Newfield Exploration (NFX) Lee K. Boothby on Q2 2016 Results - Earnings Call Transcript

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Newfield Exploration Co. (NYSE:NFX)

Q2 2016 Earnings Call

August 03, 2016 11:00 am ET

Executives

Stephen C. Campbell - Vice President-Investor Relations

Lee K. Boothby - Chairman, President & Chief Executive Officer

Gary D. Packer - Chief Operating Officer & Executive Vice President

Analysts

Ronald E. Mills - Johnson Rice & Co. LLC

Jason Smith - Bank of America Merrill Lynch

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Kevin C. Smith - Raymond James & Associates, Inc.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Kashy Harrison - Simmons Piper Jaffray

Stephen Fred Berman - Canaccord Genuity, Inc.

Michael Dugan Kelly - Seaport Global Securities LLC

Operator

Welcome, everyone, to the Newfield Exploration Second Quarter 2016 Earnings Conference Call. For opening remarks and other housekeeping items, I will now turn the call over to Mr. Steve Campbell, Vice President of Investor Relations. Please go ahead, sir.

Stephen C. Campbell - Vice President-Investor Relations

Thank you. Good morning, everyone, and thanks for dialing in today. Along with our earnings release, we also provided an updated @NFX presentation on our website. And as usual, these slides in @NFX will be very helpful and we'll reference those during our call this morning.

Following our prepared remarks today from our Chairman and CEO, Lee Boothby, will have members of our leadership team available here to take your questions. As always, please limit your time during Q&A to one question and simply one follow-up. This will allow us to get to more of you during Q&A.

Let me again remind you that today's call is being recorded and will be available on our website along with our earnings release, the accompanying financial tables, and non-GAAP reconciliations and @NFX. We will reference certain non-GAAP measures today, so please see the reconciliation in our earnings release and at the end of our @NFX.

Today's discussion will contain forward-looking estimates and assumptions, based on our current views and reasonable expectations. In summary, statements in yesterday's news release, and @NFX presentation, and on this conference call, regarding our expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ materially from our expectations, including those we've described in the earnings release and our @NFX presentation, our 10-K, 10-Q and other filings with the SEC. Please refer to the legends in our earnings release and @NFX for additional details.

Thanks again for dialing today. I'll now turn the call over to Lee Boothby.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Thanks, Steve. Good morning, everyone. Thanks for joining us for our second quarter conference call and operational update. We appreciate your interest in Newfield.

In addition to our earnings release and operational updates yesterday afternoon, this morning we announced the signing of two separate agreements to sell our onshore Texas assets for a combined price of nearly $390 million. The transactions include our unconventional assets in the Eagle Ford Shale and our conventional natural gas assets in south and west Texas. Current net daily production from the combined assets is approximately 12,700 barrels of oil equivalent per day, of which about 35% is oil.

Upon closing, the proceeds from these sales will replenish our cash balance and will be available to fund an acceleration of our activities in the Anadarko Basin at the right time. Newfield continues to high-grade its asset base.

Well, it's certainly been a very busy summer. Here at home, we worked due diligence on a recent STACK acquisition which we've now successfully closed and several weeks ago we issued an interim update release to raise our production guidance and highlight the continued advancements we are making as we HBP our premier STACK position.

In addition to the energy conference schedule over the last two months, which was quite heavy, we were able to catch up with many of you on the road and various discussions along the way. If we didn't get a chance to see you recently, simply know that our near-term objectives are very well defined.

Number one, HBP our STACK play; number two, maintain a strong balance sheet; number three, sell non-strategic assets; and four, ready the organization for the timely acceleration of our top tier developments in SCOOP and STACK when the commodity prices provide the right signals. Certainly, proceeds from today's announced asset sale give us this flexibility.

We continue to deliver outstanding results and our performance is differentiating the Newfield story. Since we recently issued an interim update in last night's earnings release and @NFX is full of details, we will focus our call this morning on what's new and leave ample time at the end to address any specific questions that you have.

So, let's get started with a quick summary of our second quarter financial and operating results. Our domestic production in the second quarter was 13.7 million barrels of oil equivalent and total company production was 15.3 million barrels of oil equivalent of which 45% was oil and 63% was liquids. This was slightly ahead of the projection we gave you in our June update – interim update release.

For the second quarter, we had a loss of $3.36 per share which included the impact of the ceiling test write down, derivative losses and G&A expenses associated with our restructuring of the organization. Excluding these items, net income for the second quarter was $64 million or $0.32 per share on revenues of $381 million.

Net cash provided by operating activities was $306 million and discretionary cash flow from operations was $228 million. Our earnings per share and cash flow compared very favorably to Street estimates for the second quarter. Our cash operating expenses for the second quarter stated on a unit of production basis were below guidance.

Year-over-year, our lease operating expenses are down about 25%. This is a nice combination of higher volumes and the great strides we have taken to improve our cost structures throughout the organization. Our domestic LOE for the second quarter was $3.37 per BOE, down another 4% from the first quarter of the year. As always, we updated our guidance numbers in @NFX for the third quarter and full year.

For the second quarter, we had $12 million or $0.06 per share in one-time G&A expense associated with restructuring on the continued refinements we are making in our organization. We're estimating additional one-time cost of $18 million for the remainder of the year with about half expected in the third quarter.

Important to note, are some very healthy trends underway in our consolidated cost structure. I think it's definitely worth spending a moment to highlight a few of them for you. First, our lower LOE is being driven primarily by SCOOP and STACK. Our recurring lease operating expense in the Anadarko Basin is currently less than $2 per BOE, the lowest of all of our operating regions. Since this is our fastest growing region, we are seeing improving LOE cost on a consolidated basis.

With the lion's share of our capital being allocated to Anadarko Basin, production in our remaining operating regions is on decline. As higher cost areas naturally decline and our growth accelerates in the Anadarko Basin, we expect to see continued positive trends in our margins.

Upon closing the sale of the Eagle Ford and south Texas assets, we should see further improvement in our consolidated cash operating cost on a unit of production basis. Our differentials to both NYMEX WTI and Henry Hub are improving as well. This is a direct result of the shift underway in our production mix by basin. Our lowest realized oil price is the Uinta Basin, our highest is STACK and we expect the continued favorable trends in our revenue per BOE going forward.

Lastly, this list of positive trends has reduced G&A expense, something that has been underway since the oil price slide in the second half of 2014. We moved early and aggressively to reposition Newfield for the prospect that oil could remain lower for longer. These tough decisions have paid off, we consolidated our Denver, Tulsa and Houston offices and re-aligned a more efficient workforce into The Woodlands. We anticipate that these steps will result in more than $60 million in annualized savings in 2017 forward or about 30% less G&A expense than in 2014.

As I mentioned earlier, STACK is driving our improved oil price realizations. Our new STACK oil pipeline to Cushing is operational and we are seeing great market demand for this high quality barrel. Our most recent batch sales have sold for NYMEX WTI plus about $0.50 per barrel. So even after transportation expense, we are netting NYMEX less $2.50 per barrel. Substantially, all of our oil production in STACK should be fully on pipe during the third quarter.

On the balance sheet, you'll see we ended the quarter with $165 million in cash on hand post posting of our recent STACK acquisition. The proceeds from the sales of our Eagle Ford and conventional south Texas gas properties will replenish our cash balance and more than bridge any deficit between our cash flow and planned investments in 2016 and 2017.

Let's talk in more detail now about the Anadarko Basin. STACK has certainly garnered a great number of headlines recently and is one of a few select areas in the country that has seen an increasing rig count in the face of low commodity prices. Industry activity has led to the drilling of more than 500 STACK wells to-date with consistent results across a multi-county area. This extensive well control along with our more than 100-plus operated STACK wells today provide us with heightened confidence in the size of this prolific resource, the depth and quality of our undrilled prospect inventory and its ability to drive corporate growth and production and reserves well into the future.

Recent transactions in STACK have been extremely competitive and valuations for undeveloped acreage have been very strong. Our legacy acreage position in Kingfisher and Canadian counties is now sandwiched between recent billion dollar plus transactions and undeveloped acreage values of $15,000 to more than $20,000 per acre.

In this business, there is significant value created by identifying an unseen opportunity and founding a large scale resource play. Even post-closing of our recent STACK acquisition, our all-in acreage cost in STACK total less than $3,000 per acre. Our low entry cost should boost our full cycle rates of return as we drill thousands of development wells over the next few decades.

We have a top tier acreage position in STACK and it's detailed on page nine in @NFX. And there are several key things to note about this acreage. First, our acreage is largely contiguous and lends itself to a very efficient future development. In HBP mode, we have largely drilled lease line pairs, purposely leaving nearly two miles of undeveloped ground between our initial wells. This will be ideal for proper infill spacing in the future. The contiguous nature of our acreage will allow for more than two-thirds of future wells to be super extended laterals or SXLs. We have proven time and again that SXLs are the most efficient way to develop resource plays.

Second, we have exposure to all hydrocarbon phases across our acreage. As you transition from dry gas in the Cana Field and move north and east, you enter the oil window, which is what we originally targeted when our leasing began here five years ago. Today, we have solid representation to the west where we are confident that EURs and gas content both move significantly higher.

For us, it's about rate of return. Well costs are lower in the oil window. As gas content increases to the west, EURs also rise. It all has a great ROR, and we are very fortunate to be represented across the entirety of the STACK play today. Oklahoma, more specifically the Anadarko Basin, provides commodity diversity and optionality. Once HBP'd, we will have the flexibility to target the right commodity at the right time.

And third, we can now see the end of HBP and are planning for full field development. We expect that our legacy acreage in Kingfisher and Canadian counties will be about 95% held by production by year-end 2016. For much of the last 12 months, we've been primarily drilling to hold acreage in the northern and eastern portions of our acreage. Although we have continued to see very consistent results, I can assure you we are looking forward to the high-grading of drilling locations during the future development phase.

Newfield and others are pressing forward with several important pilots in STACK. We are all working to understand the optimal spacing for our future development wells. Fortunately, we share working interest in many of the pilots conducted to-date. We're accumulating a great deal of information from both our operated pilots and outside operated pilots where we own interest. By early next year, we should know a great deal more in terms of thinking about the development phase.

In @NFX, we show recent 24-hour production results from our new Raptor-X pilot, which just commenced production. As you'll see on page 10, this pilot includes four wells and was drilled to test a 12-well spacing configuration, two layers in the Meramec, upper and lower. With wells drilled approximately 880 feet apart, the Raptor-X is showing strong early results. 24-hour production rates range between 1,400 and 1,700 barrels of oil equivalent per day.

We are very encouraged with these early results. But as one of our completion engineers stated, bad things show fast, but good things take time. We will continue to watch these results over the next several months to draw meaningful conclusions to aid in our future development decisions.

Our Chlouber Pilot is currently drilling, with five infill wells spaced 1,050 feet apart to test a 10-well configuration in the Meramec, upper and lower, two horizons. Following the Chlouber, we will commence the Dorothy Pilot in the fourth quarter. The Dorothy will include four wells to test 5,000-foot laterals. Our planned spacing between wells will be 1,050 feet, simulating five wells in a single Meramec horizon. We expect to have information to share with you early next year.

To-date, we released information on about 100 STACK wells. This is a very large sample. In fact, the largest in the industry. Our longest-producing wells have now been online for four years or more. Newfield as founder of the play has more operated well data than any other player in the region. When looking at the long-term production from our wells to-date, we see outperformance to our previous 950,000 BOE average type curve. Today, we raised EUR on our average type curve by 15% to 1.1 million barrels gross equivalent for our unbounded wells on our legacy acreage in Kingfisher and Canadian counties.

Let me be clear. This new average type curve is reflective of only our legacy acreage in Kingfisher and Canadian counties, which constitutes nearly 200,000 net acres where we have significant well control and long-term production data.

Clearly, as we move to the west in Blaine and Dewey, we expect that these areas will likely have a different hydrocarbon composition and likely a different type curve. As we gather additional information from our operated wells planned here in 2017, we will share results and update you on our expectations. For now, there's lots of information from our peers who are having great success in Blaine, and we look forward to wells in this area very soon.

Regardless of where we drill in STACK, we know that targeting and geology will continue to be extremely important. In addition, completion design and size will contribute to EUR. But the simple issue for us will be, how do we maximize our rate of return across the play for decades to come? We will continue to work the issues and navigate to the optimal completion. It's early. We don't have all the answers, but we are very encouraged by what we've seen.

We continue to make great strides operationally to improve efficiencies in both drilling and completion. We are firm believers today that larger proppant and fluid volumes are both leading to higher EURs and improved production performance. Today's type curve increase is not merely a reflection of larger completions. We have only recently begun testing the larger sand and fluid concentrations, and we will continue to gather more information on the road ahead. As we learn more about the subsurface across a very large area, we will adjust our completion jobs to create the best recovery, highest returns, and maximum net present value.

Today, we're pumping more proppant than we employed in 2014, early 2015 and testing a combination of cross-link and hybrid fracture stimulations. Our goal is pretty simple, arrive at the best rate of return for development and create the most long-term value for our shareholders.

We know that there are significant efficiencies still to be captured and are highly confident in our ability to deliver additional efficiencies and development. In fact, a recent best-in-class well was drilled and completed for less than $6 million gross.

We have been working behind the scenes over the last several years to prepare the full field development in STACK. Although, many of these initiatives don't benefit us today, they will be hugely instrumental in the future.

Here are some of the things that we've been doing in STACK. We have carefully placed our HBP wells, our lease line pairs of HBP wells have left the acreage in the best position for future drilling and development optimization of well placements. We have nearly two miles of virgin surface and subsurface acreage between about a third of our HBP wells drilled today.

We made significant investments in an extensive water infrastructure network to allow us to officially source, move, store and recycle water during our upcoming development operations. We worked to develop an expandable natural gas gathering and processing system with our partner, MarkWest. Newfield and others are today considering a new open season on several proposed pipeline projects in STACK that will add 750 million cubic feet a day of takeaway in 2019 and beyond. We're confident that the infrastructure will be there to timely manage our growth outlook from the basin.

Lastly, we are actively permitting for full-field development and preparing for higher levels of activity in the future. We expect that about two-thirds of our wells next year in STACK will be development wells drilled from common pads. We look forward to continuing to drive down cost, exploit operational efficiencies and improve our margins.

As mentioned earlier, we closed on our recent acquisition of acreage in STACK. This was a great fit for us with about half of the acreage overlapping our legacy STACK acreage in Kingfisher and Canadian Counties, and the remainder gives us a solid representation to the west.

In addition to the Raptor-X Pilot, we had four additional wells that recently commenced production. These wells are outlined on page nine in @NFX. The rates on these wells were impressive and range from about 1,400 barrels of oil equivalent a day to more than 2,000 barrels oil equivalent per day. Each of these wells has strong liquids rates between 80% and 90% of the total production. We have additional wells planned in these areas for later this year.

With strong results in STACK, we plan to increase activity in the second half of the year and we will look for additional opportunities as we enter 2017. We've today announced a revised production outlook and capital budget for 2016. Our plan to keep a rig active in our new STACK acreage and our quickening pace in days to depth is affording us the ability to drill additional wells this year with the same rig count. Our beginning-of-year plan called for the drilling of about 50 wells in STACK. Today, we estimate that we will drill more than 60 wells in 2016 including all pilots.

Our new guidance for 2016 domestic production is 53 million to 54.5 million barrels of oil equivalent. Recall that we have now raised guidance three times due to superior operational results year-to-date, and we are now including volumes associated with our recent STACK acquisition and additional planned activity in the second half of 2016.

In China, our Pearl Field continues to produce near peak rates and the expected natural decline has been slower to materialize that forecast. We also increased our expectations for China due to this continued outperformance. In fact, our guidance for 2016 is now about 700,000 barrels ahead of our beginning of year projection.

Our second half estimate for this year reflects our expectations for natural decline as well as the timing of liftings. Peal continues to produce near peak rates over 25,000 barrels of oil per day. China liftings in 2016 expected to total about 5 million barrels of oil equivalent.

When combined, the total company production for 2016 is now expected to be 58 million to 59.5 million barrels of oil equivalent. Our production guidance today includes our Eagle Ford and south Texas properties through yearend. Upon closing of these sales in late September, we plan to again update our production guidance for the year.

Our capital budget for the year is now $700 million to $750 million, there's a helpful table in today's @NFX publication that reconciles or budget back to the original $625 million to $675 million beginning of year plan. Our increased capital budget is supported by an improved outlook for 2016 cash flow from our legacy production as well as anticipated 2016 investments in our recently acquired STACK assets. In addition, we now have better clarity around the asset sales proceeds and timing. At current commodity prices, we expect that our capital spending will exceed cash flow by less than $100 million. Again, proceeds from the planned non-strategic asset sales should be an effective tool in managing our debt levels and maintaining a superior capital structure.

So that concludes our prepared remarks this morning. We appreciate your interest in our company and your investment in Newfield Exploration. I'm confident that our new near-term business plan is sound, and that we are executing well along the path that will make us better, more efficient and more profitable in the future.

Operator, we're now ready to take the questions.

Question-and-Answer Session

Operator

Okay. Thank you. We'll take our first question from Ron Mills with Johnson Rice. Please go ahead. Your line is open.

Ronald E. Mills - Johnson Rice & Co. LLC

Morning. Lee, you talked about potentially two-thirds of your wells being development wells next year. How do you reconcile that with the new higher average EUR that you put out? Because presumably in development mode, you would, given HBP status, you'd be able to move your rigs to some of your best acreage. Is that a fair comment?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. So, we're just trying to give you some color that we've – through the execution of the operating teams and just been outstanding, again, year-to-date both in terms of time, efficiency and cost. We're in a position now that we can see 95% of our legacy core position in Kingfisher and Canadian will be HBP at year-end. So, it's rational to set up a program that is going to become increasingly development-dominated. So, relative to that program, we're saying that two-thirds, estimate – or somewhere around two-thirds of the wells we expect to drill in that acreage position in 2017 will be development wells. So, to that end, that's the point that was being made there.

Certainly, there are incremental efficiencies that will be gained in development that we've talked about, the ability to shave somewhere around $750,000 to $1 million off of a well and drill from common pads where you got infrastructure and facilities in place. We believe that's still achievable and certainly will be something we'll realize. That will translate to higher returns on a well basis.

And there's outstanding information that we outlined in the call that none of us have at this point, and that'll be the information that we pull, it will take some time over the next course of the next year or so. We and our other friends in the play will be studying the pilot data to optimize both lateral distance between horizontals laterally and vertically, the vertical offset throughout the STACK productive intervals. So, those will be pieces of the puzzle that we won't completely know but we'll have – we have plenty of data to know we can enter the early phase of development with confidence and with high expectations in terms of the results.

I think the last part of your question having to do with expectations per se, I would say because of those cost savings, the efficiencies, the shift to two-thirds of the spending on development wells and the ability then because it's HBP to sort highest return to lowest return areas, we'll be targeting the highest return areas of the play. And that's the part that we referenced in the call that'll be very, very exciting.

So, team's excited. We're going to continue to execute through this year, but the team's worked hard the last five or six years to get ready for development, and I hope they're listening in right now because I know they're going to enjoy it and have fun. We're going to have fun reporting on the results.

Ronald E. Mills - Johnson Rice & Co. LLC

Great. And then my second question just relates to the completion design. You've started to use increased levels of proppant. What are your plans going forward? Are you still seeing improvements, and do you continue to think increased proppant concentrations can further help?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Well, I think the team, and I'll let Gary give you some color here in a second, but I think the team has done a good job in a workmanlike fashion, focused on development to get us information, kind of using the old scientific method of don't change 15 variables at once so you confuse yourself. We've been marching through this development step-by-step with a very logical approach. First step, you go back to that was a big step change was the reduction in spacing between perf clusters. And that was something we saw outstanding results a couple of years ago, and it led to the first increase in the type curve.

Since that time, the team has been working on various combinations of fluid volumes and proppant and mix in terms of the fluid systems. And again, they've taken a very sequential, methodical approach so that we can understand the data that's coming back to us. Again, focused on development not the short term. So, we're at the point today where we're testing higher fluid volumes and higher proppant volumes and I indicated in the call commentary earlier that we're seeing some encouraging signs. But a lot of the higher volume and higher proppant is fairly recent data and not really a part of most of the work that's been done in terms of the 100 well data set that's been released.

And then ultimately, we know from past experience in other plays that not every area in this play will probably have the same frac recipe. And so you'll end up with some areas that you think that option A is the best approach, other areas will be recipe B and some other area might be recipe C. But in general, I'm confident that we have the data and are acquiring the data we need to optimize. And I'll flip it to Gary to see if he's got any other color he wants to add.

Gary D. Packer - Chief Operating Officer & Executive Vice President

No. I think you said it well, Lee. We are utilizing lease line pair tests where we're able to compare some of these results that Lee alluded to with increased proppant or increased fluids so we can make better direct comparisons between those results and we'll have more to report on that over the next 90 days or six months.

Operator

Great. Thank you. Next, we'll move to Jason Smith with Bank of America. Please go ahead. Your line is open.

Jason Smith - Bank of America Merrill Lynch

Hey, good morning, everyone, and congrats on the results. Lee, you've done a great job of tacking on acreage over the last few years. So just, it seems like most of the major packages are now spoken for. I'm just wondering, are there any incremental opportunities at this point in the Anadarko that you're interested in, or are you happy with where things stand now?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Well, Jason, first of all, thanks for compliments to the team. It's certainly been an outstanding first half and a good quarter. Thank you for those comments. And we were joking before the call started, amongst ourselves, that one of the things we're proudest of over the last – there for the last several years is, our team's put exploration back into Newfield Exploration's name in a big way. And that's a big driver in terms of the results in the portfolio and the quality assets we have. And I'd be remiss not to give them all a pat on the back.

And of course, the operational guys coming along behind that, driving down costs farther, faster than we might have otherwise imagined. It's just icing on the cake. So, the team is performing at a high level. And I'm being polite. But I'll just say that if we have anything going on in exploration and/or if we had our eye on any other acreage, the last thing I'd do is announce it on this call, because we have a lot of friends and a lot of competition.

But the truth is, the big obvious packages have largely transacted, you've got three large transactions within the core STACK position there that we talk about, just in the last seven or eight months. We were fortunate to pick off the one that we wanted. And the other two went for attractive prices, saying that Newfield's acreage is in a really, really good spot.

So, as far as I'm concerned, we've got really strong companies in the play, credible operators. Everybody has got a great acreage position, it's a big area. And we're moving to the point where I think people can share and help each other optimize. It's going to be a pretty exciting time for the play going forward.

We'll all continue to compete with each other because that's just what we do. And hopefully, we can find some areas to scrap for some additional acreage. And anybody has any out there that you want to sell, please call Larry Massaro right after we get off this call.

Jason Smith - Bank of America Merrill Lynch

Thanks for that. And I guess, just on the other side of the equation, with the Eagle Ford and south Texas now announced, and the focus, clearly, on the Anadarko going forward, where does everything else fit, just in terms of capital allocation? I guess I'm just – maybe just looking for also an update on statuses on those ongoing JVs and projects you guys are working on in places like the Uinta and the Arkoma?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Wow, you guys are doing a good job this morning. Steve is going to rewrite his instructions. Two questions, you guys are probably driving four or five (30:42). I'll see if I can cover the key points.

First off, I'll just say that I think we've demonstrated over the last several years that our team – and that means the entirety of the team, management team, asset teams, operating folks, commercial side – have become accustomed that assets have a life cycle. And we've embedded within our leadership team the grow – what I call the grow, hold or divest mentality, and it's something we talk about every day. Leaders throughout the organization have to ask themselves, are we trying to grow an asset and are we holding this asset, are we divesting this asset, and that leads to very healthy dialogue.

So, we've been consistent. I've been consistent that it's not a question of if, it's more a question of when. We have no need to sell any other assets today, with the announcement of these transactions, but we all know that, at the right place and time in the future, that there will be additional asset transactions, and I know that our team will perform at a very high level when that day comes.

Oh, JVs. Gary's reminded me that part three of your second question, I think, was JVs, so I'll let Gary give you some color on kind of where we're at on the JVs.

Gary D. Packer - Chief Operating Officer & Executive Vice President

As you alluded to, we had a JV in the Arkoma Basin. That will be restored in 2017. We look forward to getting back into that area and continuing the trajectory of improved EURs and lower cost there. In the Uinta Basin, we had a 20 well program. We're about a quarter of the way through that. We went into it with a thesis that we can apply learnings elsewhere in the organization and realize those benefits in the Uinta. We went in there very encouraged and we remain so. It's very early days there, but we like what we see so far.

Operator

Great. Thank you. Next, we will move to Josh Silverstein with Deutsche Bank. Please go ahead. Your line is open.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Thanks. Good morning, guys. I guess just taking on some of those other assets out there. There is still a lot of transportation and processing costs that are still bogging down cash flow a little bit. Just wanted to see if you're able to renegotiate some of those? It seems like there is still kind of assets that you're sticking with right now, and the opportunity to reduce the roughly $70 million, $75 million of those costs?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. So, I think the outline that Gary gave you, the JVs in the Arkoma and the Uinta were not chosen by accident. Certainly, we've got technical and economic drivers in terms of wanting to continue to advance the ball and the learning curve, but the fact of the matter is, the drilling activity delivers volumes. Volumes go a long way towards offsetting those costs. So, we get high returns. We get to advance the learning curve, and we get to offset volumes. So, I'd say that the team's focused on it. And we'll continue to work it going forward. I really like the logic that the team used to put these in place and, frankly, I think they did a good job getting them negotiated and executed.

Josh I. Silverstein - Deutsche Bank Securities, Inc.

Great. Thanks. And can you just talk a little bit more about the rig moving into some of the western or northern acreage in the Anadarko Basin? Just kind of where you guys are testing it, any of the pilot space – pilot opportunities that you're thinking about for next year there as well?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Well, the pilots are generally associated with the areas within our legacy Kingfisher, Canadian Country acreage footprint and areas immediately west of there. And I think that we're in a number of pilots operated by others and we've got several that we're operating ourselves. And with regard to anything outside of those confines, I would simply say that I'll reference my Newfield Exploration comment earlier. And we'll just have no comment on anything that might be exploration.

Operator

Thank you. Next, we'll move to Kevin Smith with Raymond James. Please go ahead. Your line is open.

Kevin C. Smith - Raymond James & Associates, Inc.

Hi. Good morning and congrats on another solid operational quarter. I believe you touched on this on your prepared remarks, but just trying to make certain my notes are correct. So, do you plan to keep a rig in Blaine County on the recently acquired acreage?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. We're going to continue to run a rig there in that portion of the acreage that we've had really good results on between now and the end of the year. Yeah.

Kevin C. Smith - Raymond James & Associates, Inc.

Got you. Do you have a number of wells you plan on drilling on that acreage by yearend?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Look, we're tied up on pilots and a lot of other activity. It's probably four wells or five wells just given the time horizon that we're looking at. But probably four or five incremental wells would be my guess.

Kevin C. Smith - Raymond James & Associates, Inc.

Okay. And then just lastly, I realize, I apologize three questions. But do you have any HBP worries outside of Kingfisher and Canadian County? And I'll jump back in queue after that.

Lee K. Boothby - Chairman, President & Chief Executive Officer

I would say we don't have any HBP worries because the team is executing on a pretty workmanlike fashion. Some of you guys, most of you guys probably met John Jasek by now, but he and the team are all over that. And so I don't lose sleep about acreage that needs to be HBP'd. And I think they've got a good plan. They're executing well, and we'll stay on top of that. But we don't have any material issues in that regard. And I'll remind you that the acquisition that we recently closed on, 95% of that acreage is HBP. So, there's not a short-term driver to have to drill. There's a desire and a want to drill. And we'll just call that development, and I'll reference the earlier comments on the percentage of wells drilled in development in 2017.

Operator

Great. Thank you. Next, we'll move to Jeff Campbell with Tuohy Brothers. Please go ahead. Your line is open.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Good morning, and I echo the compliments on the strong quarter. My first question is, how do you account for the outperformance of Pearl?

Lee K. Boothby - Chairman, President & Chief Executive Officer

The outperformance in Pearl is pretty easy to account for, and I don't – I apologize, Jeff, I don't know that I've ever had a chance to talk to you about it. But we have a history of – we kind of pioneered some of the horizontal oil developments in shallow waters in Southeast Asia. We had operations in Malaysia where we developed several fields. The Pearl field was our first horizontal development offshore in China, but I would – as far as operating development. But I would tell you that reservoir simulators are great tools, and teams do a great job of putting all the data in, but every single field, every one that we developed in Asia outperformed the initial reservoir simulation.

And there's a number of reasons for it. It's fluid properties, the quality of the reservoir, it's the math not being perfect when you go vertical to horizontal comparisons, a whole host of things. But I would tell you, none of us are surprised it outperformed. But when you have a lot of really talented people and reservoir simulators telling you the answer is X, you can hope and pray that it's X plus. But until you see it demonstrated, you know, it's an unknown.

So, we took a conservative posture on the front-end. I think it's a prudent way that the team described it. And frankly, we've benefited at Pearl by all of the things that you'd want working in your favor. There's more oil in place than probably was imputed. We're getting a higher recovery efficiency than you might otherwise have assumed. The rates have sustained themselves for far longer than any of the reservoir simulations would have predicted.

And today, with a couple years of production data, the team is able to recalibrate the reservoir simulation and we know at some point it'll go in decline but we want to enjoy this plateau production for just as long as we can. Cash is king. Larry tells me get the cash in the bank is the objective in China. And he never lets any of us forget it.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Well, it's a high-class problem to have, and I'm sure there's a few people that were looking at that asset and didn't make a good enough offer that are gnashing their teeth right now.

Lee K. Boothby - Chairman, President & Chief Executive Officer

You're probably right. And they're welcome to pick the phone up and call Larry. Larry does transactions both ways. He's happy to buy and sell.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Got to get Larry busy. Could you...

Lee K. Boothby - Chairman, President & Chief Executive Officer

We got to keep Larry busy. He gets in trouble if we don't have him busy.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

Yeah. I know how that works. Could you remind me what the average lateral lengths were on the Raptor-X pilot wells?

Lee K. Boothby - Chairman, President & Chief Executive Officer

10,000. That would be feet, not meters.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

I'm sorry, I couldn't hear it. Did you give an answer?

Lee K. Boothby - Chairman, President & Chief Executive Officer

10,000 feet. 10,000 foot laterals.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

10,000. Okay. So, they were SXLs. Okay.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yes.

Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.

If I can ask one last real quick one. On slide 11, you show a comparison between two SXLs and one XL. I was wondering if could tell me what was the average cost of the two SXLs and the cost of the XL?

Lee K. Boothby - Chairman, President & Chief Executive Officer

I don't have that information in front of me. I think that they're all part of the progress that we've made. So, my guess is that the SXL wells would be in line with kind of the average we've had year-to-date. And you got the color on that? Gary has dug it up. I'll let Gary answer that question.

Gary D. Packer - Chief Operating Officer & Executive Vice President

Yeah. I mean, generally speaking across the area, year-to-date our SXLs have been about $6.8 million. We expect that number to go down to $6.2 million by yearend. The XLs that we've drilled year-to-date run a little over $5 million and we continue to see good trajectory on those and we'd like to see them by yearend to get down to around $4.5 million. So that kind of gives you a feel.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Thanks, Gary.

Operator

Great. Thank you. Next we'll move to Kashy Harrison with Simmons Piper Jaffray. Please go ahead. Your line is open.

Kashy Harrison - Simmons Piper Jaffray

Good morning and thanks for taking my questions. So, with the successful divesture of the Texas assets, you now have about $390 million of dry powder. How are you thinking about deployment of that capital to the STACK in 2017 just given the current forward strip?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Well, you got $390 million coming in in September there and $100 million plus that we had on the balance sheet at the end of the second quarter so I'd say the cash balance will be settling somewhere in the $0.5 billion range which is a nice luxury of – I'll quote the earlier commentary, it's probably a high-class problem in today's world.

And I think that we said in the call that it positions us very well because we're able to rotate our operational and technical talent into focus in the development phase of the SCOOP and STACK assets that we've been talking about at some length this morning. That's positive. And it gives us the ability to accelerate that development activity at the time of our choosing, which we've been consistent over the last couple of years saying that when the market forces indicate that stepping on the accelerator is the right option, this play is going to get – we're going to accelerate.

And I think the – we're reminded of the volatility that you've seen in the commodity here over the last two and a half years and we expect that's going to continue for the next – I don't know, 12 months, 18 months. And hopefully, we'll get some clarity somewhere along the way to accelerate development. But it's a good place to be and we're – we continue to be more focused on the things that are generating the really exciting returns, and we've got the cash to do what we need to do to take care of the business.

Kashy Harrison - Simmons Piper Jaffray

And just a follow-up from me. As you enter full-field development mode and start thinking about bounded EURs versus unbounded EURs, do you have any initial expectations on the impact for activity maybe perhaps based on your experience in either the SCOOP or the Bakken or some other region?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. So, I'd start out by saying that in development, first objective is that you do want to have some level of interference. So, it'd be illogical to think that you're not going to space this at a point where you've got what we call constructive interference. That's what we're drilling the pilots for. I mean, I'd be doing nothing but speculating. I think that in a lateral sense, if you go off of demonstrated activities in an individual layer, five wells, six wells, seven wells per horizon, you've got a lot of examples where that's worked effectively. So if I were leaning into something, I'd probably say that I would expect that kind of spacing per layer. The big question remains, how many layers and what the vertical offset is going to be as you develop the other areas. We'll be optimizing – mentioned rate of return as a driver, but ultimately, we're optimizing to maximize net present value.

If you go back historically and you got to remember that a lot of these historical plays that long-term production are gas, we're producing oil here, so there are other variables, but typically, 10%, 15%, 20% type of interference for what it affects – impacts the EURs would be expected as you optimize. And I think we've been consistent on reminding everybody of that, and I think if you listen carefully to the call script earlier, there are a lot of factors that get involved. Oil price is a factor. Well cost are a factor. You've got a – there's a continuous optimization program there. But I think the best guidance I can give everybody is that don't run with the unbounded type curves and think that's going to be just exactly what the development wells will be. If it is, then we're going to keep drilling closer until we find the optimum spacing. But at this point, we're excited. We've got strong data, 100 plus wells, demonstrated 1.1 million barrel EUR, and the pilot projects are underway. So, a good place to be and a lot of good information and as I mentioned earlier, quality operators to help us solve that problem.

Operator

Thank you. And we do have time to take two more questioners. Our next question will come from Stephen Berman with Canaccord Genuity. Please go ahead. Your line is open.

Stephen Fred Berman - Canaccord Genuity, Inc.

Thanks. Lee, the Raptor pilot and the four wells on slide nine that all came with the Chesapeake acquisition, I think I heard you say, can you talk a little bit about how much of that was Newfield involvement on the drilling and completions versus the prior operator?

Lee K. Boothby - Chairman, President & Chief Executive Officer

We inherited, as part of the acquisition, the activity. Give our friends at Chesapeake a pat on the back. I think they got the pilots moving in the right direction. It was one of the items that was very attractive to us about the package, because it would accelerate our knowledge base, and I think they made a smart call and they've started this one out, as I mentioned in the call. It's a two-layer test. They've got the first four wells down. So it'd be six wells per layer, 12 well DSU.

The other two pilots that we did mention earlier back in the second quarter, that are Newfield operated would be the Chlouber, which is presently drilling, and the Dorothy, which is going to be drilled before year-end. The spacing in these are reasonably similar. I think you can do the math. The six well scenario gives you 880-foot lateral spacing and the five well gives you 1,050 feet. So, we're going to have good pretty tests kind of in that range. That's similar to the spacing that we've had in the well pairs along lease lines. So, we'll have a lot of data to kind of calibrate.

And again, I'd take you back to the discussion we had earlier in this call in the Q&A on Pearl, it will give our engineers an opportunity to optimize their simulations and give us the answer. So, we need time. I think that – I hate – I know you guys aren't typically very patient, but the truth is, in all honestly, you need to give us and our friends in the play time to get the data, analyze it and tell you what the right answer is. Impatience is not going to accelerate that process.

Stephen Fred Berman - Canaccord Genuity, Inc.

And the four wells on slide nine, the Wittrock, Stangl, Stark and Indominus Rex, those were pretty much Chesapeake as well?

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. Those were all part of the acquisition. That would be correct.

Stephen Fred Berman - Canaccord Genuity, Inc.

Okay. And then one follow-up. The incremental or additional CapEx you announced with the release, how is that broken out between Q3 and Q4? Can I assume it's more back-end loaded?

Lee K. Boothby - Chairman, President & Chief Executive Officer

No, it's front-end loaded.

Operator

Great. And we'll take our final question from Mike Kelly with Seaport Global. Please go ahead. Your line is open.

Michael Dugan Kelly - Seaport Global Securities LLC

Hey, guys. Good morning. Lee, I think it was probably a pretty important comment you made earlier that, you said that the current type curve uptick really is predicated on that 100 well set and isn't – doesn't really bake in too much on the enhanced completion front. Just kind of wanted to get your gut take on how much data you are going to need, kind of timing, and how impactful these enhanced completions could be, because it does look like every well you've kind of just annotated on the map here, of recent wells, is 25% or higher above kind of peak rates versus what you have in the type curve here. Thanks.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. So, I think that – go back to 100 well base though. I think what's really important about that is, we've drilled east, west, north, south across that 200,000 acre legacy position over there in Kingfisher and Canadian counties. So, we have a good data set. So, it's well founded. On top of that, you've got a lot of activity by others now, and the Devon would be one that comes out, the recent transaction that's now Marathon over to the east, you got a lot of data that you can put down on that footprint, say, wow, there is lots of really, really good wells being drilled. If you time vintage them over the last four or five years, you'll see a general continuing improvement as the organization, ours and the industry, the other players in the play, have learned.

So, we're at a good place. You are correct. I'll say it again, that the 1.1 million barrels is based upon Newfield's operated data, 10,000 foot laterals in that core footprint. So, we haven't used any of the acreage to the west, any of the acreage in any of the other areas. So, that's the basis for that comparison. And frankly, it's just the progression of the things that we've been doing in terms of optimizing completions. Crystal clear, but a very important point. I think you were good to follow-up on it.

Michael Dugan Kelly - Seaport Global Securities LLC

Just quickly for me too. I know that's an average type curve across the Kingfisher, Canadian area. Could you give us a sense on how much variation you have in there between really where do you think is true hotspots and maybe something that's more on the fringe? Thanks.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Yeah. I would tell you that we've been consistent on this since day one. It's been – the play has been incredibly consistent across that footprint. Where we have the data, we've had incredibly consistent performance, both Newfield operated wells and outside operated wells. So, we understand it. It's easy to understand. The 1.1 million barrels is a good representation of that area. So, that's reiteration.

Beyond that, since it's been consistent, we also said peak 10P/P90 ratios have been very tight in this play. One of the tightest of all the plays that we've studied. That remains true. And you all know that since it's an average, there'll be some wells above it, some below it. But that's a good representation of what the average well looks like, based on that data set.

Operator

Thank you. And that concludes our time for Q&A. I'll turn the call back over for any closing comments or remarks.

Lee K. Boothby - Chairman, President & Chief Executive Officer

Well, again, hopefully you can tell our team is excited. I'm happy to – really pleased to be able to put these results out. It's good to get the Texas divestiture on the board and behind us. We're excited about back half of the year. I appreciate your interest and investment in Newfield and we look forward to updating you on the road ahead. Thank you very much and have a great day.

Operator

Thank you. That does conclude today's conference. You may disconnect at any time and have a great day.

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