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Noble Energy (NYSE:NBL)

Q2 2012 Earnings Call

July 26, 2012 10:00 am ET

Executives

David R. Larson - Vice President of Investor Relations

Charles D. Davidson - Chairman, Chief Executive Officer and Member of Environment, Health & Safety Committee

David L. Stover - President and Chief Operating Officer

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

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

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

John Malone - Global Hunter Securities, LLC, Research Division

John P. Herrlin - Societe Generale Cross Asset Research

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

Operator

Good morning. Welcome to Noble Energy's Second Quarter 2012 Earnings Call. I would now like to turn the call over to David Larson, Vice President of Investor Relations. Please go ahead, sir.

David R. Larson

Thanks. Good morning, everyone. Welcome to Noble Energy's Second Quarter 2012 Earnings Call and Webcast. On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

Earlier this morning, we issued our earnings release for the second quarter, and it is available on our website. We have also posted a few supplemental operational slides that we hope you will find useful as you review our results today. You may have also noticed in the morning's press release that we have reclassified our North Sea operations as discontinued operations. To assist you with the accounting impact, we provided an additional table to our earnings release.

Following our call today, we expect to be filing our 10-K with the SEC, and it will be available on our website. In a few moments, I will be turning the call over to Chuck, who will discuss our results for the quarter and some of our ongoing efforts to grow and monetize our project inventory. Dave will then provide a detailed operational review and our -- on our near-term plans and outlook. We'll leave time for Q&A at the end and plan to conclude the call within the hour. [Operator Instructions]

I want to remind everyone that this webcast and the conference call contains projections and forward-looking statements based on our current views and most reasonable expectations. We provide no assurances on these statements, as a number of factors and uncertainties could cause actual results in the future periods to differ materially from what we discuss here today. You should read our full disclosures on forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business.

Finally, we will be referencing certain non-GAAP financial measures, such as adjusted net income or discretionary cash flow on the call. When we refer to these items, it is because we believe they are good metrics to use in evaluating the company's performance. We provide you with reconciliations in our earnings tables.

Now let me turn the call over to Chuck.

Charles D. Davidson

Thanks, David. Good morning, everyone, and thanks for joining us today. We've got lots to cover as our activity levels remain very high. I'm going to start out by reviewing our second quarter results, including our full year guidance and then comment on some of our planned activities for the rest of the year.

And before we get to the numbers, let me just comment on the reclassification of our North Sea properties to discontinued operations. David referenced this in the opening. We are doing this as a result of our recent announcement to divest the majority of our North Sea business. Previous quarters have also been reclassified to reflect the impact of this change, and you can see the references to discontinued operations in the schedules that accompany our earnings release this morning.

Adjusted net income for the second quarter totaled $145 million or $0.77 per share diluted. Excluded from adjusted net income were unrealized gains from commodity hedges and 2 domestic asset impairments related to commodity prices. As previously announced, we have recorded $118 million pretax in exploration expense related to the Deep Blue project, which reduced earnings this quarter by approximately $0.42 a share.

Revenues from continuing operations were $966 million for the quarter. That's up 15% from the second quarter last year, with a big driver in the growth being crude and condensate revenue, which was up 57%. Our total sales volumes for the quarter, including sales from discontinued operations, were 231,000 barrels of oil equivalent per day, which was near the upper end of our second quarter guidance range. As expected, total sales were down from the first quarter due to planned maintenance early in the quarter at the Atwood plant, as well as reduced gas sales in Israel where we continue to manage reservoir depletion.

In addition, we experienced an impact in the DJ basin of approximately 4,000 barrels a day equivalent as a result of third-party processing downtime and hot weather. Over 85% of the volume decrease from the first quarter was in natural gas sales, with the remaining decrease in natural gas liquids. Crude oil volumes were actually up 2% over the first quarter. Sales from continuing operations averaged 224,000 barrels of oil equivalent per day. Of that amount, sales of crude and condensate represented 86,000 barrels a day, which is a 62% increase over the second quarter last year.

Domestic sales totaled 134,000 barrels of oil equivalent per day and benefited from the first full quarter of production from South Raton, as well as the start up of Galapagos near the end of the quarter, as well as strong results from the horizontal drilling programs in the Marcellus and the Wattenberg and the Niobrara. Internationally, sales volumes were 90,000 barrels of oil equivalent per day. We brought Alba back to full production after completing maintenance early in the second quarter and delivered another very strong quarter of production from Aseng.

As I mentioned previously, our decision to divest certain North Sea assets has triggered reporting our entire North Sea business as discontinued operations. As a result, all of our North Sea production has been removed from our reported sales volumes. Financial results for discontinued operations are rolled up to a single line item in the table as income from discontinued operations net of tax, and as David mentioned, we've provided an additional schedule in the back of this quarter's earnings release that gives greater detail on that line item.

Separately, we've also announced that we've entered into sales agreements for our mid-continent and Permian divestiture packages. To help you through the volume story on all of this, on Page 4 of the supplementary slides that we've provided alongside our earnings release, we have reconciled our original 2012 sales guidance, that is the range of 244,000 to 256,000 barrels of oil equivalent per day. We have reconciled that to a new pro forma range of 234,000 to 242,000 barrels of oil equivalent. This pro forma was prepared by removing all the North Sea volumes for 2012 and adjusting volumes for all U.S. divestments based on the expected closing dates.

In looking at our performance to date, as well as estimates for the remainder of the year, we're raising our full year sales guidance by about 2,000 barrels of oil equivalent above the original pro forma guidance. Thus, the new guidance for the full year is 236,000 to 244,000 barrels of oil equivalent. I know there's a lot of pluses and minuses to get there, but really the bottom line is clearly that the strong performance at Aseng and now Galapagos are helping us to lift the guidance range.

Additionally, as noted in the press release, we have lowered the guidance range for lease operating expense. We've raised the range on DD&A to reflect the greater mix of new high-value oil production and adjusted exploration expense guidance to reflect our latest estimates. All other guidance items remain unchanged.

Our discretionary cash flow for the quarter was just over $700 million. That's up 7% from the second quarter last year. Liquidity remains very strong at over $3.7 billion. Our already announced $1 billion of non-core divestments will provide additional support to our strong balance sheet. On our divestment program, I'm very pleased with the interest in the marketplace and the speed at which we've been able to execute. We expect to continue divestments of our smaller non-core packages throughout this year and into next year.

David mentioned at the beginning of the call that for this quarter besides the earnings release, we also provided a package of supplementary slides. We believe this material will be helpful to you in understanding not only our quarterly performance but also the key drivers of our growth going forward. I mentioned earlier that our activity levels are extremely high, and we have many exciting things happening in virtually all of our core areas. The supplementary materials provide additional detail and color on our programs, and I encourage you to review the package.

In the DJ basin, Dave will discuss later some of the substantial improvements we're seeing in our horizontal drilling program there. It's hard to believe that it was only 15 months ago when we began seeing the upward inflection point in production from the horizontal Niobrara that told us that this program truly had the potential to dramatically change our company. At that time, we had been running 3 horizontal rigs and had about 30 horizontal wells online. Since then we've experienced more than a fivefold increase in production and now have 7 rigs drilling horizontal wells, with plan to be at 10 rigs by year-end. Our horizontal well count should easily top 250 by then.

The era of vertical drilling in Wattenberg is rapidly coming to a close. Our plan today for this region bear little resemblance to what they were 15 months ago. Field development plans have gone through dramatic changes in scale and scope, and major industry investments are being made in oil transportation, gas processing, gas and NGL transportation to accommodate this growth.

Earlier this year, we announced we expected to invest $8 billion in this region over the next 5 years. Our operations continue to expand northward. We recently opened our new operations center in Greeley, which will expand as we grow our activities in the DJ basin. At this new facility, our technicians are able to remotely monitor, operate and optimize production from over 6,000 Noble-operated wells across the basin. Utilization and expansion of this technology are bringing tremendous efficiencies to our operations and enhancing our safety and environmental performance.

Switching over to the Eastern Mediterranean. We're rapidly moving forward with the development of our major discoveries there. The development of Tamar, which will provide gas to the Israeli domestic market, is progressing on schedule. Obviously, the sooner we can provide that gas to the growing market, the better.

After receiving approval from the public utility authorities and the Israel Antitrust Authority, the sales agreement with Israel Electric Corporation has now received final regulatory approval from the Israeli cabinet. This long and detailed process is now over, and the contract is fully executed and effective. While we continue to progress Tamar towards first sales oil next April, we've been developing 2 smaller fields, the Noa field and the Pinnacles field to support near-term domestic market needs.

Noa started delivering gas in the second quarter, and we just now brought Pinnacles online after resolving some gas-specification issues. The cost of substitute fields in Israel is very expensive to us, so there's significant economic benefits to our customers and the people of Israel from these gas deliveries. Once Tamar is online, our work is not over by any means. Domestic demand continues to grow, and we're working on additional solutions to meet this growing demand.

With respect to exports, we're studying several options. The first phase of our pre-FEED work on LNG site locations has been completed. Additional concept selection studies will be completed before launching a FEED study targeted for the first half of next year. To complement our onshore initiatives, we're also developing floating LNG strategies. We're learning a lot about the technology that could be applied to Leviathan and Cyprus, and we're evaluating those options as well.

Discussions with potential Leviathan partners are ongoing, with several companies already having been through the data room and several more scheduled in the coming weeks. Also, we expect final recommendations from Israel's gas policy committee shortly. We're optimistic about both our domestic and export sales plans. We have numerous options. We'll continue to move forward in parallel several of these over the coming months.

Let me finish up with just a brief review of our exploration activities in each of our key offshore basins. In West Africa, we look forward to beginning the drilling of an exploration prospect offshore Cameroon, called Trema, around September 1 with Atwood Hunter rig. Trema is an oil prospect in about 2,000 feet of water, with gross unrisked mean resources of approximately 120 million barrels oil equivalent and a 38% geologic chance of success.

Following Trema, we plan to spot an appraisal well at our Carla discovery before the end of the year. Carla is located beneath the Alen field and has an estimated gross resource range of 35 million to 100 million barrels equivalent, with about 80% liquid content. Following Carla, we've got a deep inventory of West Africa drilling plan for 2013.

In the Gulf of Mexico, our appraisal well at Gunflint has reached TD at 29,975 feet. While we still have a rig on location and we're finishing up the open hole evaluation, we can provide a preliminary status at this time. Hydrocarbons have been found in several, but not all of the target sands that contain hydrocarbons in the original discovery well. The appraisal well has also confirmed excellent reservoir properties and continuity, thus establishing the commercial viability of the field. The results to date indicate that the resources are within Noble's previous range, although likely below the midpoint, given not all of the sands are showing pay at this appraisal location.

Our plan is to drill a new well later this year in the southern part of the field, which we expect will determine the development of Gunflint as either a subsea tieback or as an standalone host facility. The current well will be temporarily abandoned for future use as a producer.

Also in the Gulf of Mexico, we next plan to spud an exploration well at our Big Bend prospect later this year. This oil prospect is located near our second oil prospect named Troubadour. If successful, we envision using subsea tiebacks for these yields just as we recently completed Galapagos.

And in the Eastern Mediterranean, we're working on arrangements to spud a well to test the deep oil potential offshore Israel in 2013, and in Cyprus, we plan to spud an appraisal well at our discovery there by early 2013, depending on rig availability, with that well to better -- help us better understand the resource potential and better define our development options there.

I continue to remain very excited about the path we're on. Our major projects execution continues to be outstanding with Aseng and Galapagos, delivering exceptional results that are well above expectations. The same can be said for our unconventional developments in the DJ basin and the Marcellus. Our next generation of projects are on track for 2013, and we have lots of high impact exploration in front of us. I wouldn't trade our position for anyone at this point.

So with that, I'll turn the call over to Dave, who will take you through a review of our ongoing operations.

David L. Stover

Thank you, Chuck. I will touch upon the operations in each of our core areas, beginning with our activities in the Marcellus Shale play, as next month we'll mark the 1-year anniversary of our announcement of the joint venture with CONSOL.

By focusing on our Marcellus areas that provide the strongest returns, we're now producing over 2.5x our net production at the time of the announcement last year. For the recent quarter, we averaged 74 million cubic feet per day from our Marcellus horizontal program. All of this production is from the dry gas area, and we expect to start our first wet gas production by the end of this month.

In the wet gas area, we are currently operating 1 rig and will be adding 2 additional horizontal rigs in the third quarter. We took over operatorship of the first pad, which was drilled by our partner in Marshall County, West Virginia at the beginning of the year. The 5 wells on that pad have been drilled and completed, and we are finishing the gathering system hookup, which will allow transport of the wet gas to the MarkWest processing plant.

The second pad has 8 wells that have been drilled, and completion operations are underway. We estimate that those wells will also reach first production in the third quarter. The third pad contains 7 wells and drilling is nearly complete. We'll then be moving our rig to the fourth pad, which will likely be an 11-well pad.

Our longest lateral in the wet gas area so far is approximately 6,200 feet, and we're actively optimizing our lease positions to allow us to continue maximizing lateral lengths. In the dry gas area, planned drilling operations for 2012 were completed in central Pennsylvania and northern West Virginia.

During the quarter, CONSOL brought the first well of a 4-well pad onto production, and although we only have a short production history, this well produced just under 18 million cubic feet in a 24-hour period. These 4 wells are among 8 recent wells with lateral lengths of 8,000 feet or greater, and they demonstrate the partnership's successful efforts to increase lateral links where possible. CONSOL is presently operating now 2 horizontal rigs, both in southwestern Pennsylvania where drilling efforts will be focused on several pads in Greene County.

Strong well results in southwest and central Pennsylvania and in West Virginia have allowed us to increase our EUR significantly above our acquisition model. We now believe our Marcellus net risk resource estimate is closer to 10 trillion cubic feet equivalent compared to the original estimate of just over 7 trillion cubic feet equivalent at the time of the acquisition. On Page 11 of our supplementary slides, we show an example of this increase for our southwest Pennsylvania dry gas area.

Looking forward. In 2012, we now expect to drill just over 30 wells in the wet gas area and just under 60 in the dry gas area. We're benefiting from our continuing trend of lengthening laterals and now believe that our average lateral length in 2012 will be greater than 5,000 feet. The efficiencies of pad drilling, the initiation of production in the wet gas area and our focus on the high EUR and high net revenue interest area of southwestern Pennsylvania will all have a positive impact on the economics of our program. By the end of the year, we expect to be producing 140 million cubic feet equivalent per day net from the Marcellus.

In our second onshore domestic core area, the DJ Basin, second quarter production averaged 73,000 barrels of oil equivalent per day despite an impact of approximately 4,000 barrels of oil equivalent per day from third-party processing facility maintenance and unseasonably warm weather. Crude oil represents 40% of the production, with another 17% from NGL.

Our horizontal program continues to outperform expectations and is rapidly expanding. During the second quarter, this program accounted for 24,000 barrels of oil equivalent per day or approximately 1/3 of our DJ Basin production. Our horizontal production is up 60% year-to-date and is currently producing 27,000 barrels of oil equivalent per day net, with 66% liquids. Since June of last year, the horizontal production has more than tripled. We're adding an eighth horizontal rig in August and have contracted 2 additional horizontal rigs that will start up before the end of the year.

In the first half of this year, we spud 83 horizontal wells and performance continues to improve as a result of a number of key learnings. Slightly more than half of these wells are in the extension area, where the wells brought on production this year are tracking EURs almost 10% above the 310,000 barrel of oil equivalent type curve, with greater than 75% liquids. We have highlighted this year-over-year performance improvement on Slide 7 of the supplemental material. In the core area, we spud a total of 24 wells this year, where liquid content average is close to 60%, and again, our EURs are exceeding previous type curves. And in northern Colorado, where we plan to drill 35 to 40 wells this year, we continue to see approximately 80% crude oil content on the wells completed to date.

With respect to our extended reach lateral program, our initial well is located in the extension area. This 9,000-foot lateral continues to track above a 750,000 barrel of oil equivalent type curve even after a year of production. Cumulative production to date is close to 200,000 barrels of oil equivalent. Our next 2 extended reach wells are approaching 30 days of production, with excellent results similar to the first extended reach well. We just finished completion operations on our fourth long lateral well and recently turned it to sales. We have plans for approximately 10 additional extended reach wells this year.

We are collecting a significant amount of production and performance data at our first EcoNode pilot project, which began production earlier this year. We call this 9-well project as testing aerial and vertical recovery of the Niobrara formation. We encourage -- we are encouraged with the performance of all 9 of the wells. In fact, it appears that the wells placed closest to each other at 40-acre spacing are producing the best.

Based on these results, we are preparing another increased density pilot project. This program will consist of 15 wells in a section, testing different development concepts with 40-acre density and multiple targets. We will, again, be targeting the B and C benches, but also intend to horizontally test the A bench and the Codell from the same pad. The 15-well pilot will be located in the extension area near the 9-well pilot, and we expect to spud the first well in August with initial production late in the fourth quarter.

Our goal with these pilot tests is to maximize the economic recovery of the original oil and gas in place, while minimizing our surface footprint. Refer to supplemental Slide 8 and 9 for further information on these 2 pilot programs. The majority of our development plans this year are focused in the oilier extension area, where we envision new numerous multi-well pads incorporating the EcoNode concept supported by a central processing facility, with pipeline infrastructure enabling the offtake of oil and gas. Meanwhile, we will continue to delineate the northern Colorado portion of our acreage in preparation for the implementation of our next-generation development plan building up on the EcoNode and central processing facility concepts.

With respect to infrastructure, we're obtaining additional oil transport and gas processing capacity through pipeline and plant expansions, new gas plants and a new rail terminal. The capacity of the White Cliffs oil pipeline was previously expanded to approximately 75,000 barrels per day. We have approved an infield oil gathering system, with initial capacity of 50,000 barrels per day, with an expansion capability to 80,000 barrels per day. The system should be operational in the third quarter of 2013.

We have also committed 10,000 barrels per day to a new rail terminal in the area expected to be online late next year. Third-party gas processing capacity continues to increase through expansions and new facilities. And with respect our water needs, we have a number of water supply projects underway to support our development.

To summarize our DJ Basin activity, we're on pace now to drill close to 190 horizontal wells this year, with 75% of those on multi-well pads. Our vertical program will be ramping down to 1 rig by the fourth quarter, as we continue to shift capital to our horizontal program. Our production has grown dramatically, performance continues to exceed expectations, and we are encouraged with recent data from our pilot project as we continue to focus on increasing recovery.

I will now discuss our Deepwater Gulf of Mexico operations. In the Gulf of Mexico, production averaged 15,000 barrels of oil equivalent per day throughout the second quarter, up over 30% from the first quarter, primarily due to the first full quarter of production from South Raton and a small contribution from Galapagos in June. We will see greater growth in the third quarter with the benefit of a full quarter of production from the Galapagos field.

Current oil production from the Galapagos field is about 30% greater than our original expectations and has significantly increased our contribution from the Gulf of Mexico. As Chuck mentioned earlier, our next Gulf of Mexico exploration well will be Big Bend, with another Gunflint appraisal targeted for late this year. We were also active in the recent Gulf of Mexico lease sale where we were the apparent high bidder on 6 blocks.

Turning to our international activities. I'll begin in the Eastern Mediterranean. We've been working hard to bring on additional supplies of natural gas. During the quarter, we completed and started production from 2 wells in the Noa field. We also recently started producing from our well in the Pinnacles field. Overall, we expect to hold our Israel gross production between 200 million and 250 million cubic feet per day over the third quarter as we continue to manage our volumes until Tamar comes online.

Our development plans at Tamar are progressing thing on schedule for sales to commence next April. Well completions are continuing, and we recently completed a flowback test. The deck and jacket fabrications are over 95% complete and progressing toward platform installation later this year. We plan to begin commissioning Tamar in the fourth quarter. As Chuck mentioned, finalizing all approvals of the Israel Electric contract and the continuing increased gas demand in the country sets us up well for our 2013 deliveries.

At Leviathan, we completed a successful gas flow test on the #1 well and are evaluating drilling an appraisal well in the fourth quarter. We are targeting initial Leviathan production to support the growing domestic market in the 2016 time frame, followed by an export project. We've been pleased with the interest shown in our Leviathan marketing effort, and we continue to move toward a new partner announcement by year-end.

In West Africa, we continue to see great results from Aseng. It produced an average of 63,000 barrels per day throughout the second quarter and hit a daily peak rate of just under 70,000 barrels per day. We initially brought production on at 50,000 barrels per day, and the strong reservoir performance has allowed us to continue ramping up production. We plan to produce the field at a gross rate of 65,000 to 70,000 barrels per day through the third quarter. By the end of the second quarter, we had already produced nearly 14 million barrels of oil.

We're also making good progress on our Alen project. All major platform fabrication has been delivered, and power generation modules and gas compressors have been installed. The subsea platform, well operations and flow line installations are complete, and the project remains on schedule. We believe there are significant prospectivity remaining in our current lease positions offshore Equatorial Guinea and Cameroon. As Chuck mentioned, we have exploration drilling starting this quarter and continuing through 2013.

Before we open the call to questions, let me touch upon our expectations for next quarter's volumes. As I mentioned in our last earnings call, we expect tremendous growth from our core operations during the second half of 2012. For the third quarter, we estimate volumes to be 242,000 to 250,000 barrels of oil equivalent per day, up 10% from second quarter based on the midpoint. On supplemental Slide 5, we show the adjustments to the range, which include announced U.S. asset sales and discontinued operations.

Onshore volumes will continue to grow with the DJ Basin activity and the initiation of our wet gas production in the Marcellus. Our Gulf of Mexico production will also be up with our first full quarter impact from Galapagos. Internationally, we expect West Africa sales to remain strong and volumes in Israel should reflect the added deliveries from Noa and Pinnacles.

The significant growth in the second half of this year is the initial springboard for our 5-year average annual growth rate of 17% we highlighted late last year. Combined with the ongoing exploration and appraisal activities and the continued progress on the major 2013 startups for Tamar and Alen, this is an extremely active and exciting time for Noble Energy.

So now we'd like to go ahead and open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

A couple of questions. First, can you just talk to the cost trends that you're seeing drilling horizontal wells in both the Marcellus and in Wattenberg and whether you're seeing any changes per lateral foot or any atrocities from using those longer laterals, et cetera?

Charles D. Davidson

Yes, Brian, I think what you're -- initial results are very encouraging. What the target is, is as you continue to move out beyond these 4,000 to 5,000 foot horizontal laterals, you're really looking for something in a 2:1 ratio of improvement of recovery versus costs, and that's kind of what we've been seeing so far. So I think the real question is, is that proportional as you continue to move out from, say, 4,000 to 5,000 feet to 8,000 to 9,000. So that's really the price that you're looking for there. And as we've noted a number of times, especially where we're deep in the program in the Niobrara, the big driver of efficiency has been that our drill times have been coming down steadily, and so now we're -- it's one of the reasons that our well count for this year is moving up instead of -- we've just been able to drill the wells more quickly.

Brian Singer - Goldman Sachs Group Inc., Research Division

If we look at EUR charts that you have in your presentation. I mean, it does look like some of the wells that you've drilled so far are actually above your revised EUR, your revised type curves. Is that just conservatism? Or do you feel like you've drilled better wells than what you expect to have on average?

Charles D. Davidson

I think we're really starting -- continuing to improve and learn as we go out here. Part of it is how your bring the wells on production and how you maximize performance, especially in the early time period of the wells that sets you up for better recovery over the longer time period. I'd say on those charts, none of those reflect the extended lateral piece. For example, the charts on Wattenberg, those are those 4,000 to 5,000 foot operations. So I think we're just continuing to improve as we go, and we're continuing to learn as we go as you would expect in these types of plays, and I'd say we're probably further along in the DJ Basin than we are in the Marcellus.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And lastly, on Israel, can you put any more color on -- I guess, any greater certainty, if you have it, for where Leviathan facility, the LNG facility, would be located. And then as you speak with potential partners, whether there are specific key milestones that you all need to see from the government before moving forward.

David L. Stover

I think, Brian, I think the real key indication we're going to see is from the policy committee that is looking at their requirements for an LNG exports from Israeli gas, and of course, we've talked to them about the benefits of having perhaps a single combined facility in the Eastern Mediterranean rather than several. So I think the key milestones there will be the policy committee's report, which we do expect to have shortly. On our side of it though, we have as I mentioned, we've done a lot of pre-FEED work on a number of sites, Cyprus as well as Israel, also looking at floating LNG as well. So we've got a lot of pieces moving forward. Key milestones going forward are certainly the policy report, the work that we're doing to solicit a partner, which, again, that progress is we're making nice progress there. And hopefully, we'll be announcing something by the end of the year. We're getting a number of companies interested that have gone through the data room. And then in parallel with all that, we're doing some of this early engineering work on a number of options.

Operator

We'll take our next question from Leo Mariani with RBC Capital.

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

Just curious about the downtime you saw in the second quarter in the DJ. Is that something you think is going to persist into the second half? And just curious if you've seen similar downtime in July.

Charles D. Davidson

I think most of that was back in April, Leo, with some of the facility maintenance and some of the downtime on the facilities. More of what the recent has been in June, maybe a little bit in the early July, has been the hotter weather. It's been extremely warm up there, I think approaching 100, is the third part of it. And when you get that really warm weather, it kind of ends up backing of some pressure. You end up with a little higher pressures in the system out there. So we get some relief from the weather, we'll be okay.

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

Okay. So no problem selling any of your NGLs at this point?

Charles D. Davidson

Well, the early -- one of the third-party downtime was with the problem with a fractionator. And so far our volumes -- of course, we go through a third-party processor as well, and those volumes have been moving out. We all know that the NGL market is very soft. Ethane, of course, is very, very soft, so we'll see it going on. But it's -- again, it's from our business, NGLs is not a huge part of our business so any impacts don't appear to be material to us at this time.

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

Got you. And I guess just in terms of Israel, where is your current Mari-B production? And what do you expect Pinnacles to add as well?

David L. Stover

Yes. I mentioned in the call, for the quarter we'll be running in that 200 to 250 range total. I think when you look at capacity, Mari, we've been trying to keep that in the 75 to 100 range. Noa has had capacity to get up to 100, but -- so we'll be in that 70 to 100 range on that, and Pinnacles is probably in the 50 to 75 range. So just putting all those pieces together, we'll run in that 200 to 250 for the quarter.

Charles D. Davidson

Some of these components may have the capability to deliver at higher rates, but as -- I know you're well familiar with the story is, we are managing this, the bridge, all the way to next April when we expect Tamar to come on. So we're trying not to get into a position where we have a sudden depletion and then, say, the winter months that we don't have any gas to sell. So it's very much a managed sales process right now.

Operator

We'll take our next question from Brian Lively with Tudor, Pickering & Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Can you guys remind us what you are looking to sell or what you're looking to do with the Leviathan data room?

Charles D. Davidson

Yes. The Leviathan data room is open for companies who are -- we have asked to consider coming in as a partner in the development of Leviathan and potentially an export project in the Eastern Med later on. So these are companies who are reviewing the data because the anticipated transaction would be that they would be purchasing an interest in the Leviathan field.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And just a follow-up to an earlier question. On your Q3 guidance, how have you risked back for potential hurricane downtime? And are there any other planned maintenance downtimes you see across the portfolio?

David L. Stover

Yes. In both third quarter and fourth quarter, we put hurricane downtime risking in there. I don't remember exact Levi amount, but it's 10% or so, I think, of the volume for the quarter in the Deepwater. So that's part of what we go into the year budgeting for and planning for some downtime for third and fourth quarter. And I don't think we really have any planned maintenance of any significance in the third quarter right now. We finished up the West Africa maintenance early in the year, so we'll just knock on wood that some unplanned maintenance doesn't come up.

Operator

We'll take our next question from Dave Kistler with Simmons & Company.

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

Real quickly on Gunflint. If I recall correctly, the range you guys had around it was 70 million to maybe 500 million-plus barrels. With what you've seen to date and with plans to drill another well, what are initial thoughts on timing to sales and maybe development costs that we should be thinking about incorporating as we build out a model around that?

Charles D. Davidson

Dave and I will tag team on that. What we're seeing right now is we could see a combination process on the development of Gunflint, and we've shown some of the mapping before. But it looks like we've got a nice 4-way structure there based on the original well and this appraisal well we've drilled. And as we've mentioned on the call, we've got another well to the south that we wanted to drill. But you could anticipate now that one possibility is to go forward with a subsea tieback on the 4-way while there's probably still some exploration that needs to be done in the deeper zones. That's one possibility, but we're still working with our partners. Some of our partners would say that maybe there's a possibility this could still be a single-hosted facility, and they'd like to see the results of this next appraisal well. But as you know, if it turns out to be a subsea tieback, that could possibly shorten, maybe by a year, the production timing as to when first production would come. But we'll know more after the next appraisal well. And I know you asked about cost, but it's way too premature to figure that out at this point.

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

Okay. I appreciate that. And then maybe switching back over to the DJ Basin and the down spacing program, and I apologize if I missed this. But based on the results you're seeing right now, what's kind of anticipated timing to calling maybe victory to down spacing and what would that mean to total recoverable reserves in that area?

Charles D. Davidson

Well, I think the key is where we end up on this 40-acre type pattern and a big key to that, Dave, is this next pilot that we're doing that we're actually just starting the drilling now. So we won't start really seeing production from this next pilot until probably late in the quarter. So 2 things. We'll continue to monitor the wells that we had essentially set up on 40-acre spacing in the previous pilot that have looked very strong, and I think we included that in the supplemental slide. And you can kind of see that performance relative to some of the other wells. So that's given us some real encouragement. Now we need to get this next 15-well pilot drilled and start to produce from that, and that will give us a lot more data over a wider range here that will -- you'll really start to understand that data a little bit better by the first quarter next year. But if you go back to our resource potential and everything we've talked about, the 40-acre potential is something new. So we just need to get a handle on that, and I'd say it's very encouraging today. But we'll have a lot more information on that the first half of next year.

David L. Stover

And as you could expect, we would -- our thinking is, is that increased density may be more applicable to some parts of the area than others, and we have to figure all that out. But you're on the right track if the resources are going up as we get these positive results from the 40-acre test.

Charles D. Davidson

And I'd say the other thing there. We're testing some different things on vertical recovery there with this new pilot too. That will all enter into that picture. We kind of laid that out on the supplemental slide also.

Operator

Our next question comes from Bob Brackett with Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

I had a question on Leviathan. What fraction of Leviathan's reserves have to go to the export market to make the project viable?

Charles D. Davidson

Well, with Leviathan at 17 TCF, within almost any range, you've got more than enough resource. And I'm talking about -- the general discussion in Israel, so far, has been maybe roughly half, but we'll see what the final policy decision is on that. So you've got, even at half, you've got 8 or 9 TCF that's available, which is enough to support a project, but I think what's more important here is to try to make sure you've got an efficient project for the Eastern Med because of the additional resources at Cyprus. And there will be -- under this policy there will probably be several fields that will be set up to allow for exports. It won't just be Leviathan. So we're trying to see if we can to make sure that this thing is as efficient as possible, hopefully a single point location for exports. There may be a land base, as well as a floating. But I don't think right now we're as concerned about the amount of gas that's available for export. We certainly would like to see as much as possible because it makes a project more efficient, but we just want to make sure the logistics work out.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

But if that number is 25% or 0% that's allowed to export, does the project still work?

Charles D. Davidson

Well, it depends on how much you add at Cyprus because this is not necessarily just a single field. But I've not heard of any numbers that low. So that's just kind of speculating and is beyond what any speculations occurred in Israel.

Operator

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

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

A couple -- let me just go back to the Wattenberg. I know it sounds like you have got additional capacity coming on in 2013 as far as processing and getting some of the third party processing capacity up. But can you talk about between now and then -- I mean, you're ramping activity. I would say Anadarko is ramping and others. But it seems to be getting pretty tight as far as the takeaway capacity until '13, and yet you're still adding the rigs in the back half of the year. So can you just talk about what we're up against for the next 2 or 3 quarters as far as getting [indiscernible]?

David L. Stover

Keeping an eye on capacity and takeaway and managing the field to in tune with that. Now a lot of our effort, I'd say the majority, almost all of our effort has been in the northern part of the field, moving up into northern Colorado, which is the area we're continuing to delineate. And that's where we have the real high oil percentage, if you will. I think if you get the northern part of the field up in northern Colorado, we're up to 80% oil, 80% crude up there. So it minimizes the amount of gas you have to handle as part of that, while your allowing some of this additional processing, this expansion to catch up with that. So I think we've managed the field operations to be in sync with the capacity expectations, and what we see going forward with a large part of that being the focus in the northern part where you have the high crude content. Again, the whole idea is to stay a year or 2 ahead of this with the third-party processors to make sure that everything syncs up with our drilling schedule.

Charles D. Davidson

And at the same time, as Dave, I think, mentioned in the call, is that we're winding down rapidly the vertical program. A lot of that vertical program was in some of the higher GOR areas with the refracs and with the drilling of vertical wells. So it's managing all the pieces.

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

Okay. Fair enough. One final question. Just as I look -- again, back to the DJ, can you guys talk about -- as you look to the Codell, but can you talk about any results in the Codell? As far as I know, there's been some chatter out there from some other players. And then have you done anything with the Greenhorn? And do you think it's prospective?

David L. Stover

Yes. I'd say first on the Codell, we've done a few tests on the Codell. And if you look at this 15-well pilot, we've got a couple more tests that we're going to do on the Codell. So it's something that still continues to interest us, and we've seen some encouraging results on the tests we've done now. Whether it's something that can be drilled horizontally across the whole field, I don't know. That's part of as Chuck alluded to earlier that some of these things may apply to different parts of the field differently. On other formations like the Greenhorn, I'd say they're kind of secondary behind what we're doing with the Niobrara and Codell here at this point. Still, it's somethings we're continuing to look at. We'll do some, what I would call exploratory work on some of that over the next year or so, but this is just a basin with a lot of resources and a lot of things that have shown hydrocarbons, and it's just something else that's further back in the queue right now.

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

Okay. As far as the baseball analogy, what inning would you say you're in as far as field development and as far as climbing that learning curve?

David L. Stover

In -- I'd say in the Niobrara, we're probably in, I'd say, third inning or so of that as far as the horizontal Niobrara, of what we still have in front of us. And some of those other formations like Greenhorn and stuff, I'm not even sure we've stepped up to bat yet.

Charles D. Davidson

I think the other thing, just to add to it, is if you look up the history of Wattenberg, which goes back into around 1970, this field has reinvented itself a number of times. But this one is stunning. The horizontal development in this field is truly stunning, and we're probably cautious about assuming we know everything there is to know here. And I think Dave's got it pegged just right, is that for every quarter, we're setting new records, and we're learning new things. And fortunately, most of it has been extremely positive.

Operator

We'll take our next question from Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I just had, I guess, another couple of questions on the DJ program. On the 40-acre pilot, you highlighted that the 40-acre test seemed to be performing better. Any thoughts as to maybe what's driving that, why you'd see better results from the 40 as opposed to the 80?

David L. Stover

I mean, one of the theories, Michael, is that really the more you break this rock up and the more you get it connected, the more recovery you're going to get out of this just as tight as this formation is. So what you start to see as you get down to the smaller spacing is you start to get this a little better connected and then more broken up. And with the brittleness here, that may lead to just better recovery overall.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

And what do you think those recoveries are trending versus any internal target picture?

David L. Stover

I mean, if you go back to what we said when we started this on 160-acre horizontal Niobrara, based on our original type curves we're thinking about 5% incremental recovery for that. So as you keep cutting that in half, you're looking at 5% potential incremental price for each reduction in spacing. So I mean, that's kind of the price we're looking at.

Charles D. Davidson

Yes. We're absolutely -- in terms of ultimate goals, we're trying to push this well beyond 10% recovery. But we're still testing what the limit might be. We're also still getting a handle on how much original oil and gas in place there is, as to whether that's still growing as we continue to unlock some of this.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Fair enough, I guess. I'll just ask then what is the kind of current thinking on original oil plays [ph]?

Charles D. Davidson

We've started out and we always said it's kind of 20 million to 30 million barrels per section, per 640. And we haven't really changed that yet. But I'd say it's probably gravitating towards the upper end of that.

Operator

Our next question comes from Arun Jayaram with Credit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

I wanted to follow-up, Chuck, a little bit on Leviathan. Obviously, you're waiting a little bit on the export decision. But there seems to be quite at a bit of chatter that you guys have launched a tender for an early production system at Leviathan with perhaps an FPSO in a 1.2 BCF of capacity perhaps coming online in 2016. I just wanted to get your thought process. Obviously, with Tamar that would take a deliverability well above 2 BCF potentially, which is a little bit higher than Israeli consumption. Just wanted to get your thought process behind an early production system at Leviathan.

Charles D. Davidson

Well, first of all, we are pursuing a number of options, and what we're zeroing on is that the demand for gas in Israel has grown substantially. And so we see a bigger market there than probably what we saw at the time we designed Tamar. And so we are looking at a number of options of how we can provide incremental gas to the Israeli market. The other thing is that the early results from the policy committee, and we'll see what their final results are. As suggested, they do want to have split deliveries from fields, so that -- it's not just a matter of Tamar supply the domestic market and Leviathan goes to export, is that we expect that on certainly the larger fields, they will be split between domestic and export. So that means that Leviathan would have a component that goes to domestic, and so we've been doing some work to see how we might develop Leviathan ahead of an export project because an export project is more long term. Ahead of an export project, that could help meet this increased demand of gas from Israel.

Arun Jayaram - Crédit Suisse AG, Research Division

And that timing perhaps, Chuck, would 2016 be a possibility?

Charles D. Davidson

Oh yes, that's a possibility. And as you know that getting early production from Leviathan really boosts its value.

Arun Jayaram - Crédit Suisse AG, Research Division

Right exactly. Okay. Now let me shift gears a little bit in terms of the DJ. At the analyst meeting, you guys had talked about an inventory of about 2,000-plus wells possibly doubling based on down spacing. It seems like you obviously had some good success at 80 acres pushing to 40. When are you thinking -- or what are you thinking about the inventory today? And are you ready to say today, based on initial results of the inventory, it's pushing that 4,000 well number?

David L. Stover

I mean, you're absolutely right in the recognition that the inventory is growing because that inventory we talked about last -- well, I guess, last November or so included some 80 acre but not a lot of 80 acre and also didn't include all this northern Colorado piece. So between getting more comfortable with the 80-acre and the northern Colorado, that's grown the inventory a good bit and now we'll see where we get to on the 40-acre. And again if I go back to 40 acre, to be able to really start to get a good idea of how that's going to fit into the inventory of locations, you're looking at the first half of next year. But it's not unrealistic to be pushing this to 4,000 at some point here.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And just one real quick one. It looks like now the rig count is moving to 10 on the horizontal side, which is up a little bit, I think, from 9 previously. Any thoughts as we think about 2013 on how many horizontal rigs you plan to have next year?

David L. Stover

Yes, I mean, we'll continue to work through that here as we get into the budget cycle. I mean, we'll be exiting the year with 10, so that's kind of our starting point. For next year, I think the other thing we'll be looking at pretty hard is the efficiencies because it's not taking as many rigs to drill as many wells, even on the horizontal program. You know what, at one time, we were think it would be 12-day wells to drill or turning out to be under 10 on a lot of this. So that's going to be a factor into the number of rigs that we need. The main thing we'll be working on is how many wells do we want to set ourselves up to drill, horizontal wells, next year. And then we'll back, back into the rig portion.

Operator

Our next question comes from John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

I just want to know, can you give a little more color on the 2 more recent extended reach wells you had in the Wattenberg? You said their actual results were kind of comparable to Wells Ranch. Are you seeing a certain -- a similar EUR potential for those and similar IPs?

David L. Stover

The reason, John, we haven't given more color is we're still less than 30 days in on those. So we don't like to get too far ahead of ourselves. What I would say on that performance within that 30-day time frame, it looked very similar to that type curves of that first extended reach horizontal well. If you go back and look at that. But that's something -- as we get another quarter into this and we can get closer to 120 days, we'll overlay that with the first one and be able to highlight how it compares.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And Marcellus, was it similar targets, similar parameters?

David L. Stover

Right, similar thing. It is just cleaning up now. In fact, I think we just put it on production in the last couple of days.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And just on Gunflint. If I recall correctly, you talked in the past about the potential -- the appraisal, you're testing a potential spillover to another structure. From what you're seeing here, can we assume that, that spillover is not the case and it's just flowing closer?

Charles D. Davidson

We're still going through the evaluation of that but we've got -- we had, as I mentioned, there were some zones that had paid down to our current appraisal location because our appraisal is down-dipped moving more into that syncline line, other zones didn't. And then we've got some deeper zones that look kind of interesting. So I'd say the jury is still out in terms of understanding the resources there. But I'll give you that our thinking is there's probably some resources in the 3-way as well but we can't tell from this location what extent that might be.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And just one last one. Just anything you can say about Sierra Leone plans there.

Charles D. Davidson

Still early, just in the phase of -- we've just been notified of the license, so there's work to be done. But going into that, we thought that was a very interesting and prospective area, so we're excited to -- it looks like we'll be invited to be a part of the exploration.

David L. Stover

More than 2 blocks it is.

Operator

Our next question comes from John Herrlin with Societe General.

John P. Herrlin - Societe Generale Cross Asset Research

Three quick ones. With Aseng, why the better performance reservoir? Or is it bigger than you thought?

Charles D. Davidson

I think on Aseng it's-- we always knew we had a high quality reservoir, and so it's really that reservoir performance when we look at the drawdown. It's just the wells had the capability to produce within the limits of our -- the boundaries that we set for drawdown on that. And we drilled these wells directionally, horizontally, and it gave us a lot of productivity. And then I think on top of that, John, is the fact that the surface facilities, the FPSO has performed extremely well. So we haven't -- we just haven't seen reservoir bottlenecks or surface bottlenecks. It's allowed us to-- we've been doing some modeling to make sure that we don't do anything that damages the ultimate recovery of the field by going at these higher levels, and everything we see suggests that's not the case.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, good.With respect to Gunflint, what's your standalone volume threshold, your standalone facility threshold rather than the subsea? 100 million barrels?

David L. Stover

On standalone, it's probably at least 100 million. I mean, I think what we have now you've got 2 wells that we know we can produce and tieback to a subsea at a minimum. And as Chuck said, we'll continue to evaluate the larger portion of it.

Charles D. Davidson

I think where you -- it's not only volume, but it's also looking at if you do a subsea, how much they can handle, right? And if it gets to where you're leaving a lot of oil in the ground or production capacity back up because they can't handle, then it's starts pushing you toward that standalone as well. So there's a number of moving pieces, and we really need to drill that next well to get a good handle on it, but that's the things being balanced.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me is on the Cameroon lockout you described. Could you give a little bit more information on trap types of the 3-way or the 4-way, that sort of thing?

David L. Stover

Well, most of the work that we have been doing in that area, they have stratigraphic boundaries. You've got sand deposits that flow, so you got a structural component and a stratigraphic component. So I wouldn't call it a 4-way by any means.

John P. Herrlin - Societe Generale Cross Asset Research

It's a combination, Chuck?

Charles D. Davidson

Yes.

Operator

Our last question comes from Charles Meade with Johnson Rice.

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

My question was more on especially -- Slide 7 you talked about the different way you're completing these wells on the DJ. And I get on the first bullet point, you're talking about snubbing on completion that you're trying to hold the pressure there. But I'm less clear on how to interpret the early drill-out. And I was hoping maybe, Dave, you could address what you're doing there and how that perhaps fits with the closer 40-acre space that you're doing.

David L. Stover

Yes, I mean, this is just -- in general, what we've moved to is being able to move on these wells quickly after drilling these, go in and clean them out. In a lot of cases, with coiled tubing, go in and clean these out, while you're continuing to flow these back. So you continue to use the reservoir energy and not get in the situation where we started with some of these. When we initially started producing wells up here, we've let them flow and until almost they had died, if they will, or they lost energy. And then you go in and run tubing and move on. What we're doing now is we're starting with these from the beginning, getting them cleaned up early -- getting them cleaned out early, getting them set up so that you can move into production quickly and not be stopping and starting with these wells and playing with the reservoir energy that they have. So you're really using that with you upfront and getting in early, getting coiled tubing in there, running and cleaning out quickly while these wells are flowing and then getting them turned on to production. Again, what we're doing is kind of holding some -- if you will, holding some pressure on these to start to let them come on a little slower than they did initially, not open them full up. And you're starting to see some real benefits from these, especially as you line them out over the first 30 days or so.

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

And are you guys still doing the slow packers? Or are you doing the plug and parallel?

Charles D. Davidson

We're using like a packers plug. Then where you have multiple packers so that -- and really where that helps us is in speed of the completion operations so that we can go through a full well stimulation process pretty quickly.

Operator

And that concludes today's question-and-answer session. Mr. Larson, at this time, I will turn the conference back to you for any additional or closing remarks.

David R. Larson

There's a few more questions on the call there. But we've kind of hit our -- went a little over our time limit. Those that we didn't get to, I'll just remind you that we will be available to take your calls after the call. And then finally, I'd just like to thank everyone for participating in the call today and your interest in Noble Energy. So have a nice day.

Operator

That concludes today's conference. Thank you for your participation.

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