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Noble Energy (NYSE:NBL)

Q2 2011 Earnings Call

July 28, 2011 10:00 am ET

Executives

David Larson - Vice President of Investor Relations

David Stover - President and Chief Operating Officer

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

Analysts

Brian Singer - Goldman Sachs Group Inc.

Dan McSpirit - BMO Capital Markets U.S.

Joseph Magner - Macquarie Research

Bob Brackett - Sanford C. Bernstein & Co., Inc.

Leo Mariani - RBC Capital Markets, LLC

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

John Herrlin - Societe Generale Cross Asset Research

Peter Kissel - Howard Weil Incorporated

Douglas Leggate - BofA Merrill Lynch

David Kistler - Simmons & Company

Irene Haas - Wunderlich Securities Inc.

David Wheeler - AllianceBernstein

Operator

Good morning, and welcome to Noble Energy's Second Quarter 2011 Earnings Call. I would now like to turn the call over to David Larson. Please go ahead, sir.

David Larson

Thanks, Jenny. Good morning, everyone. Welcome to Noble Energy's Second Quarter 2011 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 have issued our earnings release for the second quarter, and hopefully, you all have had a chance to review the results. Later today, we expect to be filing our 10-Q with the SEC, and it will be available on our website at that time.

The agenda for today's call will begin with Chuck, discussing the quarter and an overview of our major projects. Dave will then give a more detailed overview over our operations, along with a review of our activity levels to the second half of the year. We'll leave plenty of time for Q&A at the end, and plan to wrap up the call in less than an hour. We would ask that the participants limit themselves to one primary question and one follow-up. Should you have any questions that we don't get a chance to get to this morning, please call and we'll do our best to answer you.

I want to remind everyone that this webcast and 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 future periods to differ materially from what we discuss.

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. We'll reference certain non-GAAP financial measures such as adjusted net income or discretionary cash flow on the call today. When we refer to these items, it's because we believe they are good metrics to use in evaluating our performance. Be sure to see the reconciliations in our earnings release tables.

One other item before handing it over to Chuck, is hopefully you all received notice that we are planning an analyst meeting later this year, on November 15, in Houston. Please make sure to put that on your calendar. We look forward to providing a significant update on our global portfolio, highlighting significant growth and an opportunity set that we believe is unique in the industry. With that, let me turn the call over to Chuck.

Charles Davidson

Thanks, David, and good morning, everyone. Noble Energy's second quarter wrapped up a very positive first half of 2011. As we look forward to the rest of the year, we're accelerating a number of our development projects and we've also made important additions on the exploration side. I want to begin this morning with just some brief comments on our quarterly results, which were supported by better-than-expected volumes and robust oil prices, both of which led to another quarter of strong earnings and cash flow.

I'll follow with the review of our updated guidance and comment briefly on our plans for the remainder of the year.

Adjusted net income for the second quarter was $263 million or $1.44 per share, that's up 35% from the second quarter of last year. Excluded from adjusted net income were a couple of items, including a gain on asset divestiture related to our exit from Ecuador, as well as a couple of asset impairments onshore in the U.S. Field performance at Oliver Creek field in East Texas and Iron Horse in Wyoming, combined with the low natural gas price environment led to the impairment. And finally, we have the unrealized portion of the mark-to-market on our hedges as well. All-in GAAP net income for the second quarter this year was $294 million or $1.61 per share, diluted. Revenues were nearly $1 billion with approximately 75% coming from liquids, pricing for both West Texas Intermediate, as well as Brent light [ph] crude drove our liquid revenues to its highest quarterly amounts since mid-2008. Global liquids pricing also supported our equity method income and we've now raised our full year equity earnings outlook for the NGL and methanol plant and Equatorial Guinea by $40 million.

Total sales volumes for the first quarter averaged 215,000 barrels of oil equivalent per day, outperforming the midpoint of our second quarter guidance as a result of both high demand in Israel, as well as a strong contribution from the DJ basin. Our domestic volumes made up 53% of total volumes or 115,000 barrels of oil equivalent per day. The DJ basin with high vertical and horizontal drilling activity continues to deliver growth. It was up 8% from the second quarter of last year and up 5% from the first quarter this year. Production growth in the basin is coming primarily on the liquid side as we continue to accelerate development in a lower GOR regions of the Wattenberg field and the Basin. Total U.S. oil volumes were down versus second quarter last year, and that primarily is a result of the 6,000 barrel-a-day sale of onshore mature assets last year.

On the natural gas side, volumes are down primarily from natural decline in the Rockies and the Mid-Con areas, as well as in the Deepwater Gulf of Mexico. Internationally, sales totaled 100,000 barrels of oil equivalent per day, which was up slightly from the second quarter last year. Strong growth in Israel offset lower volumes in Equatorial Guinea as a result of timing of liquid liftings there, as well as some downtime from the NGL and methanol facilities in Equatorial Guinea. The 2010 period also included 27 million cubic feet per day from the Ecuador assets, and of course we're -- we announced earlier, were pleased to have concluded the sale of that business during the second quarter of this year. We're now completely out of Ecuador.

We had stellar quarter in Israel with very high gas volumes. Power generation demand for gas was very strong, and competing imports from Egypt have been substantially reduced. The combination resulted in high demand for our own gas from the Mari-B field in Israel.

In the earnings release this morning, we noted that we've increased our sales volume outlook for the year to range from 215,000 to 218,000 barrels equivalent per day, which is at the top end of our original guidance. Performance to date has been strong, and we expect to continue selling high volumes in Israel. And in addition, we're optimistic about volume growth throughout the remainder of the year in the DJ Basin. Most of our cost items for the second quarter were within expectations and most of our year-to-date amounts look good versus full year guidance. We have updated our exploration expense expectations for the year to range from $380 million to $440 million, reflecting the acceleration of the Cyprus well and the addition of the Senegal and Guinea-Bissau opportunity. Our adjusted effective tax rate for the second quarter was lower than anticipated at 33% with 52% deferred. The deferred amount was higher than our expectations was impacted by the settlement of prior year tax reviews. We're expecting a 50% effective tax rate in the third quarter as the catch-up for new U.K. tax rules goes into effect. It should come back down to normal level in the fourth quarter and still be within our full year guidance for the year. We were just about cash flow neutral for the second quarter with nearly $660 million in discretionary cash flow versus $700 million of capital expenditures. Year-to-date cash flow is flat with our CapEx amount. Our cash balance grew to over $1.5 billion at the end of June, and our total debt was unchanged to $2.8 billion. Liquidity now is over $3.6 billion, and our debt net of cash is only 15%. We bumped up our capital program for the year, with about half of the $300 million in incremental capital for new opportunities, including 2 high-impact international exploration opportunities, as well as the new development projects in Israel. We executed an agreement during the second quarter to obtain a 30% interest in the AGC block that includes about 2.4 million acres offshore Senegal and Guinea-Bissau. The first prospect Kora was testing a very large oil prospect. Results on the well were disappointing but we have a number of additional prospects on the acreage, and we'll be working with our partners on further evaluation and future plans there.

The other exploration addition to our capital program this year is offshore Cyprus, where we plan to start a large prospect in the fourth quarter that is targeting the same natural gas interval already discovered at Tamar and Leviathan in Israel. We recently secured a third deepwater rig for the Eastern Mediterranean, which has allowed us to move up the drilling timing for the Cyprus well.

On the development side, we've added the Noa development project offshore Israel. Israel is a -- excuse me, Noa is a near-term solution to a tight natural gas market in Israel. Drilling should begin shortly with plant tie-in to the existing infrastructure at Mari-B. The remainder of the capitol increase is focused on acceleration of our major projects. We've grown our well count, and the horizontal Niobrara play is 20% for the year due to continued drilling efficiencies and expanding rig counts. Our terms are -- excuse me, our teams are currently running 4 horizontal rigs in the DJ Basin, and we'll be growing that to 5 within the next month. We're also intently focused on progressing our liquids development at Aseng and Alen and we're certainly excited to say that Aseng continues to progress ahead of schedule and is now expected to start up by the end of this year.

I want to finish with some comments on our planned activities for the remainder of the year. Onshore in the U.S. it's all about accelerating the horizontal Niobrara program. We continue to have very strong results within Wattenberg. With our latest set of wells outperforming prior well averages. Team continues to do a great job in improving completion designs and Dave will mention the well results in just a bit. At the same time, we continue to work the portion of the play to the north outside of Wattenberg, where we're continuing our 3D programs. Overall, including those Wattenberg and the northern parts of the play, we now expect to drill a total of 85 horizontal wells this year, a 20% increase over our original plan.

In the Deepwater Gulf of Mexico, we had excellent results in Santiago and have now been able to integrate that success into our Galapagos plans very nicely, with first production expected early next year. Another positive step for us in the Deepwater Gulf is that we've now received the drilling permit for Deep Blue. Operations in Deep Blue are expected to commence in the next week or so and we should have well results there in about 2 months. As a reminder, we were performing a sidetrack operation at the time of the moratorium last year. Deep Blue has a 50% chance of success. We're targeting up to 200 million barrels equivalent on a gross basis. Our interest in Deep Blue is 34%. Following Deep Blue, we plan to drill the first Gunflint appraisal well and are continuing to work the process to obtain the related permit for that well. For exploration prospects that we plan to drill next year, we've already submitted one exploration plan and have 2 more expected to be in the bureau by the end of the third quarter.

In West Africa, I already mentioned how pleased we are with the progression of the Aseng and Alen. On the exploration front, we're excited to relaunch our operated activity in West Africa during the second half of this year with plans for 1 or 2 wells, likely offshore Cameroon. The first of our identified oil prospects is named Wobby on the Tilapia block offshore Cameroon. The well should spud in early October and we would expect our results in late November. Wobby [ph] is a 100 million barrel plus legacy prospect who's targeting deeper potential in the Douala Basin, with the chance factor of around 25%. We operate Wobby [ph] with a 50% working interest. Following that, we will likely move the Atwood Aurora jackup rig to the Alen development work.

Offshore Israel, we have 3 rigs operating. One on Tamar development, making great progress on the 5 development wells there. A second rig is drilling the Leviathan 3 appraisal well. And then we've brought in the third rig for the Noa development, which will also support our exploration plan in the region including our prospect in Cyprus. So it's a very active and meaningful exploration program in the second half of the year, combined with the ongoing development of major projects, things are moving forward a very fast pace for Noble Energy. Our first major project, Aseng is less than 6 months away from coming online. And then Galapagos will follow shortly afterwards. And finally, with the progress that the company is making on all of our programs, combined with a very positive outlook as you would've noted in the last couple of days, our Board of Directors decided to raise our quarterly dividend payout this quarter by about 22%, from $0.18 a share to $0.22 per share. The management team here at Noble is looking forward to the meeting that David mentioned with the investor community that's planned for later this year. We intend to provide a very detailed review on all areas of our business at that time. So with that, Dave, I'll turn it over to you.

David Stover

Thanks, Chuck. As we highlighted the second half of the year, we'll see increasing levels of activity in all of our core programs. Today, I will provide an update on our major projects before wrapping up with expectations for the remainder of the year. Let's start with our international projects.

In West Africa, we're extremely pleased with the status at Aseng, which continues to progress ahead of schedule. With first production expected by the end of the year, this is a real accomplishment for not only Noble Energy, but all of our partners, the FPSO teams and Equatorial Guinea. This will certainly give us a nice start to 2012 with over 17,000 barrels per day of new oil production. The Aseng FPSO is expected to sail in September, arriving at the field early in the fourth quarter to begin hookup and commissioning. All 10 wells have been drilled and completed and the subsea installations are ongoing. At the same time, we're ramping up activity on our second operated Equatorial Guinea liquid project at Alen. Construction of the production platform has begun and the wellhead jacket is substantially complete. The Atwood Hunter drilling rig should be back in the third quarter when it will begin drilling 1 and completing 3 gas injection wells at Alen. Development plans will be supplemented with the second rig, the Atwood Aurora jackup, which will drill and complete the 3 production wells beginning in the fourth quarter. First production at Alen is still planned for late 2013. However, our teams are intently focused on project acceleration here as well. These are 2 very important operated major projects for Noble Energy. Combined Aseng and Alen will contribute over 35,000 barrels per day net, significant contribution to the near-term volume and cash flow growth outlook.

Our next, Equatorial Guinea liquid project is likely to be Carmen-Diega, where appraisal activity was conducted this last quarter. We first drilled the vertical well then 2 sidetracks encountering a mix of oil and gas. While our teams continue to evaluate the results and review multiple geologic models, it looks like Carmen-Diega is a good candidate as a tieback to the existing infrastructure. Final development plans will likely require another appraisal well next year. We continue to make progress on gas monetization in West Africa. Our team is working closely with both the Equatorial Guinea and Cameroon government, we are currently the chair for the group involved in the Equatorial Guinea effort.

Moving to the Eastern Mediterranean. Chuck has already mentioned the excellent quarter for our operation offshore Israel. Our teams did a great job completing the near-term deliverability project to Mari-B, finalizing the compression installation during the second quarter.

As the demand picture in Israel continues to grow and with reduced imports of natural gas from Egypt, we've been working with our partners and the Ministry of National Infrastructure on available options to continue meeting near-term demand until Tamar comes online. In response, we're moving forward with the Noa development, a 1999 discovery with 30 to 40 billion cubic feet gross to develop. The Noa project allows us to continue producing Mari-B at high rates, bringing another source of gas through our existing facilities before Tamar is ready. First production at Noa should be in the second half of 2012. Potentially supplementing Mari-B deliverability by up to 100 million cubic feet a day gross from 2 wells. The rig is already on location and should begin the first Noa well in the next couple of weeks. We expect to move this rig over to begin drilling our Cyprus exploration test by early fourth quarter. The Cyprus prospect is our largest undrilled prospect in the Eastern Mediterranean area. Tamar continues to move forward on schedule and on budget.

In June, we completed batch drilling of the top hole sections for the 4 new development wells and are proceeding with drilling out the wells to total depth. All of the subsea trees have now arrived in country and the platform fabrication is underway. The majority of our line pipe has arrived and installation is scheduled to begin in October. Project commissioning is still scheduled for late next year, with first sales in early 2013.

At Leviathan, we spud the #3 appraisal well in late June and expect to TD a well late third quarter. The plan is to then move the rig back to the Leviathan #1 deep test, to resume operations that were suspended earlier in the year, as we waited additional equipment. Timing for results at Leviathan Deep is at year end. Nothing has been tested this deep and the basin before, so we look forward to the results and knowledge we will gain from drilling this section.

During the third quarter, will be soliciting proposals from several LNG contractors to develop LNG plant prepaid studies for multiple sites that are under consideration. This is part of our ongoing effort to progress monetization solutions for our significant Eastern Mediterranean gas resources.

In the Deepwater Gulf of Mexico, we recently finished completion operations at Santiago, so all 3 wells at Galapagos are now ready for first production. The majority of the subsea flow line has been installed and good progress is being made on the top side at Na Kika. Our expectation is for over 10,000 barrels of oil a day net when Galapagos comes online early next year. In anticipation of further work at Deep Blue and Gunflint appraisal this year, we picked up an additional 180 days of time on the Ensco 8501 rig from our rig-sharing partner. This puts us in great position with regards to our drilling plans for the remainder of 2011, as well as into 2012 when we are targeting returning to new exploration in the Deepwater Gulf.

After Deep Blue, we will have around 35 days of rig upgrade before spudding a Gunflint appraisal well in late October, early November. The exploration plan for Gunflint has been submitted, and we anticipate sending in the application for Permit to Drill in the next couple of weeks. It's approximately a 100-day well and we may perform a sidetrack depending on well results.

We recently completed the unitization agreement for Gunflint, whereby all of the partners came to consensus on interest and operator shift. Portions of 2 additional blocks were added to the now 5 block area and we will have a 26% working interest in this project. The approval of Noble Energy as operator was a big vote of confidence in our operating capabilities. Getting this agreement finalized is a very positive step for us and the partners, ultimately saving time and money for the appraisal program and full field development.

Finishing the operations review with the onshore U.S. program, our focus is on continuing to accelerate the horizontal Niobrara play in our 400,000-acre Wattenberg position. With an inventory of over 2,000 possible locations and 600 million barrels of oil equivalent of net potential, this is a huge development opportunity for our company. Results today continue to highlight the play as a major development project and our teams are approaching it that way. We're currently operating 8 vertical rigs and 4 horizontal rigs in the DJ Basin, and we expect to add a fifth horizontal rig in the middle of August. We continue to see improvements in our drilling times, and as a result, it looks like our well counts will be up some from our original expectations. Current plans are for around 15 additional horizontal Niobrara wells this year compared to our previous plans. This will increase our overall 2011 horizontal program to approximately 85 wells.

Of our last 12 horizontal Niobrara wells in Wattenberg that have been online 30 days or more, 75% of those are in the low GOR area portions of the field. The 24-hour IPs on those 12 have averaged about 835 barrels of oil equivalent per day. For the 30-day average of over 600 barrels of oil equivalent per day and a high liquid component over 60%. When compared to the previous 12, these rates are up 10% to 15% highlighting the work our team has been doing in the reservoir and production optimization areas. We anticipate a fast acceleration in our number of well completions per month in the second half of the year. In the second quarter, we were completing 4 to 5 horizontal wells per month, and we are expecting 8 to 10 per month during the remainder of the year.

Our current horizontal Niobrara production is about 10,000 barrels of oil equivalent per day gross or 8,000 barrels of oil equivalent per day net, up approximately 5,500 barrels of oil equivalent per day gross from the beginning of the second quarter. With the increased pace of completions, we're on track to see continued significant growth from this program for the remainder of the year. We recently drilled and completed the longest lateral ever performed in the DJ basin at over 9,100 feet in the northeastern part of Wattenberg. The well is completed with 40 frac stages, and we'll be watching closely as the well cleans up and starts producing shortly. Building infrastructure in the Wattenberg continues to be enhanced where the third-party gas processing facility expansion recently starting up, adding about 75 million cubic feet a day of capacity. In addition, DCP announced further expansion plans for a new plant operational in 2013, which will add an additional 100 million cubic feet a day. On the oil side, the first White Cliffs expansion is now complete. Increasing that capacity to 50,000 barrels a day with plans to go to 80,000 barrels a day by early 2013.

The seismic program supporting our Northern DJ basin effort continues. And to date, we have brought in 870 square miles of 3D, with an additional 420 square miles planned for this year. Most of this 3D is in our 440,000-acre position north of Wattenberg, and we anticipate drilling some wells there before the end of the year. We recently drilled 2 horizontal wells in our low [ph] area, south of Grover. We should have result from those at the next quarterly call. At the same time, we're looking at additional recovery possibilities and further expansion of our development program in Wattenberg.

Chuck already mentioned our full year volume guidance increased to 215,000 to 218,000 barrels of oil equivalent per day, which was the top end of our original range. For the third quarter, we estimate volumes to be 215,000 to 220,000 barrels of oil equivalent per day. Our onshore U.S. volume should be up driven by the DJ Basin program. Deepwater Gulf will be down from natural decline in plant maintenance, as well as the impact of a Swordfish gas well that watered out in the second quarter. Higher volumes in Equatorial Guinea and strong demand for natural gas in Israel should contribute to increased International volumes despite the impact of some scheduled downtime in our North Sea assets.

In summary, volumes are growing and we are accelerating a number of major project developments, which are set to deliver material impacts to Noble Energy. On the exploration calendar, we will also be testing impact prospects in each of our core areas the second half of the year. So with that, Jenny, at this time, we like to go ahead and open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we will hear first from Dave Kistler with Simmons & Company.

David Kistler - Simmons & Company

Real quickly, focusing on the Wattenberg area. With the CapEx increase that you talked about, can you kind of help break that down for us in terms of what might be attributed to efficiency gains? What might be attributed to cost fleet? And obviously, we know a portion of it is going to go to the new rig that's drilling.

Charles Davidson

Yes, Dave, I think the majority of it is obviously the additional wells. I mean, you think about 15 new wells at around 45 -- $4.5 million per wells, so that's close to, what, $70 million a piece just from that. So that's the majority of it. I mean, there's been some cost on the completion side, but I'd say definitely the vast majority of it is just the additional activity.

David Kistler - Simmons & Company

Okay. And then you mentioned efficiency gains, how much your time to drill decreased?

Charles Davidson

I think if you go back a year, we were looking at 15 to 20 days. It kind of spud the rig release out there, and we're seeing now. We can get down on some of the rigs. We're getting down closer to that 10 days spud to rig relief on some of it. I mean, you still have different areas, different things but as we continue to move more and more to pad drilling, we'll see that continue to improve.

Operator

And our next question comes from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets, LLC

Just a quick question on the well cost you just mentioned there, in Wattenberg and in Niobrara, you talked about $4.5 million. That number seems to be upward from [ph] I think your last update, is that just primarily attributed to much longer laterals? Can give us a little bit of color around there? And additionally at Niobrara, you talked about a little bit better well performance in terms of EURs, can you just quantify that for us?

Charles Davidson

Yes, I think -- Leo, I think we've been pretty consistent on that $4.5 million for a while now. If you go back last year, we may have been in kind of $4 million or so, but obviously we're seeing some completion costs so often this kind of larger percentage of the overall cost now. But I think this year, we've been pretty consistent at that $4.5 million. I think on EURs, we're probably still a little early to change anything on the EUR piece. I think what we did note with as we started to see some of these new wells and continue to tweak the completions, we've seen a nice improvement on the 30-day, 60-day averages, but we want to see that play out a little longer.

Leo Mariani - RBC Capital Markets, LLC

Okay. That makes sense. And then to quick question here on Israel. I think your gas pricing is up prematurely in the second quarter. I guess I saw some numbers out there indicating that you guys might be approaching $6 so far in July. Is that accurate? Are you seeing that type of pricing here in the summer and maybe just give us an update on any gas contracts you guys are working on?

Charles Davidson

Well, I think -- Leo, on Israel, of course, we've got really our base contract with IEC is in 2 components. One is -- which makes up about 60% of volume is pretty much fixed at a low level. And the second piece is indexed off of a suite of liquid prices. And so what happened is as our Brent prices have moved up strongly and related liquid prices has moved up that pricing on that second piece. But now that we've seen where Brent is not moving up aggressively much further. I think that we'll probably see gas prices sort of stay in this range. It's hard to predict obviously oil prices, but keep in mind that 60% of that volume is pretty much fixed at a low level. So it's a -- I mean the key thing in Israel is, of course, is the fact that our volumes have moved up strongly. And that has certainly made a big impact on our Israel business. But I wouldn't expect any severe changes in the gas pricing.

Operator

Our next question comes from Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil Incorporated

Just a follow-on with a couple more out of Israel, with the pipeline disruptions from Egypt right now, clearly, you're looking forward to accelerate production out of Mari-B, some additional compression but my question is, is there any way to accelerate Tamar or is that much more hampered by just equipment deliveries?

Charles Davidson

That's a -- if there was a way that we could move up Tamar any further, we would certainly do it, given the need for natural gas in Israel. But that schedule is fixed by some very unique installation equipment that's the hinge. In some instances, there's only 1 or 2 in the world. And so that schedule is very tightly fixed as is the fabrication pieces. And really, the logistics of putting this all together. So we're doing our best, but we really don't see that schedule changing. The most important thing we're able to do to help the near term in Israel is the development of the Noa, which will add, as Dave talked about, substantial deliverability hopefully next year. So that's how we're trying to work through it, but Tamar is a major project with a lot of things that are locked in.

Peter Kissel - Howard Weil Incorporated

Got you, okay. And secondly, with Nicaragua and France exploration programs, are you able to comment on the recent 3D shoot that you got one of your partners making some comments on a few days ago?

Charles Davidson

We're still interpreting the -- all the data and that's going to have to go through probably several iterations of not only 2D but then later hopefully 3D data. So no, really, I don't really have anything to add.

Operator

And we will hear next from Joe Magner with Macquarie Capital.

Joseph Magner - Macquarie Research

Just question on the acceleration of the Aseng project timeline. Should we expect that the volume ramp will change at all with the acceleration or will the 17,000 or 18,000 barrels a day that were expected early 2012 come online later this year?

David Stover

I think what we're looking at goes to try and get production started by the end of the year, and it'll ramp-up as you bring that on. I think the plan is still to bring that up to 50,000 barrels a day gross which is what correlates to that 17,000 barrels a day or so net, for us. But I think what we'd do is ramp it up at the end of the year and get it to that 50,000 then hold it there for a little while and see how it performs.

Joseph Magner - Macquarie Research

And I guess what period of time do you think that ramp will build over?

David Stover

That will probably take at least a few weeks up to a month.

Joseph Magner - Macquarie Research

And then just one follow-up on Israeli gas prices. There's some reports in the news recently about discussions around Tamar pricing, can you provide an update on where those stand, and what we should expect to hear going forward?

Charles Davidson

Well, we continue to be in discussions with several potential customers for Tamar gas. And obviously the largest is our current customer, Israel Electric. And so those negotiations are continuing. I'm hopeful that we'll finalize the terms of that shortly. It has been a very dynamic process as you can imagine with really the disruption of imports from Egypt. And so it's -- it's changing some of our customers views on how much gas they need in the future and we're trying to work through that, of course, even as the large as Tamar is, it got finite volumes. So we're trying to make sure we meet our customers' needs. But I don't have anything more to add in terms of where the negotiations are. We need to hold those until we finalize things with the customers.

Operator

And our next question comes from Irene Haas with Wunderlich Securities.

Irene Haas - Wunderlich Securities Inc.

A question on Cyprus, the well you're going to drill there, how many days are going to take roughly total depth, cost to drill and complete? And are you still thinking using Cyprus as a hub for export? Is this still a good locale in terms of thinking your next stage of development and export plans?

David Stover

Yes, Irene, the well will take probably 2 to 3 months. I mean, it's similar depth as what we've been drilling over in Israel. So not a whole lot different there. I think as far as the Cyprus is still a potential opportunity for a hub, for exporting. I think that's still a viable option over there. And we just have to see how that plays out. First thing is to get a well drilled over there. And again, like we said, we should be in there by early fourth quarter, which means we'd have some results on that by beginning of next year.

Irene Haas - Wunderlich Securities Inc.

Okay, great. Can I slip with one more question, offshore Cameroon, those project, your prospect to drill this fall is seismic good to look for DHI or not?

Charles Davidson

This is a little bit deeper prospect, and so this is not -- I think it's closer to some of the oil prospects that we've identified in the Equatorial Guinea side where you don't see DHIs and you're having to try to calibrate your seismic to really what are dimmer amplitudes. And so we're hopeful that, that may be indicative of an oil. And that's why we kind of refer to it as an oil prospect but as you know, without a DHI, it increases the risk and makes it more difficult to calibrate. But obviously we're focused on oil in the region. So we're going after some of those types of prospects.

Operator

And our next question comes from John Herrlin with Societe Generale.

John Herrlin - Societe Generale Cross Asset Research

Can you give us a postmortem on the Kora well?

Charles Davidson

We need to -- we estimate that, we have just gotten the, are just getting the final logs from that. Our partners, because of various reasons, decided to announce results, I would say, early. So you need to give us a rain check on that until we have a chance to actually go through and look at the final logs. It is still being evaluated, and so it will be a little more time on that.

John Herrlin - Societe Generale Cross Asset Research

Okay. With your 9,100-foot Wattenberg well, is that currently on production and how many frac stages did you make there?

David Stover

John, it's currently starting to flow back, up the casing. We just now put it on production to start flow back. It was actually about 40 stages for the completion set. It's something we're going to be real interested in testing and see how that looks.

Operator

And moving on, our next question comes from Bob Brackett with Sanford Bernstein.

Bob Brackett - Sanford C. Bernstein & Co., Inc.

On Niobrara, can you talk about the contribution from natural fractures versus the hydraulically fractured matrix?

Charles Davidson

Well, I think when you look at Wattenberg, which is a predominant area that we're developing now, we've always had what we believe is good matrix contribution because on a number of vertical wells there. So we expect that the matrix is contributing heavily in the Wattenberg area. When you go outside Wattenberg, we have much less data there and I think you've got, the industry is still assessing contributions from the 2, knowing that as they move around, they drill some wells in areas that have a high frequency of fractures and other areas that are more quiet. But I think at this point, it's for us, given the fact that our activity is so concentrated in Wattenberg, it would really be speculative on our part to guess at the relative contributions further to north. I don't know, Dave, if you want to...

David Stover

No, I think your point is right. In Wattenberg, we're obviously seeing good matrix contribution in that piece and that's predominantly what we're producing down there.

Bob Brackett - Sanford C. Bernstein & Co., Inc.

And then for the low GOR stuff, time will tell?

Charles Davidson

Well, that, I'd say there's a good portion of Wattenberg is low GOR area. I mean, a good portion of that, that's the 1,000 to 5,000 GOR when you look to the North and the East. Like I said, out of those last 12 wells that we talked about, 9 of those were actually in that what we would call low GOR area of Wattenberg in that 1,000 to 5,000 GOR area.

Operator

And we'll hear next from David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

You guys talked about the third-party midstream coming online in the Niobrara in June 2011. Prior to that coming online, were you curtailing the wells and does that give you an immediate bump to fill that capacity or it does it take some time?

Charles Davidson

Obviously, what happens in Wattenberg, as you run out of processing capacity, it raises the field pressures. And so I think the answer is yes, you see some backup. I mean, we could adjust it by and obviously, it will affect more some of the higher GOR areas or gassy areas. But again, it obviously affects the older wells more because they can't buck [ph] the pressure. We actually do see a little bit of a pickup there that comes on and optimizes out, but -- I think from now on, given the development that's going on in that area, we're going to have to see continued expansion of the mid-stream. Dave mentioned another project coming on in, I think, 2013. That will be a substantial edition I think as we continue talks with the mid-stream operator, that's going to take a lot more expansion based on our forecast for the amount of drilling and the development we're doing.

David Stover

As Chuck mentioned, David, the recent additions in the blank [ph] capacity obviously helps support this increasing number of completions per month that we're going to see and execute over the second half of the year.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. So that rate of change really does enable those high completions and that blank [ph]capacity. So the constraint between now and year end is what I'm thinking about?

David Stover

And obviously a large portion of these completions will still be in those low GOR areas, and so that helps also.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And then, trying to think through a lot of exploration going on, can you talk about, primarily given excellent rates, targets everything on those lines. Any indications going into 2012 around -- now that the thing has been moved up, you accelerated the Niobrara, you bring in Noa, and you obviously Gulf of Mexico was declining, but it reversed as well. Anything would be helpful as you think about going into the next year.

Charles Davidson

Well, I think as we prepare for our investor meeting later this year, as you could probably guess, we'll want to give you some a very crisp outlook at that time on what our view is near term and long term. We're really excited about how these projects are accelerating. And obviously they have impacts near term as well as long term. And so I think we'll be able to give you a better idea a little bit later in the year.

Operator

And our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

On Deep Blue, can you refresh us on any additional work that you've done during the moratorium and your expectations as you begin the re-drill process?

David Stover

There's not a whole lot new to talk about there. If you recall, when we -- before the moratorium, we'd gone down, and we'd seen oil in a couple of intervals, we're probably a little off-structure. And the whole thought has been to come back and sidetrack up structure here to test some of these things we saw indications how much is what improved our chance factor. I think, originally, we were down there probably around that 25% to 30%, and now we're saying about 50% chance on the side track. I think size-wise, we're still saying it has potential up to 200 million barrels gross on this. So we're just anxious to get this drilled and sidetracked. And here in a couple of months, we'll have a better answer on that.

Brian Singer - Goldman Sachs Group Inc.

Okay, great. And then going back to Israel, on Noa. Can you talk to any differences in pricing terms and costs versus Mari-B, and whether you think the additional production from Noa will be enough to satisfy Israeli gas demand as Mari-B declines prior to Tamar being fully ramped up in the event that there remain disruptions in imports from Egypt?

Charles Davidson

Well, let's see. I think I have to make about 10 assumptions before I can even start answering those. But let me say a couple of things. One is that the Noa incremental volume will help a variety of customers that we have out of Mari-B. It's all part of meeting the market. So is it we'll look developing it, the clearly important thing was we saw a strong market demand with the Egyptian supplies being disrupted. So it will feed into that. And I would expect the pricing on that to be a result of the blend of our customers that go off of Mari-B. As far as whether it will meet the needs, I mean, as Dave mentioned, that it potentially has 100 million cubic feet a day of deliverability to what we would have as deliverability off Mari-B. The big assumption there is the volumes that are taken from Mari-B between now and the start-up of Tamar. So we're hopeful that this will be an important component of bridging the gap. It's not only about -- it's more about deliverability than it is about resource, because Mari-B will continue on past Tamar for a while but it's maintaining that deliverability for times like right now where it's hot in Israel the volumes off Mari-B are really at the maximum. So this is all about supplementing the deliverability at a critical time and with the timeframe that we have, it means that Noa will be available in the third quarter of next year, which is a high demand, hard-to-find, hot part of the year for Israel. So that's what our hope is, we've worked hard with the state of Israel to look for solutions to help bridge this, because of the loss of Egyptian imports. And of course, I can't forecast it or when or to what levels those imports will resume. So we're just trying to what we can to meet the market needs between now and Tamar.

Brian Singer - Goldman Sachs Group Inc.

Great. And if I one last in. I think you mentioned in your comments that you'd be pursuing some pre-seeds [ph] steady plans for LNG in the next couple of quarters, are all those plans focused on, geographically, on Cyprus?

David Stover

We're actually looking at a couple of different areas on that, Brian. So we want to keep all options open at this point.

Operator

And our next question comes from Doug Leggate with Bank of America-Merrill Lynch.

Douglas Leggate - BofA Merrill Lynch

I guess a couple of follow-ups on some of the things that have been asked already, but starting off with the Wattenberg. What do you need to see in terms of de-risking the acreage? I guess if you'd quantify to what extent you feel comfortable with the 2,000 locations, because clearly 5 rigs sounds a little bit light and probably is the case. What do you need to see before you start accelerating activity? And I have a follow up, please.

David Stover

I think, Doug, we're actually moving in to acceleration mode right here. When you look at the number of completions of wells, additional wells we're drilling this year. The plan now is to look at how much we can accelerate into next year on that. I'd say when you look at the question of de-risking, we feel Wattenberg is essentially de-risked when you look at the spread of wells that we've drilled from core of the field to edges of the field. So we are in full development mode now with the emphasis on how quickly can we continue to ramp up and accelerate.

Charles Davidson

And again, thinking about it, that 2,000 locations is for the Wattenberg area which is around 400,000 net acres. So in much of that area, we're looking at 4 horizontals per section. We'll continue to test that. Obviously there'll be some areas that will fall off. But that's a full program, and we would -- as Dave said, we consider Wattenberg, given the fact we've drilled so many wells. And I think this year alone we'll have close to 75 of our wells in Wattenberg at its very deepest.

Douglas Leggate - BofA Merrill Lynch

Chuck, where do you see the rig count getting to ultimately?

Charles Davidson

We'll just keep stepping it up. Now there's a couple of critical things here. We're working with State of Colorado on peel [ph] drills on Wattenberg, and we're hopeful we'll see some rules come out later this year. That will help facilitate the pace because it's a very land-intensive process. So if that happens, we'll be looking for probably some more ramp-ups in 2012. I think more on that a little bit later in the year. Our goal right now is to get this 5th rig in there and then see how we can continue to feed it. But the real positive has been, as Dave mentioned, the drilling times are coming down. So that's been adding to the well count, and we need to now accelerate the completions, because they take a lot of time as well. And so we've got to work not only rigs but completions. And that consumes a lot of resources. So the -- it is a major project, we're moving a lot of pieces, but the idea, of course, is to get the development project, we need to accelerate it as fast as the people and the service companies and the various other parties that are involved can support it.

Douglas Leggate - BofA Merrill Lynch

Okay. My follow-up is just something about Israel real quickly. In light of everything that's happening with Egyptian disruptions, can you kind of characterize perhaps how contract discussions have maybe changed with customers outside of Israel Electric? It would seem that there is obviously a little more competitive year or so ago. Where are things standing now in the context of how you might expect to basically look at volumes overall, outside of your core customers?

Charles Davidson

Well, I think it has created a large amount of uncertainty in the market there. So customers -- our customers, as well as customers of Egyptian Gas are trying to understand where they will get their future volumes. So we've certainly seen more interest from customers that were using Egyptian gas, and as I mentioned before, we've got -- we were trying to supply the need as best we can. The near term is very difficult, because we have only maximum of 600 million a day deliverability off Mari-B. In Tamar, the project that we're developing has finite deliverability as well. So we're doing our best to meet the market needs. But clearly we have seen increased demand and more concern about the gas supplies there. The good news is we've discovered a lot of gas between Tamar and Leviathan. We discovered now some 25 trillion cubic feet of gas resources in the basin. So there's a lot of gas there. And now it's a matter of working the development projects and making sure that the market is met. It's a challenge though.

Operator

And we will hear next from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

At Wattenberg, can you speak to development spacing assumptions today, and what you might test going forward?

David Stover

Yes. I mean, right now, I think, Chuck alluded to it. All our assumptions is that they got 160-acre spacing. And I'd like -- that's a subject that we'll continue to have to evaluate and understand with maybe some pilot work down the road and so forth. It's not just the spacing, it's how do you get the next 5% recovery out of Wattenberg whether it's spacing, whether it's how we're handling completions, because that's the huge prize out there. This first 5% recovery from the 160-acre spacing assumption is, 600 million barrels net to us. So our focus is not just on the spacing, it's on lateral length, it's on completion, optimization, all of those pieces that look at what's going to unlock the next recovery space.

Dan McSpirit - BMO Capital Markets U.S.

Got it. And then one last one here. Can you tell us the gas-oil ratio on the 9,100 foot lateral?

David Stover

Not yet, Dan. And we just turned it on. [indiscernible] so it's got to unload and then it stabilized. It is in the low GOR areas, though.

Operator

And we will hear next from David Wheeler with AllianceBernstein.

David Wheeler - AllianceBernstein

With the Gunflint utilization in the 2 additional blocks, what's been discovered resource size at this point? And how -- what could an appraisal add to that resource amount?

Charles Davidson

Well, I mean we still got the same prospect size on Gunflint. Obviously, by having an interest in the outlying blocks and spreading interest across that it exposes Noble to a greater net, based on how it might go up in size. But we've got to do the appraisal. As you may recall, one of the appraisal will test whether or not it does expand further off the discovery block. So I would say right now, we wouldn't change the overall range that we put on Gunflint. It's a pretty sizable range. It's well up from what it was under the original prospect. But as we've been saying all along, we need to get that next appraisal well drilled to really understand is this a discovery that's more centered on the discovery block or is it one that spreads into the outlying block.

David Stover

But it's been real important, Dave, to get that interest defined for every party upfront before having to try and work that on appraisal wells down the road. So that was a definitely, a significant feat.

David Wheeler - AllianceBernstein

Okay, great. And Dave, did you mention when you're talking about the Wattenberg, are you looking at other horizontal opportunities other than the Niobrara?

David Stover

We really didn't talk about anything other than Niobrara here. We'll continue to see if something makes sense, but we're really focused on the Niobrara right now. What we talked about in the Niobrara is we're continuing to look at different portions of the Niobrara as to how to optimize that on a horizontal basis.

David Wheeler - AllianceBernstein

Okay, good. And in terms of LNG prospects in Cyprus, maybe come out of Israel. You talked about the proposals from contractors, does it make sense to bring in a upstream partner or a partner, an LNG operator, potentially?

Charles Davidson

Well, I think right now we have to understand the scale of the base and then the resource. So I think step one is drill the Cyprus prospect, which is, as Dave mentioned, our largest undrilled prospect as we see it in the basin right now. That will help set the resource size, and do some of this pre-seed work to understand what's viable. And I think at that point then, you're at the stage where you can decide just what should be the structure for going forward in terms of whether it's looking at upstream or mid-stream partners or partners who have expertise in LNG operations or LNG global, LNG marketing. I think all those options are open to us, but we need to do know what the scale of the project is to start with.

Operator

And that concludes the question-and-answer session today. At this time, I would like to turn the conference back over to the speakers for any additional or closing remarks.

David Larson

Thanks, Jenny. Yes, again, we kind of hit our time frame here. We know everybody's really busy during this conference -- or the earnings season. So anybody that we did not get to on the call today, please don't hesitate to give us a call and we'll try to talk to you through your questions. With that, I just like to say again, thanks, everybody for your interest and participation in the call today and have a good day.

Operator

And again, that does conclude today's conference. We do thank you for your participation.

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