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Executives

David L. Stover - President and Chief Operating Officer

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

David R. Larson - Vice President of Investor Relations

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

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

Brian Kuzma - JP Morgan

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

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

Noble Energy (NBL) Q3 2011 Earnings Call October 20, 2011 10:00 AM ET

Operator

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

David R. Larson

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

The agenda for today will begin with Chuck discussing the quarter, along with an update on our annual guidance and touch on our ongoing exploration activities. Dave will then give a more detailed overview of our operations and plans for the remainder 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 please ask that our participants limit themselves to one primary questions and one follow-up. Should you have any questions that we don't get to this morning, please don't hesitate to call and we'll do the best 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 the future to differ materially from what we would talk about today. You should read our full disclosure on forward-looking statements in our latest news release and SEC filings for a discussion of all 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 is because we believe they are good metrics in using -- to be used in evaluating the company's performance. Be sure to see the reconciliations in our earnings release tables.

One other item before handing it over to Chuck. Hopefully, you all are aware that we are hosting an Analyst Day on November 15 in Houston. Please make sure to put it on your calendar. We look forward to providing a significant update on our global portfolio, the significant growth that we expect and the opportunity set that we believe is unique within the industry. With that, let me turn the call over to Chuck.

Charles D. Davidson

Thanks, David and good morning, everyone. The highlights section of this morning's earnings release clearly shows what an outstanding quarter it was for Noble Energy. Sales volumes were well above expectations and if adjusted for last year's sale of onshore U.S. assets as well as our exit from Ecuador, would have been a record. The quarter saw a record production from our horizontal Niobrara program in the DJ Basin as well as record production in Israel. Our major projects remain on track with the same continuing to be well ahead of schedule.

And finally, we announced and closed in the quarter the acquisition of a very significant position in the Marcellus Shale to the formation of a joint venture with CONSOL Energy. As a result, we now find ourselves rapidly speeding toward a significant inflection point in our growth profile. An inflection point that's driven by accelerating Niobrara drilling, the new and rapidly growing Marcellus production, as well as the pending startups of Aseng in West Africa, as well as Raton South in Galapagos in the Deepwater Gulf of Mexico.

It has indeed been a very busy and exciting quarter for Noble Energy, so I'm going to start with a quick summary of the quarter. We reported adjusted net income for the third quarter of $234 million or $1.24 per share. That's up from $225 million for the third quarter last year. Adjustments this quarter were primarily related to unrealized mark-to-market gains on our hedges. GAAP net income for the third quarter this year was $441 million or $2.39 per share diluted.

Revenues were $924 million, down slightly from last quarter, with weaker commodity prices offsetting the volume growth. 73% of our revenue this quarter was from liquids, including natural gas liquids and methanol. Discretionary cash flow was $588 million for the quarter, up 18% over the third quarter 2010. Total sales volumes for the quarter averaged 224,000 barrels of oil equivalent per day, outperforming the high end of our guidance for the quarter. Our domestic volumes made up just over 50% of total volumes or 113,000 barrels of oil equivalent per day. Total U.S. volumes were down versus the third quarter last year, as a result of the sale of the onshore mature assets we had at that time as well as some natural depletion.

The DJ Basin, with the addition of another horizontal rig expanding our drilling capacity there, continues to deliver impressive growth. The DJ Basin produced a record 65,000 barrels of oil equivalent per day for the quarter. That's up 18% from the third quarter of 2010 and up 10% from last quarter.

Additional production growth is expected as we increased the pace of horizontal drilling and completion activity. As we have stated before, the growth in the DJ Basin is primarily from liquids and as a result, the liquid percentage of the entire area now is up to 55%. Dave will have more to say about the performance of our drilling and production when he goes over our operations later in this call.

Internationally, sales totaled 111,000 barrels of oil equivalent per day, which was up slightly from the third quarter last year. Our sales volumes grew in EG, the result of timing of liquid liftings and in Israel, where we experienced record sales at Mari-B throughout the summer peak demand period. The volume growth overcame the production loss from the sale of Ecuador assets and the lower sales from the Dumbarton field in the North Sea, where a planned production shutdown of the FPSO there was extended. The work on that FPSO has been completed at the end of August and production was restored in September.

I wanted to make a few comments about our entry into the Marcellus Shale. As I stated when we announced this transaction, we believe the Marcellus is one of the most attractive gas plays in North America and that the partnership that we have entered into with CONSOL Energy, will deliver significant value going forward. Noble has a partner in CONSOL that shares our values and our focus on capital discipline and performance. In addition, we have created a deal structure that closely aligns the economic incentives of both partners.

We plan to leverage our experience and success in Wattenberg to help realize strong growth that is expected to materially grow production, cash flows and reserves. We're pleased that the transaction closed as scheduled and that the development is progressing better than anticipated. The process of exchanging operational knowledge has already begun and we're coordinating with CONSOL to make sure that we both implement best practices to enhance the performance of this joint venture. CONSOL has drilled 58 wells already this year and their production results are very encouraging, particularly the early performance of their recently announced 10-well pad.

At the end of September, net production was 50 million cubic feet equivalent per day, and by the middle of this month, it was over 60 million cubic feet equivalent per day. Utilizing a multi-well pad allows greater efficiencies in drilling and in gathering.

Moving to multipad development has been made possible at this time because the large percentage of acreage held by production, which means we don't have to skip around drilling a lot of single wells just to hold acreage.

In the earnings release this morning, we noticed that we have -- we noted that we've increased our sales volume outlook for the full year to range from 220,000 to 222,000 barrels equivalent per day. This is the second increase this year and is 8,000 barrels per day or 4% higher than our original guidance using the midpoints of the range. 2,500 barrels equivalent per day of the 8,000 barrels is attributable to Marcellus production in the fourth quarter. Production performance this year has obviously been strong and we expect the additional volumes coming online from South Raton and the Gulf and Wattenberg and perhaps a bit from Aseng late in the quarter, which will help offset some of the seasonal drop in Israel demand in the fourth quarter.

Our cost items for the third quarter are generally aligned with our expectations and remain within guidance ranges for the year. We maintain our focus on keeping a low cost structure even as we grow our production. In the fourth quarter, however, we expect lease operating expense in DD&A unit costs to move up to the ranges of $5.20 to $5.60 per barrel equivalent and $12.25 to $12.95 per barrel, respectively.

The LOE unit cost are impacted by maintenance projects at Alba, the startup of Aseng and a higher production mix, which is basically a result of seeing lower Mari-B sales being offset by higher North Sea sales in the fourth quarter. The DD&A costs are impacted by the Marcellus, startups of Aseng and South Raton and again a higher cost of production mix, again, seeing higher sales volumes out of Wattenberg in the North Sea, offset by the very -- lower sales from Mari-B, which of course, is a very low-cost source of production for us.

Exploration expense is estimated to be $150 million to $200 million for the fourth quarter and that's being driven by a large number of exploration wells that will be decisioned by year end. Last quarter, I mentioned our effective tax rate would rise in the third quarter due to the impact of a retroactive tax change related to a change in the U.K. tax laws. As expected, our adjusted effective tax rate for the third quarter was 44% with 26% deferred. The tax changes are retroactive to March of this year and this resulted in a charge for the quarter of $46 million. We did not include this charge in the adjustments we made to determine adjusted net income, but you'll want to note it when reconciling to your estimates.

Our expectation for the fourth quarter is that our adjusted, effective tax rate will return to a level that corresponds with our full-year guidance of 34% to 38%. Our capital expenditures for the quarter, excluding the Marcellus acquisition cost totaled approximately $735 million. Our full-year capital spending remains essentially in line with our guidance of $3 billion, even with the $110 million included to fund the Marcellus development in the fourth quarter.

As we announced earlier, we funded the Marcellus acquisition from cash on hand and $400 million from our previously undrawn $2.1 billion credit facility. We ended the third quarter with a cash balance of $1.3 billion and total liquidity of $3 billion and our resulting net-debt-to-cap ratio of 26% is well within our investment grade rating. Last week, we further strengthened our liquidity by establishing an upsized 5-year $3 billion revolving credit facility.

I wanted to finish up here before turning it over to Dave and talk about our near-term exploration plans. At our Deep Blue project, we have now reached total depth and have discovered additional hydrocarbons in the sidetrack. However, it will require additional data and time to fully evaluate and develop forward plans with our partners. Since the evaluation is ongoing, I'm going to refrain from speculating on future plans until we're fully aligned with our partners on the plans going forward.

Our current international exploration efforts are in Cyprus, where we spud a well in mid-September, in Israel where we're drilling the Dolphin prospects and in Cameroon, where we began drilling a well earlier this month at our Bwabe prospect.

The Bwabe prospect offshore Cameroon is our first exploration drilling in the Tilapia block to test our deep oil target and we expect results in the fourth quarter. The Cyprus prospect is our largest undrilled prospect in the Eastern Med and the results for drilling will provide additional clarity with respect to the resource level there. A better understanding of this resource is necessary as we evaluate our monetization options and we expect results on the Cyprus prospect in the fourth quarter. The appraisal work at Leviathan will also enhance our clarity around the size of our gas resource base there.

We're evaluating proposals for an LNG plant pre-FEED study for several potential export sites under consideration. This is part of our ongoing effort to advance monetization solutions for our significant Eastern Mediterranean gas resources. Partnered discussions will follow the completion of the pre-FEED studies.

Finally, let me remind you that our first major project, Aseng in West Africa, is making extremely good progress and now is expected to come online in the fourth quarter. That's at least 6 months ahead of our original schedule for this project, the first of many that will bring the production over coming years. And certainly, we're benefiting from the tremendous experience we've had at Aseng.

The management team here at Noble Energy is excited about our portfolio, our progress towards developing its rich inventory of opportunities. We intend to provide a very detailed review of all areas, including our newest core area at our Analyst Meeting in November and we certainly look forward to seeing you all there. So with that, Dave, I'll turn it over to you.

David L. Stover

Thanks, Chuck. As you highlighted, this is a significant period in the growth of our company. Today, I will provide an update on all 5 of our core areas before wrapping up with expectations for the remainder of the year. Let's start with an operational look at our recent joint venture in the Marcellus shale. As Chuck mentioned, the joint venture with CONSOL is designed to create strong partner alignment. This partnership is governed by a structure, which includes the joint oversight and operations through a development committee with equal representation of Noble and CONSOL staff.

Under the predefined development plan, together we will grow the rig count from 5 horizontal rigs today to 16 horizontal rigs in 2015, with noble expected to be operating 6 of the rigs at that time.

The plan is for the joint venture to add roughly one rig per quarter, alternating between the partners. Noble Energy will pick up its first operator rig in January 2012.

Partners have 2 dedicated frac crews with an option for a third next year. We are leveraging our experience with our liquids rich development in Wattenberg by focusing our initial portion of the operations in the wet gas area of the Marcellus. Our knowledge transfer from Wattenberg to Marcellus is already in progress through peer reviews and technical consultations between the Noble Energy and CONSOL teams, and early feedback from our teams has been very positive.

Net production was 50 million cubic feet per day when we closed at the end of the third quarter and is growing at a pace that is faster than we originally modeled. We're extremely pleased with the way the joint venture has started off with the first 5 wells from a new pad, initially adding over 10 million cubic feet per day net in October. We look forward to providing more details on our outlook for this new core area at our November analyst meeting.

In our other core onshore U.S. asset, the DJ Basin, the acceleration of our horizontal Niobrara play continues. We are operating 5 horizontal and 8 vertical rigs in the DJ Basin and are on pace to have over 80 horizontal wells drilled this year in the Wattenberg field. Additionally, we plan to have drilled 7 horizontal wells in northern Colorado and one in Wyoming by year end. Of the wells in Wattenberg, 15% are in the higher GLR area and the remainder in the lower GLR areas of the field where we've experienced roughly 70% liquids.

Our pace of drilling and completions continues to increase. In the third quarter, we completed an average of 8 horizontal wells per month, including 10 in September, a significant acceleration from the 4 completions per month that we averaged in the second quarter. We expect to maintain a rate of 10 horizontal wells completed per month throughout the fourth quarter. This activity level is translating into production growth. At the end of September, our horizontal Niobrara production was 14,500 barrels of oil equivalent per day gross or 11,500 barrels of oil equivalent per day net to Noble Energy. This is up 64% from the 8,900 barrels oil equivalent per day gross at the end of the second quarter. We feel very good about the momentum of this program.

At this time, I want to mention the performance of just a couple of the new wells which are contributing to this production growth. First, the 9,100-foot lateral well in northeastern Wattenberg has been on since mid-July and performing extremely well. It is still producing 750 barrels of oil equivalent per day with 85% liquid content after 80 days of production. Another significant well is the Tamar well that is located in the high GLR area and appears to rival the Gemini well based on its early production profile. Tamar has set a new peak 24-hour rate record at 1,282 barrels of oil equivalent per day for our Wattenberg operations, while on a reduced choke with over 2,200 pounds of flowing casing pressure. We will have much more to say about the horizontal Niobrara program in November as well.

Shifting to the Deepwater Gulf of Mexico, our development projects are nearing completion. Topsides work supporting South Raton will conclude in the fourth quarter and approximately 2,000 to 3,000 barrels of oil per day net to Noble Energy will be online before the end of the year. At Galapagos, the work on Subsea Systems and the Nikita topsides are about finished and production will begin in the first quarter of 2012. The resulting production will be 10,000 barrels per day net to Noble.

Our well at Deep Blue has reached its total depth, as Chuck mentioned, and we're evaluating next steps. After the ENSCO 8501 rig undergo some upgrades, it is planned to spud a Gunflint appraisal well before the end of the year. The Gunflint appraisal is necessary to narrow the resource range before final planning and sanctioning. Currently, the gross resource range is 70 million to 500 million barrels of oil equivalent. Depending upon the drilling results, we may also perform a sidetrack.

To support the future appraisal work in our exploration inventory, we will pick up an additional rig on a shared basis. Noble will have 2 separate 4-month slots with the ENSCO 8505 in 2012 and 2013, which will share our Gulf of Mexico workload with the ENSCO 8501. I will now move to our international areas beginning in West Africa.

The Aseng project continues to progress and is on pace for first production before the end of the year. The Aseng FPSO left the shipyard in September and arrived on location, Offshore Equatorial Guinea, this past weekend. It arrived with testing completed and the focus is now on hookup and commissioning. We expect first production by the end of the year. Production is expected to ramp up to 50,000 barrels of oil per day, 17,000 barrels per day net to Noble Energy. The Alen project is on budget and on schedule for first production in the fourth quarter of 2013. The wellhead jacket is being installed now and the production platform is 25% complete. That, with Hunter rig, is on location and drilling the gas injection wells. The Atwood Aurora jack-up rig will begin drilling the production wells later this year. Before relocating to drill the Alen production wells, the Atwood Aurora will finish the Bwabe exploration well that recently spud offshore Cameroon.

Moving to the Eastern Mediterranean. It was an extremely active quarter. Natural gas demand out of Israel remained particularly high through the summer months. As a result, Mari-B operated at full capacity to help satisfy the demand during the third quarter. Our teams continue to maximize deliverability out of Mari-B and the compression installations from the second quarter made that cost possible.

Mari-B continues to perform well, producing an average of 550 million cubic feet per day gross over the quarter. With these high production rates, we expect some decline to finally set in and impact next year volumes. In order to help satisfy Israel's gas demand until Tamar comes online, we are moving ahead with the development of Noa, a smaller field that will be tied back to Mari-B.

The Noa project will provide an additional source of gas and offset some of the Mari-B decline. 2 development wells were recently drilled by the Noble Corporation Homer Ferrington rig, and completion operations will commence next year. First production from Noa is scheduled for the second half of 2012 and the 2 wells will provide up to 100 million cubic feet per day of supplemental production for Israel.

Tamar continues to move forward on schedule. The Transocean Sedco express rig completed drilling the third production well and has relocated to complete the drilling of the Leviathan number 3 well. After drilling Leviathan number 3, and 1 to 2 exploration wells, the rig will move back to Tamar to finish development drilling and completion work. Tamar platform fabrication is about 40% complete and line pipe installation is underway. Project commissioning is still scheduled for late next year. At Leviathan, as mentioned earlier, appraisal drilling has resumed at the number 3 well and should reach total depth sometime in December. The Homer Ferrington rig is drawing the Cyprus prospect that Chuck discussed. When finished, it will be available for use offshore Israel.

At our third Eastern Mediterranean rig, the ENSCO 5006, formerly the Pride North America, riser repairs are complete and drilling operations are now underway on the Dolphin exploration well in the Hanna license. Dolphin is a small prospect targeting the Tamar sand. The rig will then be used for completion work at Noa and for exploration drilling on other prospects in the basin.

That is a quick overview of our activity in our 5 core areas. For the fourth quarter, we are estimating company-wide production volumes to be 226,000 to 234,000 barrels of oil equivalent per day. Our new production from the Marcellus program should offset expected seasonal demand decrease in Israel, while we should see a nice liquid production increase from our horizontal activity ramp in the DJ Basin and a full quarter production in the North Sea. We should exit the quarter with South Raton and Aseng online and close to Galapagos starting up. We look forward to a strong close to 2011, and we'll be providing more insight into our future growth on our Analyst Day on November 15.

But at this time, Hanna, we'd like to go ahead -- Anna, we'd like to go ahead and open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from Dave Kistler with Simmons & Company.

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

Real quickly on the Marcellus transaction, one of the things you guys did in the JV is put a circuit breaker in place if commodity prices are specifically and that gas fell below $4 for a 3-month period. Looks like that's going to happen here at the end of this quarter. Can you talk about what that does to your funding obligation and how you're thinking about that for the rest of the year -- this year and next year? Sorry.

Charles D. Davidson

Yes, you bet. Well, we were -- we put that circuit breaker in for a primary reason and that is, is that as gas prices, if they were to move below $4 as you point out they have, then we and our partner are completely aligned on drilling economics and drilling results. And that way we believe we can make the best decisions as to the pace at which we carry out the program going forward.

We have put together a plan that was the initial plan that was part of the transaction. But that plan can be modified with the mutual agreement of both partners, and with us being fully aligned, as you would expect, we will be visiting with our partners to see what's the best plan going forward. We're, of course, very encouraged by the results we're seeing. That is intended to make sure that as we go forward, perhaps we need to adjust the pace of acceleration and drilling. These are all decisions that we need to make with our partner. But the point is that there's nothing that automatically happens when the price drops below $4. It simply eliminates or suspends the carry, so that our returns and our partner's return should be identical on the program that we drill.

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

Switching over to Israel. With volumes where they were this quarter, I'd imagine that you fulfilled any kind of obligations to your counterparty regarding volume requirements. With that in mind, how do I think then about what kind of volumes they would look to pull this next quarter and then maybe even more importantly, how pricing might change given that they've probably hit a new tier in sort of contract pricing? And if I'm misunderstanding how that's structured please, help me understand.

Charles D. Davidson

Yes, let me just a bit on that. We have -- our contracts continue on with our primary customers so it's -- we would not expect any change in the structure or pricing now. Seasonally, fourth quarter does fall down and so we would expect lower demand for natural gas in the fourth quarter is usually the case. But I wouldn't project any change in the pricing methodology at all, Dave. It continues on. Yes, we delivered a lot of gas to them. In some instances, well above what we perhaps had an obligation for, but at the same time, we understand the market demand and the situation in Israel and we wanted to make sure that we provided as much gas to that market as we could given that the alternative supplies have been suspended.

But again, our customer contracts remain in place. At some point, yes, you're right. About the time we really deplete Mari-B, we'll have completed all the contract obligations for those original contracts and quite honestly, many of those will roll over to the Tamar field at that point.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

A couple of questions on Israel. First, there's obviously been a lot of headlines regarding the Mediterranean politics and in your comments earlier on evaluating LNG pre-feeds is noted. But have you had any recent conversations on the Israel side regarding the government's willingness and interest for Leviathan gas to be exported beyond what you've expressed in past calls?

Charles D. Davidson

Well, there's a number of ongoing discussions and I think as you just referenced, I mean, some of it median and some of it as we talked to officials there in the country, they're continuing -- go through an evaluation of what will be their gas needs going forward. And also, realistically, the fact that most would view that the demand for domestic gas has gone up because the potential for imports from Egypt has been minimized. So that work is underway. There's actually a group that is assigned to look at the export question and that will be -- and are providing import, providing input and data to that group.

So it's ongoing. I look at it as, first of all, more local demand is always good. That's the positive keep in mind. The other thing is, we have found a lot of gas in that region, so that's why it's so important to get this decided early as I think is really the real question behind your question is getting the amount of gas that's needed for domestic versus export decided early, so we can make some decisions on the scale of an export project.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then you mentioned, I think, in the opening comments that you expected Mari-B to be -- whether you expect the miller to offset the bulk of declines from Mari-B. Can you talk about where you expect Mari-B to be producing when you're out and I guess, when you add the 100 million a day from Noa, what Israel volume should do next year versus this year?

Charles D. Davidson

I don't want to -- at this point, I don't want to give an Israel guidance for production for next year. We'll have some overall guidance coming in, in November. But the other thing is, as you can imagine, it is very sensitive to what the current takes are, what volumes they will take in the fourth quarter. And also, whether or not our customer decides to adjust their takes to give it a more stable supply.

So a lot of it depends on what the volumes are, taken now and customer demand and how they pace demand until Tamar comes on early in 2013. So we're dealing with a finite tank, we know that. It's a field that's produced very well and we know that with these high volumes we've delivered this year, it will reduce some of our deliverability next year, whether or not Noa offsets that decline, I can't speculate at this point.

Operator

And our next question comes from Leo Mariani with RBC Capital Markets.

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

Just kind of sticking with Israel real quick, can you guys comment on the progress of any negotiations to contract additional Tamar gas?

Charles D. Davidson

Yes, Leo, we're still in negotiation. Obviously, I think, our view of the negotiations, they're going well. We're making some real progress but we have nothing defined at this point.

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

Okay. And maybe you could give us a little bit more detail around what you guys are doing in Cameroon with that Bwabe well and times in terms of prospect size out there, and if you guys could potentially comment on what you think maybe the chance of success is?

David L. Stover

Yes. I think we've talked about that a little on the past. We continue to refurther that as our first oil prospect of greater than 100 million barrels oil equivalent gross, and I think about a 25% piece of G or chance factor on that.

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

Okay. And I guess on the Niobrara, on your prepared comments, you guys had some really strong well results there from your horizontal program. Obviously, your production's really making material strides. Can you comment on well costs for those horizontal wells and what those have done of late?

David L. Stover

I mean, the typical well cost is still hanging in there right around drilling complete around that $4.5 million. So we've seen that still hanging pretty flat on that.

Operator

And our next question comes from Bob Brackett with Bernstein Research.

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

Can you comment on your Israeli Exploration Plan, kind of Dolphin and post-Dolphin wells? Are those short-cycle time domestic projects, small targets or are you looking at some larger targets?

Charles D. Davidson

Well, and Dave may want to add some color to this as well. But as he noted, Dolphin is a small prospect. The big prospect that we're drilling is the Cyprus prospect. That's the largest undrilled gas prospect that we have in the inventory and we'd expect results on that here in the fourth quarter. But as we've noted before, we have a number of other prospects in Israel and so we would expect, I think Dave may have reference, there will be at least a couple more exploration wells as we go forward here into 2012, testing some of these other prospects as well.

David R. Larson

I mean, just as we've talked a little bit earlier about how important it is to understand the demand in the countries is just as important to understand what the potential supply can be, so that's why we're continuing the exploration program on these prospects of various sizes.

Charles D. Davidson

So I think the other part of your question was whether they're designed for domestic. Any of these could be setup to provide either a domestic or an export project. In fact, I would expect that there will be ultimately, if we look far ahead, there will be a lot of interconnections and backups and redundancies of multiple supply. So it's not that we're necessarily drilling for domestic. That's what we did at Noa. As of late, it's specifically tied back to Mari-B and helped them on the gas supply situation next year. Most of these are looking at defining the long-term resource, which could be committed to either a domestic or an export market.

Operator

And our next question comes from David Heikkinen with Tudor, Pickering, Holt.

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

Just had a question more conceptually around Israeli long-term demand, you talked about a 40-year supply determination. Is there a chance that Tamar and then Leviathan could be sequentially produced as opposed to concurrently produced as an option? Or do you expect both fields to be able to be produced concurrently?

Charles D. Davidson

Well, we would expect that ultimately the production from those fields will overlap each other with some portion, if Leviathan and Cyprus -- I mean, we're dealing with a very large resource base here so we -- well, hopefully Cyprus will be successful, we'll find out here this quarter. But you would expect that, again, some of it will be dedicated to the domestic market and that right now, we're assuming that all of Tamar will go in the domestic market and we would guess that some of the Leviathan will go into the domestic market as well.

And then some of Leviathan will go into a international market. And so we could be supplying the domestic market from both Leviathan and Tamara at the same time. In fact, there's a lot of good reasons why that would make sense in terms of diversity of supply and hopefully, multiple delivery points as well into their system.

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

How does that impact ultimate peak deliverability out of a combination of the multiple projects? And would it be timing would be later? Just trying to think about timing and then peek deliverability into the domestic and the global market.

Charles D. Davidson

Well, I think when you look at peak deliverability, you really, if you want, I'll total it all up. You need to wait for the export market to be there and we've given some early snapshots of being later in this decade, and because that's when you can really kick of the volumes. Now the wildcard in all this is that we see the potential that the domestic market and domestic demand for natural gas could be moving up from what we expected before. So there could be stronger near-term demand for domestic gas even before we're ready to export.

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

Okay. And then like Dolphin as a smaller prospect, are those things to be developed faster or do they just kind of fit it in the overall scheme of a multifield development?

Charles D. Davidson

I mean, it'll depend on size and then looking again at that internal market and then how things work out from an export scenario and being able to tie these together. I mean, it'll sort itself out over the next couple of years.

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

But don't think of Dolphin as another Noa.

Charles D. Davidson

No, no, no.

David L. Stover

No. We're talking about small versus Tamar and Leviathan.

Charles D. Davidson

Yes, yes.

Operator

And our next question comes from Brian Kuzma with Weiss Multi-Strategy.

Brian Kuzma - JP Morgan

I just had a question on the U.S. production front. I wanted to make sure I understood the Niobrara or your DJ production went up so much, where was the offset mainly from? On the U.S. operations.

David L. Stover

Well, in Deepwater, you still had some decline there and actually with some other downtime there. And then the other U.S. onshore piece is that we're not continuing to invest in, those have some natural underlying decline.

Charles D. Davidson

Yes, we're not, of course, drilling in Piceance, which doesn't make sense and some of the dry gas areas. And that -- I will assume that you're talking about second quarter versus third quarter.

Brian Kuzma - JP Morgan

Exactly.

Charles D. Davidson

Yes, if you're comparing to the year before we, of course, sold some production since then.

Brian Kuzma - JP Morgan

Okay. But mainly, Deepwater, there were some hurricane outages and then just natural declines out there every season...

Charles D. Davidson

Right, yes. Especially in areas where it doesn't make sense to be drilling in this current gas market.

Operator

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

John P. Herrlin - Societe Generale Cross Asset Research

Two quick ones. One, you committed to more rig time in the Gulf of Mexico, does that mean you're perhaps more optimistic that you'll have faster permitting going on?

David L. Stover

Well, I think it gives us more flexibility on rig options. Because you may recall, the first -- the rig that we're currently using is shared with a partner and right now it's uncertain as to how much of their time they're going to use, and we wanted to make sure that we could back it up. So I would say that we're encouraged that we're getting permits that we need. But right now, I can't say that we're projecting it's going to come any faster. This just gives us more flexibility on rig choices going forward.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. That's fine, Chuck. With the Cyprus well, there's a press article saying you had some drilling difficulties, was that correct?

Charles D. Davidson

Well, what we're doing is we're drilling through the salt. We got into a little bit higher pressure, which we had to increase the mud weight a little bit and then go ahead and set casing strength just a little bit sooner than we originally planned, so that's really all that was. So it's a slight adjustment but no real change. Nothing impacting the lower horizon that would target interval.

David R. Larson

And as actually, we've seen that throughout the basin as we're in the salt that we get some variations. And so we've had a couple of instances where we've had to stop and set pipe before continuing.

Charles D. Davidson

Adjust the casing program.

John P. Herrlin - Societe Generale Cross Asset Research

Yes. Well, you did that with Leviathan for sure. Last one for me, what are your modeling for Marcellus well cost in the EURs?

Charles D. Davidson

The well cost are in that -- and then you look at some of the other folks numbers out there, but they're pretty much thinner in that $5, $5.5 type range for drill and complete. EURs, we'll have more on that as we get some more information, but we'll get into that a little more at the analyst discussion.

Operator

And our next question comes from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

In the DJ Basin outside of the Wattenberg field, what do the results look like for the horizontal Niobrara?

Charles D. Davidson

That's still early. I mean, that's something we're continuing to monitor. We'll actually drill a few more wells probably between late this year and into early next year. As you may recall, one of the things we were doing was obtaining some more 3D seismic to help us with our well planning up there. So I guess I'd still say it's still early results out there. Our focus again has been expanding the program in Wattenberg, especially as we continue to see these results in the lower GLR areas in the field that we've continued to focus on there.

David R. Larson

I think you'll see when we talk about it in November. But with the results we have seen in Wattenberg with the huge acreage position we have and the fact that it's essentially been derisked, we're trying to keep all our resources focused in Wattenberg. We'll continue to test some of these peripheral areas to make sure we're staying abreast and make sure we hold the positions that are important. But we're very focused on returns and the return right now is to drill in Wattenberg where it's been derisked. We've got the infrastructure. We're making some high liquid content wells and some really, really good completion.

Charles D. Davidson

We're continuing to accelerate that program.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's helpful. And a follow-up, whether within Wattenberg or outside, are you drilling horizontals to any other formations like the Codell? And if so, have you had results?

Charles D. Davidson

I think we've talked before -- we tested 1 or 2 that kind of touched into the Codell, but we really haven't focused on the Codell yet. I mean, we've had such good results on the Niobrara. And our real objective there is to try and continue to understand was some additional pilot work, where we're going to get the next increment of recovery out of the Niobrara.

Operator

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I have a couple of quick ones. I may have missed this earlier, but when you talk about the export scheme or the potential for an export scheme, conceptually, is it too early to think about how Noble may want to participate in that? In other words, would you be looking at a partner that would offer you tolling opportunities? Or would you look to actually participate in the capital of the actual plan, should it go that way? And I've got a quick follow-up.

Charles D. Davidson

Yes, it is a bit early. Although we have said that our primary focus, it will be on the upstream side of the project. We may or may not take an interest in the midstream piece. A lot of that will depend on potential partners, what their interests are, how we get alignment, what the structure is. So it also quite honestly, will probably depend on where the export facility is located and what its nature is. So our attention right now is to go ahead. We are doing, as we mentioned, we're getting the proposals and we will be doing a pre-FEED for export sites, and so we'll carry that work. But the intent is to use that work as we go forward to engage in discussions with potential partners.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My quick follow-up is, is there any update you can provide on pricing on Tamar in terms of contract structure? And I'll leave it at that.

Charles D. Davidson

Well, no, I don't think so. Because we're -- as Dave, I think, responded on a previous question, we're right in the middle of, I think, making some very good progress on the contract negotiations there. So I'd let that work its course before making any comment on it.

Operator

It appears there are no further questions.

Charles D. Davidson

Thanks, Anna. And I'd like to thank everybody today for their interest in Noble Energy and have a good day.

Operator

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

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