Noble Energy Management Discusses Q4 2013 Results - Earnings Call Transcript

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 |  About: Noble Energy, Inc. (NBL)
by: SA Transcripts

Operator

Good morning. Welcome to Noble Energy's Fourth Quarter and Year End 2013 Earnings Conference Call. I would now like to turn the call over to Mr. David Larson. Please go ahead, sir.

David R. Larson

Thanks, Shannon. Good morning, everyone. Welcome to Noble Energy's fourth quarter and year end 2013 earnings call and webcast. On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President, COO; and Ken Fisher, CFO. This morning, we issued our year end 2013 earnings release, and it does include our proved reserves, which you have hopefully had a chance to review. A few supplemental slides for this call were posted as well to our website this morning, and they'll be a good reference point for today's discussion. The agenda for today will begin with Chuck, highlighting our performance in 2013 and an outlook for 2014. Dave will wrap up with a discussion of our 5 core operational areas. We will leave time for Q&A at the end, and plan to complete the call in less than an hour. [Operator Instructions] I want to remind everyone that this webcast and conference call contains forward-looking statements, as well as references to non-GAAP financial measures. You should read our disclosures in our latest news release and SEC filings for a discussion of those.

With that, let me that turn the call over to Chuck.

Charles D. Davidson

Thanks, David. Good morning, everyone, and thank you for joining us. Today, we find ourselves fully engaged in executing our 2014 plan, and it is one that I find very exciting. Before moving to discuss the current year, I think it's appropriate to reflect on some of our notable achievements for 2013. Starting with production, we are up 20% over 2012. That's excluding the impact of non-core asset divestitures. Reserves were up 19% to over 1.4 billion barrels of oil equivalent at the end of 2013, and discretionary cash flow was also up 19% to $3.4 billion for the year. It's no surprise these are all record levels for Noble Energy, driven by the acceleration of our onshore unconventional opportunities, as well as the delivery of multiple major project developments in the global offshore areas. It was an outstanding year on the major project front, as we started up our first central processing facility at the Wells Ranch integrated development plan area in the DJ Basin, and commenced production at 2 offshore major projects. We also extended the project pipeline with the sanctioning of 6 new major projects during the year, including Big Bend and Gunflint and the Deepwater Gulf of Mexico, Tamar Southwest, and our compression project at Tamar in the Eastern Mediterranean, as well as the Kyoto gas processing facility in East Pony integrated development plan area in the DJ Basin. 2013 was also a year of further exploration momentum as we added 4 new discoveries: 2 in the Deepwater Gulf of Mexico and 2 in the Eastern Mediterranean which provided additional opportunities for growth in the future. We also continued to optimize our portfolio in 2013, divesting a number of assets that were no longer core to our business. At the same time, we were able to further enhance our core areas in the onshore area of the U.S. through the addition of the Allegheny Airport and Dominion acreage in the Marcellus, and the completion of a strategic acreage swap in the Greater Wattenberg area. It's all about focus, positioning ourselves with sole attention on premier return opportunities and eliminating the distractions that drain resources.

Quickly wrapping up 2013, we finished up the year with a very good fourth quarter, delivering sales volume of 293,000 barrels of oil equivalent per day, which tied our previous quarterly record, and was substantially higher than our original fourth quarter guidance. Highlighting our performance was the DJ Basin with production of 100,000 barrels of oil equivalent per day, an increase over the third quarter despite the impacts of the devastating Colorado floods and the asset exchange mentioned earlier. Our Marcellus Shale assets are delivering as well, averaging almost 200 million cubic feet equivalent for the quarter, and exiting the year at over $210 million per day.

In Israel, production was impacted positively by high seasonal demand due to cold weather and cold plant maintenance. Tomorrow's reservoir performance and reliability have been outstanding, at times supplying up to 70% of the fuel needed for electricity generation in Israel. We also experienced strong liquid volumes in the Deepwater Gulf of Mexico and West Africa despite being underlifted during the period.

In summary, all 5 core areas contributed above expectations for the quarter and ended the year in great fashion. Revenues were over $1.3 billion for the quarter with liquids representing 80% of the total. Discretionary cash flow from continuing operations was $925 million, up 10% from the fourth quarter last year, and we ended 2013 with $1.1 billion in cash, and total liquidity of over $5 billion, as well as net debt to book cap ratio of 29%. These strong metrics include the impact of a $1 billion 30-year bond issuance during the fourth quarter, which further strengthened our financial position.

On the cost side, lease operating expense was slightly lower than our expectations, averaging under $5.10 per barrel equivalent, and DD&A was $15.70, reflecting strong reserve bookings at year end. Transportation cost was up slightly from the prior quarter, primarily a result of U.S. onshore growth and the startup of the Wattenberg oil trunk line in the fourth quarter. Exploration expense included significant seismic expenditures in the Falklands and Eastern Mediterranean, as well as costs from our initial well, offshore Nicaragua.

I'll also point out that taxes, on an adjusted basis, were higher than our third quarter level, resulting from the full year true-up of the tax provision and the impact of Nicaragua well in the fourth quarter. Besides our usual adjustment for unrealized derivative activity this quarter, there were a couple of other adjustments to GAAP earnings, resulting from our continued portfolio optimization. Prior to year end, we completed the sale of deep gas rights in the Powder River basin in Wyoming, which resulted in a realized gain. This was essentially offset in terms of the impact to the P&L by an impairment recorded on our tri-state shale gas properties, which have now executed a sales agreement.

Our portfolio work continues in 2014, with our having also executed a purchase and sale agreement to divest our natural gas assets in the East Texas -- North Louisiana Hainesville play, and we're working on additional non-core divestments as well. As I mentioned earlier, we ended the year with total reserves of 1.4 billion barrels of oil equivalent, an overall increase of 19% versus year end 2012. Total reserve replacement, including additions and revisions, was a very strong 369%.

In the U.S. onshore, we added nearly 280 million barrels in total, approximately 190 million barrels equivalent from discoveries and extensions, another 50 million barrels equivalent of positive performance revisions, and the remainder primarily from the Marcellus acquisitions mentioned earlier. The very strong performance that we've been experiencing in the DJ and Marcellus are now starting to show -- starting to be reflected in reserves, and thus the positive reserve revisions this year.

Offshore, we booked reserves as a result of sanctions at Big Bend and Gunflint in the Deepwater Gulf of Mexico and Tamar Southwest in the Eastern Mediterranean. Our offshore businesses accounted for nearly 60 million barrels of extensions and discoveries and over 30 million barrels of positive performance revisions. The startup of Tamar and Alen also contributed to a significant conversion of proved undeveloped, approved developed, which resulted in our overall PUD percentage decreasing to 40% from 61% at the end of 2012. All in reserve replacement cost was approximately $12 per barrel equivalent.

At the end of last year, we provided an updated 5-year plan at our Analyst Conference, including a deep dive into each of our core business areas. It's an aggressive plan, but one we are certainly confident in delivering with essentially all the resources necessary to deliver the plan having already been discovered.

Slide 6 highlights the major outcomes from the plan. Production is planned to grow at 18% compound annual growth rate over the next 5 years, delivering more than 620,000 barrels of oil equivalent per day in 2018. Discretionary cash flow was planned in excess of $8 billion at the end of the 5-year planning period, more than double our 2013 discretionary cash flow. Proved reserves and return on capital employed are also anticipated to grow dramatically, and we'll execute the plan with significantly lower committed capital than what was assumed in our previous plan. These are exceptional outcomes for a company of any size.

Before handing it over to Dave, I wanted to just highlight some of the exciting things to look forward to this year. First, our capital budget reflects substantial acceleration in the onshore areas, significant investments for the next round of major projects, and continued commitment to material exploration. Production is anticipated to increase significantly in 2014, led by the onshore core development programs in the DJ and Marcellus, and then our Israel gas is expected to be up with growing domestic demand there.

Our onshore U.S. programs will receive approximately 70% of our capital investment in 2014 as we target the drilling and completion of over 500 wells this year. Beyond the growth in both programs, the DJ and Marcellus will also see significant down spacing activity in 2014, increased drilling of long laterals, and further focus on reducing drilling and completion costs. Success in these areas has the potential to significantly increase our captured resources and enhance already strong rates of return and net present values per well.

We will also continue exploration in the Wilson new venture play in North East Nevada this year, having recently finished drilling our second vertical well in the play and taking a vertical core for detailed analysis. Drilling results, thus far, have confirmed the existence of a thick Elko reservoir section, hydrocarbon saturation and thermal maturity. By midyear, we anticipate completing at least 1 of our 2 drilled wells, and we are currently preparing additional drilling locations for wells in the second half of 2014. In our offshore business, after bringing on Tamar and Alen in 2013, we're moving forward aggressively with the Big Bend and Gunflint developments. In addition, we're progressing multiple discoveries towards sanction in 2014, including Dantzler in the Gulf of Mexico and Diega in Equatorial Guinea. Both will ultimately be tiebacks into existing infrastructure, with first production targeted in 2016. We're also planning for multiple exploration prospects this year, including wells in the Deepwater Gulf of Mexico and Cameroon, which provide the opportunity for new discoveries this year. Our new ventures teams are progressing multiple opportunities towards first drilling, and we are supporting those programs with significant seismic and processing this year.

In the Falkland Islands, we're nearing completion of our northern 3-D seismic acquisition, which will bring our total 3D data acquired to nearly 5,000 square miles. Sizable prospects are being matured, and I would anticipate a rig contract being secured shortly in support of drilling in 2015. In the Eastern Mediterranean, it will certainly be a very busy year for Noble Energy. On the production side, we're expanding the Ashdod onshore receiving station through the addition of compression, which is designed to increase the deliverability of gas to Israel. This year, we will also begin developing our newest discovery at Tamar Southwest, tying it in to the existing Tamar infrastructure for first production in 2015.

We continue to work predevelopment on many fronts for the Leviathan field, and we are working to obtain all necessary approvals to sanction the initial phase of development this year. Discussion and negotiations regarding the Woodside farm-in are progressing now, in that we have an export policy approved, and other regulatory approvals are moving forward. We look forward to the tremendous value this partnership is capable of delivering. It's also important to point out that we're close to finalizing an agreement with the Israeli antitrust authority, which is likely to result in the sale of a couple of our smaller discoveries to another operator. The Canada fields, Tanin and Karish, total approximately 3 trillion cubic feet of gross natural gas or just over 1 trillion cubic feet net. We expect to have this matter resolved shortly as well.

The demand for our discoveries in Mediterranean natural gas continues to ratchet up. We are in very active negotiations with several potential regional customers, and I would expect us to execute a number of sales agreements this year. We also expect we'll make substantial progress towards an LNG or FLNG solution for not only the Israeli discoveries, but also for our Cyprus discovery as well.

At the same time, we'll be preparing for a return to exploration in the Eastern Mediterranean later this year or early next year or the natural gas prospect being matured for drilling in Cyprus and the high impact deep Mesozoic oil opportunity as well.

Well, it's a lot to cover and to pay attention to in 2014, what I see is a lot of possibility in all areas of the business. So with that, I'll now turn the call over to Dave.

David L. Stover

Thanks, Chuck. As you pointed out, it is an exciting time for the company, and especially thrilling to be part of creating something special. For each of our core areas, I'll cover current activity and highlight new information. Beginning with the DJ Basin, we had a strong fourth quarter, led by record production and activity levels, new infrastructure coming online and continued efficiencies as we implement our Integrated Development Plan strategy.

We ended the year with 45% year-over-year oil growth in the basin, and approximately 100% increase in our total horizontal production over the same timeframe. Fourth quarter volumes of 100,000 barrels equivalent per day is a great wrap up to 2013. Our underlying growth in the DJ more than offset the impacts of the September Colorado floods, and the volumes conveyed as a result of the Greater Wattenberg exchange in October. We've accomplished this through acceleration of both drilling and completion work, having spud over 70 wells in the fourth quarter, completed more than 85 and turned a record 90 wells to first production in the period. I will highlight the performance of a number of these Wells, including both standard and extended reach laterals after describing the infrastructure activity in the quarter. The expansion of both crude oil and natural gas infrastructure in the basin is supporting our growth. Multiple major facilities started up in the fourth quarter, beginning with our own first central processing facility within the Wells Ranch IDP area. Maximum daily oil sales from the CPF have reached nearly 20,000 barrels per day, and we're already under construction with Phase II, which is planned to double the facility capacity later this year. The Wattenberg oil trunk line, Tampa pipeline and Plains Rail facility all started up as well, reducing trucking costs and delivering Noble oil to multiple end markets.

You can see on Slide 7 our strategic approach to diversification of market for crude. Approximately 90% of our oil was either exported from the basin or tied to longer term local pricing contracts. On the gas side, the startup of DCP's Wells Ranch compressor station and their O'Connor plant has increased gas capacity in the Greater Wattenberg area. During the first quarter of this year, DCP is anticipated to further ramp-up the initial phase and add an expansion as well. DCP is already moving forward with plans for the next facility, having approved the construction of the Lucerne II plant, a 230 million cubic feet per day facility, scheduled to be online in the first half 2015.

Operationally, we're continuing to drive efficiencies and cost savings through our integrated development plan approach. As we discussed at the Analyst Conference and highlight on Slide 8, the implementation of IDPs across the DJ Basin has the potential to deliver over $1 million in net present value impact per well, resulting from reduced development and operating costs. And when you have an inventory of thousands of locations to be drilled, that's a huge impact to an already robust operating program. Our recent highlight is the drilling and completion of a 10 well pad in one of the best areas of Wells Ranch, with an average lateral length of 4,700 feet. These wells averaged around $4 million per well, about 5% less than what we showed in December, and early production is very strong. 8 of the 10 wells are tracking a 400,000-barrel equivalent curve, with the other 2 consistent with our average Wells Ranch type curve of 305,000 barrels of oil equivalent. Our activity levels are increasing in the DJ Basin in 2014, and we anticipate that we will generate positive cash flow in the play this year. Our drilling program is planning for approximately 320 operated wells this year, with an increasing focus on extended-reach laterals. Approximately 70% of our operated wells will be in the Wells Ranch and East Pony IDPs, with another 20% planned in the core Greeley Crescent and Mustang IDPs, which are being moved forward for sanction.

Now that we have relocated the rig from our Nevada play back into the DJ, we're operating 10 drilling rigs and 3 full-time completion crews in support of our 2014 activity. We highlighted during the Analyst Conference our strong level of confidence in drilling a minimum of 16 wells a section throughout the majority of our 6,000-acre position. This year, we're implementing an active down spacing program with between 30% and 40% of our total wells to be drilled at a higher density level as shown on Slide 9. These wells will be in at least 5 of our identified IDP areas, which total more than 50% of our DJ Basin acreage. With continued focus on multi-zone development, including the various Niobrara intervals and the Codell, the down spacing activity exposes us to even further upside, and I would expect first production from these wells beginning in the middle part of the year.

Shown on Slide 10 are a number of other recent well results, including extended reach laterals which continue to exhibit strong performance.

Our first Codell medium length lateral was drilled in the Wells Ranch IDP area with a 7,000-foot lateral length. The well has been online for over 2 months, with current production fairly flat at over 500 barrels equivalent per day. We have also recently brought online our first long laterals in East Pony, which are equally as exciting. The first of these was a 9,000-foot horizontal, which is currently producing over 700 barrels equivalent per day after 90 days. 3 additional long laterals, which have been producing for less than a month are performing strong as well, with similar total production at very high initial oil cut, over 95% of the total volume. We've also highlighted some standard length lateral wells in Wells Ranch and the core IDPs, which are performing very well. The Marcellus delivered a record quarter for Noble Energy, with production averaging nearly 200 million cubic feet equivalent per day and exiting the year over 210 million per day.

The fourth quarter average was up 17% from the third quarter as a result of strong continued performance from existing wells, and the impact of 19 new wells commencing sales during the period. We continue to operate 5 drilling rigs in the wet gas area with 3 in Majorsville, one in Pennsboro, and the fifth rig drilling our first wells in the Shirley area. Our partner, CONSOL, is operating 3 drilling rigs on the dry gas portion of our joint acreage, and combined, we drilled a total of 42 wells in the fourth quarter.

In 2014, the joint venture plan is to drill around some 175 wells in the Marcellus, up nearly 50% from last year. More than half are planned in the wet gas portion of the play, including our first wells in the Allegheny County Airport IDP. We'll be drilling higher density wells, testing 500-foot spacing in multiple areas. As a reminder, this is equivalent to 65-acre spacing compared to our more typical pattern of 100-acre spacing. Together with CONSOL, we also plan to drill several Burkett wells this year, following on our initial Burkett well last year, which continues to perform well. Similar to the DJ, this down spacing and multi zone activity provides substantial upside to our position.

A recent highlight on the wet gas side is the 6 well SHL-17 pad, which includes the longest laterals we have operated as a company averaging over 10,000 feet in lateral length. These wells were drilled and completed at an average cost of $9 million, which represents more than 35% reduction in total cost per lateral foot completed. The application of longer laterals and continuing to drive down absolute well cost is significantly reducing our finding and development cost across the play. Production from the SHL-17 pad commenced in December and started up at nearly 40 million cubic feet equivalent per day. On our partner operations, the application of shorter stage lengths and reduced cluster spacing is delivering very positive results. Initial 24-hour production rates on wells utilizing this completion design have been as high as 18 million cubic feet per day, and averaged 12 billion cubic feet per day per well for 8 wells brought online in the fourth quarter. These initial rates are up to 40% higher than the previous completions, and 4 of the wells had 30-day averages of more than 10 million cubic feet per day each. A large portion of the dry gas wells will be completed with this modified completion design this year, and we're implementing the reduce spacing on our wet gas acreage as well. Our first operated wells with reduced stage and cluster spacing are expected to be online in March. I'm also looking forward to commencing production from the Oxford/Pennsboro/Shirley delineation area in West Virginia, which is expected in the second quarter. The initial pad, including 6 wells will include tests of 550-foot down spacing, and reduce stage and cluster spacing.

Another highlight in the fourth quarter was the bolt-on acquisition of a relatively contiguous 90,000 gross acres in West Virginia. This acquired acreage directly offsets an area where we have seen some very strong wells come on recently, including the Philip I-13 [ph] Pad, where the average 24 hour IP for the 6 wells was more than 10 million cubic feet per day. We've already identified 350 drilling locations with net risk resource potential of approximately 2 trillion cubic feet equivalent.

Combined between the DJ and Marcellus, we're allocating approximately $3 billion in 2014 to the acceleration and development of our core onshore unconventional plays. These programs are anticipated to deliver tremendous growth this year. In addition, we are pursuing significant upside in both areas that is not assumed in our current long-term outlook. Combined with testing our Frontier play in northeast Nevada, 2014 will certainly be an exciting year for our onshore business.

Shifting offshore to the Deepwater Gulf of Mexico. Production during the quarter was 21,000 barrels of oil equivalent per day, 90% of which was crude oil and natural gas liquids. Growth from the third quarter was driven by the addition of the Ticonderoga #4 well, a development well which commenced production in late September. As Chuck mentioned, the 2013 sanctions of both Gunflint and the initial phase at Rio Grande set the stage for the next leg of production growth for our Deepwater Gulf business. Rio Grande will initially be a one-well tieback of our Big Bend discovery, with first production estimated in late 2015. Additional phases of Rio Grande will include the tie-in of our recent discovery at Dantzler in 2016, and the possibility of an expansion at Big Bend. At Gunflint, we're planning for first production in mid-2016 as a 2-well tieback to existing infrastructure. Combined, these discoveries are estimated to double our Deepwater Gulf of Mexico production base over the next few years. We're currently completing the Big Bend #1 well, and expect our first exploration well will be the Katmai prospect in Green Canyon. Towards the end of the first quarter, the Atwood Advantage drillship will join our Deepwater Gulf of Mexico program, and will be primarily devoted to our extensive development activity, including work on Rio Grande and Gunflint.

Moving to our International business. In West Africa, net sales for the fourth quarter were 80,000 barrels of oil equivalent per day. Aseng continues to perform well, and Alen production ramped up in the fourth quarter, exiting 2013 at about 28,000 barrels per day growth. Alen is expected to continue to grow in 2014 to a level of 30,000 to 35,000 barrels per day. In the fourth quarter, we completed our extended flow test at the Diega oil discovery. The well flowed at a constrained rate of 7,300 barrels of oil per day, confirming deliverability of around 10,000 barrels per day at production. Information gathered during the test indicates a larger reservoir than anticipated and project sanctions targeted for later this year. The field will be developed at the tieback to the Aseng FPSO infrastructure with first production planned for 2016.

In the Eastern Mediterranean, Tamar continues its outstanding performance and we had a very strong fourth quarter, producing 248 million cubic feet net per day. The demand for our gas in the Eastern Med, both Israel and Cyprus, continues to grow. Chuck already mentioned multiple ongoing negotiations with a number of potential regional customers. Even within Israel, we're continuing to see new potential buyers interested in natural gas. We've recently executed multiple contracts to sell Tamar gas to local distributors who resell to industrial customers. The continued demand for our gas in both Israel and other regional areas combined with the potential for multiple LNG or FLNG solutions sets us up for some dramatic growth in this region over the next decade or longer. We're making significant progress on our compression project at the Ashdod onshore receiving terminal, which is designed to substantially increase capacity and deliverability in 2015 to meet Israel's growing needs for natural gas. Coinciding with the expansion of the onshore terminal, we're also planning a tie-in of the Tamar Southwest field to the Tamar infrastructure for additional deliverability in 2015.

As I wrap up, I'd like to comment on reserves and take a quick look at first quarter guidance. As Chuck discussed, we had significant reserve additions at year end 2013, which were driven by execution across all of our core areas. The U.S. onshore was up 34%, Israel up 10%. The Deepwater Gulf and West Africa were essentially flat combined. I'm particularly pleased with the sizable performance based revisions, which alone, replaced more than 80% of our 2013 production. With just 3 years of PUD booked in the DJ, and actually less than 2 years booked on average in the Marcellus, we have huge discovered unbooked resources yet to convert to future reserves in the U.S. onshore areas and a number of offshore areas as well. Nothing has been booked yet for Dantzler or Troubadour in the Gulf, a number of our West African discoveries, and then of course, the Leviathan, Cyprus and other discoveries in the Eastern Med. This provides a platform of low-risk resources from which we will grow into the next decade or more.

On Slide 14, we've provided detailed first quarter guidance, including both volumes and expenses. We have not changed any full year expectations, and in fact, a lot of our ranges for the first quarter match what we have previously provided for the year. But as usual, there are a few things that can move around on a quarterly basis that you'll want to pay attention to. Although not shown, I will add that we expect first quarter 2014 Israel overall gas price to increase from fourth quarter 2013 to an average of $5.40 to $5.50 per MCF based on the blend of Tamar and older Mari-B contracts. When you look at our strong fourth quarter volumes this year, our 10,000-barrel equivalent per day outperformance versus initial guidance benefited from a couple of special items along with the strong performance in each area. A large portion of the improvements resulted from coal plant maintenance in Israel, and we have now seen those coal plants come back online which affects our first quarter expectations. In the fourth quarter, we also benefited from some year end true-up of plant volumes in the DJ Basin. For first quarter 2014, taking into account winter weather, we expect to average between 280,000 and 288,000 barrels equivalent per day. The mid-point of this range is an 18% increase over the first quarter of 2013, right on track with our expectations, and consistent with our overall 2014 growth rate. The sales of our tri-state and Haynesville gas properties, which total 30 million cubic feet per day of current net volume, are expected to close during the quarter. As in prior years, our volume profile is expected to continually increase through the year, exiting 2014 around 330,000 barrels equivalent per day.

So let me conclude by saying it's really a dynamic time at Noble Energy. 2014 is off to a strong start, and there are a number of important milestones and opportunities in each of our core areas. Execution is the key. We sanctioned 6 new major projects in 2013, and we now expect to sanction a similar number this year. This positions us to maintain our strong track record of delivering both in the onshore and offshore areas as we create a special and unique future for our company. Shannon, we'd like to now open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And first, we go to Doug Leggate with Bank of America Merril Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Chuck, gas prices obviously have ticked up here a bit. Can you give us an update on the current status of the carry arrangement with CONSOL and how that might change your activity level on a go-forward basis?

Charles D. Davidson

Well, a couple of items, obviously, gas prices have ticked up, and as you recall, the threshold at which the carry kicks in is when Henry Hub gas prices average $4 or above for 3 months consecutive. So certainly, as we look at the forward curve, it appears that we're headed down that path. I know Dave may comment a little bit on what impact that may have on our capital program this year, but I think I would just add that we have reached an agreement already with CONSOL on the program that we expect to execute this year. So I think it's safe to say that right now, we're not anticipating any change in that program knowing that the 2 companies, if they chose, they could mutually agree to make some adjustments down the road.

David L. Stover

Yes. And I guess, Chuck, just to add to that, as you've mentioned, we've set the budget, we've got our plans. And I don't see that changing based on any near-term outlook on pricing on that. I think the overall carry impact, and we've included that in some of the numbers, I think if it went in place here in March and carried for the full year, that's about a couple of hundred million dollars. But that's offset somewhat, probably at least by half, by the additional cash flow we'd see, so...

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Sure, great. Just one other if I may, fellows. The -- Dave, the color on your activity levels in the DJ is helpful. I'm wondering if you could maybe peel back the onion a little bit further in terms of the long lateral activity as a proportion of your overall program. And how do these -- well, it looks like fairly encouraging wells in the Codell. Has that been figured into your guidance for this year and how it might not change your development planning if you continue to see the kind of success that you saw with this first well?

David L. Stover

Yes, Doug, I think the plans for this year call for drilling somewhere between 55 to 60 extended-reach laterals, and there's a mix. There's Codell, like we've seen. Probably just a few at most. Codell, that's planned in there right now. We've also had a mix of some of the A and the C interval wells also. In fact, we've also done a few of those. I think probably, 20% to 30% of our extended-reach laterals have been outside the B interval that we've already done. And that's probably similar to what we've got planned for this year. So everything that we've laid out is based on kind of that outlook as we go forward. As we start to get into more of the Integrated Development Plans and you start to see those come together, you'll start to see a growing increase of activity of an extended reach. But that would probably be more into 2015 and '16.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. So there's no change to the plan part of the guidance you gave us in December?

David L. Stover

No change to that plan. I think the thing that we kind of highlighted today, there's a significant amount of activity that's really moving now towards this down-spacing. We're moving beyond the 16 wells per section. I think we mentioned and we show that on one of the slides, and that's throughout the field, not just in one area but in -- essentially in 5 different of our potential IDP areas. So I think that's a key component of this year's program.

Operator

And next, we go to Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

My first question -- I just wanted to ask you quickly on guidance. Dave, if I heard you correctly, you're anticipating kind of a year-end '14 kind of exit rate of 330,000, is that correct?

David L. Stover

Right.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And then you talked about -- also, Dave, about 6,000-barrel equivalents of asset sales in the first quarter. So if we -- does that 330,000 exclude those asset sales, so you would have been at 336,000? Is that -- I'm just trying to understand the exit rate.

David L. Stover

I'd say it's around 330,000 there. I mean, again, those properties tail off some. There's a little bit of decline in it. But when you look at it, overall, as far as when we will close on those, I'd say you're probably looking at some time in March. So with or without those, you're still going to be close to that 330,000 range by the end of the year.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. Fair enough, fair enough. Chuck, my second question, you may, as part of the antitrust, be -- have to sell some properties in Israel. Talked about 1 Tcf net to Noble. Could there be some meaningful proceeds -- and obviously, some good demand in Israel. But could this be -- could we anticipate some good proceeds from these properties in Israel, source of...

Charles D. Davidson

Well, of course, we -- we're still in the process of finalizing our agreement with the antitrust authority, but we do anticipate they'd involve the sale of a couple of those smaller properties. So we would expect certainly proceeds from it. Now this is a process that will go for a period of time. So right now, we've not included those in any cash flow projections or anything like that, that we've shown for guidance this year. But it's like our ongoing portfolio optimization. These are the things that, as we move through, provide some of our additional cash and liquidity as we go forward. But I don't have any estimate right now as to what might be potentially the proceeds on the sale of any properties there.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And just my final question, obviously, there's some investor concern around DJ Basin differentials. You obviously have some good outlets outside of the basin. If you're going to ballpark what you thought your estimated differential from WTI would be in '14, can you give us a range?

David L. Stover

I think when -- we've actually been looking at how is it running now versus how it ran in the fourth quarter. And it looks like for January, at least, it's very similar to what we saw in the fourth quarter. I think you'll start to see some help on that when you see the White Cliffs expansion go into place in the second quarter. It's also been impacted somewhat up there. There's been some facility turnaround and maintenance on some of the local refineries. I think those are starting to come back on somewhat. So I think a real change in the netbacks, and locally up there, probably starts to get some alleviation of pressure on that when you see the White Cliffs expansion come into play later in the second quarter. So I don't see it changing from what we've seen in the fourth quarter for the first quarter, anyway.

Operator

And next, we will go to Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

I was wondering on the Diega flow test. That sounds like a pretty strong rate, but I'm curious -- two things. One, how did that come in versus your expectations? It sounds like it was better at least on the pressure drawdown or something, but -- or the buildup. But also, is there a gas injection that you're going to have to do there? And is that -- kind of does that play into the 2016 start date?

David L. Stover

Yes, it does. I mean, it -- these reservoirs, when you start looking at things like Diega and Carla, Charles, they're a little more complex than some of the [indiscernible] and so forth. So we've had to go out and take a measured approach of testing some of this. What we saw on this flow test was very encouraging, probably at least as good or better on flow rate that we saw, probably closer to the high end of maybe what we would've expected. And the other thing that we really saw here, it provided some insight into -- from a size standpoint, we weren't seeing boundaries that we maybe would've expected from just some of the seismic and so forth. So both of those things were very encouraging. But you do have to -- and it is a reservoir you're going to have to do pressure maintenance on. You're going to have to recycle gas most likely. So it adds that complexity that takes a little time to bring it online.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Okay, got it. That makes sense. And then going back to the DJ there, if I -- just to make sure I got this right, so a lot of the big bump we saw in NGL volumes in the fourth quarter was really just the annual true-up from your plant processing?

David L. Stover

Right.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

And then I think Arun touched on this. I -- there's a lot of talk even from other operators in the basins [ph] about that weak spot pricing in the DJ. And so it was -- that was a great slide, you guys, but -- Slide 7 talking about all your takeaway there. But you're not seeing that in Q1 at this point? I guess that's what you're saying.

David L. Stover

What we're seeing in Q1 is about the same thing we saw in Q4. And one of the nice things of having that diverse supply -- and actually that marketing strategy really builds on the commitments that we made to get this Plains Rail facility in and get the White Cliffs in and now get the expansion underway on both of those. So as we mentioned, I think actually we're moving probably 80% of our volume out of the basin.

Operator

And next, we go to Leo Mariani with RBC Capital Markets.

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

Just trying to get a sense of kind of current Niobrara production, and maybe you guys can walk us through your first quarter production guidance, in a bit more detail. I guess that's down a little bit from the fourth quarter. Or maybe you could kind of help us a little bit with some of the pieces there to get there.

David L. Stover

Yes. Leo, no problem. You have a number of kind of nonrecurring or one-off items, if you look at them. It will start with one of the bigger items which I mentioned on the call. I think Chuck and I both mentioned, is over in Israel, where in the fourth quarter, you had the coal plant maintenance where it was down. So we were providing a -- if you call it disproportionate amount of gas at that point in time. We also benefit in the fourth quarter from some of the colder weather. If you remember some of the pictures over there of snow in Jerusalem and so forth. So there's kind of a step-down as those coal plants have come back on over there. So that's a -- probably at least 6,000 barrels a day or more of impact there. And then you have on infrastructure and facility infrastructure in both of Gulf of Mexico and EG. In the first quarter, you have some maintenance items there, along with the weather piece. I'd say what we're assuming for weather is probably around 3% to 4% of our volume for the first quarter, similar to what we've seen and used in the past up there. So I mean that's kind of what's impacting kind of the DJ and Marcellus portion, when you look at it. And also, as we mentioned, the DJ benefited from some of these plant true-ups in the fourth quarter. So a few things moving around there, but really right on track. First quarter is really right on track with where we expected and right on track to deliver the growth rate that we've laid out this year.

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

Okay, that's helpful. And I guess just focusing on the DJ a little bit, I think in your prepared comments, you talked about how you had somewhere around 30% of your extended laterals coming from the A, C and the Codell, sort of outside of the B bench. Could you expand upon that a little bit more? I'm really just curious as to kind of, in your different key areas there in the DJ where you think the A may be derisked, the C derisked and the Codell. And just some color on where you think it's prospective will be helpful.

David L. Stover

I'll tell you, probably, Leo, the best thing to do is look at Slide 9 that we've put in there where we talk about some of our down-spacing testing, and we kind of highlight the benches that we're focusing on, on the down-spacing testing. And you can see there's a mix of different intervals in each of those 5 IDP areas. For example, in the Wells Ranch, our base program is down to 16 wells per section in there, with a lot of B activity. So what we're moving to on down-spacing is picking up the A and C. It's all getting back to how do we get a greater percentage of original oil in place recovery here. If you go back to what we showed on analyst day, we were still under 10% on 16 wells per section with as much as the oil in place has grown up there. So if you go back to there, you get on to 24 wells per section. I think you got us back up to about 12%, and you get down to 32 wells per section. You're getting closer to 15%. So that's where we're moving towards.

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

And I guess do you think that's all going to be sort of flushed out here in 2014 where by the end of the year, you'll have a really good idea of the -- sort of how you're going to develop everything? Or do you think that some of the A, C and Codell and different areas are still kind of more in exploration mode, and there's still a question mark? Just trying to get a sense of what you think has been kind of proved up or is it still kind of in test mode here.

David L. Stover

Well, I think what we've seen, and we've had a mix of wells in each of these different horizons, so what we've seen is -- is we're taking this down-spacing into moving it closer, more towards development. I sure wouldn't call it exploration on any of this. And when you look at the different intervals in each area that we're testing, I think we're going to aggressively move through that. Now with 30% to 40% of the wells this year focused on this down-spacing piece, we'll have learned a lot by the end of the year. You look at the number of wells we're bringing on each quarter. And I'd say when you look at these 5 IDPs we're talking about, I would anticipate we'll have those 5 IDPs fairly well proved up by the end of the year.

Operator

And next, we go to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On Israel, you mentioned that you would be likely to sign some contracts with regional customers for Israeli gas. I just wanted a little bit more color, were you referring to customers to take gas who are not in Israel? And can you just give us a status on the viability of non-LNG solutions within the region?

Charles D. Davidson

Sure, I think when we refer to regional customers, what we're talking about is markets that would be outside the Israel domestic market. So some of the countries we've talked about in the past have included Jordan, Egypt, Turkey and even -- we also consider the recent announcement of gas to Palestine for our power plant there. That falls in that category of regional outside the domestic Israel market. So our view is, is that in the past year, Brian, those have strengthened substantially just because of changes in the region. And that's what we point to as a lot of optimism as we go through this year of being able to firm up additional sales to those markets. We obviously are in discussions with a number of potential customers. Don't have anything to announce at this point. But again, we're seeing strong regional demand, and as a result, what it does is -- our belief is, is that there still is a need for an LNG solution here. But it may not need to be as large as what we were anticipating a couple of years ago. And as a result, some of these regional markets give us an opportunity to not only market more gas but also to accelerate the development. Obviously, sales through pipelines in the region can be done at an earlier date than waiting for LNG. So that was our thinking, and of course, that was part of what we outlined in our December analyst meeting as well. That's what it's all about.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then just following up on that, do you expect, as you sign these negotiations this year, that you would make capital commitments on the midstream side to getting the gas from point A to point B? Or would that be done by someone else? And how should we think about the pricing relative to what you've been reporting or what you've [indiscernible] in Israel?

Charles D. Davidson

Well, I think in terms of midstream investments, it appears for some of these is that we will likely not need to be making any midstream investments, that in the case -- there could be some connections that will be made through the Israeli pipeline system, in which case they would be making those expansions and, of course, then charging a tariff for the movement of that. In some of our other discussions with potential customers, we've actually talked to them about coming to us. In other words, they making some midstream investments, again, pretty early on this since these are all under consideration. I think that we do see a strong market demand there as a result versus what we're selling in Israel that we would expect pricing to be at least that or even higher.

Operator

And next, we go to Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

A little question on Nevada. What is your #1 option if it turns out to be a successful venture? Are you still looking for the West Coast?

David L. Stover

I think yes. I think we've mentioned in the past there's been a lot of interest from some other refineries out West to pick up this type of crude if we're fortunate enough to have a significant play here. So the next step out there is to complete a well and see what we can flow out there. And we'll do that before midyear and then set up our plan for drilling some of these and actually probably testing some of the other areas that we haven't ventured into yet out there in the second half of the year.

Operator

And next, we go to David Heikkinen with Heikkinen Energy Advisors.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Just thinking about the Wells Ranch area as a whole and the longer laterals plus kind of higher sustained IPs, it seems like after 90 days, kind of the initial rates that you're talking about there and at East Pony and in the Codell are a little higher. Are you getting better completion designs? Or what's driving a little bit better 90-day rates?

David L. Stover

I think as we've evolved, David, we take the combination. We do a lot of technical work. I mean, believe me, between the geoscience and the engineering placement of the wells, and then that also goes into the completion of the wells. And we've also done a lot of work on just how we flow these wells back. If you recall, and I think Gary's talked about some of this in the past, too, we've really gone to bringing these wells back online slowly, minimizing the drawdown. And we've seen really fantastic results from that. So yes, I mean, you're right. The characterization upfront is exactly right. We're very pleased with how the performance has continued to develop out here on these new wells and the wells we're bringing in, and we're starting to bring in more and more of them each quarter.

Operator

And next, we go to Pearce Hammond with Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Just one question for me. Can you provide just a quick outlook on service cost and availability in the DJ and the Marcellus for this year?

David L. Stover

I don't -- I haven't heard of any big changes on anything there. I mean, and that's helping us obviously continue to bring costs down in both of those plays. One of the things I mentioned was that 10-well pad and Wells Ranch, for example, where the average well cost, drilling completion cost is now around $4 million. And if you recall, it wasn't that long ago where they were $4.5 million or more. Same thing when you look at that plot that we provided in Marcellus and how we continue to bring costs down in both of those areas. So I think overall, as far as pressure on service cost, it's been fairly consistent or fairly level. I haven't seen a big change there.

Operator

And next, we go to John Herrlin with Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Yes, 2 quick ones. What would the ballpark be on an FLNG facility? Do you have any sense of that? And also, when would you have to really commit to that on a cost?

Charles D. Davidson

Well, I think on FLNG, with the engineering work still proceeding, it's probably a little bit too early on that. We are looking at FLNG that would probably be a little bit smaller than you would see in an onshore, maybe somewhere around 3.5 million metric tons per annum. But again, there's a lot of engineering work that's still going on with that. Overall, I think our -- there's really not much change from what we presented in December in terms of our overall thinking on schedules going forward for the foreseeable future. Again, this is all going to be a combination of -- as we sequence in Israel, just thinking about it, starting with the additional work that we're doing on compression at Tamar and some additional expansion work there and then moving into regional sales, as well as domestic demand for Leviathan. And then the LNG -- FLNG solution is really the -- one of the final phases there. And there's still multiple options. I know Keith talked about these in December, multiple options that are being looked at. So that's a bit down the road. And I know, Dave, you may want to comment a little bit more on that.

David L. Stover

I mean, you mentioned it, Chuck. The work is ongoing right now on FLNG pre-FEED work, if you will. So we'll have a much better handle on that later in the year. But it's too early to focus on a number yet.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's fine. Regarding something you said, Dave, about PUDs in the DJ and also the Marcellus, it seems like a 3-year or 2-year time horizon is kind of short. Why didn't you book more? It seems very conservative.

David L. Stover

Well, John, the way we approach it, we look and we only book specific well locations that are tied to development plans. And that enables us to maintain flexibility in programs. What we don't want to do is to get in there and book a number of specific locations that we then have to pull off and -- as things change over time. So we don't want to get into a number of revisions, if you will. So we tie it specifically to well locations that we have tied up the development plans and laid out specifically.

Operator

And we will take our final question with Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

Yes, one quick question. Really, it goes back a bit to the analyst day, but beyond 2016, the free cash flow generation gets to be pretty stout. And I'm just curious to see if internally, you've been able to rank what ability you have to redeploy that cash. Or is it going more towards debt paydown, share repurchases? Or any sort of color you could give there will be great.

Charles D. Davidson

Well, I think anytime we have a free cash flow, we're going to look at all the options. We have been -- as we highlighted, we've continued to grow our dividend. And so we've had strong growth, and we compare very favorably with peers in the past on that. And certainly, in the past, we've looked at a number of options, but at the same time, we're -- we want to keep a very strong balance sheet. So we're not getting too excited too quickly about that free cash flow. We know it's coming. At the same time, we want to make sure we maintain a very strong balance sheet. And if there's opportunities to retire some debt, we can do that. If there's some other things like you mentioned, those are certainly possibilities. But we haven't made -- certainly, we've not made any decisions at this point as to exactly what we would do. 2016 is still a ways away.

Peter Kissel - Howard Weil Incorporated, Research Division

Yes. And another thing you mentioned in your prepared remarks were just the ongoing portfolio management and how successful that's been over the last couple of years. But looking into 2014, should we expect it to be a bit less drastic and maybe focus on some smaller noncore packages versus some larger ones?

David L. Stover

[indiscernible]

Charles D. Davidson

Well, I think we've...

David L. Stover

Go ahead, Chuck.

Charles D. Davidson

Yes, I was just going to say that we've continued to work through our portfolio. So there's the -- as we've mentioned, we've got some few cleanup items that are left and that we'll continue to look at it. But when you look outside, as we move through the year and you've looked at what we've done the last couple of years, so we've really got ourselves highly focused down to our 5 core areas plus what we have reserved outside those for new ventures. So with that, certainly, our biggest program was a year ago, and we're getting our portfolio, I think, thinned down now. So I wouldn't expect to see as significant of a program this year as what we've done and perhaps a couple of years ago. Dave, you were going to add something on that.

David L. Stover

No, I was just going to say when we talked about this at the analyst day, we kind of placed our divestitures for this year in at the end of the year. And the focus is on anything we can do to accelerate that process on some of those and pull those up earlier in the year. In our minds, that would actually be a positive. But they're not large pieces, but there are some cleanup noncore pieces, both internationally and domestically, that allows us to continue to focus on resources and everything else on the core areas that we're continuing to develop and deliver on. So that's the focus on the portfolio piece this year.

Operator

And that does conclude today's question-and-answer session. I would like to now turn the conference over to management for any closing remarks.

David R. Larson

Thanks again for everybody participating in the call today, as well as your interest in Noble Energy. I hope everybody has a great day. Thank you.

Operator

And that does conclude today's conference. We do thank you for your participation. You may now disconnect.

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