WPX Energy, Inc. Third Quarter 2015 Earnings Conference ... · reporting of the substance of the conference call. This transcript is being made available for information purposes

WPX Energy, Inc.

Third Quarter 2015 Earnings Conference Call

November 5, 2015

1 ViaVid has made considerable efforts to provide an accurate transcription, there may be material errors, omissions, or inaccuracies in the reporting of the substance of the conference call. This transcript is being made available for information purposes only. 1-888-562-0262 1-604-929-1352 www.viavid.com

WPX Energy, Inc. – Third Quarter 2015 Earnings Conference Call, November 5, 2015

C O R P O R A T E P A R T I C I P A N T S

Rick Muncrief, President and Chief Executive Officer

Clay Gaspar, Senior Vice President of Operations and Resource Development

Kevin Vann, Chief Financial Officer

Michael Fiser, Senior Vice President of Marketing Bryan Guderian, Senior Vice President of Business Development

David Sullivan, Director, Investor Relations C O N F E R E N C E C A L L P A R T I C I P A N T S

Brian Corales, Howard Weil

David Heikkinen, Heikkinen Energy Advisors

Brian Gamble, Simmons & Co.

Matt Portillo, Tudor Pickering Holt

Jeanine Wai, Citi

Biju Perincheril, Susquehanna Financial Group

Gail Nicholson, KLR Group

P R E S E N T A T I O N

Operator:

Ladies and gentlemen, welcome to the WPX Energy Third Quarter Webcast. This call is being recorded.

All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there

will be a question and answer session. If you would like to ask a question at this time, simply press star,

then the number one on your telephone keypad. If you would like to withdraw your question, please

press the pound key. Thank you.

I will now turn the call over to Mr. David Sullivan, Director of Investor Relations. Please go ahead.

David Sullivan:



Thank you. Good morning, everybody. Welcome to WPX Energy’s Third Quarter 2015 Earnings Call.

We appreciate your interest in WPX Energy. Rick Muncrief, our CEO; Clay Gaspar, our Chief Operating

Officer; and Kevin Vann, our Chief Financial Officer, will review the prepared slide presentation this

morning. Along with Rick, Clay and Kevin are members of the senior management team. Bryan

Guderian, Senior VP of Business Development, and Mike Fiser, Senior Vice President of Marketing, will

be available for questions after the presentation.

On our website, wpxenergy.com, you can find today’s presentation and the press release that was issued

after the market yesterday. Also, the 10-Q will be filed later today. Please review the forward-looking

statements and disclaimer on oil and gas reserves at the end of the presentation. They are important and

integral to our remarks, so please review them.

So, with that, Rick, I’ll turn it over to you.

Rick Muncrief:

Thank you, David, and good morning to everyone on the call. We appreciate you joining us today as we

report our third quarter results and update you on the significant progress we’ve made.

Simply put, the third quarter of 2015 was one for the record books. We announced, capitalized and

closed a transformative acquisition in just over 30 days. We now have roughly 92,000 net acres in the

Permian Basin. We also set a new mark for oil production, surpassing 35,000 barrels of oil per day for

the first time. Additionally, we have raised our production guidance and lowered our cash operating

expenses in every quarter this year.

Let’s turn to Page 2.

As we’ve mentioned before, we are a company in transition. Regardless of what business you’re in or the

type of economic climate you’re in, that will always be a challenge. I’m very proud of the culture we have

developed here. What I see daily is the confidence to be decisive and disciplined. I also see creativity,

boldness and a hunger to be the very best at what we do. Along those lines, I want to sincerely thank our

talented employees for their determination to create value, as well as our service providers who are in the

trenches with us 24/7 as we manage through this cycle. Volatile markets aren’t new. Our Management

Team will adjust as necessary if the lower-for-longer scenario plays out or if supplies tighten, driving

crude oil prices sharply higher. We will continue to make decisions based on returns on profitability, and

to look for accretive opportunities, not dilutive ones.

Turning to Slide 3, you can see by the impressive list of transactions that we’re moving decisively to

transform our portfolio of assets. Thus far, we’ve already done over $4 billion of transactions in the past

18 months. Along those lines, we are currently running two separate processes to help us reduce debt

that we added through our tremendous Permian Basin acquisition. The first process is the marketing of

our midstream system that’s associated with our San Juan Gallup development. The second process is

designed to accelerate value creation from our Piceance Basin asset. Both of these processes are

proceeding quite nicely. The management presentations have concluded, and we could be in a position to

communicate news about one, or possibly both, by year end. I think it’s also important to note that we

have numerous other monetization options that could be acted upon for further debt reductions, if, and

only if, necessary. After we see the results of these processes and work closely with our Board of

Directors, we will issue our 2016 guidance. I firmly believe that continuing to move quickly and decisively

is the right thing to do for our shareholders. Our bias for action has paid over the past 18 months, as we

exited numerous positions before the commodity price pull-back on both oil and natural gas.

http://www.wpxenergy.com/



As we turn to Slide 4, we feel that we have now built a tremendous foundation. When I look at both the

quality and the quantity of our future development locations, I can’t help but be excited. You’ll hear from

Clay in a few minutes about what we’ve done recently in our legacy assets, and I’m looking forward to

reporting on our operational improvements and strong results in the Permian Basin in the upcoming

quarters and years to come.

Along with our outstanding top-tier asset base, we have the flexibility and focus to maximize our margins

through cost controls, resource assessment, asset rationalization and hedging. This will ultimately lead to

impressive value creation for our shareholders. We own our future and the path we’re taking, and, in my

mind, we have everything we need to achieve and exceed our 2020 vision that we laid out over a year

ago. There’s still plenty of work to do and other hard decisions to make, but we’re well on our way.

At this time, I want to turn the call over to Kevin Vann, our CFO.

Kevin Vann:

Thank you, Rick. The positive momentum at WPX can also be seen in our financial results; specifically,

in the results of our assets and the cash flows that we are generating from them. This is driven by strong

oil volumes, our favorable hedge positions, reduced operating expenses and the benefit of starting to

integrate the Permian Basin operations. Lower commodity prices, understandably, are impacting our

financial statements, just like the rest of the industry. This is painfully clear in our product revenues,

which were down $159 million in the quarter, compared with last year. Even so, our Adjusted EBITDAX

was up 21% for this quarter. For the year so far, Adjusted EBITDAX is tracking just about the same as

last year, when prices were much, much stronger. It begs the question “how?”. There’s an easy answer.

It’s everything Rick just talked about. We are managing the Company vastly different today, fixing our

costs, making the hard decisions, finding better ways to do things, improving our collaboration and

focusing our capital efforts on the projects that generate the highest returns.

Let’s turn to Slide 6 and take a quick look at the quarter. This quarter reflects strong production results at

over 167,000 barrels per day of oil on an equivalent basis. When comparing these results with the same

period of 2014, our production is roughly flat across the period. However, one of the obvious takeaways

is that our natural gas production has declined by 11% between the two quarters, while our oil production,

at over 35,000 barrels, has increased by 36%. Most of the decline in natural gas production is driven by

the sale of Marcellus properties. We have aggressively taken the proceeds from our divestitures and

reinvested them in higher returning oil projects.

I will note that our quarterly oil production includes a partial quarter of activity resulting from the closing of

our Permian properties on August 17.

Our Williston oil production was down slightly, at 6%, when comparing it to the third quarter of last year.

The San Juan oil production continued to see growth and more than offset the slight decline, with an

increase of 167%. Our NGL production of 21,000 barrels, which was 4,000 barrels higher than last year,

was driven by higher ethane recovery at our Meeker plant in Colorado.

So, again, as I mentioned earlier, despite the significant decline in commodity prices between the third

quarter of last year versus this year, our Adjusted EBITDAX increased by 21%. With an oil price decline

of 53% and a gas price decline of 18%, how did we do it? First, we grew our oil volumes; second, we’ve

lowered our costs significantly; and third, we realized the benefit of a prudent risk-management approach

to hedging. I will touch on our hedge position in a couple of slides, but we continue to maintain our

discipline to hedging at appropriate levels to increase the certainty of our future cash flows.

We are reporting an adjusted net loss of $42 million for the quarter, versus $15 million in the prior year.

This decline was driven by two major elements. First, a decrease in commodity prices on our unhedged



production volumes was offset by the higher oil production and significantly lower costs. The biggest

driver of the decline, however, was the increase in our depreciation, depletion and amortization expense.

This increase in the DD&A rate was driven by the drop in reserves used in the depletion calculation

reflecting the impact of the decrease in the 12-month historical average commodity price. Without the

impact of this non-cash—and I emphasize non-cash—revision, our adjusted net loss would have been

approximately $24 million for the quarter.

As far as capital activity, expenditures for the third quarter, they totaled $205 million, compared to $629

million in 2014. This amount, which includes the new Permian activity, is consistent with where we

anticipated being through the third quarter, and keeps us on track with our full-year guidance in new

activity. As I mentioned last quarter, our capital spending on a year-to-date basis continues to be in line

with our cash flows from operations. Of the $640 million of year-to-date new activity, $629 million of that

number has been funded by cash flows generated from our operations.

Turning to the next slide, just a couple of quick points on guidance. We have revised our full-year

production guidance upwards, which is driven by the increases in natural gas and NGLs. As I previously

mentioned, higher ethane recoveries are driving the increase in NGLs. For cash operating expenses, we

have revised LOE down by $0.25, reflecting the continued cost savings realized on those projections, and

I know Clay will talk in a few more slides about the activity that’s going on in each one of our Basins.

Also, we have revised our production taxes down slightly, reflecting the lower commodity price

realizations before the impact of hedging. Lastly, the increase in DD&A guidance reflects the non-cash

adjustments that I previously discussed.

Turning to Slide 8, you can see our latest hedging positions.

For our oil hedging portfolio, we have over 30,000 barrels per day hedged at nearly $86 per barrel for the

balance of this year. This volume represents a significant portion of our remaining forecasted 2015

production. Unlike many other companies, we’ve also been successful in hedging some of our 2016 oil

volumes, with over 27,000 barrels per day hedged at an average price of $61.70 per barrel. I’ve said it

before, but we are laser-focused on managing commodity risk and protecting our cash flows. These 2016

hedges are a reflection of that commitment. Lastly, for 2017, we are approaching 10,000 barrels per day

hedged at nearly $62 a barrel.

Our natural gas positions consist of approximately 436,000 per day of fixed price swaps at $4.06 for the

balance of the year, and another 50,000 per day of volumes transacted at costless collars with the

forward price of $4.00. For 2016, we added to our position during the quarter, increasing our fixed price

swaps to 412,000 per day at an average price of $3.63. In addition, we were opportunistic in layering in

some 2017 hedges at $3.22. These hedges are obviously favorable forward pricing, but, more

importantly, they provide the certainty of cash flows needed in these volatile commodity markets. We

also have been actively hedging the basis exposure, given the favorable Western natural basis markets

available to us. Currently, our average basis price for 2016 is roughly $0.19 per MMBtu, and $0.17 in

2017.

As I turn the discussion over to Clay, I just want to add that we are acutely focused on debt reduction. It’s

priority number one from a financial perspective. We’ve already made progress and we will be quickly

making more. We understand the significance of achieving our leverage targets and what it means to

maintaining our financial flexibility. We are working closely with teams throughout WPX on deal flow and

keeping things moving across the finish line. This has everyone’s full attention and commitment.

Clay?

Clay Gaspar:



Thank you, Kevin. I appreciate Rick’s opening comments about the contributions of our team and our

service company partners. Looking back at the industry’s turbulent last 12 months, I’m extremely proud

of how we’ve made the most of the opportunities to upgrade our talent, assets and processes. In

addition, we’ve built an amazing foundation for the future. The relentless focus we’ve put on E&P

technical excellence is now yielding results that I’ll talk about today and will be talking about for several

quarters to come. So, I look forward to the future updates where I’ll certainly have much more WPX

Permian results to share with you, my hope for today is that you will be able to apply the massive

improvements in today’s presentation related to San Juan, Williston and Piceance to extrapolate the early

Permian wins that we’ve captured to date into a vision of where we’ll be able to take this world-class

asset in time.

Turning to Slide 10, I’d say I’m more excited today about our Permian assets than ever. While we are

aggressively working to quickly capture the early, and typically smaller, low-hanging fruit, we’re also doing

the very important technical work required to achieve the bigger wins that we’ll be able to demonstrate in

the coming months. As an example of these early improvements, the drilling team has dropped drilling

time by 25% quarter-over-quarter. The Marketing Team immediately knocked $2.00 off the differentials,

reducing transportation costs. We also have substantially upgraded the rig fleet to some of the best rigs

out there, and in the process cut nearly 10% off the day rate. I categorize these wins as first-inning

homeruns, but we are just getting started and the bigger wins will come with significantly better well

results and understanding the many other potential horizons that we have to explore.

As part of that longer term focus, we’ve acquired 150square miles of existing 3D seismic cover our state

line acreage. We will have that data in house in a few weeks, and that information will be critical to

landing and steering these wells. The ability to immediately utilize this 3D data represents additional

upside that we did not have baked into our acquisition assumptions.

When I’m asked about the Permian acquisitions, the usual list includes “What am I most excited about?”

The answer, without question, is the vast upside related to this incredible stack of rocks and the incredible

Wolfcamp, Bone Spring and Avalon zones. These intervals have the greatest upside and will experience

the greatest rate of change for months and years to come.

The second very common question is “What thus far has surprised me post-close?” The answer is the

vertical Delaware economics. You never really know what’s going to come out after we all take off our

buyer and seller hats, but now that we’re all on the same team, I’ve had a chance to really dive into the

technical discussions and I’ve seen first-hand that these well economics are very impressive and

shouldn’t be overlooked.

After that answer, the third question usually followed up is to pin me down on “What is the biggest

challenge?” Certainly, there’s been operational challenges in the transition. The biggest challenge thus

far has been related to poor casing design on six wells we inherited. After failures on two of the wells

during the completion, we shut down all completion activities until we worked up a remediation solution

for the four remaining wells, and a new course of action for future drilling. We now have that remediation

plan underway, a new design for future drilling, and we’ll be caught back up with our completions by year

end.

Turning to Slide 11, I’ve talked before about the upside we expect to see improving the completion

design. We now have seven wells that have 1,500-pound completions in the Wolfcamp A. This plot

shows the normalized average of those wells. The wells are all spud and most were completed before or

soon after the closing on August 17. Although these initial results are above our acquisition type curve, I

see many opportunities to build on these results as WPX drills and completes the wells going forward.

I have to mention, for the sake of my completion brothers and sisters out there, that there’s so much more

to evolving a completion design than just pumping more sand. We tend to greatly oversimplify the



message so that I don’t have to ramble on about gel loading, pump rates, mesh size and perf strategy for

45 minutes.

Our team is evaluating working every one of the dozens of inputs that go into the completion design, and

you’ll see some of those results in the upcoming slides.

Moving to Slide 12, we have a world-class hydrocarbon system in the Permian, and not only is it world-

class, it’s two miles thick, with hydrocarbon indicators throughout. In this challenging price environment,

the value of this scale and quality cannot be overstated. The right side of the slide shows recent well

results around our state line acreage. We are very aware of the impressive results that our peers are

achieving around our acreage position, and as I’ve said before, this is a high-class neighborhood with

some high-class neighbors. That said, we fully expect to surpass these results as we develop these

assets.

Looking at the Williston, if you turn to Slide 13, the Williston Team hit it out of the park in the third quarter.

Operating costs and oil differentials improved by over 50% compared to the third quarter of ’14. These

are material drivers of value to the bottom line in these wells. Specifically related to completions and

facilities, there are too many material improvements to list out, but the examples of changing how we

approach well clean-out via coiled tubing and revisions to our facilities designs are structural changes that

will yield half a million dollars in savings per well on a go-forward basis. Our well cost has been

significantly reduced, and that may be the understatement of the day. Our D&C costs are now at $6.2

million per well for an average well going forward, and where we see that it’s better to use a 6-million-

pound completion, we will be able to get those wells drilled and completed for a hair under $6 million. Two

miles, 6 million pounds, $6 million on the reservation, with some of the best rock in the Basin.

So, you ask “How’s that working for you?” Well, let’s take a look at the well results. The recent Mandaree

pad included one Middle Bakken well and two First Bench Three Forks wells. These wells IP’d at a

combined rate of over 6,000 barrels of oil per day. Importantly, we were holding back over 3,000 PSI on

each of them. Approaching two months, they still have a combined rate of 4,000 barrels of oil per day

and still have flowing tubing pressure of 2,000 PSI. These are some really strong wells.

In the graphic—if you go back one slide. On the graphic on the right, you’ll see that we’ve pumped

different completion designs on the two Three Forks wells. As I mentioned before, it’s a gross over-

simplification to say that we only change the amount of sand we pump. In reality, we’ve made several

changes, including changes to stage configurations and pump rate. The data we acquired will help us

with future completion decisions. As you can see in this case, the cheaper 6-million-pound completion

actually outperformed the 10-million-pound well. We have used this information and will customize future

job designs based on several factors, and where we can, we will save the dollars upfront.

On Slide 14, you can see a graphical version of the Mandaree pad relative to our type curve. These initial

results all significantly exceed our current blended 750,000 BOE type curve. In reality, I hit the highlights

of this slide on the previous slide, but the results are so good and I thought it deserved two opportunities

to drive home the point. I can tell you this, I will take these results at $6 million D&C costs all day, even at

a $40 oil price.

Now, turning to Slide 15, and the San Juan Basin, where we had more exciting results. Oil production

grew 167%, compared to third quarter ’14. As with the Williston, we continued to see operating costs and

oil differentials dramatically improved over what we achieved last year at this time. The Drilling Team is

getting unbelievably fast in achieving a new record of 6.7 days spud to rig release, and that’s not just

days. We watch cost per foot very closely. We beat our estimated drilling costs of $130 per foot by

achieving a $114 per foot in the third quarter, and what is now becoming typical WPX fashion, our Drilling

Team celebrated by setting a new record, a new target of $100 per foot. We’re now seeing D&C costs of

$3.3 million per well for a typical 4600-foot lateral, with another $800,000 for facilities and artificial lift.



We’re working on four improvements that I believe will materially improve the San Juan performance and

resulting economics. First, we’re getting the regulatory approvals in place to drill longer laterals. We’ve

gotten a handful of these approved to date, but we are on the verge of unitizing the West Lybrook unit

that will open the doors to much more efficient development. Second, we’re landing and steering these

wells much more intently. Third, we’re orienting these wells with consideration to the geological least

principle stress to improve the stimulation. Fourth, we are stepping up the frac design in a material way.

Over the last several months, we’ve taken steps to test each of these concepts with positive results and

just this week we began flow-back on the first three-well pad that employs all four of these improvements.

The data is so new that it didn’t even make it into the slide. Impressively, the first few days of flow-back,

these wells are combining for nearly 4,000 barrels of oil per day. That’s not the BOE, that’s barrels of oil

per day. This significantly outperforms our prior test results and we look forward to additional tests to

these concepts.

We’re also looking uphole to test the Upper Gallup. The initial results of our first two- mile test in the

Upper Gallup are very encouraging. This well has averaged 1,300 BOE per day with 50% oil, 80 days

into its life. I look forward to updating you guys next quarter with additional information on these exciting

developments in San Juan.

Turning to Slide 16, and the Piceance Basin, we’re rapidly moving to unlock the value in the Piceance

Basin. We know that running one rig in the area is far from the best way to optimize value with this asset,

but this rig is doing some pretty incredible things and the team is taking on the challenge to think

differently about how approach these completions. We are applying some of the same technologies that

are in our other areas with some very impressive results.

The plot at the top right show actual well results compared to our long standing 1.5 BCF type well. These

wells will average 2.5 BCFs and some will exceed 3 BCFs. That’s pretty impressive for a total well cost of

$1.3 million. The plot to the bottom right provides and update on our 2-mile Niobrara well. This well has

averaged 13 million cubic feet for over 60 days and still has over 5300 PSIof flowing tubing pressure.

This is more than twice the performance of an offset 1-mile lateral and speaks to the improved stimulation

design.

I hope you can sense the excitement I have about what’s going on here at WPX. The Team has

embraced a culture of technical excellence and every one of these wins adds fuel to the fire.

With that, I’ll turn it back over to Rick for final comments before Q&A.

Rick:

Thank you, Clay, great job, and especially to the guys out in the field who love the work they’re doing, it’s

just second to none.

Turning to Page 17, WPX is showing discipline, putting goals on paper, measuring our success, trying

some new things and being very opportunistic. We have $85 oil hedges and $4.00 natural gas hedges in

place for the rest of this year, and $61 oil hedges and $3.60 on the gas side in place for next year. As

Kevin mentioned earlier, we’ve also been layering in some hedges for 2017.

We’re also collecting critical data about how to optimize our assets and, as has Clay mentioned and

represented, getting ready to take them to the next level. We will continue to have a bias for action and

doing things better than we did yesterday. We’re excited to be operating now in the Permian and

appreciate all the value creation ideas that are surfacing from both internal and external sources. We’re



focusing on what we can control and that’s how we manage the Company, where we spend capital, when

we deploy it, how we develop or rationalize our assets, and stay after our cost control efforts.

This concludes the presentation and at this time we can open up the line for questions. Operator.

Operator:

At this time, I would like to remind everyone in order to ask a question, please press star, then the

number one on your telephone keypad. Again, if you’d like to ask a question, please press star, then the

number one on your telephone keypad. We’ll pause for just a moment to compile a Q&A roster.

Rick Muncrief:

Mike, I think we had an issue with the audio.

Operator:

Let me just take a look for you, sir. I apologize for that interruption. We should be loud and clear now.

Your first question comes from the line of Brian Corales from Howard Weil. Your line is open.

Brian Corales:

Hey, guys. How are you? That was a great operations update you all just gave. A couple questions. As

you look at next year, how do you balance the rig count allocation? What are your general thoughts? Is it

kind of maintain with what you have now, or can you maybe talk towards that a little bit?

Rick Muncrief:

Yes, Brian, I think that, as we mentioned, it’s a little early. We want to see how we come through some of

the processes we’re running. I think that if you look at our eight rigs we’re running now, roughly 50% of

those are in the Permian, you know, a couple in the Bakken and then one in the Gallup, and currently in

the Piceance, but I think still a little bit early. Obviously, we’re really excited about the Permian. We’re

just starting to scratch the surface. We’ll certainly be getting—we’ll be getting a share of the capital, I can

assure you, and as Clay, I think did a real nice job talking about some of the results, the Teams are all

doing very, very well. It’s going to be a very interesting capital allocation process this year, so I’ll look

forward to it, but hopefully we will be able to give you some guidance shortly after the first of the year.

Brian Corales:

Okay, and it seems—the Bakkenwell results were great. Do you have any conclusions, I guess, the

amount of sand you’re using in the wells is going to vary by area? Can you maybe talk a little bit towards

that?

Clay Gaspar:

Yes, if you notice on the slide, what we did is we included a blended average of 6-million and 10-million-

pound jobs to get to that total well cost of 725. That’s a 7 and a 7.5 blended average. So, what we’re

doing—and, again, as I’ve said, an over simplification, is just talk about sand, because there’s a lot of

other knobs that we’re turning. But, based on reservoir pressure, reservoir thickness, and other

attributes, we’re starting to kind of customize the completion solution and make sure that we’re not

looking at a one-size-fits-all approach. We’re definitely encouraged. Look at that Little Bakken well, 10

million pounds, I think that was the right approach there. The Three Forks in this area are a little bit



thinner, and so we wanted to test kind of a couple of end numbers. In reality, the true optimal price is

somewhere in between—there’s a point of diminishing returns that we want to be very cognitive of, as

we’re investing technologies in these completions.

So, complex answer to a good question, and overall it’s going to be real-time decision and a continual

learning process on where should we invest. From 6 to about 10 million pounds, it seems to be the right

range.

Brian Corales:

Okay, and two quick ones. In the Gallup, obviously things are changing—great results. Can you guess

on a maybe a new EUR? It seems like your current type curve is relatively conservative.

Clay Gaspar:

Yes, you know, I would get creamed by my Team if I did that. I had to twist a couple of arms to get 24

hour, 48 hour results into the call. I mean, I didn’t even make the slide up there, because of the timing.

We wanted to include because it is something we’re very excited about, but it’s really too early to

extrapolate. I can tell you this three-well pad, it does not appear to anything geologic that’s driving those

returns. I would say, if anything, this area of the field, we had a little bit lower expectations because we

did have some offsets that hadn’t performed to expectations, so we really feel like we’re really on to

something with these four tenets of new design and we’re really encouraged about that. But I’ll withhold

the estimates of EUR for now.

Brian Corales:

Fair enough. Rick, I think your prepared remarks you talked about Piceance potentially having something

announced this year. That may be a stretch, but can you maybe elaborate a little bit in terms of what your

thinking is?

Rick Muncrief:

You bet. Brian, great question. We’ve had just overwhelming interest when we opened up discussions to

accelerate value in the Piceance. We’ve had a number of management presentations—Bryan, what was

it, about 20 or so?

Bryan Guderian:

Yes, something like that.

Rick Muncrief:

In excess of 20 management presentations to interested parties, so a huge appetite out there. There is

not many assets like this that are out being talked about, quite honestly, so we’re going to be working that

diligently. We’re going to try to accelerate getting some proposals in, and as I’ve said in my prepared

remarks, we’re hoping that we can talk about some things before year-end. That’s one process.

The other is on our San Juan midstream. Once again, an incredible amount of interest there. We went

out to over 90 interested parties and based on indications of value, we’ve pared that down to about a

dozen, plus or minus a dozen players. So once again, we’re going to try to get that accelerated.



I think it’s real important to get some of these announced, so number one, we showed to the market that

we are diligent about managing our debt; and number two, I think we need that certainly to get a good

feel about our 2016 plan.

Brian Corales:

All right, guys. Thank you.

Rick Muncrief:

Thank you.

Operator:

Your next question comes from the line of David Heikkinen from Heikkinen Energy. Your line is open.

David Heikkinen:

Good morning guys, and Clay, just thinking about the casing design problem you had in the Delaware

Basin and kind of just pace of how you’re trying to catch up, can you just update us on kind of wells put to

sales, I guess, in the Delaware, Williston, and San Juan in the fourth quarter, your expectations?

Clay Gaspar:

How many wells we will put to sales?

David Heikkinen:

Yes, just trying to think about …

Clay Gaspar:

(Inaudible)

David Heikkinen:

Yes please.

Clay Gaspar:

You know, it’s interesting because we’ve—in all of our areas, I guess short of San Juan, the other three

areas we actually slowed down completions for one reason or another, and now we’ve picked them up.

So I don’t have that well count handy, but I would say it’s a little faster clip than the regular rig pace would

normally allow because we’ve had backlog of completions of Williston, as you’re very aware from the first

half of the year. In the Piceance, we also paused completions while we looked at redesign efforts early in

the year. We still haven’t pressed on the accelerator to catch some of those up. And then as I

mentioned, in the Permian with the casing issues there, we had a little bit of a backlog of ducks that we’ll

work through by year-end.

David Heikkinen:

Okay, so it’s like four wells in the Delaware that was added, and the others are kind of just the normal

work-through that you had.



Clay Gaspar:

That’s correct.

David Heikkinen:

In the San Juan, this is kind of—you got off the cut, quickly said 4,000 barrels of oil a day. How many

wells was that? I missed the number.

Clay Gaspar:

Three wells.

David Heikkinen:

Yes, that’s what I thought you said, but I wanted to make sure. That’s pretty impressive.

Clay Gaspar:

Yes, and that is oil. One more time, that’s not BOEs.

David Heikkinen:

No, no, that’s barrels of oil. You were very clear on that part. You piqued my interest.

Clay Gaspar:

I just wanted to be clear one more time.

David Heikkinen:

That’s just the first few days, so we’ll see what …

Clay Gaspar:

Right, I agree with that.

David Heikkinen:

That’s pretty impressive, no matter how you take it.

Clay Gaspar:

(Inaudible) you know, in comparison to about 700 or maybe 800 on the good side of a normal IP of what

we would expect for the backlog in this area. So that’s just kind of a relative sense. But you’re right - it is

an IP and it’s within the first 48 hours of these wells flowing back, so we have to temper that just a tad.

David Heikkinen:

Yes. Then just on the 3D data, I hadn’t heard as much commentary from other operators about using 3D.

I mean, how—I’m just trying to get an idea of what zones are you staying in, how much better does it

make you versus the previous wells that RKI had drilled, or were they already using 3D? I’m just trying to



think about what that, you know, really staying targeted in zone difference could be from the legacy wells

to where you guys are going forward.

Clay Gaspar:

Yes, what we’ve seen in other areas in particular but also some of our peer companies in this area, has

really talked about steering—landing and steering being such a critical piece of the overall value equation.

So everything that we can get our hands on to do a better job of that, we’re leaning towards. This was

already shot seismic we got a really, really good deal on, so we’re very excited about the immediacy of

employing that information. Typically what I’ve found on this kind of investment, you buy it for one reason

and then as long as you have the staff that’s going to really use the data, you’ll find 10 other ways that it’s

going to add value down the line.

David Heikkinen:

Okay, I think that helps, so no risk details on staying in zone with that, but it will just help things overall.

Thanks guys.

Rick Muncrief:

I think that—you know, David, one thing I will say is as we’ve gotten into this is how critical targeting your

landing is in the Delaware basin, I think you’ll see us being more prudent and disciplined with where we

land and the 3D we acquired will help in that process, and I think it’s going to help drive some attractive

results.

Clay Gaspar:

It’s similar to the comment I made on San Juan - we’re going to be much more intentional about where

we land and how we steer these wells, and that seismic will certainly help that cause.

David Heikkinen:

All right, thanks guys.

Operator:

Your next question comes from the line of Brian Gamble from Simmons & Company. Your line is open.

Brian Gamble:

Morning guys. First off, I wanted to answer Clay’s question, if we can sense his excitement. I know the

team and what they give you to work with has a lot to do with it, but I think I can see you smiling through

the phone, so we appreciate you being so excited.

On the divestitures, just wanted to maybe get a true-up of what the EBITDA is, so say with both the

Piceance and the midstream pieces of San Juan is worth. Just kind of want to get a feel for if those do

close by year-end, where we’re starting from an EBITDA standpoint walking into ’16. And then Rick, I

know it’s early, but if you had to reallocate that $150 million run rate in the Piceance, just for instance,

where would you spend that money if you had to spend it?

Rick Muncrief:



Yes, you know, if we looked at where we—I guess, Brian, the way you asked that question, is that if we

could add rigs today, where would they go? I think that we currently have four rigs in the Delaware and

two in the Bakken. I think Rig No. 5 would—or the next rig would go to the Delaware, probably the next

rig would go to the Delaware, probably the next rig would go to the Delaware, and probably the next rig

would go to the Delaware. But we’re going to be looking in at the Bakken - as Clay mentioned, we’ve got

some tremendous results. So I would say, as I sit here today, without a doubt if we could add three more

rigs, they’d all go to the Delaware.

Brian Gamble:

Great, and then on the EBITDA part?

Kevin Vann:

Yes Brian, this is Kevin. In terms of the EBITDA, the San Juan midstream, you can kind of plan for about

$25 million to $30 million of EBITDA coming out of it. On the Piceance, it kind of depends on the type of

deal that we end up doing. I think the all-inclusive Piceance EBITDA, you can—it’s realizing at

somewhere around—that current commodity price is somewhere around $175 million.

Rick Muncrief:

The other thing I would add about the San Juan midstream is there’s going to be some additional growth

opportunities, so we’ve really got a unique position there on how we put that pipe in, very strategically and

very well thought out. So the company that buys it, not only the EBITDA that we would have for next

year, but it will certainly have a lot of growth not only with our volumes but others as well.

Brian Gamble:

Great, and then maybe a question for you, Kevin, on the cost side of things. Obviously rolling in a

Permian asset changes some of the metrics, and good to see the current guidance, especially the LOE

guidance trending downward. But as you look out over the next couple quarters and full integration of

that asset, running four rigs yourselves, how do the different cost buckets start to move around for the

near term?

Kevin Vann:

Well, definitely as we switch the portfolio more to—the production percentage more towards oil, you’re

going to see just the natural trend of that going from gas to oil, you’re going to see that trend up a little bit.

But as Clay mentioned earlier, I think the continued focus that we’ve got on the LOE, that has continued

to come down to offset some of that. So I don’t expect an increase just because of the change in the—or

a dramatic increase in terms of the change of the production profile.

Brian Gamble:

What about any DD&A associated with that (for next year? The current guide up a little bit, you

mentioned the caveat for the quarter and it’s understandable, but what about moving past Q4?

Kevin Vann

You know, DD&A, what we’ve seen this year - and again, I’ll emphasize that it is a non-cash charge, but

the DD&A rate for this year, I hope is about as high as you’re going to see, because it’s again just

reflecting, just like some of the full cost companies have been taking a lot of impairments. It’s reflecting

that change in your 12-month average price, your historical 12-month average price, so as prices have



continued to come down throughout the year, your reserve base associated with that calculation has

continued to decline. So I think we’ve just about hit the bottom there.

Brian Gamble:

Great. Then maybe one on hedges real quick - you added some during the quarter. Clearly well results

continue to improve across the board. I know you want to try to mitigate exposure to the commodity risk,

but Rick, I guess at what point do efficiencies trump the need to lock in any cash flow? Do you continue

to hedge at these levels, or are there certain pricing points that you’re looking to hedge at, or are you

comfortable now where you’re are and maybe let the rest float into next year and see where oil goes?

Rick Muncrief:

Well, I’m pretty comfortable that we’ve done a nice job, where we are today. You can’t ignore where

prices are today, but I think what we’ll do, Brian, is we’ll continue to be opportunistic. If we see some

strengthening in ’16, we’ll probably add some more in, and certainly if you look at the results Clay was

reporting on a while ago, our three core basins are just really, really looking very well, very good. Even if

you look at some results in the Piceance, it’s encouraging.

So I’d say we’ll continue to be opportunistic. We’ll look for opportunities. I don’t think we have a set price

per se, but I think we’ve done a nice job even building some of the book into ’17.

Brian Gamble:

Great, thanks Rick.

Operator:

Your next question comes from the line of Matt Portillo from TPH. Your line is open.

Matt Portillo:

Good morning guys.

Rick Muncrief:

Morning Matt, how are you?

Matt Portillo:

Good. Just wanted to follow up on the San Juan. You guys talked about the completion innovation

ongoing there. I was hoping that we could get a little bit of commentary around how you think about the

current inventory and some of the things that you’re testing, as you mentioned, additional zone

delineation or down-spacing opportunities that could expand that over time.

Clay Gaspar:

Yes Matt, so we’ve talked about 400 wells of inventory. Those are really one-mile wells with a few one-

and-a-halves in there. I’m hoping that well count goes down, but goes down because we’re drilling longer

laterals. We have a really large—the westLybrook unit) I mentioned is about a 10, 13,000 acre unit that

once we get that approved, we’ll be able to stack in these wells on this 45-degree azimuth, longer laterals

on average about 7,500 or 8,000 feet, and then we’re going to go in and do the same thing with the other

units. So I would say the overall perspective area hasn’t changed. The well count will likely go down



because we’re able to drill the longer laterals, and as you’re aware, they’re differentially valuable

methodology to do.

Rick Muncrief:

That’s in the regressive only, and then you take the upper Gallup and you can have more inventory adds

there too.

Clay Gaspar:

That is correct.

Matt Portillo:

Great. Just a follow-up question alongside—I know this is a bit of off the beaten path, but on the

Piceance, you guys have seen obviously a pretty significant improvement in the well results, early time

data here. Any color if those end up holding in terms of the typecurve improvement or performance, what

that could potentially do the breakeven economics here and kind of the improvement and attractiveness

of this asset as you go through the process?

Clay Gaspar:

This is Clay. You know, I’m looking around the table because we all have a say in this. As Kevin

mentioned, we still have a high financial priority of debt repayment, getting that side of the house in order

so that we are healthy and we can make all kinds of decisions just based on where the best value is. I’m

working every day extremely hard to make that decision really, really tough, so we’re trying to improve

things, and I can tell you that team is at least as fired up at least as much as any other team, and they

want to compete for those dollars, which is exactly what we want from the team.

Bryan Guderian:

Matt, this is Bryan. You know, I think we have sufficient well results with the larger fracs now over time.

This is something that we tested throughout our drilling programs over the years, where we’re pretty

confident that we’re going to see a significant uplift from increasing the size of those stimulations, so I

certainly, I think, am willing to stake a claim here that those improvements are going to hold over time.

Just to what degree, I think is something that we need to measure as we go forward, and then we need to

find the right—certainly the right balance between the size of those stimulations, well density, and the

other factors that come to play.

Matt Portillo:

Great, and then last question from me, just around the Permian asset base. We’ve talked a lot about the

upstream part of the business. You guys acquired what appears to be quite valuable midstream assets as

well with that transaction. Could you talk about some of the, I guess, growth opportunity or build-out as

you think about progression of your development on the upstream side for your midstream business over

time, and ultimately how does this fit strategically within your portfolio for the medium term?

Rick Muncrief:

Sure Matt. Yes, it’s something that we’re looking at real closely right now. You know, when you start

looking at the growth opportunities, I think the first thing would be just on the state line acreage, putting a

crude oil system, gathering system in there. We’ve seen how much value generation that you can

understand and realize, just even the San Juan asset is a pretty good indicator of that. We will put a



crude oil system in first, but we’ve also got quite a few opportunities if we wanted to take some third party

water with some offsetting producers. We have a lot of phone calls about that. We’ve had some

unsolicited offers, actually, for the assets, and so quite an exhaustive list of opportunities. We could also

take some third party gas as well, so quite an interesting asset that came with the RKI deal.

I think it’s a little early. We’re continuing to learn not only there from a micro perspective close to our

acreage what we could do with the asset, but we’re spending quite a bit of time, being very diligent in

understanding the macro opportunities that exist - take-away capacity on crude and gas, and processing,

all sorts of things. So we see a very, very valuable asset there. When we rolled it out, we felt like there

was half a billion dollars of value. I think that’s understated by a fair amount now, but we were

conservative at the time. A lot of opportunities there, so we’ll continue to update everyone as we move

forward.

Matt Portillo:

Thank you very much.

Rick Muncrief:

Thank you.

Operator:

Your next question comes from the line of Jeanine Wai from Citi. Your line is open.

Jeanine Wai:

Hi, good morning everyone. So in terms of the Permian, I’m looking at Slide 11. I’m not sure if you

covered this in your comments, but I think you said that all of these wells kind of came on at the same

time, so I’m just wondering what’s causing the kick-up in production from, say, Day 150 out, because it

doesn’t seem like it’s a sample size issue.

Clay Gaspar:

Yes, these wells, we have varied production from about 30 days to 250 days, and as I mentioned, it’s a

normalized plot so what we do is we time normalize and stack them up back to time zero, and then at the

beginning we have the full seven wells and then it gets fewer and fewer, to finally having the one

Covington well that has the longest life. So you can see, the immediate step-ups and changes in rate.

That’s basically when the prior well drops off.

It’s a pretty small well count - seven wells, so as I’ve mentioned in the call, I would—I’m excited about

that, but I see lots of upside and I don’t want people to over-read that this the optimized 1,500 pounds

frack job that we’re going to pursue going forward. There’s a lot of work to do that we’re working on now

to continue to improve the results that we’ve seen so far.

Jeanine Wai:

Okay, and then in terms of potentially increasing capital efficiency and returns, what percentage of your

acreage is already set up for long laterals, or put another way, how much blocking and tackling is there

still left to do so that you can drill a meaningful amount of 7,500 and 10,000 foot laterals?

Clay Gaspar:



I wish there was more. There is—because that is definitely the intention and that’s something we’re

working on now with the land department. But we have a fair percentage - I don’t know the overall

percentage, but along the State, the line itself, we have a whole section of single sections and then half-

sections that would work quite well for us. There is a three-section area that’s stacked up to the

northwest that’s very clean and easy for us to get to, and then there’s a few other areas that we have

focused on.

But we’re discussing now with offset operators. I think the benefit of having sophisticated neighbors is

that they see the value as well, so we’re trying to work deals where we can block up, they can block up,

and share in the benefits of longer laterals.

Jeanine Wai:

Okay, and then when do you think, given your rig count and your activity plans, when do you think we’ll

be able to get more results on long laterals?

Clay Gaspar:

For the Permian in particular?

Jeanine Wai:

Sorry - for the Permian, yes.

Clay Gaspar:

You know, I think the wells that we’re drilling now, all four rigs we’re running on one mile Wolfcamp wells.

We have a vertical program that comes on and off as well. I would say in the next—by year-end, we

hope to be drilling some long laterals, but that will be a few months after that before we have meaningful

results to report on the improvement of longer laterals versus one mile.

Jeanine Wai:

Okay, great. That’s all for me. Thank you.

Rick Muncrief:

Thank you.

Operator:

Your next question comes from the line of Biju Perincheril from Susquehanna Group. Your line is open.

Biju Perincheril:

Thanks. Clay, you guys have done a tremendous job in bringing down well costs in the Bakken and San

Juan, and I was just wondering if you could sort of give us some details, so where your starting point is

now in the Permian and what sort of opportunities do you see near term where that cost could go.

Clay Gaspar:

Yes, one of the things I mentioned early on as we were talking about the deal itself, I did not—I would not

have characterized the RKI team that operated this area as sloppy when it comes to cost. There is



certainly upside related to ideas around the completions and drilling the longer laterals and applying some

of the technology that we’re really excited to see the response from all the other basins, so the $7 million

starting point for a Wolfcamp well is not that far out of the money, looking across our peers. What I would

say is the savings that we will capture, we will likely—most of that, we will invest in larger stimulations,

longer laterals, and have some offsets.

So my biggest target, as I mentioned in the remarks, is more about well performance and really

understanding those other horizons. That’s where I see massive value-add for this asset.

Biju Perincheril:

Then when you think about development there going forward, obviously you have had several zones

there, they all look prospective. How are you thinking about 2016? Is it sort of moving into development

mode, targeting one zone, or are you still in appraisal mode, testing multiple zones?

Clay Gaspar:

We’ll have to balance that. As you’re aware, we want to chase value as a huge focus for us. At the same

time, we need to understand what some of these—the areas just half a step off from state line, what that

means to us as part of our portfolio. Rick mentioned earlier, we’ve had tons and tons of incoming phone

calls, everything from midstream assets to every piece of the upstream as well, and there will be deals to

be made but we need to understand what we’re trading out of to block up, to increase both the laterals

like Jeanine mentioned in the prior question.

So it will be a balanced approach, and we also need to start looking on the z-dimension and start looking

down the hole and figuring out how these other zones, Wolfcamp B and the other Bone Spring intervals,

how they really stack up. You can see it from the offset operators - they’re making some really, really

strong wells, so we need to incorporate that in as well. At this point, I just don’t have a good overall

summary strategy to lay out and tell you exactly where we’re going to be, but that will be forthcoming in

the next few months.

Rick Muncrief:

One thing I’d add, as Clay mentioned in his prepared remarks, this is a great area. There are some great

companies down here working, offsetting this, and so we’re all going to be learning collectively. I think

that’s a real advantage for us, versus some of our other basins where we may be the only one out drilling

and testing. So what it does is it just lengthens your resource assessment base and ultimately your long-

term development planning.

Biju Perincheril:

Then going back to that Slide 11, just wondering, in those seven wells, are you—are there other variables

that you are tweaking that sort of explains some of that variability? Are these all landed in the same

landing zone, or other completion variables?

Clay Gaspar:

Yes, it’s a complex story. That’s why we normalized it, and we’ve talked about how you present this data.

There’s a couple of wells that were drilled a little bit—that are shorter laterals. A couple of them had

drilling issues. What we’re finding is these wells, even the Covington well that is really the best

performing well so far, it takes a while for these wells to clean up, so we’re thinking about adjusting our

type curve to reflect that in the first 30 days, just bringing them all a little bit slower and seeing how do we

improve that over time.



Some of that is related to these upsized completions. We’re pumping a lot more fluid, so how do you get

that fluid back off of these wells. There may be—you know, in Version 2.1, you’ll be seeing us tweak the

fluid and watch the same amount of sand, so that we have less clean-up time and improved well

performance.

So on a blended basis, the first 30 to 60 days, I’m not at all concerned about that. I think the 750,000—or

excuse me, 670,000 that we ran the acquisition economics, I still feel very good about and based on the

significant improvement we’ve seen in the other areas, just give it a little bit of time. It takes a little bit of

time to work through some of these things, but given a little bit of time we will have significant

improvement to what we based the acquisition on.

Biju Perincheril:

Got it, thanks.

Rick Muncrief:

Thank you.

Operator:

Your last question comes from the line of Gail Nicholson from KLR Group. Your line is open.

Gail Nicholson:

Good morning, gentlemen. Looking on Slide 10, you talk about a $2 per barrel improvement in the oil

differential in the Permian. I wonder if you can just give a little more clarity on what you’ve actually done

to drive that down, and do we think that there’s more improvement coming or do we think the next big

improvement on that differential is going to be driven by putting in an oil gathering system?

Michael Fiser:

Yes, this Mike Fiser. Good question. I think it’s a little of both. We’ve seen trucking costs come down in

the last few months, so we are getting some benefit there already. Certainly the next game changer will

be getting this oil on pipe, and we still think even from where we are today, you’re probably looking at

another $2 of upside on that differential. Currently, I think in Q3 we were around $5 on our differential.

Gail Nicholson:

Great, and then just looking kind of at the well costs, you continue to improve those. I mean, in ’14 you

were looking at $11MMfor a Bakken well, and now you’re 6.2 plus a $1.1 million for facilities. When you

guys think about efficiency as service cost reduction, can you quantify, are you 50/50, are you 60/40,

30/70? Can you kind of quantify what you think a drilling versus a service cost reduction?

Clay Gaspar:

Yes, we get that question, and I cringe at that question every time because it’s such a difficult thing to nail

down. I’ve been saying 50/50. I think it’s leaning more towards these structural changes, like I pointed

out around doing things differently - how do we clean these wells out, is there a more efficient

mechanism, applying technology, and changing our behaviors. But those behaviors, sometimes it’s just

our bidding strategy. For the first time as an organization, we have a supply chain organization that’s



looking collectively cross the Company and really leveraging the scale that we have to pull together the

best solution for the Company, and that’s materially changing the outcome.

Now would you put that into just better negotiating, or is it a strategic structural shift? I would say it’s

probably some of both. So if you’re going to pin me down, I will say 60/40 on more structural than cyclical

cost savings at this point.

Gail Nicholson:

Okay, great. Thank you very much.

Operator:

There are no further questions at this time. I turn the call back over to the presenters for closing remarks.

Rick Muncrief:

Thank you. We want to thank everyone for joining us today, and hopefully you can see that we’re

showing discipline, putting our goals on paper, measuring our success, trying some new things and being

very opportunistic. As we mentioned a while ago in Kevin’s remarks, we have $85 oil hedges, $4 gas

hedges the remainder of this year, a nice hedge position next year at $61 and $3.60 on the gas side, and

we’ve already been layering in some 2017 crude hedges. We also had some nice basis hedges that we

went through.

So I think from a structural standpoint, we’re doing a nice job there playing some defense. We’re also

collecting critical data about how to optimize our assets going forward and to take them to the next level,

and I think Clay did a very nice job explaining our progress there. We’ll continue to have a bias for action

and doing things better than we did yesterday.

We’re excited to be operating now in the Permian and really appreciate all the value creation ideas that

are surfacing, both from internal and external sources. The two processes that we’re running are going

quite well. I’m very pleased with that, and we’re focusing on what we can control, and that’s how we’re

going to continue to manage the Company: where we spend capital, when we deploy it, how we develop

or rationalize our assets, and continue to focus on driving down our cost structure.

This concludes the presentation, and we’d like to tell everybody to have a nice day. Thank you very

much for your interest in WPX.

Operator:

This concludes today’s conference call. You may now disconnect.

Documents

WPX Energy, Inc. Third Quarter 2015 Earnings Conference ... · reporting of the substance of the conference call. This transcript is being made available for information purposes