout the year.

We've reduced drilling time significantly, currently averaged about 16 days of drilling time and 20 days spud-to-spud. And of course, this transition allows us to get at the efficiency that we expect from pad development, zipper frac shared facilities and so forth.

I do want to share that at the beginning, as you've seen in your review of the Bakken over the years, as you move to pad developments, we'll be drilling 3 wells in succession and then completing 3 wells sequentially. And that activity can take 90 to 100 days or so. And so there will be some production lag in the beginning, and we would expect that in Q1, but it is planned and to be expected.

Current well costs are about $5.5 million, and we're confident -- we've only drilled 16 wells. I think we're confident we can drive them lower. And our completion activity at our first 3-well pad is underway this week, and we expect those wells to deliver in early March. And so we'll have results from those wells in the next call as well.

And with that, I'll turn it to Rod for the financial results.

Rodney J. Sailor

Thank you, Bryan. This morning, we released earnings for the fourth quarter and year end 2012. Fourth quarter results were impacted by approximately $1.4 billion in impairment charges, of which $1.1 billion was related to the Appalachia Basin. The impairment was a result of a decline in forward natural gas prices in the fourth quarter of 2013. Appalachia was further impacted by a widening basis in the Northeast.

Absent these impairment charges and some miscellaneous other onetime charges, our adjusted net loss from continuing operations in the fourth quarter was $66 million or $0.34 per share versus a loss of $0.20 per share in the fourth quarter 2012.

Full year adjusted net loss from operations in 2013 was $244 million or $1.22 per share versus a loss of $0.62 per share in 2012. A reconciliation of these numbers is included with our release. Equivalent of production volumes were down approximately 7% in the fourth quarter of 2013 compared to the same period a year ago. This decline was driven by lower natural gas volumes and lower NGL volumes, resulted from continued low recovery rates in ethane.

Domestic oil and condensate volumes were up approximately 39% in the fourth quarter 2013 versus fourth quarter 2012, driven by a 32% increase in Williston production and continued strong results, as Bryan mentioned, from our San Juan oil production.

Adjusted EBITDAX was $192 million for the fourth quarter compared to $256 million in the same period for 2012. And for the year, adjusted EBITDAX was $779 million versus $1 billion in 2012. Capital expenditures for the quarter were $311 million versus $356 million for the fourth quarter 2012, and for 2013, we spent $1.154 billion versus $1.5 billion in 2012.

Turning to the next slide. We released first quarter and full year 2014 guidance earlier this month. This is the first time we've released quarter guidance, and we will continue to release the upcoming quarter on subsequent calls.

In 2014, we will continue our focus of growing our oil production and developing our oil reserves, primarily those located in the Williston Basin and the San Juan Basin. More than half our planned for 2012 -- or excuse me, 2014 capital expenditures are in domestic oil properties, which included, as Bryan mentioned, 62 gross wells planned in Williston, an increase of 25% versus 2013; and 29 gross oil wells planned in the San Juan Gallup Sandstone, which is nearly a doubling of our 2013 activity.

We'll also continue to focus our natural gas drilling effort in the Piceance Basin because of our scale and efficiency of that operation, combined with the significant infrastructure already in place. I will also point out, we continue to see an approximate $0.60 uplift from NGLs. We will -- we are moving to increase our natural gas volumes over current production in the Piceance Basin by developing with an average of 9 rigs in that basin for 2014, of which approximately one rig will be focused on the Niobrara Shale. Our capital program in the Appalachia Basin will be limited to completions in 2014.

I will point out that in February of this year, we are seeing lower ethane recovery rates, and it's too early to tell whether that would impact the first quarter volumes. It shouldn't have a negative impact on earnings as it indicates there is higher value leading the ethane in the gas stream.

Finally, our next slide shows our current hedge position, pretty self-explanatory. We do not anticipate adding any additional hedges for 2014, but we continue to look for opportunities to hedge our products in 2015.

With that, I will turn it back over to Jim to close.

James J. Bender

Thanks, Rod. Slide 16 discusses our outlook for 2014. I'm not going to read through the bullets. I think you've all had a chance to look at it. I just want to make one statement. Yes.

I believe our 2014 plan is challenging, but it is also very achievable. And every single member of this management team, and frankly, every single employee at WPX understands that we must deliver on our promises. We must deliver on this 2014 plan.

In addition to the operational aspects of the plan, we are continuing to move forward on the sale of our interest in Apco and on the formation and initial public offering of an MLP. We remain optimistic about an Apco sale, but I have nothing further to report at this time.

Finally, we have undertaken a detailed study of our costs, and we will take whatever actions are necessary to better align our costs with our operations.

In closing, I just want to make the point that our 2014 plan is setting us up for a stronger financial performance year-over-year. If you assume prices as of the forward strip at February 21, we would expect EBITDAX growth of 35% to 40% to approximately $1.1 billion in 2014.

And with that, I would open it up for questions. David?

David Sullivan

Yes, yes. We're ready it up to open it for -- open up the queue.

Question-and-Answer Session


[Operator Instructions] The first question comes from Jeffrey Lamborn [ph], TPH.

Unknown Analyst

First question on the Bakken. You laid out in your presentation the 4 rigs running in the northern part of your position. I was wondering if you can break down how much of your acreage is around that area versus how much is in the southeast part of your position where you show that one rig will be?

Bryan K. Guderian

Yes. This is Bryan. I don't know the -- first of all, I want to clarify. Our program in 2013 was heavily oriented towards development on the Van Hook Peninsula, which is the area north of the lake and would reflect activity on our northern tier acreage, if you will. Our 2014 development plan will be focused predominantly in what we call the Mandaree area, which is our acreage south of the lake. Roughly about 25% of our acreage lies on the peninsula north of the lake, and 75% of our acreage would lie south in the Mandaree area.

Unknown Analyst

Great. And I guess, could you provide any commentary on what you're seeing in terms of performance between the 2? What you're expecting or maybe what your thoughts on type curves are between the 2 areas?

Bryan K. Guderian

Sure. Reserves do vary across the play. Our Middle Bakken reserves range from probably a low end of around 700,000 MBoe up to over 1 million MBoe. The Three Forks reserves tend to be, I think, a little more consistent across the play. And so the assumptions that we're using, I think, we're slightly over 800 MBoe on average for the 2014 Middle Bakken wells that we will drill and about 600 and -- I think it's 630 or 640 MBoe for the average Three Forks well that we'll drill in 2014.

Unknown Analyst

Great. And next on the San Juan. Just trying to get a better idea of well performance there and what sorts of EURs you're expecting in that asset with the lower GORs?

Bryan K. Guderian

Right. I'd say we're still in the range that we've been talking about now for the last couple of quarters. What we're seeing is MBoe in the 450 to nearly 500 range. Those are, I think, type curves that we've provided or, at least, provided information around in the past. We bought into the project based on -- I believe, it was a 350 MBoe type curve, which had very nice economics associated with it. And so you can imagine the sort of results that we're seeing here early time. The returns are very, very attractive.

Unknown Analyst

Okay. And then last question from me. On the Marcellus, can you talk about your long-term plans for that asset?

Bryan K. Guderian

Well, I can tell you on a short-term basis, we certainly understand the need to get to a point of stability in our production operations up in Susquehanna County. And we've talked many times about infrastructure performance, and I think we're pretty much there now. There is still expansion and maintenance issues ongoing with -- related to our service provider there, but we're in a position now where we feel like -- as those are completed in the coming 30, 60 days, we're in a position to flow all of the existing production that we have there now. And so we have been limiting capital in the area due to the volatility of the midstream operations. We now have a plan to go back in and do a fair number of workovers. We need to get our wells back online, get the field pressures sorted out. And we're also going to try a couple of -- we're going to try a new completion design here early in the year. And so on a near-term basis, we basically need to get our production flowing optimally and get to a point of stability with the infrastructure. I think the results of that activity and what we see in well performance throughout 2014 will really drive what our investment would look like in 2015 and beyond. Certainly, the gas price rebound would give a much more positive outlook on Niobrara. There are some issues going on within the basin in terms of pricing netbacks related to basis differentials and so forth. We actually have our volume protected with firm transport on Millennium and so we can get out. So I think as we go forward, it is the stability of the Susquehanna infrastructure and the performance of our wells that will really drive our investment decisions.


[Operator Instructions] With no other questions in queue at this time, we'd like to turn the call back over to Mr. Jim Bender, CEO, for closing remarks.

James J. Bender

I don't have anything further to add. Thank you so much for your interest in WPX, and we look forward to speaking to you again and announcing the results of our operations going forward. Thank you.


Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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