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Newfield Exploration (NYSE:NFX)

Q1 2013 Earnings Call

April 24, 2013 9:30 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

Analysts

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

Subash Chandra - Jefferies & Company, Inc., Research Division

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

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

David Heikkinen

Peter Kissel - Howard Weil Incorporated, Research Division

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Dan McSpirit - BMO Capital Markets U.S.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Operator

Good day, everyone, and welcome to the Newfield Exploration's First Quarter 2013 Earnings Conference Call. Just 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 our 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 2012 Annual Report on Form 10-K and subsequent quarterly reports on Forms 10-Q for a discussion of factors that may cause actual results to vary. Forward-looking statements made during this call speak only as 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, please let me provide a housekeeping request. [Operator Instructions] Mr. Lee Boothby, please go ahead, sir.

Lee K. Boothby

Thank you, operator. Good morning, everyone. Thanks for joining us today for our first quarter conference call. Operationally, we're off to a great start in 2013. In fact, we're right where we want to be towards our execution of our 2013 through 2015 plan and we're looking forward to sharing our updates with you today. As always, members of our management team are here today to answer your questions following our prepared remarks.

In late 2012, we made some strategic decisions that defined Newfield's future direction in our path to long-term value creation for our stockholders. First, the future of our company is in North America and we are now laser focused on delivering profitable growth from our 4 domestic growth engines, the Cana Woodford, the Uinta Basin, the Eagle Ford and the Williston Basin. You will see that our progress this year to increase the liquids production, lower drilling costs, optimized completion practices and improved overall project returns, provide significant encouragement across all of our liquids focused plays.

Second, we're on track to deliver strong domestic liquids growth in 2013, '14 and '15. Our track record of more than 20% compound annual growth rate in domestic liquids production growth over the last 4 years, helps to validate the growth potential of our assets and we believe our 2013 domestic liquids production should increase nearly 40% over last year.

We'll provide some additional comments later on the strength of our production and helpful guidance for the next quarter.

And third, as we announced at year-end, we are exploring strategic alternatives for international businesses. These are quality assets with proven people, a track record of execution and significant upside through our prospect inventories. Our recent 1.5 trillion to 3 trillion cubic foot original gas in place discovery certainly validates the quality of our inventory and the upside in our Malaysian business. The process is progressing well and we expect to have our data room open in early May.

I'm absolutely confident that we're making the right strategic decisions to build value for Newfield stockholders. Our leadership team understands the critical importance of superlative execution in 2013 and we are united in our plans to deliver on our results. You will see today that our first quarter accomplishments are certainly a step in the right direction.

Let me share a few of our exciting highlights to kick off the call.

Our Cana Woodford production in the first quarter was ahead of our original plan. We continue to see very strong oil performance and our economic footprint is expanding. Our most recent wells have averaged nearly 2,000 barrels of oil equivalent production per day, that's gross initial production, and our 60-day average gross production is about 1,300 barrels of oil equivalent per day.

As we have proven time and again, our drilling performance and scalable resource plays shows rapid learning curve advancements over the first 2 to 3 years. In the first quarter, we lowered our drilling case cost per foot by about 30% when compared to our 2012 actual results, and 20% compared to our fourth quarter 2012 results. We're now drilling and casing our South Cana wells for about $925 per completed foot. And we expect to continue to show future efficiency gains as our development progresses.

From our working interest in outside operated wells we know that we are leading the way in achieving these efficiencies in the Cana Woodford. And there's additional information in today's @NFX to illustrate this point. In the Williston Basin, we delivered some of our best wells to date during the first quarter. As a result of recent wells and better-than-expected performance from our existing wells, we've increased our growth estimates for the Williston Basin. We now expect our Williston production to grow 25% year-over-year compared to our original target of about 15%.

Our 4 most recent Bakken wells had average initial gross production rates of more than 3,100 barrels of oil equivalent per day and nearly 1,000 barrels of oil equivalent per day over their first 30 days. During the first quarter, we also drilled 2 Three Forks wells with an average gross initial production of nearly 2,400 barrels of oil equivalent per day and they averaged nearly 900 barrels of oil equivalent per day over the first 30 days.

In the Williston, we continued to show well cost improvements, excluding about $900,000 in facility and artificial lift cost, we are now drilling and completing our wells for $8 million to $8.5 million. Our average completed well cost in the Williston for our Super Extended Lateral wells in the first quarter was $8.9 million and we recently drilled and completed a best-in-class well for $7.4 million. Including facility and artificial lift cost, our average gross completed well cost in the Williston in the first quarter were $9.8 million.

In the Eagle Ford, we continue to post solid efficiency gains by drilling Super Extended Laterals, or SXL wells, as we call them, we believe that the longer laterals improve returns and we're implementing them across the company's portfolio today.

In the first quarter, our average well cost in the Eagle Ford were $7.7 million, down from a fourth quarter 2012 average of about $8.4 million. We are now drilling exclusively for multi-well pads in our West Asherton area and are today completing a batch of 6 new wells. These completions will help drive that 12% quarter-over-quarter liquids growth that I referenced earlier.

Lastly, we're progressing well in the Uinta basin, both in the greater Monument Butte unit and in the Central Basin region. Our early 2013 focus has been on improving drill times and optimizing our completions in the Uteland Butte. During the first quarter, we completed 4 additional Uteland Butte wells, with an average gross initial production of about 1,000 barrels of oil equivalent per day.

Recent results are consistent with our prior wells and provide us with continued encouragement on the size of this resource and our future growth outlook. All of these wells had lateral lengths of about 3,800 feet.

In March, we spud our first Super Extended Lateral well in the Uteland Butte, a 9,900-foot lateral, results are expected midyear. Later in the call today, we will discuss our plans to drill longer laterals in multiple zones across the Central Basin.

Our Uinta production is expected to grow about 10% in 2013 and 20% in 2014. This increase comes to the addition of new refining capacity in the Salt Lake City region. Although we have the refining capacity in hand today to execute our 3-year plan, we continue to explore other options to move crude out of the Uinta basin and into new markets. These new markets could provide competition for our crude, better price differentials and allow us to grow future oil volumes at a quicker pace. Before we move to a more detailed discussion of our focus areas, I'll cover our first quarter financial results. To aid your modeling efforts, I'll also provide some guidance on our second quarter liquids growth and expected costs and expenses.

For the first quarter, our results exceeded first call estimates. We earned $0.45 per diluted share on revenues of $651 million in the first quarter. Our cash flow from operations was $323 million. Our production in the quarter was ahead of our original plan and cash operating costs were lower than our full year guidance ranges.

Sales were 11.7 million barrels of oil equivalent in the first quarter, which included 9.1 million barrels of oil equivalent from our domestic operations. Our international liftings were about 2.6 million barrels of oil equivalent. Our production in the first quarter was 56% liquids. We've completed our transition to a liquids-focused company. Most of our reduced costs early in the year, like major expense, for example, were simply related to the timing of our full year capital expenditures.

When looking at individual expense categories, you will notice we increased our domestic transportation expense. As our NGLs become more material with growth in the Cana Woodford, processing costs were reflected in the transportation expense. Our realized prices are higher by a like amount and offset the higher transportation expense.

Consistent with our beginning-of-year forecast, we expect to see strong liquids growth in the second and third quarters. This increase is largely related to new pad completions in the Bakken and Eagle Ford and continued growth in the Cana. We expect that our domestic liquids production in the second quarter will be about 4.5 million barrels of oil equivalent, that's up more than 12% from our first quarter production.

Our international liftings in the first quarter came in higher than our beginning-of-year expectations at 2.6 million barrels. And we still expect to produce about 7.2 million barrels of oil equivalent for the full year. For the second quarter, we expect international oil liftings to be about 1.8 million barrels. As you know, we are exploring strategic options for these businesses but our forecast assumes a full year run rate for ease of modeling.

I'll now turn the call over to our Chief Financial Officer, Gary Packer to cover our operating updates. Gary?

Gary D. Packer

Thanks, Lee. Good morning, everyone. We have some meaningful updates this quarter and we're excited to share them with you today, most importantly, to demonstrate that we are on target to deliver on our 2013 through 2015 plans. Our domestic production is now revving up significantly and we expect to see momentum build into 2014. Our liquids growth improved our cash flow and transitioned us once again to a company delivering double-digit profitable growth with spending levels better aligned with our cash flows. Many of the highlights that I will cover this morning are detailed in our newly designed @NFX Publication.

Let start with the Cana Woodford where we have 7 operated rigs running today in the Anadarko Basin. Our first quarter net production averaged 14,400 barrels equivalent per day, that's about 4,300 barrels a day higher than our fourth quarter 2012 average. We continue to see excellent well performance. Our recent focus has been in the south wet gas and oil portions of our acreage, and we've completed 6 new wells in the first quarter and they are performing ahead of our type curves.

Our net Cana production should exit 2013 at about 26,000 barrels of oil equivalent per day, up from about 10,000 barrels a day in the fourth quarter last year. At that level, it will become our largest producing asset. That's impressive, when you consider this has taken less than 3 years to move this play from the initial concept phase. Our Mid-Continent team has done a great job for us and they are working other high potential play concepts today.

Our drilling in the Cana is becoming increasingly more efficient. This is not a surprise to us, as we have demonstrated these trends in multiple areas like the Granite Wash, Arkoma Basin, Monument Butte and the Williston Basin, to name a few. We are drilling our wells faster and cheaper through innovative bit designs, mud systems and modified casing programs.

Our quarterly average drilling case costs in the South Cana were about $925 per lateral foot, or more than 20% lower than our fourth quarter average of 2012. I fully expect to see more gains as the year progresses.

Our 3-year plan is focused on the North and South Cana. These development areas have about 500 potential locations on about 4,800 net acres. These areas are where we currently have the most well control and the focus of our near-term drilling program.

Today, we're leveraging other people's money and are rapidly collecting that in the central region of the Cana Woodford. Today, 2 outside operated rigs are running and we have interest in many of these new wells. This helps us to cost-effectively expand our economic footprint and better understand our ultimate resource potential. With a handful of successful wells in the central region, we could add operated activity later this year. We estimated up to 1,000 potential drilling locations in the central region alone.

Our Williston team is executing extremely well today. Our production early this year is ahead of schedule and we expect oil growth this year from the Williston of about 25%, that's up from our original expectation of 15% year-over-year growth. We expect to grow about 25% year-over-year again in 2014. Our drilling teams are capturing efficiencies through the longer laterals and pad drilling, and as we summarized in our operations report last night, our most recent completions in both the middle Bakken and the Three forks are performing very well.

In March, we added a fourth operated rig in the Williston Basin. All of our drilling today is being conducted from multi-well pads. These reduce the time between wells, allow us to simultaneously complete our wells faster and cheaper and we save money with shared production facilities. At our current pace, we expect to drill about 35 operated wells in the middle Bakken and 7 wells in the upper Three Forks this year.

During the first quarter, we completed some of the best wells to date in the Williston Basin. These were not only the highest IP rates we have seen, but more importantly, they captured efficiencies through less drilling days and optimized completion practices. In our Sand Creek Federal area located in McKenzie county, we completed 2 wells in the middle Bakken and 1 the Three Forks. Our 2 middle Bakken wells have averaged gross initial production of 3,500 barrels of oil equivalent per day and a 30-day average of 1,100 equivalent per day. The Three Forks well has a gross initial production of 3,450 barrels of oil equivalent a day and averaged 1,100 barrels over its 30 days as well. Lateral lengths in these wells were approximately 10,000 feet.

Our returns in the Williston Basin continue to improve through lower completion cost and in the quarter, we drilled a Three Forks wells with a 9,000-foot lateral for $7.4 million. That was a best-in-class well, facilities and artificial lift, add another 900,000 barrels. Let's move to the Uinta Basin.

We estimate more than 760 million barrels of oil equivalent incremental net unrisked resource potential in the Central Basin across our 139,000 net acres. The size of the prize makes this an important asset for the company. In fact, the basin has the scale and the resource potential to drive our corporate growth and profitability for more than a decade. Our objectives in the basin today are clear. Number one, is moving Uteland Butte and Wasatch plays into rapid horizontal development. To date, we've drilled nearly 50 Wasatch vertical wells and 4 Wasatch horizontal wells, and about 15 horizontal wells in Uteland Butte. Production data from both horizontal and vertical wells provides encouragement for the potential of these 2 plays. Our goal is to efficiently accelerate development activity levels in Uteland Butte and the Wasatch.

Second on our list of these objectives, is to partner with state authorities to advance regulatory rules to allow for the drilling of the optimal well. Current regulatory rules and setbacks from section boundaries limit our maximum potential length to date to just under 4,000 feet. We are working hard to advance these rules to allow longer lateral wells, as our lateral lengths contact more of the productive horizon, our production rates and EURs will increase, while our cost per lateral foot decrease, ultimately, improving returns. In addition, they reduce surface disturbances and truck traffic due to fewer locations, longer laterals certainly are our future.

I'm happy to report today that we are drilling our first SXL well in the Uteland Butte, a 9,900 foot lateral. We have 15 additional permits approved by the State of Utah in hand and plan to drill 5 to 6 additional SXL wells in 2013.

We will use the upcoming results to push for expanded permitting for SXL wells in 2014 and beyond. In the Wasatch, we have collected production data from the 50 vertical wells in the performance from the 2 producing horizontal wells that continue to impress us after nearly 300 days of production. We have a solid understanding of the resources with at least 5 major identified productive oil horizons throughout the 1,200 foot vertical Wasatch intervals. This is an oil saturated horizon, offering potential for multi-horizon, stacked, lateral developments. We are today working to secure permits for SXL wells in the Wasatch formation and hope to drill our first SXL wells later this fall.

Third, it is imperative that we accelerate through tremendous value of our giant waterflood asset, the greater Monument Butte. We estimate more than 2 billion barrels of oil in place. We have completed more than 600 40-acre waterflood patterns and we have more than 1,000 patterns remaining to complete.

As part of the waterflood development, we plan to drill more than 200 20-acre infill wells per year and convert about 200 wells to injection per year over the next 6 to 8 years. During the first quarter, we averaged 4.2 days to drill a Green River well and increased our water injection levels to a recent high of 85,000 barrels a day. We are maximizing our production, utilizing our facilities to gather and reuse water and improve the overall efficiencies of our operations.

We are running 3 operated rigs in Monument Butte today, drilling 20-acre infill wells and completing our substantial inventory of waterflood patterns. Soon, we plan to test 10-acre pilots in multiple areas within the unit.

And fourth on our list of objectives, we must secure expanded and long-term markets for our growing Uinta production. We have taken some significant steps over the last 18 months to secure future markets for this oil growth. Today, Tesoro is in the first of 2 planned turnarounds to ready their facilities for an incremental 9,000 barrels a day of refining capacity, which is expected by late 2014. We signed 7- and 10-year firm agreements with Tesoro and HollyFrontier, securing 38,000 barrels a day of firm refining capacity. We expect to grow or Uinta gross production to about 50,000 barrels a day by late 2015.

In addition, we are aggressively exploring refinery markets outside of the Salt Lake City region. Just last week, we railed about 30,000 barrels a day, with more planned, to a refinery outside the Salt Lake City Basin. Our ultimate goal is to create new markets for this high-value crude and provide future visibility on our growing oil sales. I strongly believe that we have resource in the Uinta to support these markets for our growing oil production.

In the Central Basin, all of our first quarter horizontal completions were in the Uteland Butte. We've completed 4 the wells and average initial gross production rates of about 1,000 barrels a day with a 30-day average, on the first 2, of about 715 barrels of oil equivalent per day. These wells are consistent with our first 11 wells and we look forward to our midyear results from the first SXL wells in the Uteland Butte and we expect it to be a game changer for our economics.

Our goal is to continue to improve productivity and returns while lowering our F&D cost. The Uteland Butte is a play that could rapidly move to horizontal development in 2014 through 2015.

Our net production in the Uinta Basin in the first quarter was about 21,000 barrels of oil equivalent per day and reflect higher than normal oil inventories in the field. We talked about this on our February call, so this is not a new issue and its impact was included in our full year guidance.

The inventory build in the field is related to turnarounds in the Salt Lake City refineries that I previously mentioned. These are scheduled facility maintenance and recent expansion efforts to build capacity for our feed. We remain confident that our net sales will increase to about 22,000 barrels a day in the second quarter and more than 25,000 barrels a day in the third and fourth quarters as the new refining capacity becomes available.

In the Eagle Ford, our development efforts are focused on the West Asherton field and we are seeing exceptional improvements in our returns. Today, we are running 2 operated rigs and drilling SXL wells in common pad locations. We are right on target with our Eagle Ford plan and expect to drill about 35 operated wells in the play in 2013.

During the first quarter, we drilled 6 new Eagle Ford wells with average lateral lengths of about 7,500 feet. These wells are in various stages of completion today with one of the pads in early flowback. Our operation teams did an excellent job for us in the first quarter and our well costs were lowered by more than $400,000 when compared to our average cost in 2012. Recent SXL wells were drilled and completed for $7.7 million, gross.

As we predicted on our original guidance, our production ramp in the Eagle Ford in 2013 will be back-end weighted, due to the pad drilling and the timing of our simultaneous completions. Our Eagle Ford net production averaged about 4,800 barrels of oil equivalent per day in the first quarter, with no new pads coming online. We are looking for a surge of oil production from new pads in the second quarter and third quarters and expect to exit 2013 at about 14,000 barrels of oil equivalent per day. We expect that our Eagle Ford production will grow 75% year-over-year in 2013, an additional 50% in 2014. Our Eagle Ford returns today are among the highest in the company. We estimate that our SXL wells and gross EURs in excess of 550,000 barrels of oil equivalent with a production stream that is largely comprised of black oil.

That's a quick highlight reel from our major areas of operations. In summary, we are executing very well in 2013, we feel confident in our ability to meet our expectations for the year. I'm encouraged by the improvements we are seeing in our drilling programs across the company and we're refining our completions to maximize EURs and production, with today's execution building positive momentum for 2014 and 2015.

I'll now turn the call back to Lee for any closing comments.

Lee K. Boothby

Thanks, Gary, and thanks, to all of you for joining us today for our first quarter update. Over the last several months, we've made some significant strategic decisions and have aligned our capital, personnel and talents towards a common goal. Being a profitable North American-focused resource company. Our capital investment program this year remains at the $1.7 billion to $1.9 billion range, the delta between our cash flow and our investments levels will be financed through our $1.25 billion credit facility, which was undrawn at the end of the first quarter.

Our domestic liquids growth in 2013 is very strong and you see from today's results that we are improving returns and profitability throughout our operations today. We provided some quantitative examples of lower well cost, more effective completions, higher EURs and improving operating expenses. Our domestic focus today is on 4 key resource plays and we're transferring best practices rapidly amongst these areas.

I appreciate your investment and continued interest in our company. Know that we are confident in Team Newfield's ability to execute on our plan and the plan trajectory will make as a larger, stronger and more profitable company.

Operator, I'll turn it over to you to assemble the questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Dave Kistler with Simmons & Company.

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

Real quickly, with production exceeding kind of the high end of your guidance in the quarter, having production exceeding your expectations across your 4 key areas and taking up the Bakken production estimate, there was no adjustment to the full year '13 guidance. Kind of curious if you can walk us through, are you expecting maybe greater declines on the gas front or just being conservative as you are working on executing your plan throughout the balance of the year?

Lee K. Boothby

Dave, I think it's, very simply, that it's early in the year. We're off to a good start. We are very encouraged by what you articulated across all of those areas. I think that sustaining that momentum during the course of the year certainly would be strongly positive relative to the forecast plan. But we're early, stay tuned and we look forward to updating you on our progress at the end of the second quarter.

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

Okay, great. And then just as a follow-up. In the Bakken, can you kind of walk through maybe any discernible differences between the 2 Three Forks wells that you drilled? Obviously one of them was an absolute standout. And just trying to think about was there any sort of design difference in the well, geologic difference, anything like that, that helps you think through the targeting of your next 7 Three Forks wells?

Lee K. Boothby

Well, we think they were both great wells, Dave. I think, as you indicated, one is absolutely outstanding and we hope it has many brothers and sisters. I would take it as very, very encouraging. As far as design differences, I'll flip it over to Gary, I'm not aware of any design differences between the 2 wells. I think it's just a matter of uncertainty when you drill through a play like that, but we'll keep them both. Gary, do you have anything on that?

Gary D. Packer

They're in 2 different areas of the field, that probably has something to do with it. I'm not aware of any differences in the design that we have between the 2 wells.

Operator

And we'll take our next question from Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

First of all, I got to see the @NFX document back, very helpful. First question, I guess, Lee, if you could just remind me on the international sale, potential tax treatment and repatriation cost that might be associated with bringing those dollars back, if any?

Lee K. Boothby

Well, I think that, Subash, I don't know that I've had a chance to talk to you, but I know we've been in the road a lot over the last 6 to 7 weeks and talked to a lot of folks. I think the way Terry described it, very clearly, is that it's a tax -- it'll be a tax-efficient transaction. We'll end up leaving 10% behind for whatever the realizations are in China and everything else comes home.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, great. And my follow-up is, so the rail options, I guess, you're working on here are pretty small, and I assume there are sort of ways to maybe get rid of some of the inventory you've built. But could you address maybe how scalable this current effort might be?

Gary D. Packer

It's something that we're exploring. I would suggest that for the barrels that we've moved thus far, we have an opportunity to probably move about 3x of that this year, it's something that we're currently exploring. It -- we're not going to announce where we're moving it, but we're moving it to one of the coastal refineries. And based on how those runs take place, it's our belief that they could be materially scalable from where we're at today.

Subash Chandra - Jefferies & Company, Inc., Research Division

So 100,000 barrels is sort of what you think you could do this year, and that includes what you -- your materially scalable comment?

Gary D. Packer

I would say we could probably do an incremental 100,000 barrels this year and that's just in, basically, batch loads. Based on how that goes, we could scale it significantly over the year, yes.

Lee K. Boothby

I think, Subash, remember, we're limiting, within the next 2.5 years, within the constraints and the timing of the expansions we've already signed up for. So part of the scalability comment is kind of above and beyond and accelerating some of that inventory. Looking forward, it's going to take some time to develop those markets, but I think it's very encouraging that there's interest being expressed on multiple coasts today and we hope to be able to establish some outlets outside of Salt Lake City. I think that'll be net net positive for all of the -- our operations in the basin and, frankly, for everybody operating in the basin.

Operator

And we'll take our next question from Leo Mariani with RBC.

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

Just hoping to dive into the Cana Woodford a little bit more. You guys reported a strong batch of well results this quarter. Of notice in that, that group of results, your 60-day rates were actually a little bit better than your 30-day rates. Just wanted to get some comments from you guys on why you think the declines have been so shallow in that play? Kind of what have you learned so far? That would be helpful.

Lee K. Boothby

Leo, thanks for reading the information, that makes the guys feel good. I think there have been a lot of people involved in the company pooling that information together and delivering results. Remember that we've been pretty clear over the last several months that in 3 of our key areas, we're utilizing control flowbacks, so we're not producing wells to maximize IPs, we're producing wells to maximize EURs and return. So with that, we're managing the drawdowns. Downhole, we think that gives us a much more effective stabilized completion and drawdown regime for the wells and should ultimately translate to what we're seeing in early returns, higher EURs and higher returns for the wells. So that would be part of the reason you'll see a higher later rate that you're just working through the math of managing the drawdowns.

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

Okay, that's helpful. So I guess, wanted to also get your sense on the Cana. Obviously, you guys have increasing lateral lengths there. You talked about some cost reductions in terms of drilling dollars per foot. Just wanted to get a sense of what the current long lateral well costs are right now, and I guess, you guys are hopeful that you continue to see improvements there, so just wanted to get a sense of where they are now and where you think they could go, eventually, here.

Gary D. Packer

Yes. As far as the long lateral wells, they're typically in about $11 million range, that would be in a southern gas area. In a development mode, we think we have opportunities to bring those down further. This is all in the area in the south. As we move to the north, we have an opportunity to remove a casing string. We've done that, thus far, this year, that brought -- drops out about $500,000 to $750,000 off of that, those wells are a little shallower, and we don't require quite the same casing program that we do in the south, so I would drop that roughly $1 million.

Operator

And we'll take our next question from Amir Arif with Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just as you move from '13 into '14, I mean, your production growth profile that was laid out increases from 5% to 18%. Can you tell us if that is achievable with the current run rate of capital spending? Or does that require a pickup of drilling in your key plays?

Lee K. Boothby

The short answer is yes. It's achievable with our current run rates. And if you look at the 3-year plan, '13, '14, '15, I think the range of capital spend across that 3-year planning horizon was $1.4 billion to $1.6 billion, so you can assume it's about $1.5 billion a year. I think that's a key point in that 3-year plan, and I think that also is exciting because what we're seeing here, early in the year, play out or the gains in our operating teams around the portfolio translate through that 3-year plan because we're anchored on the de-risked portion of the inventory that we carried in into this year at the end of 2012. So I think we're in good shape to execute and execute it in range with the forecast CapEx.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then the follow-up question, just on the Uinta, as you get new takeaway capacity there, will you get the differentials at that time, or have you locked that in as you locked in the new takeaway capacity for the region?

Gary D. Packer

We have no fixed contracts on the barrels that we're moving right now outside of the basin. So basically, we're floating with the market, and it's being priced similar to what we have in the basin. If your expectation -- if we enter into a longer term agreement that it would be a price premium to what we currently would see.

Operator

And we'll take our next question from David Tameron with Wells Fargo.

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

Just on the rail issue, can you guys talk about what the cost is to rail that out? And I realize that you don't have contracts in place and, obviously, you've left the differential for the region, but could you just talk about what the cost would be?

Lee K. Boothby

No, I think it's premature to talk about the costs, I mean, we'll tell you more about the rail option as we get more information. I think the exciting part is, we're moving the barrels today, we're testing the markets and all of that will develop as we move forward. Gary, if you have anything you want to add?

Gary D. Packer

No, I just say, David, it's really net neutral to where we're currently at right now when we take into account the price we're receiving and the transportation. So it's really -- it's too early to tell. I look at these as kind of some test runs that we're making to see how it goes, not only for Newfield but also the refiner.

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

All right. I think, Gary, in the Uteland Butte, can you talk about the wells, I think, it's 11 wells you drilled, prior to the ones you released today, can you talk about what those look like at the back end of the curve? If they're holding up, et cetera?

Gary D. Packer

Yes, everything is holding up in those wells. They've -- they flattened out pretty well and as you see, I mean, we're, essentially, you see a similar phenomena here to what we see in the Cana. We're seeing 60-day and 30-day numbers about flat with each other, about 600 barrels a day, and I think that gives you a vision for what's taking place. In February, in our @NFX we put out some type curves and I'd say, the wells are performing very well with the type curves that we published there.

Operator

And we'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the extended offset dates, you mentioned that you do plan to test some of the deeper benches in the Bakken later this year. Can you just talk about that? And what is your hypothesis on this potential across your Bakken acreage position?

Gary D. Packer

The -- we'll be testing -- excuse me?

Brian Singer - Goldman Sachs Group Inc., Research Division

A deeper Three Forks bench, sorry.

Gary D. Packer

Yes. We like the potential and while it's pretty preliminary for us, up on the Nesson Anticline, so I would say, in the areas of Westberg and Lost Bear, we see the second benches as prospective. We're going to be drilling a well here shortly that will target both the second bench, the first bench, as well as the Bakken and we'll be analyzing that for communication across all those zones and see how they perform. If the second bench test is perspective there, as I said earlier, we see those benches perspective across the entire Nesson. As we move off the Nesson, we see it, at least at this point, we see it less prospective, but it's early.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, thanks. And then just following up on the Uinta rail test. Can you just give us the chronology of kind of what to expect here? You're doing the rail test now, how long do those tests continue? And then, how long would the next step be, assuming the next step would be just determining whether signing a contract or -- I guess, give us the positive case, in terms of how you would get from these tests to future incremental production?

Gary D. Packer

Got you. Well, as far as where we sit right now, we have already backshipped the volumes that we spoke to in the @NFX publication. We are currently in discussions of moving a volume that could be up to 3x or 4x that and, with success in those negotiations, those volumes could start moving as early as May. We have adequate capacity and inventory as we currently spoke and this gives us some additional flexibilities to navigate the turnarounds that are currently taking place with the Sora. It will be premature for us to talk about how that translates into a longer-term agreement but that is certainly something that we are interested in, as well as the refinery [indiscernible]. So it's a -- but that is something that I would look for at the end of the second and through the third quarter, for us to give more transparency on these additional rail options.

Lee K. Boothby

And Brian, I think it's important to remember that we've got all the refining capacity we need in place out through 2015. So think about the rail, it's either acceleration or it's growth beyond the planned horizon at this stage. So we'll keep you posted as the information comes in and we'll walk together.

Operator

And we'll take our next question from David Heikkinen with Heikkinen Energy Advisors.

David Heikkinen

Your Uinta program and your guidance doesn't include any of the other outlooks, either rail or the pipeline study. That's not in your guidance. And then your current 2013 production, any volumes, that 100,000 barrels, that would be moved wasn't in the original target as well.

Lee K. Boothby

The volumes in terms of the 100,000 barrels a day, David, I'll remind you in the February call, we talked about inventory, managing inventory through the turnaround. So if that -- I wouldn't be thinking about that as an incremental volume just in terms of working through the barrels that we've got in the field today.

David Heikkinen

Okay. And then in the Eagle Ford, can you just get to the 7,000 barrels a day, are you basically just completing the 6 wells that are waiting on the pad, the completions are underway, how does that stagger, as you think into 2000 -- into the second quarter, how many wells you'll have waiting on completion and kind of same thing in the third quarter?

Gary D. Packer

Yes, we have a series of -- David, we have a series of completions all planned in pad sequence for this year. It looks to me as if we -- in the second quarter, we'll be bringing on approximately 16 new wells through pads that will be contributing to that. So it's not just the 6 that we've already drilled. As we head into the end of the third quarter and into the fourth quarter, we see about another half dozen wells coming in. So in order to achieve the kind of -- this ramp-up that we focus, we've got quite a few.

Operator

And we'll take our next question from Peter Kissel with the Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

Maybe just one more on the Uinta rails here. Just curious to see what the current rail car availability looks like for the insulated rail cars? And how much of a bottleneck that could be to scalability that was mentioned?

Gary D. Packer

Certainly, it's a limitation today. We have the rail cars arranged to move the volumes that we've already spoken of in the batch -- in a batch mode. If we wanted to ramp it up more, certainly, it would be something that would have to be addressed. But we're not contemplating that at this point, our focus is on moving the volumes that we've already mentioned, as well as the optionality that we have in 2013 and it's my understanding that the rail cars are in place to do that.

Peter Kissel - Howard Weil Incorporated, Research Division

Okay, great. And then one other quick question on an asset that hasn't been mentioned in several quarters and that's the Arkoma Woodford. With the run-up in strip prices here, is there any point in the near future where you see that competing well for capital versus the 4 main areas that you've highlighted in the call, or is that still pretty far down on the totem pole?

Lee K. Boothby

I wouldn't say it's down on the totem pole, I'd say, it's HBP, so we've got that position all taken care of, it is dry gas. We've stayed away from having the conversations about a price trigger relative to activity. Although the run-up, we're certainly closer to the point where you can start thinking about investing there. But our plan is anchored on the 3-year horizon on the liquids plays and I would say that we've got a ways to go on gas before the returns on -- in the Arkoma, gas are going to compete with the returns that we're generating in oil today. Especially with the operating gains that we're seeing day-to-day.

Operator

And we'll take our next question from Rudy Hokanson from Barrington Research.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Quick question. Could you talk a little bit more about the prospects with the Wasatch wells, where you were talking about 5 -- I think you said 5, possible areas with the stacked lateral? I was a little confused about what you've been finding there? And if you could talk more about what the potential might be.

Lee K. Boothby

Rudy, I'll talk just very briefly about it and then I'll flip it over to Gary, because I think he's gathering a couple of facts for you. Remember the 50 wells that we talked about drilling, the vertical wells. So each one of those wells is drilled through the entirety of the 1,200-foot Wasatch section. On average, those wells have had about 6 completion intervals throughout that 1,200-foot section, so co-mingled completion intervals. So we know there's mobile oil from top to bottom in that 1,200-foot section, and we know that, that mobile oil was distributed across the entirety of that basin. And you can look at the maps that we've put out here over the last 2 or 3 months where they've got updates in terms of well activity to kind of get a feel for the scale and scope of that footprint. What Gary was talking about, as we've presently got 2 wells down that are under completion, which were our first 2 stacked laterals and they're shown on one of those handouts that we talked about. What Gary went on to say is that there are several horizons and it's 5 or more, if you want to think about it in those terms, that we would imagine being able to think about multiple stacked horizontal developments in terms of each one of those horizons through the 1,200-foot thick Wasatch section. But I'll flip it back to Gary, I think, he got some additional color.

Gary D. Packer

Yes, I guess the way we think about it, Rudy, is, over 1,200 feet, we have 26 mapped horizons. In those 26 mapped horizons, we can see 5 different target intervals where we think we can connect up to 5 in each one of those horizontal wells. That allows us to adequately drain the entire resource. So as currently as being talked about, when you think about the Bakken, with the Bakken targets, as well as the multiple benches in the Three Forks, it's very conceivable that you can imagine, on an upside case, where you could have multiple horizons in each one of these -- multiple horizontals, in each one of these 5 horizons. Now I'm painting a picture for an upside case, that you could easily see how you could be talking about 15 or 20 wells a section from a horizontal standpoint to adequately drain these resource. Now that number has not reflected any of the numbers that we've talked about. Even when we talk about unrisked resource in our February announcement, I think we were talking about 4 to 6 wells a section and that would be in the absolute upside. But as we get more and more information, this becomes a potential reality. What we're currently doing right now in the 4 wells that we've currently drilled, 3 of those wells have all targeted the same interval, and we like what we've seen from the 2 that have been placed on production. The fourth well has been drilled in a stacked perspective immediately above the horizon that we've historically drilled. So now, we're in the process of completing these wells, and we'll be able to monitor how they interfere or communicate with one another and drain that horizon. Based on that information, it would be -- we believe, it could be scalable to the other horizons. It's very early on, and again, as I referenced in the call or in the -- in our prepared remarks, the key to this is also getting the SXLs drilled, getting these long laterals contacting more area. We believe, with the information we've already accumulated in conversations we're having with the state this month, we believe we'll be able to get our first well drilled, SXL well drilled this year. Based on how that one goes, we'll attempt to make that scalable in 2014. So it's very early but we like what we see so far.

Lee K. Boothby

And Rudy, I would just think, very simply, the easiest way to think about this is the Wasatch, that 1,200-foot thick interval, is a 3D spacing problem, that's what we're trying to work through, is the 3D spacing.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

As a quick follow-up, as you work on this as soon as you drill, how are you using seismic to help you delineate what might be down there? I'm just thinking of all the advances going on with seismic and being able to read some of these things that are going on in various reservoirs. Are you increasing your use of seismic or is this still more of a using original information and then relying upon the engineering of the well right now?

Lee K. Boothby

Well, we've got 3D seismic data across most of the acreage in the Central Basin. We've got a team of people that are working all the high-end attributes and modeling across the basin, that's part of the value of having those 50 vertical wells, plus all of the data that we've got in Greater Monument Butte. And then we're also going to have microseismic data on the 2 stacked laterals that Gary just talked about, and that's to test both the vertical propagation of the frac, as well as the lateral propagation. So I think we're loaded up on the technical side and as data flows in, I think we'll build or refine it, and it will be part of the solution in terms of the 3D spacing challenge that I talked about in the earlier question.

Operator

And we'll take our next question from Dan McSpirit been BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

You speak to the Cana Woodford becoming the company's largest producing asset. Does this mean or does that mean this play affords the highest rate of return among the 4 core areas, or is it simply more scalable than others at this point in time?

Lee K. Boothby

Well, I think we're generating really attractive returns in all of the development areas today, and I think we've documented that fairly well. And certainly, we've been consistent over the course of the last several months in talking about the Cana Woodford, particularly, the wells we drilled down in the South Cana area, both in the wet gas window and the oil is generating some of the highest returns in the portfolio. But clearly, because of the scale and scope of our operations in the acreage footprint and, remember, the success that we had in '12 on derisking acreage, we're in a great position here to do what we said we were going to do at the beginning of last year, accelerate the development. So what you're seeing is the accelerated development in the Cana Woodford. We're able to move the volumes today there, but that's one of the advantages that we have with our portfolio is we can shift capital around between the 4 areas and balance out the needs at any given point in time. Today, Cana Woodford is carrying the freight and the other plays are generating nice returns as well, but it is a strong part of our growth engine.

Dan McSpirit - BMO Capital Markets U.S.

Got it, okay. And as a follow-up, can you give us the operator rig count for first quarter '13 across the different operating areas? What does it look like at year-end here, again, across the same operating areas? And forgive me if I'm overlooking this guidance in what may you have already published.

Lee K. Boothby

You're asking about our operated rig count?

Dan McSpirit - BMO Capital Markets U.S.

Correct.

Lee K. Boothby

Yes, I think that information was provided in February, but for the one that we spoke, we plan on having 7 rigs running through 2014. So it's consistent with Lee's prior answer about kind of a flat capital program. So we're currently running 7 rigs and that's expected, we expect to run 7 rigs in '14 as well.

Operator

And we'll take our next question from Gil Yang with DISCERN Capital.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Could you talk about the stacked laterals? A lot of companies have talked about doing stacked laterals but it never really seems to take off as much as the promise. Is there a real advantage here? And what are the risks of pursuing that strategy?

Gary D. Packer

Gil, we've actually explored and drilled some stacked laterals already. We've already done this in the South Cana, for instance, where we've actually drilled laterals in a staggered fashion to minimize interference. And that's proven to be quite effective. We've also drilled stacked laterals in the Granite Wash. As you remember, as we were pursuing the Marmaton, Redford, Cherokee and so forth, those were also multiple horizons drilled within the same Granite Wash section and we've proven that, that to be an effective, accretive way to develop the asset. So -- and obviously, in the Bakken, it's currently taking place. And whether you want to argue about communication, there is a certain -- as we've always talked about, a certain desired amount of communication. But it's also about, as we drill these stacked laterals, just making sure we get adequate recovery of the resource that's in place. Some of it may be in acceleration, some of it's incremental. So I think we're just applying a development scheme that's already -- we've already utilized in other areas.

Lee K. Boothby

I think the thickness of the section, Gil, is the key when you're thinking about comparing the results between where various stacked lateral approaches have been utilized. And we've got over 1,200 feet a section here, so we're in good shape.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

And maybe I've misunderstood, you're not talking about stacked laterals out of the same vertical board, you're talking about just stacking laterals out of separate vertical boards?

Lee K. Boothby

No, separate individual wells. So the only -- a part of the stacked laterals at that the horizontals are going to be stacked in the section.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay, got you. All right. So there's no effort to put multiple laterals into the same vertical bore?

Lee K. Boothby

We have no interest in increasing the mechanical complexity with multi-laterals out of a single well bore. Not what we're talking about.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

All right, that's sort of what I was thinking. Second thing, with the Bakken savings, do -- you cited $900,000, maybe you talked about this in detail earlier, I missed it. But the $900,000 savings facility, is that repeatable per well, or is that on the first well you can somehow do some savings?

Lee K. Boothby

The savings part was in the execution form at a field level. The $900,000 that you're talking about, I think, is a facilities and artificial lift -- completion in our -- facilities, infrastructure and artificial lift cost associated with the wells here. So you've got to drill and complete plus facilities costs and we're giving you both sides of that equation. Gary, do you want to add there?

Gary D. Packer

No, I think that addresses it.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. So the $9.8 million that you cited was the all-in well cost, including the facilities fees?

Gary D. Packer

Yes. We've historically recognized that a lot of times when our well costs are being compared to some of our competitors, that the facilities costs are being left out of some of the numbers. So we wanted to provide you the transparency in the breakdown between facilities and total well costs. So we are clearly seeing advantages this year that we had not even anticipated as we entered the year through additional efficiencies in what is a rather mature play for us. But then we're also providing you the extra clarity on the facility piece of that.

Operator

And we'll take our last question from Jack Aydin with KeyBanc.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

One question, MDU is building a refinery in the Rockies. Are you talking to them? And trying to lock in some supplies to that refinery? Or could you give us a color on it.

Lee K. Boothby

Jack, I'm sorry, but it broke up when you were talking, we didn't hear who you were referencing.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

MDU.

Gary D. Packer

Yes. I'm not familiar with that refinery, Jack, and so I can't really comment.

Lee K. Boothby

I guess, I'd like to thank everybody for tuning in this morning. We look forward to updating you on our continued progress after the close of the second quarter. Thanks for your investment and interest in Newfield. Have a good day.

Operator

And that does conclude today's conference. Thank you for your participation.

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