Noble Energy (NBL) Q4 2016 Results - Earnings Call Transcript

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Noble Energy, Inc. (NYSE:NBL) Q4 2016 Earnings Call February 14, 2017 9:00 AM ET

Executives

Brad Whitmarsh - Noble Energy, Inc.

David L. Stover - Noble Energy, Inc.

Gary W. Willingham - Noble Energy, Inc.

J. Keith Elliott - Noble Energy, Inc.

Susan M. Cunningham - Noble Energy, Inc.

Analysts

Doug Leggate - Bank of America Merrill Lynch

Brian Singer - Goldman Sachs & Co.

Pearce Hammond - Simmons Piper Jaffray

Paul Sankey - Wolfe Research LLC

John P. Herrlin - Société Générale

Charles A. Meade - Johnson Rice & Co. LLC

Arun Jayaram - JPMorgan Securities LLC

Irene O. Haas - Wunderlich Securities, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Gail Nicholson - KLR Group LLC

David R. Tameron - Wells Fargo Securities LLC

Paul Grigel - Macquarie Capital (NYSE:USA), Inc.

Operator

Good morning, and welcome to Noble Energy's Fourth Quarter and Year-End 2016 Earnings Results Webcast and Conference Call. Following today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded.

I would now like to turn the conference over to Mr. Brad Whitmarsh. Please go ahead, sir.

Brad Whitmarsh - Noble Energy, Inc.

Thanks, Dana. Good morning, everyone, and thank you for joining us today. I hope you've had a chance to review our fourth quarter 2016 news release which highlights another strong quarter of outperformance for Noble Energy. We also released our 2017 detailed guidance yesterday, and both of these releases along with a number of supplemental slides are available on our website. Later today, we anticipate filing our 10-K with the SEC.

Following our prepared comments, we will conduct a question-and-answer session. I would ask that analysts limit themselves to one primary and one follow-up question. Dave Stover, Chairman and CEO; and Gary Willingham, EVP of Operations, will provide some commentary. Ken Fisher, EVP and CFO; Keith Elliott, Senior Vice President of the Eastern Med; and Susan Cunningham, EVP of Exploration, are also here and will be available for Q&A.

I want to remind everyone that this event may contain projections and forward-looking statements as well as certain non-GAAP financial measures. You should read our full disclosures in the latest news releases and SEC filings for a discussion of those items.

For the fourth quarter, total company volumes came in at 410,000 barrels of oil equivalent per day, it's the high end of our guidance, while organic capital was below expectations. Onshore, the DJ Basin had a great quarter from enhanced completions, and we saw strong results from new wells in the Delaware Basin as well. Robust volumes in the Gulf of Mexico and strong natural gas demand in Israel were also significant contributors.

Of particular note, total company oil volumes of 131,000 barrels per day were above expectations, and again, this was driven primarily by the DJ Basin and the Gulf of Mexico.

I would also point out that our U.S. oil differential tightened to more than $1.00 during the fourth quarter, as we continue to optimize our pipeline and rail markets onshore.

On the costs side, unit lease operating expense stood out, down about 10% compared to the fourth quarter of last year. DD&A was below guidance as well, reflecting strong U.S. onshore reserve adds.

Discontinued operational outperformance allowed us to deliver a beat on earnings and cash flow for the final quarter of 2016.

I want to point out some slight changes to our guidance and reporting going forward. As you can see on the slides, we are providing additional transparency on our volumes, including a breakdown between the U.S. onshore and offshore and by each hydrocarbon as well. Beginning with the first quarter of 2017, our reporting of actuals will reflect this same level of detail.

With that, I'll turn the call to Dave.

David L. Stover - Noble Energy, Inc.

Hey, thanks, Brad. And I appreciate your bearing with me as my voice is a little raspy this morning. Say, looking back at 2016, it was an impactful and significant year for Noble Energy. Amidst substantial changes in commodity prices, beginning in 2014 and through most of 2015 and 2016, Noble stayed on course, delivered what we set out to do, and actually accomplished much more.

2016 was truly a year of outstanding operational, financial, and safety results. It was also one of great progress on key strategic objectives which we've outlined on slide 4.

I don't believe there are many peers with this extensive of a list of accomplishments over the year. I'm truly proud of our teams for delivering these achievements. We exit 2016 exceptionally well positioned to deliver top-tier long-term shareholder performance.

Before moving to our 2017 outlook, I'd like to take a moment to turn your attention to our 2016 year-end reserves update. As you can see on slide 5, we ended the year with total proved reserves of 1.4 billion barrels of oil equivalent, which was up slightly from the previous year. Organic reserve replacement was over 190% of 2016 production from nearly 300 million barrels of oil equivalent of additions and performance revisions.

Even more impressive, total F&D cost was less than $5 per barrel of oil equivalent on an organic basis. Within the U.S. onshore, our increased activity outlook, along with performance improvements across all basins, led to an organic replacement of 280%.

On the right portion of the slide, you can see an adjustment to reserves for the divestments made in 2016. Including the 3.5% of Tamar as well as the Marcellus JV dissolution. Additions more than exceeded production and positive performance revisions, and essentially every one of our business units offset divestment impacts and price revisions from a lower SEC price deck. At the end of the day, the DJ Basin was up 13%, as was our combined Texas position. And the Marcellus was up 10%, despite the JV dissolution impact.

We continue to remain prudent on PUD bookings, having between three to four years at most of future activity reflected in proved reserves. And internationally, given the Leviathan sanction expected this quarter, you will see a material increase as first reserves from the field are booked in 2017.

Now, let's turn to 2017, on slide 6, we've outlined our major goals and outcomes for the year with a primary focus being the acceleration of our development programs, both onshore and offshore. Onshore, we're driving additional capital efficiency gains while rapidly increasing our activity. The expected closing of the Clayton Williams transaction in the second quarter will further our ability to benefit from this focus.

With the expansion of our onshore program, our midstream business will continue to grow. This is showcased through our integrated development approach, as multiple new NBLX facilities are starting up this year.

Offshore, we will begin development of our world-class Leviathan project in Israel. Another key objective listed, we're targeting additional asset proceeds of at least $1 billion for 2017. There are multiple pathways to achieve this target, including a potential dropdown of retained assets to NBLX, farm-down of Tamar and/or Leviathan working interest, and potentially monetization of assets that may make better sense in someone else's hands. And we have the opportunity to participate in a very material exploration prospect, offshore Suriname, late in the year.

We're already off to a great start in 2017. We have leading positions in two top oil basins in the U.S., and we'll enhance our Delaware position upon closure of the Clayton Williams Energy acquisition. Both our DJ Basin and Delaware Basin positions contain 2 billion barrels of oil equivalent resources net to Noble.

Slide 7 and 8 are essentially repeats from the acquisition announcement, so I won't spend much time on these.

Drawing your attention to slide 8, I will remind you of the enhancements to our plan through 2020 with the acquisitions, as we aggressively develop our high-quality inventory. The outlook we provided in January is 3 percentage points to 5 percentage points higher across the board on volumes versus the November outlook represented in red diamonds. And operating cash flows grow at an even higher rate, up 7 percentage points from our November outlook.

Following the announcement, we've had great conversations with many shareholders and analysts, and the response has been extremely positive. The discussions have focused on how well the acreage fits with our existing position, the incremental impact to our onshore inventory, our ability to generate additional value as well as how it increases our volume and cash flow growth outlook.

Obviously, one of our major goals for the year is an efficient and safe integration of the company and assets into Noble. In particular, Gary will highlight the outstanding performance we've had through both drilling improvements and enhanced completions during the fourth quarter, and I look forward to seeing the results that our unconventional expertise can bring to this high-quality asset.

Now, let me highlight the momentum of our Leviathan development. We are on track to sanction the project this quarter with first gas targeted by the end of 2019. The final steps of the sanction are coming together nicely as we finalize contracts and permits required to begin construction. We're seeing excellent support from the energy ministry and other government agencies. Our teams continue to progress engineering design and have already begun purchasing long lead materials. We're bringing our key supply partners onboard, many of whom were part of the teams that deliver our highly successful Mari-B and Tamar projects.

In addition, we're planning to commence Leviathan development drilling by the middle part of the year. So, we're moving full speed ahead. Total capital spend in the Eastern Mediterranean is anticipated to be over $500 million this year, and our teams are excited to begin development of this world-class asset.

Before turning the call over to Gary, I want to spend a few moments on our outlook and plan for 2017. As we discussed in November, we're planning our business with a view that oil prices will remain in a range between $50 and $60 per barrel for the next few years. Despite the expected increase in U.S. onshore industry activity, when you step back and look at the global picture, I still see this as a reasonable range to plan our business. With this as a backdrop, I really like how we are positioned on the far left side of the cost curve in the U.S. with two huge oil plays onshore and substantial running room. Offshore, our strong oil linked cash flows and huge international gas resources which are ultimately linked to oil prices rather than U.S. gas, provide further support.

Looking at our 2017 volumes and capital outlook, we made a few adjustments from what we've provided late last year. We've raised our organic capital expenditure range to $2.3 billion to $2.6 billion, reflecting the rig additions for the expected timing of our Delaware acquisition and an accelerated rig addition in the DJ Basin. We've also built in some additional costs for the higher intensity completions that we have planned in the DJ and the Delaware.

As shown on slide 10, 75% of the total capital will be allocated to onshore development. Add in our Eastern Mediterranean program, and you have 95% of the program focused on these assets. We've also increased full-year total company volumes, 15,000 barrels oil equivalent per day compared to our November analyst event. This results in a 2017 range between 415,000 and 425,000 barrels of oil equivalent per day.

We've indicated on slide 10, the build throughout the year of total company volumes are expected to steadily increase each quarter with the second half of 2017 averaging between 440,000 and 460,000 barrels of oils equivalent per day. This is up more than 10% over the second half of 2016 after adjusting for divestments.

In the first quarter, we're impacted by a substantial underlift on oil in West Africa and the fewest number of U.S. onshore completions this year. You can also see the impact of the Marcellus JV dissolution and Tamar's 3.5% divestments within the first quarter. Obviously, the second half trajectory really stands out, reflecting our organic growth onshore along with the timing of the Clayton Williams acquisition.

The rig additions we've just made in the Delaware, the timing of new Eagle Ford completion, and a third rig added to our DJ Basin in the second quarter allows for a consistent volume growth trajectory throughout the year. As I have shown, current momentum, combined with our upward trajectory through 2017, puts us in a great position to deliver our long-term outcomes.

Now, let me hand the call over to Gary to provide further details on our robust U.S. onshore outlook for 2017.

Gary W. Willingham - Noble Energy, Inc.

Thanks, Dave. We've highlighted our U.S. onshore program on slide 11, including details of wells to be drilled and brought on production by basin. We began 2017 with seven rigs running and will increase this throughout the year to exit with nine rigs across our U.S. positions.

As mentioned earlier, the DJ, Delaware, and Eagle Ford drive substantial total and U.S. onshore oil production growth for Noble. Combined, these assets are expected to be up by approximately 60,000 barrels of oil equivalent per day by the second half of 2017 over the second half of 2016.

Oil makes up nearly half of the increase and our total oil onshore is expected to be up nearly 40% from the second half of 2016 to the second half of 2017. Three months ago, at our U.S. onshore update, we spent a substantial amount of time highlighting the strength of our U.S. onshore portfolio and our differentiated operational execution. I'd like to highlight some items that demonstrated this in the fourth quarter and how these results position us for another impactful year in 2017.

We exited 2016 with an accelerated pace of development. During the fourth quarter, we added two onshore drilling rigs in the Delaware Basin, bringing our total onshore rig count to seven, three in the Delaware, two in the DJ, and two in the Eagle Ford. I've been impressed with the operating efficiencies our teams continue to generate, especially on the drilling side where we are reducing both total drill time and costs, and doing so with outstanding safety performance.

Within the DJ Basin, we reduced average time to drill a long lateral wells at under six days. And in the Delaware, our average drilled footage per rig per day is up nearly 30% from the start of 2016. So, our long track record of driving efficiencies continues.

Looking at well productivity, clearly the results we are delivering from enhanced completion techniques highlight our leading onshore capabilities. We again saw great results from using longer lateral wells and higher proppant concentrations across our U.S. onshore position.

On slide 12, we've outlined some of these strong results starting with the DJ Basin. During the fourth quarter, we had 19 wells in Wells Ranch that reached peak production. The average lateral length was 6,500 feet, and you can see the wells in green on the plot versus the 1 million Boe type curve we provided in November.

Wells had an average proppant concentration of over 1,800 pounds per foot versus our type curve of 1,400 pounds per foot. And it's notable that 60% of the production from these wells is oil, which is considerably above our type curve assumption.

In addition, the blue line shows extended results for wells with 2,500 pounds per lateral foot or more. These 13 wells, none of which were represented in the green line, show even slightly better performance.

So, the key takeaways are value creation is not just about IP 24-hour or even IP 30-day, but sustainable performance over a longer period of time.

These enhanced completions and the way we are controlling the flowback of our wells is providing a longer plateau of production. In the case of these wells, peak production is being reached around day 90, and in some case, even out to day 120. It will be important to watch declines on these wells and the potential impact to ultimate recovery.

Our development plan in 2017 will continue to shift towards higher proppant intensity completions, targeting an average of around 1,800 pounds per foot while continuing to test some wells with over 2,000 pounds per foot. The majority of our wells on production in 2017 will be in the Wells Ranch and East Pony, some of the oiliest areas in the entire basin. We will be adding a third rig to our DJ Basin drilling program in the second quarter, a little earlier than expected, and we will run these three rigs for the remainder of the year.

Earlier this year, DCP announced plans for the next two major gas processing plants to be constructed in 2018 and 2019, along with a number of near-term projects to help expand capacity in 2017. This is a major step to ensure processing capacity keeps pace with the growth outlook in the DJ Basin.

On our own side, NBLX has commenced construction of the Mustang central gathering facility which should be operational late this year. We're drilling a number of wells in 2017 that will be ready to tie in to that facility late this year or early in 2018.

We've also seen very good results from our enhanced completions in the Delaware. Looking at slide 13, we provided initial performance of our most recent five wells that were brought on production in the fourth quarter. The wells tested a range of proppant concentrations between 3,000 and 5,000 pounds per foot.

Four of the wells were landed in the Wolfcamp A and are, on average, performing in line with our initial expectations for larger completions, above the 1.2 million barrel of oil equivalent type curve. It is still very early days with less than 60 days of controlled flowback production on most of these wells, and we will continue to watch performance uplift through time.

I'd like to draw your attention to the Sam Prewitt well. This well was completed with 4,200 pounds of proppant per foot. It's averaged over 1,000 barrels of oil equivalent per day for the first 30 days from a short lateral length and a 77% oil. Importantly, this is the southernmost well we have brought online to-date and is the closest well to the Clayton Williams Energy acreage.

Similarly, the Sky King and Jersey Lilly wells on the western extent of our acreage continue to confirm the quality of our acreage position. And orange on the map, we showed the Gaucho Estate which is Noble Energy's first operated Wolfcamp B well. It was completed with 3,000 pounds of proppant and is performing consistent with our initial expectations for the Wolfcamp B.

Similar to the DJ, it will be important to see what production rates are after 60, 90 and 120 days. In addition to the 35 wells expected online on our existing acreage in 2017, we will be bringing online 15 wells in the Clayton Williams Energy acreage this year following closing. Our activity will continue to focus on enhanced completions with the majority of our wells in the Wolfcamp A interval.

We've highlighted on the bottom left of this slide some of the operational efficiencies we're seeing with our Delaware drilling program. Compared to the first three quarters of 2016, fourth quarter average drill times reduced by two days even with an average lateral length increase of over 30%. This improvement resulted in an average drilling cost per lateral foot reduction of nearly 40%.

In addition to the integration of Clayton Williams Energy in 2017, our Delaware priorities are to continue to drive substantial operating efficiencies as we've transitioned in the full development mode. We're focused primarily on long laterals and multi-well pads. In fact, we recently completed the drilling of our first 10,000 foot wells on the three-well Monroe pad, and frac operations are currently underway. This pad includes our first 3rd Bone Spring well.

With that, I'll hand the call back to Dave.

David L. Stover - Noble Energy, Inc.

Thanks, Gary. Before ending our comments today, I would like to take a moment to acknowledge the contributions of Susan Cunningham, who'll be retiring next month after 16 years of service to Noble Energy. Susan has been instrumental in establishing an industry-leading exploration program and team, and has been a valuable member of the executive team. Susan, we certainly wish you the best in retirement.

In summary, I am pleased with what we accomplished last year and where we're headed. Noble Energy has a clear line of sight on its future. We're designed for generating industry-leading returns from a world-class portfolio. We are already off to a great start this year.

So, let's go ahead, Dana, and take some questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. We'll go first to Doug Leggate with Bank of America.

Doug Leggate - Bank of America Merrill Lynch

Good morning, everybody.

David L. Stover - Noble Energy, Inc.

Good morning, Doug.

Doug Leggate - Bank of America Merrill Lynch

Dave, I've got two questions, if I may. The first one is on the Wolfcamp A and B results that you talked about, and I realize there are lots of land limits on the A's in particular. But I'm just kind of curious, are you honing in on what – or how would you characterize, I guess, what a standard well design, if there is such a thing, that you view as optimal in terms of returns for the incremental cost of the proppant loading and taking into account any limitation you might have in McMoRan, what should we think as the – the opportunity you could take as you think about the development programs being called?

David L. Stover - Noble Energy, Inc.

Doug, just to make sure I'm clear, you're you talking about what's standard lateral length we're looking for?

Doug Leggate - Bank of America Merrill Lynch

It would seem that the Wolfcamp A result obviously was shorter than, I guess, we would think going forward as a normalized sort of standard well design if there is such a thing but more importantly, I guess, I'm thinking about the incremental costs of the proppant loading relative to the uplift you've seen, relative to some of the other wells around you. The uplift could've been a little better, but I realize that the bigger problem you've got longer cleanup times and so on. So, I'm just trying to understand if you're honing in on what you think a standard well could look like, and obviously, would you expect that to come with a higher type curve?

David L. Stover - Noble Energy, Inc.

Yeah, I'll turn it over to Gary in a minute, but first, I'll say that we're very encouraged by what we're seeing so far, and Gary can kind of explain why and how we're thinking about it.

Gary W. Willingham - Noble Energy, Inc.

Yeah, Doug. This is Gary, I think when you look at what we've done so far, some of these wells, as you point out, the lateral lengths are in the 3,500 to the 5,000 foot range, certainly we're transitioning to longer laterals. We mentioned just having drilled the three-well Monroe pad that's 10,000 foot lateral. So, just like in the DJ and the Marcellus, we think longer laterals are the right way to go here.

As far as the proppant concentration, I'd say it's still really early. The five wells that we just released range anywhere from 3,000 to 5,000 pounds, and that's above our type curve that we released in November which was 2,000 pounds. And very excited with what we're seeing so far with these higher proppant loadings, but we just need to see more data here as we've said that we need to see in the DJ Basin over time.

End of the day, we're really focused on what creates the most value, not the highest initial production rate or the highest EUR. So, we need to get a little more production data and make sure that we understand what the highest value completion is. And when we think we've got enough data, then we'll adjust type curves if we think we need to. But certainly, that's what we're focused on right now.

Doug Leggate - Bank of America Merrill Lynch

Yeah, I guess that it down for me but I guess what I was trying to understand was, are you at a point when you can confirm whether the costs of the incremental proppant loadings is still on an upturn or an improving curve, or if you sort of crossed the point of optimal return if you like, and it's still too early?

Gary W. Willingham - Noble Energy, Inc.

Doug, we're certainly not there yet in the Delaware. I mean these five wells we just released are the first ones we've done with a higher proppant loadings, and we've got, most of the wells, 60 days or less of production. So, I think we've said in the past, through these higher proppant jobs, we'd like to see at least six months, maybe as much as a year of production data, really be able to understand what the true ultimate uplift in EUR is versus maybe early time performance, and make sure that translates into value.

Obviously, the higher proppant jobs cost more, it takes more time to pump. So, cycle times are longer. And we just need to make sure that at the end of the day, it's worth it. We've been very encouraged with what we've seen, but we just like to see more data before we zero in on what we think the optimum completion is.

Doug Leggate - Bank of America Merrill Lynch

I appreciate your patience with my question. My follow-up is only a quick one. Big inflection on production in the back end of the year, could you give us some idea of pacing of – of how your completion schedule, in terms of rigs relative to production looks as we move through the year? And I'll leave it there. Thanks.

David L. Stover - Noble Energy, Inc.

I think, if I heard you right, Doug, the question's on the completion schedule in the second half of the year relative to the first and what's driving...

Doug Leggate - Bank of America Merrill Lynch

Right.

David L. Stover - Noble Energy, Inc.

...what's driving the production increase in the second.

Gary W. Willingham - Noble Energy, Inc.

With that and – with regards to the Permian as well, Doug?

Doug Leggate - Bank of America Merrill Lynch

Yes.

Gary W. Willingham - Noble Energy, Inc.

Yeah, I mean, you're definitely going to see completion activity pick up through the year. We just added two rigs to our legacy position there in the fourth quarter, going from one to three. We anticipate closing the Clayton Williams acquisition in second quarter. They're running one rig right now, and we've said we'll add another two rigs there by the end of the year. So, huge increase in drilling activity from fourth quarter of 2016 through the end of 2017, and you'll certainly see the pace of the new wells online pick up as well. I think when you look at the total Permian, we've said we'll bring about 50 wells online for 2017, and the vast majority of those will be in the second half of the year.

Doug Leggate - Bank of America Merrill Lynch

Great. I'll give . Thanks a lot, guys. Appreciate it.

Gary W. Willingham - Noble Energy, Inc.

Dana, are you there?

Operator

I am. We'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs & Co.

Thank you. Good morning.

David L. Stover - Noble Energy, Inc.

Hey, Brian.

Brian Singer - Goldman Sachs & Co.

Picking up on the topic of well costs, wanted to actually switch to the DJ Basin. Can you just give us an update on your well costs there at latest and greatest level of completion intensity and lateral length? And just give us some sense for where you see all that heading over the next year and any service cost inflation you expect in the DJ.

Gary W. Willingham - Noble Energy, Inc.

Yeah, Brian. This is Gary. I think when we talked in November, we had rolled out costs in the DJ of $5.5 million to $6 million, depending on where it was, and those were based on the same type curves that we rolled out at the time, which were based on 1,400 pounds per foot at average proppant concentration. Clearly, the wells we've brought on recently are higher proppant concentrations than that. So, those come with a higher costs. But I think we'll continue to evaluate those completions. And as we've said, 6 to 12 months of data is probably what we need to zero in on what the right design is. So, later this year, we'll probably be coming out with some updates on those curves. I think in the meantime, we're certainly watching our costs, and understanding where those are headed.

I think when you look at all the different cost categories and the different basins we play in, we would expect to see something on the order of 5% to 15% cost inflation, depending on what it is and where it is. We've certainly included some of that, I think, in our midpoint guidance offset by some further assumed efficiencies. If we see some of the higher cost inflation numbers that some folks are quoting out there, that'll push us more towards the high end of our capital guidance for the year. But on an individual well basis, again, we're focused on value. Obviously, the bigger jobs come at a bigger costs, and we just need to ensure that we get the value for that through the higher EURs over time.

Brian Singer - Goldman Sachs & Co.

Got it. And I'm sorry, can you just give us – you mentioned a $5.5 million to $6 million based on 1,400 pounds per foot, what's the current number for 1,800 pounds and lateral length of 9,000 feet, or how much more is that right now?

Gary W. Willingham - Noble Energy, Inc.

Oh, just going from 1,400 to 1,800 adds another probably $300,000 to $500,000, something like that, assuming no further efficiency improvement. But we'll see where we land.

Brian Singer - Goldman Sachs & Co.

Okay. And in DJ, how do you – you highlighted the production mix and how the oiliness has particularly improved from some of the recent IPs. How do you expect that to trend over the life of the well?

Gary W. Willingham - Noble Energy, Inc.

In the DJ?

Brian Singer - Goldman Sachs & Co.

Exactly. Yes, in the DJ.

Gary W. Willingham - Noble Energy, Inc.

Yeah, I mean, I think, you see oil mix declining over time. The wells do get a bit gassier over time, so it'll definitely decline off. I think the type curve that we put out there in November for Wells Ranch, we assumed 40% oil. That's 40% over the life of the well. So, 60% in these first three months or so on these wells is certainly above the average we've assumed for the life. That'll come down over time. We'll see how it compares to the 40% over the life of the well.

Brian Singer - Goldman Sachs & Co.

Okay. Great. And last one, as you go into the development phase for Leviathan over the next year, you highlighted some of the flexibility you have to sell assets, I think, $1 billion is what you mentioned. Do you have a specific target for net debt-to-EBITDA or a comfort zone based on commodity prices, or how aggressive you want to ramp activity elsewhere we should think about?

David L. Stover - Noble Energy, Inc.

Well, I think Ken does a good job of looking at a number of factors. It's not just net debt-to-EBITDA but all the different factors that also tie in to our discussions with the rating agencies, and – so, we continue to look at all of those, and stress those at lower price. One of the things – if you go back to last year, one of the discussions we had with the rating agencies that really landed well was our stress case when we looked at much lower oil prices and how we were able to withstand much lower prices over a number of different criteria. So, it's not just a criteria.

Brian Singer - Goldman Sachs & Co.

Thank you.

Operator

We'll go next to Pearce Hammond with Simmons & Company.

Pearce Hammond - Simmons Piper Jaffray

Yeah, good morning and thanks for taking my question. I'm just curious on that Mustang IDP. What does that do for total net DJ deliverability versus where deliverability is at today?

Gary W. Willingham - Noble Energy, Inc.

Are you talking about gas capacity in the basin, Pearce? Or what are you – give me a little more idea what you're talking about.

Pearce Hammond - Simmons Piper Jaffray

Yeah, so gas capacity in the basin.

Gary W. Willingham - Noble Energy, Inc.

Well, I mean, I think as we move into drilling some wells in the Mustang – and we're not drilling a tremendous number there this year, it's more towards the end of the year. But those are definitely gassier areas, and so, you'll see a higher gas cut there. We've timed that to the first facility that NBLX is building in that area to make sure we've got capacity there, and then I think it's certainly timed very well with some of the capacity additions that DCP has planned with the first – the next big plant coming on in 2018 and then some in-field optimization and capacity improvement projects they're doing this year. So, you'll definitely see a little more gas from those wells, but I think it's matched up quite well with the capacity growth that we see coming in the basin.

Pearce Hammond - Simmons Piper Jaffray

Thank you. And then, my follow-up is, where do you see current sand cost? And then, what is your target for 2017, in the Delaware Basin, your average sand loadings that you're expecting on the wells that you're going to complete?

Gary W. Willingham - Noble Energy, Inc.

Yeah, I mean, I think sand cost is one of the things we're watching, and I think it's not just the cost but availability. We've had very good supplier relationships on sand for a number of years and feel quite confident that we'll be able to get all the sand that we need. But obviously, costs are creeping up. I think it's within that 5% to 15% range that I mentioned overall, depending on what service and what area. I think as far as what we're assuming for the Delaware for this year, the type curve is still based on 2,000 pounds per foot. Obviously, the wells we just released were higher than that, 3,000 to 5,000 pounds. I think most of the wells you're going to see us complete in 2017, at least until we have some more longer-term data on the higher completions, are probably in that 3,000-pound range. Those come at a higher cost again, obviously, so that's part of the increase in capital that you've seen since our November analyst day.

Pearce Hammond - Simmons Piper Jaffray

Thank you very much.

Operator

We'll take our next question from Paul Sankey with Wolfe Research.

Paul Sankey - Wolfe Research LLC

Hi, everyone. Just a direct follow-up to the sand question, if I could. Is that the biggest pressure that you feel on costs, or are there other areas that are of more concern to you? Thanks.

Gary W. Willingham - Noble Energy, Inc.

So, I wouldn't say it's the highest by any means. I mean we've got our eye on sand, we've got our eye on pumping services, drilling rigs, tubular. So, we're watching everything. We've got good long-term relationships with key suppliers in all of those areas. So, we feel pretty good with our ability to control those costs and offset some of it with efficiencies as best we can. So, sand is part of the mix, but it's certainly not the only one.

Paul Sankey - Wolfe Research LLC

Okay. But would it be the biggest one or are there other things that worry you more?

Gary W. Willingham - Noble Energy, Inc.

I wouldn't say it's the biggest one. I also wouldn't say I'm overly worried about any of them.

Paul Sankey - Wolfe Research LLC

Okay. Fair enough. A total change of tack, if I could. We were in Washington yesterday, speaking to policymakers. What's your perspective with your business mix of policy in Washington, and what concerns you there or excites you? And I'm thinking not only about domestic policy, but obviously also foreign policy. Thank you.

David L. Stover - Noble Energy, Inc.

Well, I think I probably won't get into any policy contemplations here, Paul, because I'm not sure I know exactly where it's going whether it's domestically or internationally yet. So, we'll reserve comment and judgment, and see how it plays out.

Paul Sankey - Wolfe Research LLC

Yeah, I think that's fair enough, insofar as it does seem that there's tremendous uncertainty about where we're headed, I just wondered if you guys had a particular agenda that you wanted to promote in any way?

David L. Stover - Noble Energy, Inc.

No, we'll stay we'll stay flexible.

Paul Sankey - Wolfe Research LLC

Good. Thanks a lot.

Operator

We'll go next to Irene Haas with Wunderlich. Hearing no response, we'll move on to Charles Meade with Johnson Rice.

David L. Stover - Noble Energy, Inc.

Are we losing people there, Dana?

Operator

I think so. We'll move on to John Herrlin with Société Générale.

John P. Herrlin - Société Générale

Yeah, hi. Thank you. With Leviathan, Dave, will you book reserves at the end of the first quarter with FID or year-end?

David L. Stover - Noble Energy, Inc.

We'll book them by year-end. I mean obviously, it'll be set up to be booked with FID but just – as far as actually reflecting it externally, it'll show up at the year-end reserve booking.

John P. Herrlin - Société Générale

Okay. That's fine. With the Eagle Ford, given Clayton Williams, is it as critical for Noble going forward?

David L. Stover - Noble Energy, Inc.

Is what as critical, John?

John P. Herrlin - Société Générale

Eagle Ford.

David L. Stover - Noble Energy, Inc.

Oh, Eagle Ford. Well, it's still a sizable position when you look at the resource, it's still close to 0.5 billion barrels, and it's going to be a nice impact especially as we finish out a number of these wells in the South Gates Ranch this year. I think, longer term, the real driver will be our ability to define the Upper Eagle Ford as a key target, and do some of those tests and we'll have some of those tests later this year. So, it's still a very nice contributor.

John P. Herrlin - Société Générale

Okay. Thanks. Last one for me. With the greater sand loadings, do you feel that you're just keeping the brittle formations open more, or are you getting more communication, say, with the interbedded clayier type shales within the formations?

Gary W. Willingham - Noble Energy, Inc.

Yeah, John. I mean those are all things that we're looking at. I think as we get through this year and talk about what changes, if any, we're going to be making to type curves, we'll roll out some commentary as to why we think performance might be better.

John P. Herrlin - Société Générale

All right. Thank you.

Operator

And we'll take our next question from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Co. LLC

Gentlemen, can you hear me this time?

David L. Stover - Noble Energy, Inc.

We can, Charles. Sorry.

Charles A. Meade - Johnson Rice & Co. LLC

Okay. Whatever – no, whatever got Irene got me too there, and I apologize if maybe I've missed. I know John just asked a question about Leviathan, but if I could follow up on that. Could you talk about how that's going to progress over the year? I know you mentioned that you have sanction expected sometime this quarter, but can you talk about what we will expect in the way of construction progress or things along those lines in 2017? And also talk about what your preferred time line would be for a sell-down or to entertain a sell-down there?

David L. Stover - Noble Energy, Inc.

Yeah, I think – let me take the second question, and I'll turn the first one over to Keith, since he's driving all that timing in the project. The second question, as far as timing on sell-down. I think for Leviathan sell-down, that's probably best after sanction obviously, and as we get a little further on in the project. But we'll be open to looking at when we can get the value that would make sense. I think on Tamar, what we've talked about is I think we still have, what, five to six years on that. Five years from a timing standpoint. But I would expect that probably over the next couple of years, you'll see us bring that down to the 25%. A lot of interest in that opportunity, especially when you look at the cash flows.

Onto the first part of that, I'll let Keith talk a little bit about how he sees the progression of construction work over the next couple years.

J. Keith Elliott - Noble Energy, Inc.

Yeah, Charles, we're moving into the development phase there now. We have started a procurement for – of the raw materials for both the subsea and the platform construction project. I'd expect that that would lead us into moving to cutting steel around early second quarter to midyear. At the same time then, we'll be moving toward bringing a drilling rig in to the field to start the first development drilling sometime around the midyear to, again, mid second quarter.

Charles A. Meade - Johnson Rice & Co. LLC

Got it. That's helpful, Keith. And then, if I could ask a question going back to those DJ completions, and perhaps this is best for Gary, but I know you've filled a lot of questions on this already, but I'm wondering if you could talk about – I thought one of the most striking slides you had was the one people have talked about already, showing that uplift with your more recent completion designs. Can you talk about perhaps what you may be doing differently on the flowback of those wells with the higher proppant concentrations that is making them continue to increase their rate all the way through 90 days or beyond? And – yeah...

David L. Stover - Noble Energy, Inc.

Charles, I would have to echo your comment. That's one of my favorite slides in the pack, on slide 12, I think the results are just phenomenal, what we're seeing there. But let me turn it over to Gary, and I'll contain my enthusiasm here.

Gary W. Willingham - Noble Energy, Inc.

Yeah, Charles, and I don't think we want to give away too much of what we're doing, but we're definitely controlling flowback on those wells. And I would say, they're staying flatter for longer under that control of flowback than what we've modeled for a typical type curve. And then, once we start seeing decline, we see shallower decline than is modeled in the type curves. So, the combination of those, if you can picture kind of a flat production profile versus a declining type curve, over time, the outperformance – cumulative outperformance versus type curve just continues to widen, right, until the actual production starts to decline as well.

So, that's what we're continuing to see on these wells as we get out to 90 to 120 days, we're continuing to see widening performance versus the type curve, over 50% above as we've noted in the comments. We'll see how much longer that lasts before we start to see some decline, and what the ultimate uplift to EUR is. I'd be surprised if it's 50%, but it'll certainly be more than what we've got modeled in the type curve. So, again, we'll gather some more data, continue to watch the wells, and later this year, probably come out with some new type curves for that area.

Charles A. Meade - Johnson Rice & Co. LLC

Thanks, Gary.

Gary W. Willingham - Noble Energy, Inc.

Yes.

Operator

And we'll go next to Arun Jayaram with JPMorgan.

Arun Jayaram - JPMorgan Securities LLC

Morning. Gary, I was just wondering if you could give us a bit more color on what you're baking in, in terms of your outlook, in terms of enhanced completions on the production and CapEx side. It sounds like you are baking in higher completion costs, assuming 3,000 pound completions in the Delaware, but it's unclear what you're doing on the production side.

Gary W. Willingham - Noble Energy, Inc.

Yeah, Arun, I think on the cost side, as we said, we'll focus mainly on kind of a 3,000-pound average in the Delaware this year. We'll probably continue to have some higher than that, but on average, that's probably a pretty good number to assume.

In the DJ, again, probably 1,800 pounds for average, some higher than that as well, but that's versus a 1,400-pound type curve. I think as far as what we assume for production, we're certainly looking at the early results in both areas, and as we've said repeatedly, very encouraged by it. But also, until we have enough data to really increase the type curves, I'd say we're continuing to be a bit conservative in how we're modeling production in those areas until we have more long-term data.

Arun Jayaram - JPMorgan Securities LLC

Fair enough. And I was wondering, Gary, if you could just comment on your thoughts on your initial Wolfcamp B completion as well as the Upper Eagle Ford.

Gary W. Willingham - Noble Energy, Inc.

Yeah, excited about the Wolfcamp B. I mean this is the first Wolfcamp B well that we've brought on as Noble Energy. I'd say, it's producing right in line with our type curve expectations. It's pretty flat right now, so we'll get some more data. That's another one where we've got less than 60 days of data on, so we obviously we need to see some more data. But very excited about that as our first Noble-operated deeper test in the area.

I think when you look at 2017, in the Permian, probably about 80% of our activity will continue to be focused on Wolfcamp A, Upper and some Lower. But we will start to test more 3rd Bone Spring, more Wolfcamp B. And so, we're excited with these early results.

On the Upper Eagle Ford, also quite excited. We've talked in the past about how we're looking at areas where historically the Upper Eagle Ford compared similarly to the Lower Eagle Ford, and then with our enhanced completions, we thought we could increase performance on both of those zones to where they would be very nice programs. I think the first well that we've got on supports that assumption. We're very happy with the production we're seeing out of this first Upper Eagle Ford test. It's actually as good or maybe even a little better than some of the recent Lower Eagle Ford wells that we've had in the area. But it's one well, so we need to get the second well online. We need to get extended production from both. We need to get some tests in some of the other areas. We've talked about some L&E tests that – or Upper Eagle Ford tests in the L&E area that we've got coming on later this year as well as a pilot in North Gates Ranch. So, all that data, we'll inform our conclusions as we go forward, but very excited with what we're seeing in the early days.

Arun Jayaram - JPMorgan Securities LLC

Thanks, Gary.

Operator

We'll go next to Irene Haas with Wunderlich.

Irene O. Haas - Wunderlich Securities, Inc.

Yes. Can you hear me?

David L. Stover - Noble Energy, Inc.

Irene, you're there.

Irene O. Haas - Wunderlich Securities, Inc.

That's right. Thank you. So, a quick question on – oil price differentials is looking better, can you give me a little bit color on which geographic mix it's coming from?

David L. Stover - Noble Energy, Inc.

Well, I think some of what you're seeing is a reflection up in the DJ, as we've moved more product through the pipeline. I mean it results in a little higher transportation costs, but it's more than offset on the netback revenue. So, that's really stood out over the last quarter and into this quarter.

Irene O. Haas - Wunderlich Securities, Inc.

Great. If I may ask, one other question is, everybody is drilling these longer lateral wells with higher intensity frac, delivering more oil, and probably with a flatter decline, I mean what would that do in aggregate to U.S. supply? I mean, are we going to see probably the money you spend getting more oil for longer with less decline, is that what we should expect for sort of the U.S. oil macro?

David L. Stover - Noble Energy, Inc.

It could be. I think the companies that have the large contiguous positions will benefit probably the most with the ability to put a larger percentage of their wells into the longer laterals and design them for longer laterals. So, yeah, we'll have to see how it plays out, but we've seen the efficiency improvements over the last two years. I think I've always said I don't think we're at the end of that. I think a big driver of that will be some of this longer lateral and higher proppant concentrations . But as Gary said, we're only going to do what creates real value for us in the price world that we're in.

Irene O. Haas - Wunderlich Securities, Inc.

Got you. Great. Thanks.

Operator

We'll go next to Mike Scialla with Stifel.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Hi. Good morning. Another question on the enhanced completions in the DJ. There's been some thought, I think, that the completions there with the bigger fracs may work in the oilier areas like Wells Ranch or East Pony but maybe not so much in the gassier areas. But I believe, you showed back in November some data from the Moser wells and the Mustang area that looked pretty encouraging, just wonder if there's any update on those.

Gary W. Willingham - Noble Energy, Inc.

Yes, Mike. We haven't given an update on them in the pack, but performance is still very strong on those wells. I think, in general, you're right. I mean I've heard the same thing that as you move to the gassier areas, the optimum proppant concentration could be lower than what we see in the oilier areas. Obviously, our experience, so far, has been limited to those Moser wells. And so, as we drill more wells in the Mustang area later this year, we'll start to get a better handle on that ourselves, but that is a possibility.

I think when you look at the performance of those initial Moser wells and the proppant concentrations that those were pumped at, I can't remember exactly what it was, I think it was around 1,400 pounds per foot, which in and of itself is enhanced, right, relative to the historic frac designs in those areas. It's just not as enhanced, if you will, as the oilier areas. But we're quite happy with that. We'll continue to watch those wells. And as we move into the gassier areas in the coming years, not in a big way anytime soon but in the coming years, we'll test different designs there just like we have in the oilier areas.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Okay. Thank you. And then, on the Wolfcamp, a lot of your competitors have been talking about two zones within the Wolfcamp A nearby, wondering if you're thinking along the same lines. And if so, any plans to test that concept either with the staggering or stacking wells this year?

Gary W. Willingham - Noble Energy, Inc.

Yes, I mean we talked about Wolfcamp A, Upper and Lower as well. And both will be a focus for us in 2017. I think when you look at our existing position prior to Clayton Williams where we're going to drill around 30 wells or so, probably two-thirds of those are in the Upper, a little less than a third maybe in the Lower, and then a few Bone Spring wells.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Okay. And last one, if I could. Gary, you mentioned when you did the acquisition of Clayton Williams that you really didn't put a lot of value on the Bone Spring, some other operators there have been talking about the shale intervals in the Bone Spring in the Southern part of Reeves County, I wonder if that is anything you guys have looked at yet.

Gary W. Willingham - Noble Energy, Inc.

Well, I wouldn't say we spent a whole lot of time looking at it yet. We don't have the deal closed yet, but it's certainly something that we're keeping an eye on other's activity as we get the deal closed, and start to ramp up activity, we'll keep an eye on it. Near term, I think you're going to see most of the activity on the Clayton Williams acreage continue to be Wolfcamp A as well. But you're right, we didn't put any value really on anything beyond the Wolfcamp A, so to the extent other zones, whether it's 3rd Bone Spring, Wolfcamp B or C have value potential going forward, that's just additional icing on the cake, if you will.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Great. Thank you.

Operator

We'll go next to Michael Hall with Heikkinen Energy Advisors.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Thanks. Good morning. Just wanted to go back to the DJ in the context of the initial results on these enhanced completions. I mean, if you think about this kind of leading-edge result and the potential implications around the EUR relative to the well cost increase, how do these compare within the portfolio at this point in terms of how they compete on returns or F&Ds relative to the Del Basin in particular, but also relative to Eagle Ford?

Gary W. Willingham - Noble Energy, Inc.

I think they perform quite well, Michael. I mean when you look at the onshore economics that we rolled out in November, DJ economics were very strong, 30% to 50% returns, that was at the type curve assumptions, so 1,400 pounds per foot. It would be equivalent to the black line on the Wells Ranch plot that we released again today that were, in the early days, showing 50% performance above. So, clearly that outperformance adds possibly substantially to the economics. And again, we continue to drive efficiencies and costs down where we can too.

So, economics are only getting better. They certainly compete with anything else in the portfolio, and it's in an area that we continue to focus a large part of our capital program on, drilling roughly 150 wells this year and bringing on 120 or so.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Right. Great, makes sense. Yeah, it certainly seems like you'd think it competes with most anything in the Lower U.S. and I guess just as a follow-up, trying to think through, if you continue to have these sorts of results that are outperforming expectations in DJ, Delaware, and Eagle Ford, really I mean, how should we think about potential use of, let's say, additional proceeds from that outperformance, meaning as you bring in more cash, recycle more cash, what's kind of the anticipated first use? Would you accelerate activity or, I guess, just put it on the balance sheet? How should we think about that?

David L. Stover - Noble Energy, Inc.

Well, from an activity standpoint, Michael, I think we're staying consistent with what we've been talking about which is going to be DJ and Delaware. I mean that's going to be dependent on performance, but what we've seen, there's nothing that would change our mind at this point.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

But potentially though, if you continue to have the outperformance, you'd maybe do more in those areas? Is that – am I hearing that right?

David L. Stover - Noble Energy, Inc.

I think if you look at our plans for 2020, it shows increasing activity over that plan, then it's just a matter of how fast and what supports any changes over that period of time. So, as Gary said, it's too early to tell, but we're sure watching it awfully close.

Michael Anthony Hall - Heikkinen Energy Advisors LLC

Got it. Appreciate it. Thanks.

Operator

We'll go next to Gail Nicholson with KLR Group.

Gail Nicholson - KLR Group LLC

Good morning, everyone. I'm going to actually switch tack to – on the exploration side. You guys have the test in Surinam late 2017. You picked up some more acreage in Newfoundland. When you think about your exploration portfolio holistically, what area or region are you most excited about? And if you had some incremental CapEx to allocate to exploration activity, where would that go?

David L. Stover - Noble Energy, Inc.

Yeah, well, I think there's a number of areas we're excited about. I think we're not spending as much as we did a few years back, and we're probably not spending in as many areas, but what we are spending it on we're pretty excited about. The project in Surinam, for example, is a very large opportunity that our folks have worked with partners to continue to progress, and we're excited to get that drilled. I think the same thing goes for what we picked up offshore in Newfoundland, the acreage we have in Gabon and continuing to look at that area. But I guess, Susan here, probably I ought to turn it over to her to give some of her comments.

Susan M. Cunningham - Noble Energy, Inc.

Yeah, generally, I still like West Africa if you get the right opportunities. We're excited about what we have in Gabon, and we're looking at other possibilities. And we're also evaluating Mexico. We've decided the last couple bid rounds not to participate, but we're still evaluating it and looking for the right thing with the right kind of economics on it.

Gail Nicholson - KLR Group LLC

Okay, thank you. And then, just in regard to the higher oil composition at Wells Ranch, do you think that is more driven by the choke management, or do you think that's potentially more driven by the enhanced completion design?

Gary W. Willingham - Noble Energy, Inc.

That's a good question, Gail. I think it could be a combination of both. But again, as I said before, I think we'll continue to work through why we think we're getting better performance than we expected to see. And as we get later in this year and start to update some type curves, we'll roll out some information as to where we think that's coming from.

Operator

And we'll go next to David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities LLC

Hi. Morning. Just one quick follow-up. If I think about the Marcellus, the decision to go ahead and complete those wells, what – I mean obviously price impacts that. But what was the decision there, and then, how do we think about the Marcellus as part of the portfolio going forward?

David L. Stover - Noble Energy, Inc.

Well, I think, like we've talked about, we've got some developed, drilled uncompleted wells that we're focusing on this year. And then, we'll continue to watch the longer-term outlook for gas price as we move through the year.

In our plan, we had plan to bring a rig in later this year. Of course, that's always dependent on how it's competing in the portfolio and the economic outlook. I think overall in the area, we'll continue to look at what makes sense for us to do relative to what others' plans are in the area. And if there's something that makes sense for somebody else that they have a plan to do differently and it fits in their portfolio different, we're open to looking at that. But for right now, our plan is to focus on the uncompleted wells this year that have very good economics, very competitive, and then evaluate the rig as we're getting closer to later this year and looking into next year.

David R. Tameron - Wells Fargo Securities LLC

Okay. And then, just one more back to the DJ. Is there any difference in the way, whether it's the Niobrara or Codell, those formations are accepting the proppant, are you seeing a difference? And I know the focus has been obviously the East Pony and Mustang, but have you seen a difference in that?

Gary W. Willingham - Noble Energy, Inc.

Difference between Niobrara and Codell?

David R. Tameron - Wells Fargo Securities LLC

Yeah, as far as the enhanced – as far as which rock is willing to accept the higher proppant, is there a difference between formations?

Gary W. Willingham - Noble Energy, Inc.

Well, I mean, I think just given the nature of the formations, it's a little bit easier to pump into the Codell. But I'm not sure as far as the performance of that whether we've seen a whole lot of difference.

David R. Tameron - Wells Fargo Securities LLC

Okay. All right. Thanks.

Operator

And we'll take our final question today from Paul Grigel with Macquarie.

Paul Grigel - Macquarie Capital (USA), Inc.

Hi. Good morning. Just one on first quarter guidance here to start. You note the DJ is likely to decline. And the release notes that's due to the low north completions in the first quarter. With the flatter declines that you guys have talked about, should we be viewing this as due to timing of completions that happened in fourth quarter, or even back to third quarter? Just trying to reconcile the declines there, given the relative uplift that we've seen from the increased proppant.

Gary W. Willingham - Noble Energy, Inc.

Yeah, Paul, I think it's both. We actually had fewer completions in the fourth quarter of last year than the third quarter. And then, looking at 2017, we've got the fewest number of completions in the first quarter of all the quarters through 2017. So, it's just a bit of a low spot over those two quarters in the completion activity. Typically, I think we've seen that kind of through the winter period in past years, too. So, that's just kind of what's driving it.

David L. Stover - Noble Energy, Inc.

Yeah, I think if you go back and look at the last four years, first quarter's been the lowest quarter for us, three out of those four years.

Paul Grigel - Macquarie Capital (USA), Inc.

Perfect. And then, as a follow-up to that and without pressing too hard on to 2018. Given the strong second half growth, how should we think about momentum into 2018, given the number of completions that are back-half weighted and the typical seasonality in 1Q? Should we be viewing 2018 in a similar vein? And then, how should we thinking about kind of a longer-term governor on activity? Is that still spending within cash flow post the acquisition and post the update today?

David L. Stover - Noble Energy, Inc.

Well, I think, as you said, it's too early to give the outlook and trajectory for 2018. But I think in general, and I'll go back to my comment, if you look at history. Historically, the first quarter or the first half has usually been less than the second half, just based on activity and also accounting for winter months, et cetera. So, I would expect without having a clear view of it yet that I'll be surprised if it's not a little bit of the same.

I think as far as spending, we're continuing to look at over the next four or five years. And what we laid out for our plan was the ability to spend within cash flow. In a $50 world, if we get a $60 world, we're probably generating excess cash flow, with the plan we've laid out, that would drive us to look at what we could accelerate especially if we're seeing the results, like we're seeing in these program, so far. So, we'll continue to develop that and lay it out as we go.

Paul Grigel - Macquarie Capital (USA), Inc.

Perfect. Thanks for squeezing me in.

Operator

And this concludes our question-and-answer session. I would now like to turn the conference back over to Brad Whitmarsh for any closing remarks.

Brad Whitmarsh - Noble Energy, Inc.

Yeah, I just want to say thanks to all of you for fitting the call in to your schedule this morning. Look forward to having a follow-up conversations with many of you over the next several days.

Operator

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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