Newfield Exploration Management Discusses Q1 2014 Results - Earnings Call Transcript

Apr.30.14 | About: Newfield Exploration (NFX)

Newfield Exploration (NYSE:NFX)

Q1 2014 Earnings Call

April 30, 2014 11:00 am ET

Executives

Lee K. Boothby - Chairman of the Board, Chief Executive Officer and President

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

Lawrence S. Massaro - Chief Financial Officer and Executive Vice President

Analysts

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Subash Chandra - Jefferies LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Dan McSpirit - BMO Capital Markets Canada

Richard M. Tullis - Capital One Securities, Inc., Research Division

Philip Cannel

Operator

Good day, everyone, and welcome to Newfield Exploration's Fourth -- First Quarter 2014 Earnings Conference Call. Just as a reminder, today's call is being recorded. And before we get started, one housekeeping matter.

Our discussion with you today will contain forward-looking statements, such as strategic initiatives and plans, estimated production and timing, drilling and development plans, expected cost reductions and planned capital expenditures.

Although we believe that the expectations reflected in these statements are reasonable, they are based upon assumptions and anticipated results that are subject to numerous uncertainties and risks.

Actual results may vary significantly from those anticipated due to many factors and risks, some of which may be unknown. Please see Newfield's 2013 Annual Results -- Reports on Form 10-K and subsequent quarterly reports on Form 10-Q for a discussion of factors that may cause actual results to vary. Forward-looking statements made during this call speak only of today's date, and unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements.

In addition, reconciliations of non-GAAP financial measures to GAAP financial measures, together with Newfield's earnings release and any other applicable disclosures, are available on the Investor Relations page of Newfield's website at www.newfield.com.

Before turning the call over to the Chairman, President and Chief Executive Officer, Mr. Lee Boothby, let me provide a housekeeping request. [Operator Instructions] Mr. Lee Boothby, please go ahead, sir.

Lee K. Boothby

Thank you, operator. Good morning, and welcome to our first quarter 2014 conference call. We're off to a great start in 2014. Our operating personnel helped us post another great quarter, and we are executing extremely well across our domestic focus areas. We look forward to providing you with today's update and taking your questions at the end of our brief prepared remarks.

I'm joined today by other members of our management team including our CFO, Larry Massaro; Chief Operating Officer, Gary Packer; and Steve Campbell, Vice President of Investor Relations.

Let me open today with some highlights from the first quarter. On February 10, we closed the sale of our Malaysian business for approximately $900 million. This was a very tax-effective sale, and proceeds were immediately used to fund a portion of this year's capital budget and to repay all of the borrowings under our revolver. We fully restored the capacity under our $1.4 billion revolver.

Our first quarter production exceeded the mid-point of our guidance by more than 400,000 barrels equivalent. Let's talk for just a second about oil growth, not liquids, but oil growth. Our oil growth in 2014 is largely back-end-weighted. The planning of new pads in proven plays like the Williston and the ongoing development in the Anadarko and Uinta Basins. We expect that our second half 2014 oil production will be nearly 15% higher than our first half oil production. In short, we expect that our second half oil production will grow by more than 1 million barrels over the first half. Again, we are focused on oil growth, and that is driving our forecast expansion and cash flow.

The cost and expenses for the quarter were in line with guidance, and the projected improvements over 2013 and our cash operating costs are materializing. The efficiencies in our operating expenses are leading to higher margins and improved earnings.

In February, our midstream partner in the Anadarko Basin completed a significant upgrade for our SCOOP system. We are today producing more than 35,000 net barrels of oil equivalent in the SCOOP and STACK, and remain very confident in the growth trajectory outlined in our 3-year plan.

I continue to be very impressed with the results being posted in both our SCOOP and STACK plays. In our @NFX publication, we provided updates to our average performance versus the tight curves outcast 400 days. Please note that the average of the 23 wells and SCOOP wet gas and the 15 wells and SCOOP oil continue to track above the tight curve. In STACK, we now have 11 producing wells across an area in excess of 300 square miles, and the average production data show outstanding conformance to the type curve, out to 600 days.

The key in resource plays is to meet and/or beat the statistical averages the data set grows and expense. Stay tuned for more good news as 2014 unfolds.

In the Uinta Basin, we are today drilling SXL wells in the Wasatch and Uteland Butte formations. Several of the wells are online, and we plan to share longer-term production data with you around midyear. We are encouraged by both the early production and the recent progress we are making to lower completed well cost and enhance returns. The Williston Basin and Eagle Ford teams continue to execute extremely well in these oil developments. These plays will each grow by more than 35% year-over-year. More importantly, efficiencies of full field development are translating to the bottom line as these plays are helping to drive the improvements in our overall cost structure.

Gary Packer will cover more play-related highlights with you shortly. I like where we sit today. Our leadership team clearly understands what it takes to be a premier, and the key is to creating shareholder value. The ingredients include solid execution quarter-after-quarter, deep inventory, high-quality drilling prospects, sustainable profitable growth and production and reserves, and strong capital structure. We've completed our transition to a liquids company, and we are combining strong liquids and cash flow growth with an improving outlook on cost. We are focused on delivering the targets outlined in our 3-year plan.

When executed, this plan delivers a 20% CAGR in cash flow and liquids production. We're on course to improve our debt-adjusted production growth on a per share basis, it navigates our program where our capital investments and cash flows are more in balance. We're confident that we are taking the right long-term steps to create value for our stockholders.

Before we get into our operational update,

let me quickly cover our first quarter financial and operating highlights.

Excluding the items noted in our news release, our net income from continuing operations was $60 million or $0.44 per share. Cash flow was $345 million. Both earnings and cash flow in the first quarter beat consensus estimates. First quarter production from continuing operations was 10.7 million barrels of oil equivalent, which exceeded the mid-point of our guidance by about 400,000 barrels of oil equivalent. Our discontinued operations provided another 1 million barrels of oil equivalent during the quarter. The China production was approximately 200,000 barrels.

We are pleased with how our cost and expenses came in for the first quarter of 2014. As you know, our 3-year plan is modeled around improvements in our cost structure, which are driven by efficiencies in our developments. With Malaysia sold and China being a very small part of this year's production, investors can now see the Newfield of the future much more clearly. We invested $397 million in our domestic business in the first quarter. $26 million went to discontinued operations. Our outlook for 2014 capital expenditures is unchanged and remains approximately $1.6 billion.

Before I turn it over to Gary, let me update you on our China sales process. We are completing our underwater inspections of a jacket and making plans to make repairs early this summer. We expect to reschedule the installation of the LF 7 topside facilities for the third quarter and to achieve first oil production in the fourth quarter of 2014. We continue to work with our bid group on the planned sale of China. We anticipate resolution later this year. We will keep you informed as more information is known. I'll turn it over to Gary.

Gary D. Packer

Thanks, Lee. Let me give you a quick summary of our drilling programs, starting in the Anadarko Basin. SCOOP and STACK plays have certainly received a tremendous amount of attention in recent months. In fact, there are more than 35 industry rigs running in these plays today.

Our first quarter net production in the Anadarko Basin averaged 29,500 barrels of oil equivalent per day. We are producing today well more than 30,000 barrels equivalent per day net. The 2014 growth forecast is on track, and we still expect to exit 2014 with nearly 50,000 barrels of oil equivalent per day of net production.

The Anadarko Basin will receive nearly 1/2 of our 2014 capital investment this year. SCOOP and STACK plays are allowing us to combine high rates of return, a large operated acreage position, high working interest and rapid liquids growth. We remain extremely excited about our results to date. See, the Anadarko Basin is capable of driving our corporate growth in cash flow and production well beyond our 3-year plan.

I laugh when we get the frequent question, when are you going to go faster? Keep in mind, we have moved from the 1 operated rig in 2011, when we drilled our first well in the STACK area, to 4 operated rigs in 2013. Now, we're up to 8 operated rigs today. We've doubled our investment in the Anadarko Basin over the last year. We continue to look for more ways to efficiently move dollars toward the basin.

It's easy to go fast. The challenge is doing it efficiently and honor the commitments we have made in regards to our balance sheet. So where are we today in SCOOP and STACK? I'll start with SCOOP. We continue to see strong performance from our wells. 6 of our 8 rigs are -- operated rigs are running in the Basin. In yesterday's news release, we published a summary table on our first quarter well results. Rates are consistent with our previous wells. In today's @NFX, we plotted all of our wells against our tight curves.

Based on the drilling data set, we are very confident in delivering on our 3-year plan. The SCOOP investments are generating the highest returns in our company today. Our activity to date, as well as industry activity, has been heavily focused in the SCOOP South Wet Gas play where 21 rigs are running.

In 2014, we plan to drill about 20 Newfield wells in the South Wet Gas and about 25 wells in the South Oil. We continue to see solid efficiency gains in the SCOOP drilling program.

In our first quarter, the drilling cost per lateral foot decreased 17% when compared to our average of 2013. We've modified our casing designs, increase our lateral lengths, moved to more [indiscernible] development pads, improved drilling penetration rates and reduced downtime between wells, a true team effort. A significant upgrade was recently completed on our SCOOP midstream system. We now have 200 million cubic feet a day of gas processing capacity.

As we mentioned earlier, we had about 4,500 barrels of oil equivalent per day curtailed for this first 6 weeks to the year. This expansion allowed us to return all of our curtailed wells to full production and tie in recent completions. We expect the second upgrade this September to add an additional 80 million cubic feet a day of gas processing capacity.

In the second half of 2014, we'll be drilling our first operated wells in North SCOOP. This is about 40,000 net acres that sit north of SCOOP and south of STACK.

There are 10 industry operated rigs running in this area today. We have participated in several wells to date and are very encouraged by the early returns that we are seeing. Stay tuned for more information from us later this year.

Over the next 2 years, our production from the Anadarko Basin is expected to become more oily as we shift drilling activity into our STACK play. We have more than 150,000 net acres in STACK, and our working interest average is about 60%, which is very high for Oklahoma. In addition, as the name implies, we have STACK geologic pace in the Woodford and Meramec Shales that provide up to 700 feet of hydrocarbon column to exploit.

In addition to the Woodford and the Meramec, other prospective formations exist. We plan to test them in the future.

Our 2014 STACK program has several objectives. First, we are drilling the whole acreage. We plan to drill about 20 SXL STACK wells for 2014, and for the next 2 years, our drilling program will be largely dedicated to HBP efforts. The second objective is to learn more of the optimal development well spacing. We are placing our wells on adjacent east-west section boundaries and gathering spacing data as we HBP. Each SXL well holds 2 sections. Third, we're quickly delineating, and therefore, de-risking our acreage. To date, we estimate that our drilling has de-risked about 1/3 of the STACK acreage. Our 2014 program will test the boundaries of our acreage and we expect it will delineate and de-risk about 70% of our acreage by year end. And fourth, we plan to drill about 20 wells this year and are testing multiple objectives in the STACK. We will be coring wells in several areas, staggering adjacent Woodford and Meramec test, as well as drilling upper and lower Meramec wells on tighter spacing.

If production results on 10 STACK wells to date, then about on end, 30-, 60- and 90-day rates remain strong. Our longest-producing STACK well has now been online for about 3 years. This was a short lateral drilled in 2011 to test the exploratory concept.

Well, that has now been online for 920 days and the production is still 65% oil, and the cumulative production is 73% oil over a 3-year period.

This well gives us confidence in our tight curves and future oil growth projections. We have 2 rigs running in STACK today. We have production results on all of these wells, and we feel very strong about their performance.

Our first net -- our first quarter net production in the Uinta Basin averaged just under 25,000 barrels of oil equivalent per day, slightly exceeding our plan. In the Uinta Basin, we are advancing 2 plays, the ongoing development of our Monument Butte waterflood and the ongoing assessment of our horizontal plays in Central Basin. We are, to date, drilling our first handful of SXL wells in the Central Basin and we are encouraged with our early results. We're drilling wells in both the Uteland Butte and the Wasatch plays with lateral lengths approaching 10,000 feet. As proven in multiple other plays, SXLs lower completed cost per foot, maximize production rates, improve EURs and rates of return. We have 2 operated rigs running in the Central Basin today and plan to drill about 15 SXL wells this year. Around midyear, we will have production history on about a half dozen or so SXL wells to update you upon. We remain confident that SXLs will be the key to unlocking the economic value of the vast resource in the Central Basin. We have the necessary permits in hand today to execute our 2014 program, and we continue to have constructive dialogue with state regulators and permanently amend field rules to roll out for SXL's development in the future.

Our investment levels and near-term growth outlook in the Uinta Basin will continue to be determined by the timing of refinery expansions, the regulatory environment and our internal pledge to allocate our capital to the projects with the best returns.

As you know, we have agreements in place with both HollyFrontier and Tesoro that add about 20,000 barrels of oil per day of new capacity in the Basin by 2016. New transportation initiatives, both rail and pipeline, provide encouragement that our future crude growth will not only have a home, but the potential to receive more favorable pricing in the market.

In addition to rail, one of our refining partners continues to advance discussions and planning for a 60,000 barrel of oil per day oil pipeline on the Uinta Basin into Salt Lake city.

The Williston Basin and Eagle Ford developments are progressing extremely well. These plays are benefiting from the synergies of full field development through SXL wells, common drilling pads, shared facilities and use of in-place infrastructure. They're delivering solid returns and providing free cash flow to fund our large-scale programs in the Anadarko and Uinta Basins.

In Williston Basin, we continue to run 4 rigs and expect to drill about 50 operated wells this year. The first quarter production averaged nearly 15,000 barrels of oil equivalent per day. This is about 10% higher than our fourth quarter 2013 rig. We are on track to grow our Williston production to about 40% this year with a consistent 4-rig program.

We brought online 16 wells in the first quarter, including 12 that are Bakken wells and 4 wells in the first member of the Three Forks. As always, we show 30-, 60- and 90-day production averages and add-on effects. Our Williston Basin wells averaged initial production rates of about 2,400 barrels of oil equivalent per day, and our recent 10,000-foot SXLs were drilled and completed for an average of $8.4 million, including facilities.

Our Williston team is executing extremely well and building on the efficiency gains achieved over the last 2 years.

In the Eagle Ford, our first quarter production averaged over 11,000 barrels of oil equivalent per day and in line with our planned expectations to grow year-over-year volumes by about 30%. We reduced this year's drilling program in the Eagle Ford to one rig, which allowed capital to flow into the Anadarko Basin, as previously mentioned. We expect that our one-rig program will hold current production levels relatively flat throughout the year. One rig will allow us to drill about 20 wells.

I'll turn it back to Lee for closing comments.

Lee K. Boothby

Thanks, Gary, and thanks to you, all, for dialing in today. We appreciate your interest in our company.

We're off to a great start in 2014. We beat first quarter production expectations, and our cost and expenses are exactly as modeled. Our operating teams are executing extremely well, and we are focused on delivering on our 3-year plan, which combines liquids growth with cash flow growth and improving margins and profitability. As we said in February, we believe the achievement of these objectives will lead to improved net adjusted production and reserve growth metrics and lower leverage ratios, and we intend to deliver. This time, we're happy to take your questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

The first question is just to achieve the 50,000-barrel a day exit rate that you're targeting in the Anadarko Basin, can you just summarize for us what you need on the midstream side for in terms of the STACK and the SCOOP for processing and takeaway? And then the follow-up question is the -- I believe this quarter, you did test the Lower Meramec. If you can give us any color on that well?

Gary D. Packer

As far as the takeaway for the exit of this year, we referenced in the call that we have 80 million cubic feet a day that we're going to be bringing online in -- early in the third quarter. And those are the requirements that we see to make the 50,000-barrel-a-day number. And as far as the deeper test, that well is currently drilling as we speak. And it's called the Brueggen, I believe.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

So that will come out with 2Q results?

Gary D. Packer

Once we have the 30-, 60-day numbers, we'll have it out to you.

Operator

Our next question comes from the line of Leo Mariani.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

I was hoping you could maybe speak a little bit more in terms of what you're seeing on rates of return on your STACK wells. I know it's early, and sort of how those kind of compare with SCOOP?

Gary D. Packer

Really, nothing more to add other than what we showed in February with -- we just have the 2 initial wells and they're in line with expectations. We generated a return on the first 8 wells of about 35%. We expect that just to get better as they do on all these plays. And that's very competitive in the portfolio and in our space. They're not going to compete with SCOOP wells, which are some of the best in the industry. But we feel like both of them certainly deserve capital allocation in our program.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess, as you guys progress into 2015, you talked a little about, in your prepared comments, about need to sort of HBP more STACK. Does that mean we could see more rigs kind of move to STACK next year to satisfy those requirements versus SCOOP?

Gary D. Packer

Well, the current plan contemplates that we will HBP from -- many of these leases already have built-in expansion capabilities. We are examining all opportunities to reallocate capital and move incremental rigs into the area, and I think Lee referenced that in the call. So it's not currently built into our plan. Rest assured that we're looking at every alternative, and whatever we do will be accretive to the information we've already outlined in our 3-year plan.

Operator

Our next question comes from the line of David Tameron.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

In the STACK, if I look at those 90-day rates, it ticked up a little bit from the 60-day. Is that just particular to these 2 wells or is that something you're seeing with some of the more recent wells you drilled, including the ones at the end of last year?

Lee K. Boothby

I think it's important to remember, when you look at STACK, and I think we've got a total of 11 wells in the curve that we published, obviously, the newer wells, when you look at the details, sit inside of the 90-day rate. We've seen outcomes above and below the type curve. The average sits right at or just above the type curve. So we're very, very encouraged of what we're seeing. As mentioned earlier, we continue to step out and test the limits of the play. I think that's one of the features that we're going to be working on in 2014. And I would say at this point that we've had a number of issues. Remember, it's HBP, not development. So all kinds of infrastructure related to managing developments and optimizing lift and all that stuff, that's still yet to come. I think when you look at the Mary well, which I think was a new [indiscernible] lease, that's a well that has continued to get better and better throughout its first 4 months or so of production. So you've got a lot of different things going on in terms of completion optimization, lift optimization, and we're in HBP mode, not development. That's the key to keep in mind when you think about looking at these results. I see a lot of people take head fakes on individual well data without having any understanding on what's going on out in the field. It's a path for fools. So I would say be careful, those of you that are tempted to go down that path.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. And then for my follow-up, let me choose. Uinta, and you guys have -- I guess, in the fourth quarter when you previously talked about it, you talked about that weighing of XL -- or SXLs being more Uteland Butte than Wasatch. Is that still the plan? And can you tell us what your well cost run out there versus what you think a target well cost may be?

Gary D. Packer

Dave, we continue to look to balance that out. I would suggest to you that in your -- you said it accurately, we had more Uteland Butte than Wasatch at the end of the quarter. We're going to -- I would suggest that we'll probably see more balance in that as the year unfolds. In regard to the well cost, if you referred to the February @NFX, we outlined Uteland Butte wells in a 10 to 12 range, and the Wasatch well in a 13 to 15 range. We like the progression that we're seeing year-to-date and in capturing the benefits of the SXL, so I think we'll be navigating to the low end of those numbers. And we're feeling more confident everyday that, that's going to be the case. But we still need to drill some more wells to prove that to ourselves.

Operator

Our next question comes from the line of Subash Chandra.

Subash Chandra - Jefferies LLC, Research Division

I was hoping maybe you could compare, contrast when you look at SCOOP oil and STACK oil specifically, against perhaps these other shale plays wherein they're multiphase reservoirs where the oil part, it didn't particularly work well, be it Eagle Ford or Utica. And then my follow-up would be, if that Cana oil was in your original -- or your prior view of what the de-risk acreage is in Cana, which I think was around 25,000 acres.

Lee K. Boothby

I will jump in the first one while it's fresh in my mind. If I miss a part of it, take me back there. I would say that the well that Gary referenced, I think, in the STACK play that has nearly 3 years of production history at this point, or certainly chasing down 3 years. It was drilled early, drilled early in the oil window, drilled well at depth, and it was drilled there on purpose so that we could gather this information and continue to calibrate performance. I would tell you that we've been very, very pleased with the performance that we've seen, both in SCOOP and STACK up up in the oil base. I think that was probably the biggest risk in the play going in. And certainly, we in the industry, we're not in the position to know one play versus another, how that's going to work. The STACK play is all in the oil [indiscernible]. If you think about the well results, now we're seeing consistency and sustained performance over multiple wells across a large area of 300-plus square miles. And everyday that goes by, we get more and more confidence in that regard. And with the planned program, ourselves and the industry, now that the industry has moved into the play, there'll be 40 to 50 wells probably by year end that we'll be able to look at specifically there for comparisons. So I think that the data set is going to be growing at a pretty good clip, and we continue to see consistency there. I think we, you and everybody watching the plays will get very, very comfortable.

And if you move to SCOOP, I would tell you that things have been very exciting down the SCOOP and SCOOP oil as we moved into the oil window, as we've seen much more gas energy than we certainly forecast going into the play. And obviously, having that gas energy for lift and sustained well performance has, net-net, been a positive. And I'd say that, that's a big part of the performance trend that you see now that we're documenting 10,000-foot laterals out past 400 days. So I'd say both of those plays, when you look at them relative to the suite of other plays and other basins and compare the numbers, I think you'll come away feeling very, very favorable.

I suspect, and we're not in the Utica or some of the other plays you referenced, so obviously, we didn't keep up the data but I'd leave our friends in the industry to talk to you about their plays in those areas. But when you cut across multiple plays and cut across [indiscernible], you've got different geology, different phase composition, different pressure regimes. You've got a whole host of things going on, and I don't think it's any one of those factors that you can probably hang your hat on. I think in a number of instances, at least the best I can tell from reading data and seeing presentations from our technical folks, it looks like people have been burned by some bad phase behavior. I would say we've seen none of that to date and in our plays, and that's part of the reason why we're very, very encouraged.

But going back to 2012, before we drilled the first well, we were concerned that was a risk. And I think the production data -- the neat thing about what we're doing is we're not up drilling for a geologic control at this point. We're drilling for production control. So the delineation's actually production delineation, not geologic delineation of these plays. And that's a pretty nice place to be. Clearly, we hope to see continuation of the good results in the northern portion of our SCOOP acreage, but again, our friends in the industry drilled a number of wells there, a lot of rig activity up in that area. We like the results and we expect to see success there. But that's an area we haven't drilled any material number of wells at this point with Newfield's tether on it. As far as the Cana question, I'll put that over to Gary.

Gary D. Packer

Well, I guess, I'd just follow up. We talked in the -- we previously referenced to 150,000 acres in the STACK. And when we've been on the road with many folks, we've referred to some maps and we've talked about how about 1/3 of that acreage position with the 8 wells that we've had to date, I would call production delineated. And we have very consistent results across that, in both the Meramec and the Woodford. The exciting thing about this year, our HBP strategy is going to allow us to reach out to the North and the East across the STACK. And by the end of the year, we ought to be in a position where we're sitting here and talking about 3/4 of our acreage position having a horizontal well in it. A lot of our activity this year is going to be up there in the Meramec, which is, I think, going to give everybody more confidence. And I'd point out that the biggest step out that we've had to date, the Yost [ph] well in the Northwest, is one of our best wells drilled to date. So it's nothing that we fear whatsoever, and it's all within the acreage that we've targeted when we put our lease -- our accumulation together, and we have an abundance of vertical well control across all the positions that says that there's really no difference across the position in which we're drilling. So I'm not concerned about drilling up against edges, and we haven't found an edge in any of the wells that we've drilled thus far. The area to keep a close eye on this year as we continue to expand in the STACK would also -- the other area would be the Northern SCOOP. And we talked about that, 40,000 net acres. Industry has done a heck of a nice job in improving the return prospectivity for that area and it's quite competitive. And you'll see us this year, I think we've got 4 or 5 wells on the board. We'll drill some wells, both in the wet gas, which will be immediately adjacent to those that others have drilled successfully and generating compelling returns. And you'll also see us, just like we have in STACK, about half of those wells will be out more in the oil space. And so stay tuned for that.

Subash Chandra - Jefferies LLC, Research Division

Yes, I'm sorry, Gary, do you have a number for de-risked SCOOP and how the Cana oil phase factors into that number?

Gary D. Packer

I don't have a number off the top of my head. I mean, we've got between, well, I would guess, 75,000 acres in the SCOOP overall. The vast majority of that has a well in it, with the exception of the 40,000 acres in the SCOOP that I've referenced. So I don't have it broken out.

Lee K. Boothby

If you go back and look at the release, we had acreage split out by wet gas, condensate, window and oil window, you'll be able to put the pieces of that together and just recognize the northern portion that, we believe, industry has de-risked a good portion of that acreage. But we haven't drilled our wells there, and that's the 40,000 acres that Gary references. But majority of our SCOOP and STACK acreage is, in fact, in the oil window.

Operator

Our next question comes from the line of Dave Kistler.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, looking at the production guidance, with a production beat above the high end in Q1, you mentioned that production going forward's going to be impacted by timing of completions, various areas in terms of where they're completing, whether it be Williston, Eagle Ford or parts of the Cana. Can you talk a little bit about is that why you're not bringing full year production up with the kind of beat that you delivered or are you being just conservative in nature?

Lee K. Boothby

It's our conservative nature, of course, Dave. I mean, I think that you've been around us, we're certainly conservative. An answer to your question, specifically, we're sitting here at the end of the first quarter, we carried good momentum out of '13, that shouldn't be a surprise to anyone. We're very pleased with the results, but we're 1/3 of the way through the year. The timing issues that you're talking about, pad drilling, we've talked a lot about that over the years. Clearly, I'd love to be able to turn those pads on earlier in time, but when you're drilling multi-well pads, you got to drill, case, complete and there's some volatility in terms of timing related to that, and that's certainly incorporated into our planning, and then the infrastructure issues that Gary have all talked about. So what I would tell you is let us see how the year unfolds. We're very, very encouraged with where we're at. I think we've got good momentum, and we'll get to the mid-point of the year and we'll give you an update. Hopefully, at that point, we'll have enough visibility that we can show you some positive upside.

David W. Kistler - Simmons & Company International, Research Division

Great. And then maybe just diving in the Uinta for a second and your comment about it being currently free cash flow positive. Will that remain the case as you progress on a 2-word [ph] program of SXL development? Or could that go back to a source of capital as opposed to a cash-generative engine?

Gary D. Packer

Dave, as far as the free cash flow, that was in reference to the Eagle Ford and Williston Basin. And those are free cash flow positive. Certainly, as you suggest, the Uinta Basin is going to be a consumer of capital, as we seek to accelerate the resource that we have there. But that certainly will not be the case in the Uinta overall.

Operator

Our next question comes from the line of Jeffrey Campbell [ph].

Unknown Analyst

My first question was regarding the Gregory pad. It looked like it had some pretty favorable-looking declines [ph]. And I was wondering, is this a geological effect or does it reference some reservoir pressure control regime?

Gary D. Packer

It's -- the only significance I would caution -- or call out on the Gregory pad is that you're right, they are performing quite well. The 2 important things about that are: One, it's a 5-well spacing. And based on those early production results, we certainly feel good about that. The other thing is they're only XL wells. These are just 5,000-foot wells. And the only reason we would have drilled those as XLs is because we had an offset spacing unit with another operator or we would have drilled this longer. I think what you're on to here, Jeffrey [ph], is just the normal variability in results that you see across any one of these resource plays, and nothing more than that. And then certainly, we're pleased with them, but I wouldn't say it's any one more thing than the other. As you know, in the SCOOP area, as you move east to west, there's variability that exists in oil and gas yields, and you're seeing some of that in there as well. But it's just normal variability in a resource play.

Unknown Analyst

Okay. And my other question was it appears that you're currently targeting the Three Forks 1 [ph] in your Williston Basin. I was wondering if you're going to do any exploration in any of the lower zones in the Three Forks over time or have you already arrived at the view that the Three Forks 1 [ph] is it?

Gary D. Packer

No, we've actually drilled a second bench of the Three Forks well last year and it was a good well for us. Just with the capital that we've allocated to the programs today, we're more heavily weighted to the Bakken and the Upper Three Forks. And we're going to allow our industry partners to kind of show us the way as far as some of the deeper benches. We are constructive on the second bench for sure up on the west anticline, where we drilled and others have drilled, and we like what's been seen there. But as far as beyond that, we're going to allow others to take a lead in that.

Operator

Our next question comes from the line of Michael Rowe [ph].

Unknown Analyst

I just had a quick question on the 4 SCOOP wet gas XL wells that you're showing here. I think these were 4,800-foot laterals, which should be lower kind of than the published type curve that you all have for the region. So I was just wondering sort of how are these -- how the performance of these wells comparing relative to your expectations? And what may the capital costs be on these, just given their short lateral length?

Lee K. Boothby

As far as the -- I'll talk, but Gary has [indiscernible] to say here. But as far as the performance, clearly, the place to look is yield per lateral foot. And I would say we've seen good conformance statistically in terms of yield per lateral foot or yield per thousand lateral feet. We believe the optimal wells where we can drill them are the 10,000-foot SXL wells. But as Gary indicated, there are a number of circumstances where geology or offset ownership and things of that nature stand in the way of 1,280-acre spacing units. In those occasions, then we'll look to drill 5,000-ish foot laterals. And so anything that's sub-5,000-foot lateral means that they've been drilled on a 640-acre spacing unit. And you're going to see the same where there'll be some areas that produce higher-than-the-average yield per thousand feet, and some will produce lower, but we've seen good conformance, relative to the yield per thousand lateral feet across the play today. Good enough for you?

Gary D. Packer

Yes, I think -- I'm not concerned about anything that's represented in there. We're going to confine the bulk of our activity to the SXLs in the wet gas window to a degree that we can. We have -- we don't have the 30- and 60-day numbers published for the first quarter, but they appear to us to be in line, and there is some graphics in our @NFX publication that actually does show our type curve relative to actual performance in the wet gas, and that -- the slide that you actually looked at in there includes both XLs and SXLs. So I'm -- we're not seeing any meaningful variability in any of those results. Just normal variability, like I referenced earlier, geologically.

Unknown Analyst

Okay, great. And then, just quickly on the STACK play. With regards to the Mary well, it looked like there was a pretty high oil cut on that. Is there something specific that's driving this or do you think that's just an anomaly and related to the general variability you're seeing across the wells you're drilling in the play?

Lee K. Boothby

The STACK play, as I said earlier, the entirety of that acreage block that we put forward is in the oil window, which means that we're actually drilling forward, from east-west, north-south, black oil. We published, if you go back and look at the data that rolled out over the course of 2013, there's some places where we put out well data in terms of 2-phase production, and you'll see a consistently high oil yield across that data set. So obviously, the Mary is not a surprise in that regard. I think that the exciting part of the Mary is that we've had good, solid, sustained and actually improving performance over the course of the first 4 months of production. So that's the part I'm excited about with regard to the Mary well, and I think we're able to continue to generate those kinds of results, as Gary indicated earlier, as we move through the HBP phase into development, then the results, returns will just improve over time.

Operator

Our next question comes from the line of Brian Singer.

Brian Singer - Goldman Sachs Group Inc., Research Division

Sticking with STACK. Can you just talk in broadly about how many different horizons you've now tested at STACK, the differences, if any, in performance? And then you may not be planning this because you're in HBP phase, but when you would test multiple horizons on the same section?

Lee K. Boothby

Well, our priority is going to be HBP mode. I think Gary said that earlier. Next 2 or 3 years, we've got a lot of work to do there. We will vary, as he indicated, the offset distances between laterals and where those laterals sit across lease lines from the section, just to start gathering some of the spacing-type performance information that we'll need in the play. But we don't intend to drill any development pilots or tie up rig time working on development pilots. We think we have plenty of time to work that into the program as things kind of evolve, if you will, in that regard. And I think they're going to be kind of measured as we work through the program. So first order of business is focus on HBP. We'll get the data we need to kind of verify our assumptions and spacing data to the extent we can during the HBP mode, then as we move towards development, then we'll get more into the spacing test and pilot. As far as the horizons, I wouldn't get too carried away with the horizons at this point in time. We put out last year that we had tested the upper Meramec and multiple wells in the Woodford and multiple wells at the 700-foot interval. So the way to think about that is the lowermost interval. The Woodford has been tested successfully and the uppermost interval of the upper Meramec has been tested successfully. It's about 700 feet of section. If you split it up into geological horizons, you could think about 4 or 5 different potential increments in there. But I think it's way too early to get caught up in that level of granularity. We just haven't had the time and the well count at this point to capture enough data to give you any more color than that.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, great. And then shifting to the Uinta Basin, you mentioned add-on effects, the thing you mentioned on the call, the pipeline and then a refinery expansion. Can you just talk about a little bit more detail about what you think the timing is there? And is this something that is going to be where Newfield is going to be a unique supplier? What type of market share do you think you can get?

Gary D. Packer

As far as the circumstances of the pipeline expansions, we have -- Tesoro has a turnaround in first quarter of 2015. And then they're essentially be at full capacity there in the first half of the year in the -- we'll start ramping up HollyFrontier's expansion in the back half of '15, and we'll hit our full stride there in early 2016. That's going to allow us to be at about 38,000 barrels a day of committed capacity from those 2 refiners. And 2016, we believe we'll have capacity to be producing well in excess of that. We do have relationships and we'll have deals in hand with some other refiners. That'll put us somewhere around 45,000 barrels a day or so. I hope that they'll put us in a position, our teams, that we can be well north of that. And that's really what it's going to take for us to either get some other refining projects in hand or more aggressively pursue rail. And we'll probably, at that point, get into the plays that we can talk about for longer terms agreements with some of the rail providers. I don't have the numbers off the top of my head regarding the market share. I do know that each of those refiners are, in fact, refining some of our -- the other basin crude. But I can't tell you the percentage. We are far and away the largest producer, and control most of that market share.

Operator

Our next question comes from the line of Jimmy Hubert [ph].

Unknown Analyst

Jimmy Hubert [ph] from Iberia [ph] Capital. In the STACK play, I had a question. If you have 20 STACK wells planned for 2014, how many of those are Meramec and how many would be Woodford?

Gary D. Packer

Yes, it's like 2/3 of the wells are Meramec wells and the balance being Woodford.

Unknown Analyst

All right. And are there different lateral lengths for the 2 zones? Or do they -- do you drill both at the same lateral length?

Lee K. Boothby

Our plan is to maximize lateral lengths. We'll drill 1,280-acre spacing units every opportunity we get. So you'll see delivered lateral lengths around 10,000 feet or just over.

Unknown Analyst

Okay. And then just one more question. The wells into the 2 different zones, the Meramec and the Woodford, what are the costs per well for each different zone there?

Lee K. Boothby

There's not a material difference between drilling the Woodford and the Meramec. There's only 700 feet of vertical section from the base of the Woodford to the top of the Meramec. So you can think about those wells in terms of to date, performance and cost, they're very, very similar.

Unknown Analyst

And what are the cost per well, you think?

Gary D. Packer

Those wells range from $9 million to $12 million in the STACK, both in the Woodford and in the Meramec, Meramec, as we referenced. The biggest variability there has been our completion cost. We continue to be able to find ways to improve our stimulation, which oftentimes has a higher cost, but greater EURs as a result of that. But we would be navigating to the low end of that once we get a few more wells under our belt.

Lee K. Boothby

You can go back to last year, we talked a lot about the distance between cluster-per-cluster spacing and we talked about reduced per cluster spacing. We cut the per cluster spacing roughly in half during the course of 2013. So fracture and testing [ph] along the lateral for the same delivered cost today is about 2x what it was entering 2013. Those were all good things.

Operator

Our next question comes from the line of Dan McSpirit.

Dan McSpirit - BMO Capital Markets Canada

Just turning to the Williston Basin, would you estimate to be the inventory of drillable locations remaining, both Middle Bakken and Three Forks? And when do you see production actually peaking from your Williston Basin operations?

Gary D. Packer

Well, obviously, Dan, it's all about how many wells -- how many rigs we allocate to the play. Right now, we're sitting here talking about 4 rigs for the foreseeable future. We do grow outside of our 3-year plan, our production volumes. And we've been talking now about anywhere between 300, 350 wells for quite awhile. And what we've found is, is that as far as our inventory, and what we found is, is that as we've been able to drive our cost down, we've been able to unlock plays that were previously uneconomic, but now, certainly, compete within our portfolio. So I think that's -- that number has a bit of a moving target to it, but that's generally speaking where we're at.

Dan McSpirit - BMO Capital Markets Canada

Got it. Helpful. And then just turning to the balance sheet quickly here, can you sketch for us how leverage is expected to trend over 2014 and periods beyond? Certainly, we can see it going lower. I just want to get a better understanding of that trend and how capital is invested in the operations.

Lawrence S. Massaro

Yes, sure. I'll take that. This is Larry. As you've seen, we've been debt suspending across our planned period. Our goal is to get to 2016 and look to try and get to free cash flow neutral then. That's what we kind of put out earlier this year in our February release. As far as this year is going, we're right on track. We're probably a little bit better than we thought at the beginning of the year, where we're still generating a deficit, and we look to cure that through the assets that we've already talked about. So we'll fund the deficit through the sale of our international, and get to 2016 and be cash flow neutral.

Operator

Our next question comes from the line of Richard Tullis.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Looking at the Eagle Ford, I know we haven't spent that much time on it, it's not really a big part of your current activity, but you did see a real nice increase in initial rates, I guess, 30%, 40% there. Was that mainly a function of changing completion method or maybe more focus on the 2 areas, West Asherton and Fashing?

Gary D. Packer

I mean, as far as overall, you have some certainly leasing timing issues regarding the pads that we were bringing in. We've also been playing around with spacing between wells. And the wells that you are seeing that maybe showing up in the public arena are seeing a slightly higher IP and a little better decline profile. And it's just a result of us continuing to identify what the right spacing is.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay. And then lastly, what's driving the increase in the LOE cost guidance? I guess, it's up about 5%. What are the main drivers there?

Lee K. Boothby

On a unit of production basis, it's down quarter-over-quarter and through the year. But the main driver in absolute dollars is just, frankly, higher production.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay. Well, you haven't raised the full year guidance though, right?

Lee K. Boothby

No, we took it up just a little bit. I think you'll see another $7 million or $8 million [indiscernible]

Operator

And our last question comes from the line of Philip Cannel.

Philip Cannel

Could you break out further, the mix in terms of liquids in both the Williston, the 12,900 per day, and the EFS at 11,000? What's oil, what's NGL?

Gary D. Packer

If you look at our February guidance, we break out average liquids per play. But our Eagle Ford play is north of 85% black oil, and the Williston Basin is around 70% black oil.

Philip Cannel

Okay. And in terms of the SCOOP, if you look at the decline curves from the wet gas to the oil, why do you think that we're trending toward the decline curve on the wet gas, but yet, the oil curve, if anything, is even moving farther away from the decline curve? [indiscernible] in both the 2 wells at this point to kind of make a decision or should [indiscernible] the curve?

Lee K. Boothby

The thing to remember about those curves, those are average curves for the wells that have been drilled, completed and brought online in that timeframe. So when you get to the endpoint, you've got one well. So whatever the oldest well in that data set sitting out there, so you see that well. So as you move back through the curve towards zero, you get the highest number of wells in the average. And frankly, that data is better data than looking out there on the tip. So it's there as a mechanical calculation, but the reason it looks like it's down is just simply you're looking at data from the oldest well. And at the front end of that curve, you've got 23 wells, and at the very end, you've got 1. The same as across both of those curves. In the case of the wet gas, the curve, the oldest well, is slightly below the trend line. And in the case of the oil that you're looking at, the oldest well is slightly above the trend line. Just a statistical aberration.

Philip Cannel

And do you think that we expect these to change significantly with the increased number of wells that are going to be drilled this year? I mean, is there any way to know?

Lee K. Boothby

I would take you back to our tight curve. That's how we build all our models. That's what we're looking at. We're continuing to step out and evaluate and optimize. We're encouraged that these are running above the type curve. It will be a happy day if that turns out to be the ultimate field level average, but we give you both so that you've got a reference point. Again, I think the key point is we're off to a good -- great start in 2014. We're excited about the results being posted in these key plays. We've got exciting results yet to come out later this year. Stay tuned. We're going to give you the data timely. We're going to give it to you in a form that you can understand, and frankly, we look forward to having these conversations.

So with that, I'd just like to tell everybody thank you very much for tuning in today, and we look forward to talking to you again in July, and we'll have some more good news to talk about. Have a great day.

Operator

Thank you, ladies and gentlemen. This does conclude our conference for today. Thank you for your participation. You may now disconnect.

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