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Noble Energy, Inc. (NYSE:NBL)

Q2 2013 Earnings Call

July 25, 2013 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

Kenneth M. Fisher - Chief Financial Officer and Senior Vice President

Analysts

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

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

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

John T. Malone - Mizuho Securities USA Inc., Research Division

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

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

John P. Herrlin - Societe Generale Cross Asset Research

Dan McSpirit - BMO Capital Markets U.S.

Operator

Good morning, and welcome to Noble Energy's Second Quarter 2013 Earnings Call. I'd now like to turn the call over to David Larson. Please go ahead, sir.

David R. Larson

Thanks, Tim. Good morning, everyone. Welcome to Noble Energy's second quarter 2013 earnings call and webcast. On the call today we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

This morning, we issued our earnings release for the second quarter, and hopefully you all have had a chance to review our results. A few supplemental slides were also posted on our website. If you have not already downloaded them, you will want to do that now as we'll -- as they will be good reference material for the discussion today. Later today, we expect to be filing our 10-Q with the SEC, and it will also be available on our website.

The agenda for today will begin with Chuck discussing the quarter and providing an updated view of the remainder of the year, highlighting our dramatic production and cash flow growth, combined with a number of exciting Exploration opportunities. Dave will then give a detailed overview of our 5 core operational programs and near-term plans. We'll leave time for Q&A at the end and plan to wrap up 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, SEC filings for a discussion of those.

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

Charles D. Davidson

Thank you, David. Good morning, everyone, and thanks for joining us today. It's hard to imagine that we're already well into the third quarter of the year. And when I look at the list of accomplishments through the first 6 months, it really reads like a full year's worth of activity, which just showcases the fact that our teams have really been extremely focused. And we're not anywhere near through for the year. There's much more to come.

Certainly, highlighting the list for the first half is that we've continued to set new production highs, driven by the acceleration and optimization of our DJ and Marcellus Shale programs, as well as the startup of major projects, including Tamar offshore Israel in the first quarter and Alen offshore Equatorial Guinea, which began commissioning late in the second quarter. Commencement of production at Alen follows the successful startup of multiple large-scale developments, including Aseng in late 2011, Galapagos in 2012 and Tamar earlier this year.

Four major projects brought online within a period of 2 years is a tremendous feat, and I'm very proud of what we have accomplished as a team. Delivering the Alen project ahead of schedule and on budget furthers our exceptional track record of execution and continues to highlight what we believe is a significant competitive advantage for Noble.

In addition to reaching record production levels, we've also bolstered our pipeline of major projects with strong Exploration appraisal drilling results. This includes a new discovery in Israel at Karish and the successful appraisal at Gunflint in the Deepwater Gulf of Mexico. I'm equally excited about what is still to come this year with further production and cash flow growth anticipated from multiple areas of our business and a number of additional major projects targeted for sanctioning.

In addition, we have 2 Exploration wells planned for the Gulf of Mexico, our first exploration well in Nicaragua, initial drilling in Nevada and a number of meaningful appraisal wells all before the end of the year.

I want to spend some time reviewing our second quarter results, which reflect the significant operational momentum we've built. Adjusted income from continuing operations for the second quarter was $249 million or $0.69 per diluted share with the adjustments from income this quarter primarily representing unrealized gains on commodity derivatives. Revenues were $1.1 billion for the quarter with nearly $900 million of our revenues coming from liquid volumes and supported by continued strong U.S. and global crude oil pricing.

We had record sales volumes for the quarter, totaling 260,000 barrels of oil equivalent per day. Volumes were led by exceptional performance internationally, where total volumes were also a record at 120,000 barrels of oil equivalent per day from continuing operations.

Strong sales in Equatorial Guinea combined with Tamar, which contributed its first full quarter of volumes, led our International performance. Domestic production totaled 140,000 barrels of oil equivalent per day for the quarter with the drivers of our ongoing growth being the horizontal programs in the DJ and Marcellus, which are benefiting from continued operational efficiencies in drilling and completions.

As we noted in last quarter's call, our second quarter volumes were impacted by late winter storms in the DJ Basin, as well as some third party facility downtime at Na Kika in the Gulf of Mexico, which handles our Galapagos production. Discretionary cash flow from continuing operations for the quarter was $765 million. We ended the quarter with over $700 million in cash and an undrawn revolver. That resulted in total liquidity of $4.7 billion at the end of June. And net debt to book cap was at 28%.

It all adds up to a solid quarter that reflected continued execution of our multiyear growth agenda. However, the numbers really have greater significance when one steps back and looks at our performance over the course of the past 4 quarters. So as compared to second quarter 2012, production this quarter was up 16%, revenues up 19%, discretionary cash flow up 20%; and adjusted earnings up 82%. All of this, of course, from continuing operations; really great progress and very consistent with our long-range plans.

Let's now take a quick review of our core operating areas and the status of our major projects before spending some time on the Exploration and appraisal calendar for the rest of the year. Onshore, we're operating at the highest level of horizontal activity in our company's history, targeting 300 operating wells to be drilled this year in the DJ Basin and approximately 80 operated wells in the Marcellus.

In each play, we're intensely focused on optimizing the drilling and completion techniques, testing various spacing patterns, testing longer laterals, delineating new areas of potential. Both of these areas in the DJ and the Marcellus continue to grow rapidly and as a result, are currently producing well above their second quarter averages, delivering new production highs for Noble Energy. Dave will be providing some further details on our current record production levels.

In West Africa, the Aseng oil project continues to perform strongly. Having recently come off the plateau of production as expected, the field has now produced over 35 million barrels of cumulative production. As mentioned earlier, the Alen project has commenced production, is expected to reach full operations by the end of this -- the third quarter. With its condensate recovery, gas processing and gas reinjection systems, this project represents Noble's most sophisticated processing system worldwide, and is expected to be a strong contributor to the company's production and cash flow profile.

Moving to the Eastern Mediterranean, we've been extremely pleased with the performance of Tamar following startup with -- while experiencing nearly 100% uptime in the field and facilities. This level of reliability on the world's longest subsea tieback with a project of this size installed in industry-leading timeframes is a significant accomplishment for Noble Energy.

We're continuing to progress plans for an expansion of the Ashdod onshore receiving terminal, which handles our gas production in Israel. This expansion, which is anticipated to be online in 2015, will take maximum capacity volumes from today's levels, which are just under 1 billion cubic feet a day, to around 1.2 billion cubic feet per day.

Recently, the Israeli government finally issued their policy on gas exports. It permits the export of some 40% of discovered resources, although the percentage is allowed to be determined on a field-by-field basis and is higher for larger fields such as Leviathan. The policy was approved by the cabinet, but has been challenged as to whether it should be approved by the Knesset. And we expect an indication from the High Court in a few weeks' time on that issue.

We and our partners are evaluating the final terms and conditions of the export policy and its implications on the scope and pace of further and future developments. In the meantime, we continue with our Leviathan phase 1 development planning and also continue to work with Woodside and our existing partners in finalizing agreements associated with the sale of Leviathan interest. The closing of these agreements has been delayed primarily due to the uncertainty over exports, as I mentioned earlier. Hopefully, we are nearing closure on that issue.

Let me wrap up with a review of our Exploration and appraisal programs, which are summarized on Slide 5, and which include a number of meaningful and impactful wells for the remainder of the year. In the Deepwater Gulf of Mexico, we have 2 new Exploration prospects to be drilled with operations currently ongoing at Troubadour, which is about 5 miles east of our East Bend -- of our Big Bend discovery. And then followed by an additional Exploration well in the Gulf later this year, right now likely to be a large prospect called Dantzler, which is approximately 14 miles southwest of Big Bend. So this is turning into a very active area for us.

We're also looking forward to commencing frontier Exploration drilling on our initial Nicaragua prospect during the third quarter with a gross resource range of 210 million to over 1 billion barrels of oil equivalent. The Paraiso prospect is anticipated to be at total depth in the fourth quarter. An initial farm-out of our position there was recently completed and is subject to final government approvals. And we're also continuing negotiations with additional parties for the further farm-out prior to drilling this prospect.

In the Eastern Mediterranean, we're currently drilling the appraisal well to our Cyprus discovery, and we'll be looking to perform our first production flow test after completing drilling operations. Results from the appraisal well will help confirm the resource size, and are important in the decision-making for domestic market planning, as well as an LNG export project there. In support of these efforts, we've already completed pre-FEED studies and have executed a memorandum of understanding with the government regarding a potential one-train LNG development. We've been very pleased with the country's desire to aggressively move forward, planning for both the domestic and export options.

New Exploration drilling offshore Cyprus and Falklands is anticipated for the second half of next year. And we've recently completed or are currently conducting significant 3D seismic programs in both areas in support of these drilling plans. While we've certainly had a strong first half of the year, we're also positioned well to set new records through the remainder of 2013. Our substantial third quarter production growth can be seen in the chart on Slide 8, which shows an anticipated 30,000 barrel equivalent per day increase versus the second quarter with new contributions coming from nearly every one of our core areas.

Just a reminder as well that while this quarter-on-quarter projection is quite impressive, we're still on a multiyear journey for growth here at Noble Energy. We'll be highlighting more of that journey at our December 17 Analyst Meeting that is planned in Houston.

So now I'll turn the call over to Dave, who will give you some more details on our ongoing operations.

David L. Stover

Thanks, Chuck. Let me start by commenting on the U.S. onshore region where we are currently experiencing record levels of production in both of our core areas, the DJ Basin and the Marcellus.

For the second quarter, DJ Basin production averaged approximately 90,000 barrels of oil equivalent per day, an increase of 22% versus the second quarter of last year. Liquids volumes continue to be a major driver of our activity in the area, comprising 62% of our production and 84% of our revenues.

On the drilling front, we have increased our rig count to 11 operated rigs, which can be seen on our DJ Basin map on Slide 9. We will operate most of the remainder of the year with 10 drilling rigs in the play, as the 11th rig will drill only a few pads before moving to Nevada to commence drilling our Wilson Exploration prospect late in the third quarter.

Through the first half of the year in the DJ, we spud over 130 horizontal wells, targeting the Niobrara and Codell formations, including 16 extended-reach laterals with the entire horizontal program continuing to be very encouraging. As mentioned in our call last quarter, we continue to see the performance of the 9,000-foot extended-reach laterals on average in excess of the 750,000-barrel equivalent type curve. And a number of the wells are performing in line with 1 million-barrel equivalent EUR.

As we continue to appraise new areas of Northern Colorado, we are testing the potential of extended-reach laterals in areas where vertical wells were uneconomic, and even a few standard length laterals performed below average. Of particular note are 2 recent wells in the Cummins area where EURs from extended-reach laterals are estimated to be more than 3x standard lateral well in the area. This is encouraging and a positive sign for areas in Northern Colorado outside of those that have already proven productive such as East Pony.

Throughout 2013, we're continuing to focus on understanding the optimum recovery plan in regards to well density, lateral lengths, multiple layers and well patterns throughout different areas of the basin. Of our total 300 horizontal wells planned for 2013, we anticipate more than 10 to be focused on the Codell and more than 80 to be targeting the Niobrara A or C bench.

Horizontal Codell wells in the greater Wattenberg area are performing in line with what we are seeing from similar length in Niobrara wells. And we're currently testing our first long lateral at Codell. With the entire 300-foot vertical column through the Niobrara and Codell observed to be productive, we have yet to see any production interference amongst tightly spaced Niobrara B wells and A, C and Codell completions.

Our primary focus remains areas with high liquid content, including the Wattenberg oil window and Northern Colorado where total liquids represent over 80% of the production stream. We'll also continue to transition to larger pads, more centralized production and water handling facilities and gathering systems to support our increasing levels of activity. We estimate that over 60% of the water utilized in our completion so far this year has been piped to location rather than trucked, resulting in an elimination of approximately 44,000 truckloads or an equivalent 3.3 million miles taken off the Colorado roads.

Recent infrastructure improvements, along with our active development program, are resulting in record production levels for Noble Energy in the DJ Basin. To illustrate the high levels of current activity, we completed 31 wells in the month of June with 604 stages pumped, a record for us and significantly above our prior record of 26 wells and 500 stages pumped in October of last year.

On Slide 10, we highlight our net horizontal production in the DJ, averaging a record 50,000 barrels equivalent per day in the second quarter and already currently around 55,000 barrels equivalent per day. In total, our DJ volumes are currently between 95,000 and 100,000 barrels of oil equivalent per day. Reflecting back to where the DJ was just 1 year ago versus the third quarter of 2012, the production levels are up about 30% and the horizontal volumes are up over 75%, highlighting the tremendous impact that our program is having.

In support of continuing growth from this leading U.S. onshore play, additional near and long-term infrastructure expansions are being brought online. An in-field oil gathering trunk line is scheduled to begin service with up to 50,000 barrels a day of capacity in September. This line will help us deliver crude oil efficiently to the White Cliffs Pipeline and the plain's rail facilities, which combined are adding 140,000 barrels a day of capacity between now and the end of next year.

On the gas side, DCP is bringing on the LaSalle plant in September of this year, which will initially add 110 million cubic feet per day of capacity. And the plant will then be expanded in the fourth quarter by an additional 50 million cubic feet per day.

Further midstream projects are also planned for 2014 and 2015, including Noble Energy's own Tioga Gas plant, which will service our wells in Northern Colorado and our adjacent LNG facility. And the LNG facility, the first of its kind in the state, will mainly provide fuel for our drilling and completion operation starting in late 2014.

Moving over to the Marcellus. We're in the process of rigging up our fourth wet gas rig. Two of these rigs are operating in the Majorsville area with one rig drilling each of our first pads in the Pennsboro and Oxford areas of West Virginia, south of Majorsville. We anticipate adding a fifth operated rig to our program later in the third quarter, which will initially focus on delineating a new wet gas area just west of Majorsville in the Moundsville

area. We're continuing to focus drilling efforts on optimizing lateral lengths and completion designs with a recent highlight that we drilled our longest lateral on the play to-date, in fact our longest lateral ever drilled by Noble Energy in any play, with a total end zone pay length of over 10,400 feet. First production from this pad is anticipated late this year.

With our drilling plans in the wet areas along with the 2 rig dry gas program operated by CONSOL, we remain on target to participate in about 80 wet gas wells and 40 dry gas wells in the Marcellus this year. In June, we brought to production the 11-well WEB 4 wet gas pad, which represents our fourth operated pad on production in the Majorsville area. Results have been very encouraging with initial gross production reaching a maximum of more than 50 million cubic feet of natural gas and 3,000 barrels of condensate and NGLs per day.

Combined with recent completions on the gas side by our partner, we've seen our current net Marcellus production increase to a record 150 million cubic feet equivalent per day, which represents an increase of over 30% from the beginning of the year. The outlook for continuing our production growth in the Marcellus through the remainder of the year is excellent, supported by our increasing activity levels.

Right now we have completion operations ongoing in various stages on 8 wet and dry gas pads combined including our first pad in the Normantown area, which is testing the southern extension of our acreage. Continuing to execute on our plans will enable us to exit 2013 with Marcellus production above 210 million cubic feet equivalent per day net to Noble.

Shifting offshore to the Deepwater Gulf of Mexico, our development teams are making significant progress, moving forward plans for our Big Bend and Gunflint major projects, which represent the next leg of production growth for our Deepwater Gulf assets. We're targeting a sanction of both of these projects later this year with initial production estimated around the end of 2015.

In the near term, our third quarter volumes in the Gulf of Mexico will be affected by 2 weeks of downtime at Galapagos for regular pipeline inspection, as well as approximately 20 days of downtime at Ticonderoga for the tie-in of a recently drilled development well and the installation of gas lift. The Ticonderoga #4 well, where we have a 50% working interest, is currently being completed with plans for first production early in the fourth quarter of this year.

Bringing the well online is anticipated to add 3,000 barrels of oil per day net to our production. As Chuck mentioned earlier, we are currently drilling the middle Miocene-Troubadour prospect, which is adjacent to Big Bend. And results are expected to -- in the latter part of the third quarter. Discovery at the 30 million to 60 million-barrel equivalent prospect could be incorporated quickly into our development and sanction planning with Big Bend.

Following Troubadour, we'll drill an additional Exploration prospect, and are currently selecting between several candidates. A leading possibility is an upper middle Miocene prospect named Dantzler, which is located only 14 miles southwest of the Big Bend-Troubadour area on Mississippi Canyon 782. Dantzler has a gross resource range of between 50 million and 220 million barrels of oil equivalent, and results would be anticipated towards the end of the year.

Moving over to the International side. A big highlight of the second quarter in West Africa was the early startup of our Alen gas condensate project, which commenced production late in the quarter. Since startup, we've been slowly ramping up volumes, optimizing all of the major component systems including our gas separation and compression facilities. We anticipate reaching full operations at the field late this quarter, 3 months ahead of our original schedule.

As a reminder, the produced condensate volumes from Alen are being transported by pipeline to the Aseng FPSO for storage and offloading. Also continuing to progress the appraisal and predevelopment of Diega and Carla, with a well currently drilling at Diega and plans to perform a long-term flow test following total depth. In Carla, we drilled an appraisal well in the southern area in the second quarter, encountered oil in the upper zone, and then lower zone was wet.

Our early development planning for these discoveries is focused on the potential for subsea tiebacks to existing infrastructure at Alen and Aseng. In the Eastern Med, we're very pleased with the performance of Tamar, which drove strong second quarter production volumes in Israel, will be a significant contributor to our growth through the remainder of the year. As a result of the startup, deliverability of natural gas to the Israel market now exceeds the average daily demand bringing us back in a position of providing for the swing in the market.

For example, this month we have delivered approximately 1 BCF per day gross on certain peak load periods during the work week, while the overall average for those days is closer to 800 million cubic feet per day, again highlighting the flexibility and deliverability of this world-class field.

Weather continues to have an impact on the overall electricity generation demand in Israel. And thus far, in 2013, it's been generally milder than in 2012. This has been evidenced in the third quarter with July electricity demand down about 7% versus the same period last year.

Natural gas sales in the third quarter will also be impacted by this year's holiday calendar in Israel, with very few higher demand workdays in September. That being said, we continue to see a strong long-term demand outlook for natural gas in this region.

With respect to Eastern Med Exploration, discovery of Karish marked our fifth discovered field of greater than 1 Tcf, and brought total discovered gas resources and basin to approximately 38 trillion cubic feet.

Perhaps of greater interest was that Karish contained higher condensate yield than our previous discoveries -- in the order of 7 to 10 barrels per million cubic feet. Subsequent lab analysis indicates the condensate is thermogenically sourced and provides further encouragement for the potential of oil in this basin.

Construction of the Atwood Advantage drillship remains on schedule for delivery late this year. As we've mentioned before, capabilities and efficiencies of this rig will enable us to drill a deep Mesozoic oil prospect in the first half of 2014. With the potential for the deep oil prospect under a number of our existing discoveries in Israel and Cyprus, we're very excited about testing this substantial new play as soon as possible.

Let me wrap up with some comments on our outlook for the third quarter and remainder of the year. As previously discussed, significant growth in the U.S. onshore regions, production capacity in Israel and the ramping volumes from Alen will all provide additional contributions moving forward. We remain in good position to meet our full year guidance with current production already close to 285,000 barrels of oil equivalent per day. And third quarter volumes anticipated to average between 285,000 and 295,000 barrels of oil equivalent per day. The midpoint of this range reflect the 12% increase from the second quarter of this year.

Overall, our rapid production growth, multiple major projects targeted for sanction, Exploration drilling in the Gulf of Mexico, Nevada and Nicaragua, as well as our ongoing appraisal programs provide a strong second half and great momentum for 2014. These are just some of the many reasons we have planned another Analyst Day late this year to update and highlight what we are building at Noble Energy.

Tim, at this time, we'd go ahead and open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll go first to Charles Meade with Johnson Rice.

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

Let me start with one kind of a financial one. Your deferred or I should say, your adjusted deferred tax rate for the quarter was a little higher than you guys had guided to, and I think most people were looking for. And I'm sure there are some idiosyncratic view -- reasons for why that happened in Q2, but I wondered if you could just give some detail on why that moves around and how that might affect the outlook for that item in the back half of '13?

Kenneth M. Fisher

Sure. Charles, this is Ken Fisher. The deferred rate came in at about 19%. That's a calculation that we do quarterly, projected on the full year's provision, tax provision and the -- we had forecast some less utilization of some foreign tax net operating losses in the foreign jurisdictions and -- but if you look at it on a full year basis, the guidance range we give is 5.

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

Okay. So if -- is it kind of a fair simplification that it's kind of like a quarterly mark-to-market on where you expect you're going to be in the year?

Kenneth M. Fisher

Yes, yes. We were high in the first quarter, a little lower in the second quarter. But yearly, guidance stays the same.

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

And then shifting to the operations, and maybe this is a best question for Dave, I was a little bit -- I know you guys had guided to lower -- higher downtime in both the -- in the DJ and the Gulf of Mexico for Q2. But the -- you had a string of 5 or 6 or more consistent U.S. oil growth broken here. And as I'm looking at the breakdown to that, it seems like with some of the -- both the slides you have on the DJ horizontal volume growth, that growth trend is attacked. And so I think what we're left with is maybe the legacy production of the DJ maybe underperforming. Or perhaps as Chuck mentioned, the -- I know there was some anticipated downtime at Swordfish for Q2, but it sounds like maybe there was the Galapagos host tieback in Na Kika might have had some unexpected downtime. So I wonder if you could decompose that?

Charles D. Davidson

Yes. I think that -- I mean let's start with -- the best news is what we're at now. So when I mentioned where we're at on overall company production and also where the DJs back up to in that 95 to 100 range. But what we saw a little bit in the second quarter was we had probably a little longer downtime on that Na Kika getting the Galapagos production back up. So that had an impact. Obviously, that's what 12,000 barrels a day -- any extra week of that has a big impact in the quarter. And then in the DJ, the other thing we saw is as we were doing some of these plant, as -- say we -- the operator was doing some of the plant facility downtime. We had a little extra plant facility downtime in the DJ on that, but that's all back up and running now. And the exciting thing up there is we're on the verge of bringing on a big new facility up there with that LaSalle plant in September. So I'd say all of that was just temporary, Charles. And that's why we're excited about where we're back up to on the DJ volumes and actually how that overall horizontal production's performing. But when you have any of that period of downtime and then bringing anything back on, it does affect the legacy wells much more than the horizontal producers.

Operator

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

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

You talked about on the call having some tightly spaced multi-zone wells in the Niobrara, basically producing from the A, B, C and the Codell. Can you give us a little bit more color on kind of what you saw on that? And if you can elaborate on what you think there the potential is for multi-zone development across broader areas of the Niobrara-Wattenberg?

Charles D. Davidson

Yes. I mean, and we've been talking, Leo, for a while here or I guess this year on how where a large part of the focus is testing these different multi-layer horizons. And what we're seeing so far is that they look every bit as good as the Niobrara B, especially when you adjust for the various thickness of those intervals in these particular areas. Like one of the comments I had in the notes here today was particularly on the Codell horizontal wells where they're looking as good as our Niobrara wells. And we're actually going to now start to test that on a little longer extended reach basis on some of that. So I think what you'll see us evolving into is we're continuing to test some of these other zones, we'll start to mix in some of these longer laterals in with some of these zones on some of this. So I'd say all of that's been very encouraging. I think we're still optimistic at the end of the day. When you settle on a complete pattern out here, you'll have a mix of different zones in some of these areas. And that's why we're continuing to say, on a base horizontal B program up here in Northern Wattenberg and in the oil window, the base program that we've been focusing around is that kind of 16 wells per section for the B. It's not going to surprise us if we don't have more wells per section where you've got a combination of the B and some mix of these other zones, depending on their thickness in different parts of the field.

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

That's helpful. And I guess you also talked about the LaSalle facility. Is that going to potentially debottleneck any production for you guys? Do you think we would see production increase maybe more significantly in the fourth quarter as that's up and running there in the Niobrara?

Charles D. Davidson

Yes. I mean, that's a good point. It'll be a big help up there as a lot of our focus has been here in the Northern Wattenberg piece. LaSalle will help to pick up a large part of that volume up there, it's what I think a little bit southwest of the Wells Ranch area, if I remember correctly, where it's located. So it actually will come into play in an area where we've had probably our largest activity here recently. So it'll be interesting to see how that ramps up. And as I've said, it's kind of in 2 phases that, that's coming on here in late third quarter and into the fourth quarter. So the real impact of that'll be seen in the fourth quarter.

David L. Stover

Just as a reminder, that plan is part of a multi-plan expansion that's ongoing there. And we expect further expansions in 2014 as well. So this is all about staying ahead of the production and managing the overall program to a very broad area. So there's been a lot of projects underway, not only that, but some compression and some other work to accommodate the gas production. So we're very encouraged by the additional facilities that are going in. And they're going to be needed because we're growing our production very rapidly.

Kenneth M. Fisher

And as I mentioned, we're putting some of our own facilities up there into Northern Colorado for that area.

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

Okay, that's helpful. And I guess just in terms of Israel real quick here. I guess I'd heard some chatter on potentially some incremental taxes levied on export gas. Wanted to get you all thoughts on that. I guess is there any potential still to develop Cyprus jointly with Leviathan? Any read on the new export policy, whether it allows for that?

Charles D. Davidson

Yes. I think on the -- I think you characterized it correctly is the chatter on taxes is our sense is that was really more of a reiteration of what's already included in the existing Shishinksy. And so we're not anticipating from our perspective and from our plans anything incremental on that side. On the thinking on the Cyprus LNG and the possibility of developing that with Leviathan, right now the export policy that's been issued basically provides that LNG would be in Israeli territorial waters, but there are some possible provisions where you could go back to the government and seek to do something differently. We're not at that point yet. We're right now moving, as we noted, moving forward with the appraisal at Cyprus. That will give us a good handle on that. We've already entered into a memorandum of understanding that is the basis of an LNG project, the one-train project at Cyprus. So we're continuing to look at all the options on Leviathan. But as just a reminder, we see some of the regional and domestic gas sales options for Leviathan. They're most likely going to be some of the early projects that we move forward because we've got increased demand in Israel and other regional demands that is -- been growing. So it's our thinking right now is that Leviathan is going to be a combination of an LNG export, as well as domestic sales. And we're continuing to move those plans forward.

Operator

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

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

Real quickly in the Niobrara, you mentioned in your remarks and in your release that you've drilled about 131 wells year-to-date. Target's still 300 completions. You've done about 113. I know you're at 11 rigs now and dropping down to 10. Can you just walk through, is it efficiencies in drilling that are going to be driving your ability to execute to that 300 wells? And any kind of color on how that 300 wells drilled ties into wells that are completed as well?

Kenneth M. Fisher

Yes. David, I'll give you a little bit of color on that. If you remember that the first part of the year, we had some late winter storms, which affected some of our completion timing and activity. And that's why I mentioned the amount of activity here in June. We had over 30 wells I think that we actually completed. So we're going to see a much higher level of completion activity here through the second half of the year catching up with some of the drilling. At the same time, on the drilling side, we've added what, 2 rigs I think since we last talked. And one of those, which will stay for a short period of time and then go to Nevada. So when I look at it and I look at the monthly schedule, we're right on track for that full year delivery with much more heavy second half of the year weight, especially on the completions, which were affected by that timing, in the late first quarter, early second quarter. So the key thing there is look at what happened here in June and what we'll be doing going forward.

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

Great, appreciate that clarification. And then just one more with respect to Israel and the export decisions right now. If I'm not mistaken, the decision that they placed was relative to export from offshore facilities. When you think about that and you're bringing gas in domestically into Israel, does that apply to exports out of country through Israel?

Charles D. Davidson

I think that we're still doing some more work on that because they are working on some accommodations for regional exports as part of that. So I think I'm probably going to wait until I see the final, final before we make a decision on that. But clearly, there are some opportunities, as you know, in adjacent countries. I think initially as they were working through a preliminary export policy, they had considered -- considered -- exempting those from the export. But they were concerned that the volume could grow very large. And so the policy as it is now involves those, but there are some procedures that you might be able to go through to get certain allowances for it. So it's -- I know that is a really complicated answer, but it's -- the simple way is I'm not sure right now.

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

Okay, I appreciate the clarifications, and I completely understand that that's something that's going to be in flux for a while as you're working through the government.

Charles D. Davidson

But I think, just as a follow-up, you have pointed out one thing that's very important. And that is the regional markets have grown and the potential for regional markets are growing very quickly. And it's changing our own thinking and our plans. And it's changing Israel's thinking as well. So it's an opportunity that is much larger than what we thought even just 6 months ago.

Operator

And we'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Dave, I wonder if I could back to your -- some of the comments you made in your remarks regarding stepping out into, I think you mentioned the Cummins area. I'm just kind of curious as to how you would characterize the running room you think you have beyond what you've already disclosed to us? Because you referenced East Pony and I'm wondering if we should be thinking that you believe that some of these former vertical areas could have the same kind of characteristics as greater Wattenberg or more like the East Pony. Again, I'm just trying to get an idea as to what you're trying to signal to us there in terms of potential. And I've got a follow-up, please.

David L. Stover

It's a good question, Doug, because that is one of the things I'd say I've come out of this quarter probably most excited and interested in is the additional potential that we continue to uncover up there. And we're seeing that as -- you pick that Cummins area, for example. Vertical wells didn't look very good in that area. The original couple standard lengths, horizontals that we tried were, I'd say, marginal there. And we went in and drilled a couple of long laterals, 9,000-foot laterals in there. And they looked very good in that area, especially when you look at the economics of that and the F&B improvement that you potentially can see in that area. And then you couple that with some of the appraisal testing that we're doing up in Northern Colorado outside of East Pony. And so far, we've had the chance to get some semblance of testing on maybe another 20,000 to 25,000 acres that -- I would put that in that category of more encouraging also at this point. So there's still areas to go up here, and I think we have probably in total this year we'll drill 15 to 20 of what I'd called these appraisal wells up here in Northern Colorado and areas that we really haven't defined or really included yet. So there's a lot more to come on this, and we're still very encouraged and why we keep going back to. We're still early in this game of unlocking all the resource value up here.

Charles D. Davidson

Let me just follow on that, just one thing. Even in East Pony, some of the early work in that area was perhaps initially discouraging. And then we went in and really started working it and really applying the learnings we had. And it's turning out to be an outstanding area. So it's not only testing new areas, but it's also bringing our latest techniques on completion work in these areas. And we're just, as Dave said, it's been a nice positive surprise that these are opening up some opportunities that we didn't, perhaps 6 or 12 months ago, didn't think that were going to be that prospective. I'm sorry, you had a follow-up. Go ahead.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Yes. Sorry, Chuck. Yes, it's kind of a related follow-up and maybe a little cheeky actually ahead of your Analyst Day in December because what we are seeing anyway, and I think what your results are showing, is that the type curves you've given us both for these longer laterals and for your kind of base greater Wattenberg, I could be forgiven, I guess, for thinking that well results you've had to-date are going to ultimately push those numbers higher. Can you give us some indication as to whether directionally that's how you're seeing things right now, and ultimately what that could mean for your stated resource potential? I think there's a couple of billion barrels up there currently?

Charles D. Davidson

Well, Doug, you're right on the first part of that. We probably won't really get into updating numbers until the December piece. But I'll you some direction or indication on some things. I mentioned that we're still seeing a lot of encouragement on these longer laterals. And we've got a number of them now that are getting closer to that million-barrel type curve. We've probably got twice as many now that are approaching that million-barrel type curve as we showed last time, probably up to 6 or so. But the whole issue with that is we don't want to get too far ahead of ourselves. A lot of this is still early data. But everything we're doing up here is still very encouraging.

David L. Stover

I'll put it this way since they never will share numbers with me because I write them down. But when I look at those curves, my expectation is the numbers are going to go up.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to ask a follow-up on the first of Doug's questions with regards to the connection between the Cummins' successes and potentially expanding the footprint in Northern Colorado. Are you seeing similar geology outside of East Pony? And is this something where we can just look at the north, the northwest and the western portion of Northern Colorado and draw this connection or I guess thinking a broad point of, hey, there are areas in where horizontals initially don't work or where verticals don't work, and we can make these extended laterals work?

Charles D. Davidson

Yes. The first part of that, Brian, it's not blanket. There is variations, there is changes on some geology, porosity, resistivity, some of this thickness of these various intervals as you're going through some of this. So we kind of have to break it down in what we call kind of pod-by-pod or piece-by-piece on this. And kind of where we've started is kind of west of East Pony. And in that area, and we'll kind of start there and work our way north from that. So the first part of this is that first 20,000, 25,000 acres I've talked about that we'd kind of concentrate on first is kind of just slightly west and northwest of East Pony. And then we still have to go from there.

Brian Singer - Goldman Sachs Group Inc., Research Division

And is this something where you'd have decent additional color on by say year end or perhaps December 17?

Charles D. Davidson

Well, we'll have some more color on that. And it's -- I think there's still -- portions of that will be in very early stages of testing. And portions of that will have some more established production history by that time. So we'll be able to get some update on what we're learning as we go. Just depends how far along we are on some of these bringing new wells on.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And lastly, in Equatorial Guinea with Alen coming on earlier, and then I think you referenced in the press release, Aseng has come off plateau, can you just refresh us on what we should expect, e.g. net oil production, to do next year versus this year when we layer in the growth from the growth from Alen, and then it would appear some declines at Aseng?

Charles D. Davidson

Well, yes. I haven't even looked at next year's yet. I'd have to go back and look at that. But when you think about Aseng, we've talked about it's kind of come off its plateau. And you have to remember we actually brought it on and actually increased its early volume higher than we originally anticipated. And then it kind of had a step function down somewhat as the first well as expected when it started to see water. And then I'd say going forward on Aseng, you can probably look at kind of 10% to 20% per year type of decline, which is what I would expect just in general. Alen, we bring that on, hopefully get that out. Well, we plan to get that ramped up to full volume by the end of the quarter. So starting in the fourth quarter, you're in that I don't remember what it was -- high teens, 1,000 barrels a day type net. And then it should hold fairly constant for kind of like Aseng for close to a year at least.

Operator

And we'll take our next question from Arun Jayaram with Credit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Chuck, Dave, I just wanted to talk a little bit. Obviously, lots of headlines on the export decision. What I'm trying to understand is as you guys interpret the export rules today, trying to understand how many trains of LNG do you think you have support for today? I think you found, call it 37 Tcf of gross gas. As you interpret the rules for large field, small field is -- how many trains of gas do you think you have today to support?

Charles D. Davidson

I think the answer to that is 2 to 3 that -- but the key on that is that -- and it came up in an earlier question, is we have this regional export that is really growing in demand. So as a result, that might move some gas from an LNG export to a regional export. So that's the variable in this. But keep in mind, and I mentioned that this is on a field-by-field basis, and so for Leviathan, it's higher than that 40%. So we've still got a lot of resource at Leviathan that can source a multi-train type of facility.

Arun Jayaram - Crédit Suisse AG, Research Division

And Chuck, just to elaborate a little bit. I know Jordan has been a place which has been short gas. If the stars were aligned, could you export gas to Jordan for say, sooner than 2018, 2019? Or would the timing be similar?

Charles D. Davidson

No. It would be sooner because you've got the ability to not only develop but also produce. And pipeline access is a lot easier depending on which route you go. And there's a couple of different ways you can go. But keep in mind, there's a pipeline in Israel that already goes to the Dead Sea area. So there's some possibilities that we can easily, we would expect to easily be able to export to Jordan much sooner than that. And like everything else, it's early on. It might be smaller volumes. We've got a lot of our capacity committed right now, but we're working to expand the Tamar capacity. And we'll be working on Leviathan, which is expected to have a domestic component, and could also help bolster these regional exports as well.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And then my follow-up question is just on Gunflint. I guess you had previously, Chuck, talked about maybe a 90 million-barrel type of discovery there. Based on the most recent well, I'm just wondering if you could maybe comment on that resource range? And maybe some thoughts, I believe it will be a tieback on the initial production and timing of that -- as soon as 2015.

Charles D. Davidson

Yes. When -- and we updated, I think, the resource size after our appraisal. Keep in mind, the deep opportunity there was not present. So we're looking now at something that's around 65 million to 90 million-barrel. So it's in that range, and yes, it's going to be a nice tieback. We're working on the host options currently on it.

Kenneth M. Fisher

Yes. When it starts up, you should probably -- it should probably start up with 2 of those prolific Miocene producers kind of towards that late 2015, early 2016 timeframe. And that would be coupled with at the same time a nice Big Bend well. And if we were fortunate to have a discovery at Troubadour, you could have 3 to 4 wells coming on around the same time out of these Miocene producers.

Operator

And we'll take our next question from John Malone with Mizuho Securities.

John T. Malone - Mizuho Securities USA Inc., Research Division

Just on Israel, is there anything that we can anticipate coming out of the legacy fields, Mari-B, Noa and Pinnacles, or is it pretty much all just a mar [ph] from this point? I mean, it reads like that was 94% of the gross production in Israel this year anyway. Is there anything left in those fields that we can see over the next 12, 18 months?

Charles D. Davidson

Well, I think you can see a little bit yet this year, and it'll pretty much deplete most of that off. I think between them, you're maybe making about 150 million a day between Pinnacles, Noa and Mari. We actually had a little work-over on Pinnacles here in the second quarter that enabled us to continue to produce that some this year. But I think by the end of the year, most of that will all be depleted.

John T. Malone - Mizuho Securities USA Inc., Research Division

Okay. And then just to ensure I heard you correctly. Nicaragua, you do have a farm-down agreed? You're just waiting for government approval?

David L. Stover

Yes. We've got a farm-down with one company, and we're still talking with several others who are interested. And yes, this is -- they're subject to government approval, but we expect to obtain those approvals. And we're set to begin drilling that well this quarter.

Charles D. Davidson

Yes, towards the end of August, early September.

John T. Malone - Mizuho Securities USA Inc., Research Division

Do you anticipate getting a carry on that? Or would it just be a straight up split in the cost of risk?

Kenneth M. Fisher

No. Because of the terms and their clause in there, I don't want to discuss the specifics. But yes, there is a promote involved and a recovery of some costs as you would expect on a prospect of that size.

Operator

And we'll take our next question from Bob Brackett with Bernstein.

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

Yes, following up on Nicaragua, can you talk about gas versus oil risking? And what would the economic threshold be if this is a gas discovery? And then I've got a follow-up.

Charles D. Davidson

Well, I think our expectations is that this is an oil prospect. And it's a large structure, and everything we know about the depth and the temperatures that we would expect it to be in the oil window. If it's gas, that's -- we would just have to look to see what the size of it is. But clearly, we have gone into this with the thinking that this is an oil opportunity.

David L. Stover

Yes, with multiple oil, large oil prospects down here is the way we're looking at it.

Charles D. Davidson

Right.

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

So when you quote that 1 in 4 geologic chance of success, that's for an oil discovery or a hydrocarbon discovery?

Charles D. Davidson

Yes. That's -- yes, because basically our model is based on it being oil. So it's tied to being the geologic chance of that -- of discovering that. You can always be surprised, but a lot of things would have to happen for that to turn into gas. And quite honestly, I think we would expect to see probably some different seismic responses if that was a gas prospect rather than oil.

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

And I can't remember if you've disclosed, are you chasing the cretaceous age source or is it a tertiary age?

David L. Stover

I'm not -- it's cretaceous, I think. And I'm not sure what else we have said on that, but...

Charles D. Davidson

Yes, the best -- the most we've said about was probably when we had our call last October where we talked specifically about all the big Exploration plays.

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

And I guess the final, if you hit -- it's a carbonate -- if you hit poor reservoir quality but you see evidence of hydrocarbons, would you sidetrack that well right away?

Charles D. Davidson

It all depends on what we saw. I'm not sure if you saw poor reservoir quality that you would just sit there and sidetrack it at that location. You'd probably want to step back and come up with a process as to why you believe the quality might improve and then decide in what direction you would go. But I'd -- to me, the best opportunity for a sidetrack would be is if you saw something that was perhaps quite positive and you wanted to see -- try to check on it, yes.

Operator

And we'll take our next question from Irene Haas with Wunderlich Securities.

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

I would like to ask a question on offshore Israel. When you mentioned earlier, the Karish discovery, you found biogenic gas, and yet you have condensate of thermogenic source. So I just want to have a little color. How does it fit with your migration model? And it certainly would be a positive indication that you could have another system working in the basin.

Charles D. Davidson

Yes. I think your conclusion is right along ours. And that is as you've -- it's just more evidence that there's a second source in this basin, a thermogenic source. We talked about, as we were drilling deeper in the Leviathan, we did not reach their primary objective there, but we saw signs of thermogenic. We have seen it in some of the condensate samples, I believe, in Leviathan. But Karish is probably the biggest example so far because the condensate yield is so much higher than anywhere else. And yes, and it's because it's through the analysis that shows it came from a thermogenic source. We've got a different source that migrated into that trap. And our job is to chase that down and find out if it's productive at its origin.

Operator

And we'll take our next question from John Herrlin with Société Générale.

John P. Herrlin - Societe Generale Cross Asset Research

Pretty much everything has been asked, but some quick ones. With Nevada, once you move the rig in, are you just going to drill a bunch in core or drill and frac? When will you start releasing information about results?

Charles D. Davidson

Yes. John, what -- the plan is we're going to drill 2 vertical wells first and understand the reservoir a little better, and based on that decide how we want to actually test this play. Now if you remember, we're expecting a pretty thick section. It could be anywhere from 1,000 to 2,000 feet. So the real question's going to be what's the distribution of hydrocarbons? Are there hydrocarbons, where at? What kind of reservoir quality are we seeing? And then come back and design, do we want to test this with a horizontal program? Do we want to offset 1 or 2 of these vertical wells into a horizontal program? Do we want to contact a thick part of the section and slant forward? Do we want to do a vertical program and frac it somehow or not even frac it, aspedize [ph] it? That's what we need to see depending on the reservoir quality, how we want to set up our completion. But we -- first step is to get some real, real true reservoir information of a couple of wells, vertical wells in the area. So I would say information will come out slowly on this one as we set up a plan for this.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. One other one. With respect to what the discussion in Northern DJ with horizontal is working versus -- extended horizontals working versus regular horizontals or verticals, in the case of the formations, is this an issue in terms of the heterogeneity being more diogenic, depositional or is it kind of both? Is it just going to be heterogeneous because of all of the above?

Charles D. Davidson

Well, you would -- because it -- I'll give you some suspicions, and that is with extended laterals working so much better than the normal laterals that you're somehow through the extension, maybe you're connecting up with some better quality at some point in it. But there's more work to be done on that. We do know there's variability up in these areas. And so we're trying to understand that variability. And maybe it's just helping us to, ultimately, to find the sweeter spots to go after.

Unknown Executive

And probably minimizing any natural completion damage, if you will, by minimizing drawdown down these wells with the longer lateral. That seems to still be a prevailing theory on what's really helping on these.

Operator

Yes. We'll take our last question from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

I'll be brief. What's your estimate of the decline rate on the legacy vertical production from the Niobrara?

David L. Stover

Yes. I think you're now far enough away from the drilling on that, you're getting more into the established lower level of decline, maybe 15% or so, plus or minus. Again, those are the wells that get impacted first on anything that changes in the field dynamics. So I think as we bring some of these new facilities on and you get into next year, you'll get a more established decline on some of those. But that's what I'd kind of expect, maybe that 10% to 20% range.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And then as a follow-up, what do you estimate to be the economic limit or the economic breakeven price for your dry gas, Marcellus operation today?

David L. Stover

Dry -- I mean, it probably continues to move a little bit because we're still seeing opportunities for increasing efficiency out there on an -- even on the production piece on just the performance, production performance. And you see that as you look at some of the overall Marcellus performance. You're down probably in the area -- and I'll temper it somewhat by what net revenue interest you're working with because a lot of what we've been drilling in the Marcellus dry, we have a very high net revenue interest that came with the CONSOL piece. So with that, you're probably down in the 2s.

Charles D. Davidson

So I want to, again, thank everyone for participating in the call today and your interest that you've had and will have in Noble Energy. And I'd like to suggest you all have a great day.

Operator

And that concludes today's conference call. We appreciate your participation.

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