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Executives

David Larson – VP, IR

Charles Davidson – Chairman and CEO

Dave Stover – President and COO

Ken Fisher – SVP and CFO

Analysts

Brian Singer – Goldman Sachs

Dave Kistler – Simmons & Company

Leo Mariani – RBC

Irene Haas – Wunderlich

Dan McSpirit – BMO Capital Markets

David Heikkinen – Tudor Pickering Holt

Rehan Rashid – FBR Capital Markets

John Herrlin – Societe Generale

Presentation

Noble Energy, Inc. (NBL) Q4 2010 Earnings Conference Call February 10, 2011 10:00 AM ET

Operator

Good morning, and welcome to today’s Noble Energy Fourth Quarter and Year End 2010 Earnings Call. At this time, I would now like to turn the call over to Mr. David Larson. Please go ahead, sir.

David Larson

Thanks, John. Good morning everyone. Welcome to Noble Energy’s Fourth Quarter and Year End 2010 Earnings Call and Webcast. On the call today, we have Chuck Davidson, Chairman, CEO; Dave Stover, President, COO; and Ken Fisher, CFO.

This morning, we issued two news releases. One, covering the fourth quarter and full year which goes through some details on our year end reserves as well, and the second one, with our 2011 guidance. Later today, we expect filing our 10-K with the SEC and it will also be available on our Web site.

The agenda for today will begin with Chuck discussing final quarter of 2010 and then we’ll highlight our capital and guidance expectations for 2011. Dave, then will give some detail overview of our operational programs including a summary of our 2010 reserves and a breakdown of our expected activity levels for the current year. We’ll leave time for Q&A at the end and plan to wrap up the call in less than an hour.

We would ask everyone to limit themselves to one primary question and one follow-up today. Should you have any questions that we don’t get to this morning, please give Brad or I a call and we’ll do our best to answer you.

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

We’ll reference certain non-GAAP financial measures today, such as adjusted net income and discretionary cash flow. When we refer to these items, it’s because we believe these are good metrics to be used in evaluating our performance. Be sure to see the reconciliations in our earnings release tables. With that, let me turn the call over to Chuck.

Charles Davidson

Thanks, David, and good morning, everyone. I’m going to go ahead and start this morning with – by covering Noble Energy’s fourth quarter results as well as full year 2010 where certainly we finished up the year with a real strong performance.

Next I’ll go over our 2011 capital and production guidance after which Dave will follow with a deeper dive into some of our recent results and also specific plans for the year.

Overall 2010 was a year of big things for us. We started out the year by adding to our core onshore U.S. position at Wattenberg and building a leading acreage position in the Central Diega basin. The horizontal Niobrara program in the Central Diega basin is still in the early phases of testing a number of the areas of the play going from the core of Wattenberg up into south eastern Wyoming. But our initial results have certainly been strong especially in the core of Wattenberg and the Wattenberg edges, which comprises the majority of our drilling so far. We are just now getting results on the areas outside of the field, but overall the program is clearly having an impact as we see our liquid volumes grow in the U.S.

Offshore we’ve added a number of new opportunities to our portfolio in the March 2010 lease sale. And our current fields there continue to have strong production. Our plans for the Gulf were severely impacted by the Macondo incident and the resulting drilling moratorium, which suspended our Deep Blue and Santiago wells. Despite the moratorium, we’ll – we were able to get permits for completion work at Santa Cruz and Isabella, which enabled us to keep our near development at Galapagos moving forward, which was certainly a big accomplishment for Noble Energy. Significant progress has made by us in the industry as a whole regarding well control, spill containment and clean up. And I feel good about the readiness of the industry to return to drilling in the Gulf.

Internationally we moved forward with the large liquid developments in Equatorial Guinea at Aseng where we completed field drilling and also at Alen where we – which we sanctioned at the end of the year. Our exploration plans offshore West Africa were furthered with new seismic acquisition, which really teased up some drilling this year that Dave will cover.

Finally in Israel, the highlight of the year was certainly the success at Leviathan, our largest exploration find ever and the biggest global deepwater gas discovery in the last decade. Interestingly, number two on that list of deepwater gas discoveries is Tamar, which is in of course the same basin as Leviathan. We operate both and sanction Tamar for development in 2010.

We ended the year with record crude reserves of nearly 1.1 billion barrels of oil equivalent, a big increase from last year as a result primarily of major project bookings at Tamar and Alen and strong reserve replacement in the U.S. led by our DJ Basin activity. This was likely the first of many years of substantial growth in reserves for Noble Energy as we convert huge amounts of discovered resources to proved reserves.

A process of moving discoveries to proven reserves and then to production is all a part of creating value. And the early indications of the scale of our value accretion are now starting to show up. As David noted in the opening, we’ll be filing our 10-K later today which will include the detailed disclosure on our oil and gas proven reserves including the reporting of our standardized measure of discounted future net cash flows related to proven reserves, which is often referred to as the SEC-10 Value.

As a result of the new discoveries that we booked progress on our major projects, and the price benefits related to our liquid risk portfolio, our reported SEC-10 Value this year increased 80% over 2009. So it’s not just about adding volumes; it’s also about adding value.

Focusing in on our fourth quarter and full year financial results, adjusted net income for the fourth quarter 2010 was $185 million or a $1.04 per diluted share after removing adjusted items, which included an unrealized loss on our derivative mark-to-market. Also, we recorded a couple of impairments at yearend that were in the adjustments.

Sales volumes for the fourth quarter averaged 219,000 barrels of oil equivalent per day in the upper half of our guidance range. We had strong performance across the board from our onshore and offshore U.S. assets as well as in West Africa, Israel and the North Sea. Our volumes were down slightly from the third quarter this year as expected due to the impact of the sale of 6,000 barrels a day of mostly oil volumes as well as the loss of 10 million cubic feet a day on average for the quarter due to determination of the production sharing contract in Ecuador. And then we had seasonal fluctuations in Israel.

Full year volumes were over 216,000 barrels equivalent per day right at the high end of our most recent guidance for the year. Rising crude oil and NGL prices continued to help us, and we were definitely able to see the impacts on the fourth quarter as well as throughout 2010 as compared to 2009.

About 20% of our total volume is tied to Brent oil prices, either directly as is the case with international oil sales, or indirectly with our Israel natural gas, a portion of it which is priced off Brent. Brent has been particularly strong recently, currently trading at over $100 a barrel.

On the cost side, I’m pleased with our performance particularly when you look at our lease operating expense and DD&A rates on a per unit basis. Our fourth quarter and full year DD&A rate was in the lower half of our guidance. We were actually slightly below the range on lease operating expense. A strong asset portfolio, combined with the sale of higher cost assets really supported our cost structure this year. As part of our portfolio enhancements during 2010, we were able to trade out of some mature onshore assets for one that has significant running room in the DJ Basin.

Full year expiration expense was slightly below the range mostly because of continued drill bit success. In the fourth quarter, we had some significant seismic expenditures, which included investments in each of our four core areas, offshore West Africa; the Eastern Mediterranean; the Deep water Gulf of Mexico; as well as the DJ Basin. We also acquired 3D seismic offshore in Nicaragua and some 2D seismic in our position offshore France. G&A for the year was right in line with our guidance.

Organic capital expenditures for the quarter was nearly $600 million, making the total for the year at $2.1 billion and discretionary cash flow for the year was $1.9 billion. At the end of the year, total debt was under $2.3 billion and we had over $2.8 billion in liquidity between our cash balances and available credit facility. Our balance sheet is considerably stronger than where our expectations were for this point a year ago. Our liquidity has improved to about $100 million, versus this time a year ago, and it is several $100 million above our prior expectations. Debt book cap has stayed pretty consistent at 25% or 15% when you factor in the cash balances.

Looking back at our goals for 2010, we’ve set out to progress the development and assessment of our major projects, to maintain our strong existing production base, to continue our expiration momentum while retaining our strong financial capacity. I really feel good about all of these areas. Overall our organization did a great job of staying focused on our goals, as well as adjusting quickly to an ever changing environment. Now, on to 2011, with more big things to accomplish this year; the year where we are rapidly approaching growth and production and cash flow driven by our major projects. Execution is key to ensuring that we deliver the greatest value for our shareholders from these projects. Our 2011 capital program is planned at $2.7 billion. That’s consistent with the average five year outlook we laid out in last year’s analyst meeting.

I’m really excited about the progression of our major projects where we’ll spend about 42% of our capital program. Onshore in the U.S., we’re accelerating the horizontal Niobrara play in the Central DJ Basin by more than doubling our well count from last year. Offshore we’re approaching first production from our oil projects at Galapagos in the Gulf of Mexico and at Aseng Offshore Equatorial Guinea, and we’re progressing the developments, of course, at Tamar and Alen as well.

Our investments in expiration will continue to be significant making up nearly 20% of our planned expenditures this year. We’re planning for a return to drilling in the Gulf later this year, and I’ve assumed the three well programs, which includes the Deep Blue and Santiago wells and then an appraisal well at our large Gunflint discovery. Our teams have resubmitted permits for both Santiago and Deep Blue that were both in progress at the time of the moratorium. At Gunflint we anticipate submitting the permit there in the very near future. Timing of permits is very uncertain and as such our program in the deepwater Gulf retains a lot of flexibility.

Internationally, our expiration and appraisal activities are centered in West Africa and the Eastern Mediterranean regions, as well as some of the new venture areas. Combined we’re targeting four to six expiration or appraisal wells between West Africa and the Eastern Med in 2011. The remaining portion of the plan is going towards near-term development projects as well as ongoing maintenance. Here we include the aggressive drilling in our vertical DJ Basin program as well as other activities onshore in our international program such as in the North Sea and China.

Our 2011 sales volumes’ guidance ranges from 208,000 to 218,000 barrels of oil equivalent per day. As a reminder, our 2011 guidance does not include any production from the U.S. offshore, excuse me, does not include any production from the U.S. onshore assets which were sold last year or Ecuador Natural Gas as a result of the production sharing contract termination last year. The contribution from those assets was about 9,000 barrels a day equivalent for the full year of 2010, so you take those volumes out, our comparable volume for last year was around 207,000, and so our guidance for this year would put us about 3% organic growth. That’s using the midpoint of our guidance range. We would expect growth then to accelerate rapidly as we move into 2012 and 2013 with the new projects.

In the U.S. we expect around 2% growth after adjusting for the 2010 property sales, and that will be led by our DJ Basin development program, which is more than offsetting decline from some of the onshore natural gas assets where we continue to commit minimal capital. The deepwater Gulf of Mexico should see some declines from our existing producing assets.

Our international production should grow about 4% this year and that’s led by increased natural gas demand in Israel and then higher volumes in Equatorial Guinea as well.

So it’s really a year about execution for Noble Energy focusing on the strategy set out a number of years ago, executing on the major project developments onshore and offshore across the globe are our highest importance to our teams. We also want to continue the momentum in exploration where we built a real legacy of success. And finally we want to advance our international new ventures as well as the unconventional organic business opportunities to potentially identify new core areas for our company.

We’re on the threshold of entering an exciting period of dramatic growth for Noble Energy.

So with that, I’ll turn the call over to Dave.

Dave Stover

Thanks, Chuck. I will begin by going through a quick summary of our reserves at the end of 2010 before focusing on our recent activity and programs for 2011. We reported total crude reserves of nearly 1.1 billion barrels of oil equivalent with reserve additions replacing over 520% of 2010 production. Additions in the U.S. accounted for about a quarter of the total adds and were led by high levels of activity in Wattenberg along with the Diega Basin acquisition in early 2010.

Our U.S. reserve replacement was approximately 250% despite taking some reserves off the books as the result of the five year PUD rule. Reserves impacted by the five year rule were mainly in our Wattenberg field where we have continued to grow our overall resource potential. And these will be converted back to crude reserves as they are closer to being developed.

Initial major project bookings at Tamar and Alen, both of which we sanctioned in 2010, accounted for the majority of our international adds. Our reserve replacement cost was very attractive in 2010. Looking beyond our crude reserves, I’m just as excited about the continued growth in our net risk resource space, which has grown to approximately 4.6 billion barrels of oil equivalent. While we moved a portion of discovered unbooked resources in crude reserves in 2010, we also grew our discovered unbooked inventory, primarily a result of the addition of over 900 million barrels of oil equivalent net from the Leviathan discovery. Our portfolio of opportunities is large with significant potential in all of our core areas.

As Chuck mentioned, our reported SEC-10 Value took a huge jump this year increasing by over $4 billion from last year. The largest impact was in Equatorial Guinea where our SEC-10 value increased $1.6 billion as a result of progress on the rapidly approaching Aseng project, the sanctioning of Alen and our leverage in this region to higher oil prices. The SEC-10 Value for Israel rose by nearly $1.4 billion due not only to the initial booking of Tamar but also due to rising Israel gas prices, a portion of which are tied to oil price.

And finally, our U.S. SEC-10 Value rose as well driven by both increased reserves and increased pricing. While there are many assumptions that go in calculating SEC-10 Values and measures, and by no means perfect, directionally, the increase this year is clearly indicating that significant value is coupled with the reserves we are adding.

Turning to our current operations and 2011 plan, let’s start with our international activity. In West Africa capital program for 2011 is about $575 million with 80% allocated to development. Our development focus is on finalizing preparations for first oil at Aseng and progressing the Alen project.

During the fourth quarter, we made substantial progress on the well work at Aseng utilizing two rigs in the field. The Atwood Hunter rig drilled and completed three production wells in the second half of the year, and under our contract sharing arrangement, elect Equatorial Guinea waters in December go to another operator. The Pride South Pacific rig is finishing the remaining well activity with an estimated completion in the next two months.

We have now installed all 10 of the subsea trees and completed our subsea manifold fabrication and system integration test. The FPSO dry dock haul renewal work is completed, and overall, I feel very good about the state of operational readiness.

Aseng remains a very significant project for us targeting 17,000 barrels a day of net oil production. Adding Alen will increase our liquid oil production in this area to around 35,000 net barrels per day. As Chuck mentioned, Alen was recently sanctioned by our board, partners as well as the government of Equatorial Guinea. We have progressed the final project design and awarded a number of key contracts including the platform fabrication and installation.

We anticipate having the wellhead jacket installed in the latter part of this year at which time development drilling and completion work for the producers will begin. The Atwood Hunter rig, once it returns to us at the end of the third quarter, will support the drilling and completion work for the injection wells.

Our exploration capital for West Africa this year is planned at around $110 million and includes two to three exploration wells, one of which will be an appraisal well in the Carmen/Diega area. This well should spud the second quarter with the Pride South Pacific rig. The processing of 3D seismic from our recent Cameroon acquisition is ongoing along with the retail abrasion of our Equatorial Guinea data and this will set up the one to two West Africa exploration wells in the second half of the year targeting additional oil opportunities.

Moving to Israel, at our existing Mari-B asset, full year gas production was up 14% in 2010 over 2009 volumes highlighting the continued growth in demand for natural gas in Israel. In the next couple of months, we will complete the installation of compression on the Mari-B platform giving us the ability to continue delivering strong sustained and high peaking gas volumes until Tamar comes online. This work is being done in advance of the summer timeframe which is a period of increased demand.

In 2011, we anticipate spending approximately $650 million in the Eastern Mediterranean with around $500 million allocated to development and the remained to exploration and appraisal activities. At Tamar, the Sedco Express rig is anticipated to be on location by April after finishing current operations at Leviathan. Development drilling at Tamar should last about a year with plans to drill four wells and complete five. Pipeline installation is scheduled to begin around August of this year and the platform, which began fabrication late last year, is targeted for installation in the second half of 2012.

We also expect to begin expanding the Ashdod onshore facility this year to increase our ability to deliver up to one Bcf per day. Drilling activities at Leviathan are continuing with plans to reach total depth by the end of the first quarter. The deeper potential has a very low chance of success, but will provide additional knowledge about exploration potential in the basin. Our exploration and appraisal plans for the Eastern Mediterranean include three to four wells in 2011, with a top priority to appraise the Leviathan natural gas discovery.

The Pride North America rig will arrive by the end of this month to drill the first Leviathan appraisal well about eight miles northeast of the original discovery location. Our objective is to further confirm our understanding of the structure and gross mean resources of 16 trillion cubic feet and we plan to flow test the reservoir at that time. We should have results by the second quarter earnings call. Our evaluation of several gas monetization options continues as we identify the best markets for the gas resources at Leviathan.

Turning to international new venture activity and Nicaragua, we have recently completed a 3D seismic survey and have a 2D program currently underway on our position offshore France. We will be spending the year analyzing results and determining the next steps for these programs. Overall our international business represents nearly 50% of our capital program for 2011.

Moving to the U.S., we’ll spend about $1.4 billion in 2011 with 80% for development activities and the remaining portion for exploration. Our deepwater Gulf of Mexico expenditures are estimated to be about $275 million with a little more than half going to development primarily at Galapagos and South Raton. At Galapagos, we finished the well completion activities at Santa Cruz and Isabella in the fourth quarter last year and we’re working closely with BP to progress facility preparations for first oil. The production handling agreement for South Raton oil has been finalized and we will be completing the subsea production system hook up in the second half of the year. Combined these two projects will add 10,000 to 12,000 barrels of oil equivalent per day net.

On the exploration side, Chuck mentioned our three well plans for the year consisting of Santiago, Deep Blue and a Gunflint well. I want to highlight the great job our deepwater team has done leading a lot of the effort to pull together generic and well specific responses to various BOEMRE requirements, especially related to subsea containment. Our partnership with Helix and Clean Gulf gives us access to the equipment and personnel to respond to a well control incident.

Turning to the onshore U.S, the Central Diega Basin program represents most of our onshore spending. Our plans for the Diega Basin will be to maintain a high level of activity in the vertical well program between new well drilling, refracs, tri-fracs and recompletions in the Wattenberg field. At the same time we will be expanding our horizontal Niobrara program based on our results and a focus on continuing to appraise our acreage. We’re planning to drill north of 70 horizontal Niobrara wells this year up from 27 last year.

We currently have three horizontal rigs drilling in the basin. Our plans have us growing to four in the April timeframe and then five in the second half of the year. These rigs will move around but on average we’ll have three to four in Wattenberg with one shared between Northern Colorado and Wyoming. Our goal is to accelerate activity in areas where we know the potential is defined. For us this is in Wattenberg, both in the core of the field and on the edges, areas where we have nice success to date and our growth outlook is not constrained by infrastructure. We’ll continue delineating our acreage position in Northern Colorado and Wyoming but at a more paced approach as compared to our plans for Wattenberg. This gives us time to test a number of different areas, learn from others in the northern part of the play as well and allow for needed infrastructure development.

In Wattenberg, including both the core of the field and the edges, we have now drilled and completed over 25 horizontal wells. So far results have confirmed high quality Niobrara horizontal potential across half of this 400,000 acre position. Twenty-one of our wells have been online for more than 30 days with an average 24-hour IP of about 750,000 barrels of oil equivalent per day, and a 30 day average of over 500 barrels of oil equivalent per day at 45% to 75% liquid content. In the heart of the field we have just now completed our sixth well, and the overall results are very strong. One of our most recent Gemini type wells, the Hanscom (ph), started with a 24-hour IP of over 1,250 barrels of oil equivalent per day and averaged 900 barrels of oil equivalent per day for the first 30 days on a restricted choke up the casing.

We’ve completed 13 wells testing the outlying edges of Wattenberg. Liquid contribution in this area exceeds 70% and has allowed us to drill economic horizontal wells where vertical wells were previously marginal. Our latest estimate based on production history and our updated outlook for horizontal Niobrara, EURs in Wattenberg is around 310,000 barrels equivalent per well, up from our previous 290,000 estimate.

In northern Colorado we have drilled and completed four wells in our 190,000 acreage position to date. We are encouraged with the results of our first two wells drilled with IPs that were 500 to 600 barrels of oil equivalent per day and 85% oil contribution. Analysis indicates we did not effectively stimulate our next two wells, and we have adjusted our planned completions for the following three wells in this area. We’re still optimistic about what we have learned so far, and our fifth well in the area will be completed by the end of February, and the next two will be completed by early April.

The third phase of our horizontal Niobrara program is in southeast Wyoming where we have drilled three wells. Two are undergoing completion operations and one has just been completed and put on artificial lift. Our next drilling in this area will begin in the second quarter.

Supporting our overall DJ Basin program in 2011, we have committed to the purchase of approximately 1,000 square miles of spec 3D seismic, and will be integrating the data into our future plans during the second half of the year. Across our 830,000 acre position, we will have 1,300 square miles of 3D by the end of the year.

Looking at our total company volumes, first quarter of 2011 sales volumes should range from 202,000 to 212,000 barrels oil equivalent per day. Compared to the fourth quarter of 2010, we anticipate some natural decline in planned down time in the deepwater Gulf of Mexico and natural decline in the onshore gas properties outside of the Diega Basin. Internationally, seasonal demand in Israel will result in lower volumes and the Ecuador volumes ended in late November as the Tcf was terminated.

Similar to 2010, we should realize significant volume build in the second half of the year from sustained growth in the Diega Basin program as well as higher seasonal impacts and demand growth in Israel. Overall our 2011 program is positioned to execute our major projects portfolio, build off our exploration success and continue to develop our high return liquid rich opportunities.

At this time John would like to go ahead and open the call to questions.

Question-and-Answer-Session

Operator

(Operator Instructions) We’ll take our first question from Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you. Good morning.

Charles Davidson

Morning.

Dave Stover

Morning, Brian.

Brian Singer – Goldman Sachs

In the Niobrara, can you talk to the liquids variability that you’re seeing? You mentioned I think rates between – percentage of liquids between 45% and 85% depending on the area you are in as you kind of go from Gemini into Northern Colorado. And can you just talk to what, if anything, the variation in the liquid deals that says about the repeatability of the play?

Ken Fisher

Yeah. Brian, I think when you look at what I would call the heart of the field, the Gemini Hanskin (ph) area, you’re seeing kind of that 45% to 50% liquid yield. You get up to the kind of the edges of the field you’re getting up into that 70% to 80% liquid yield. I think as far as the variability, we’re seeing fairly consistent results in each of those areas, but different results obviously in each area as far as liquid yield. And I think from what we can tell from the 20 some wells we’ve drilled and now about, what, six down in the heart and the rest more up in the edge of the area, what we’re seeing is pretty repeatable results in both the edge of the field and in the heart of the field.

Brian Singer – Goldman Sachs

Okay. Got it. Thanks. And then...

Ken Fisher

Yeah...

Brian Singer – Goldman Sachs

Go ahead. Sorry.

Charles Davidson

And I’d just add that it all makes sense on the liquid yields with the core of the field that – with Wattenberg core being a hot reservoir and then as it cools off and certainly goes cooler to the north this is exactly what you would expect.

Brian Singer – Goldman Sachs

Great thanks. Last year you sold some non-core assets. How do you think about asset sale potential this year? And would you consider selling any of your position in the – in the Niobrara if you could partner?

Charles Davidson

Well I think – I mean we keep a lot of flexibility on our portfolio obviously. Right now we’re working hard to really evaluate all of these areas in the Niobrara and, as Dave mentioned, we have only limited results in a large portion of our acreage positions, the northern Colorado and Wyoming. So I think our view is, is before we’d even think about a partner, we’d want to make sure we understand the results. Timing, I mean we, we have the capital to carry out our program there. So we just have to, again, I think we need to get a little bit more results, and Dave, you might add some more color to that as well.

Dave Stover

No, I mean I agree with that, Chuck. When you think about outside of Wattenberg we’re just starting to tap into that area and as – we’re learning as we go. I think the concentration there is making sure we get effective completions on the matrix and I think we’re learning a lot on that just with a little bit of information all ready.

Brian Singer – Goldman Sachs

Great, thanks. If I could ask one last one. You reported about 15,000 barrels of NGL lines in fourth quarter guidance for the U.S. is about 10 to 12. Is there anything specific about the increase in the fourth quarter or in the 2011 guidance?

Charles Davidson

No, I don’t think there’s, there’s anything more specific on that. I think you – it depends on the processing margins. We do get quite a bit of liquid contribution from our deep water Gulf production and as we noted we’re expecting some decline in that production through the year. And so that will affect the NGL volumes a bit.

Brian Singer – Goldman Sachs

Great. Thank you much.

Charles Davidson

Thank you.

Operator

We’ll now move on to our next question from Dave Kistler with Simmons & Company.

Dave Kistler – Simmons & Company

Morning, guys.

Charles Davidson

Morning.

Dave Kistler – Simmons & Company

Real quickly, in Israel, can you talk a little bit about the latest tax and royalty negotiations and whether that impacts timing of Tamar, the development process, funding of partners? And then kind of as a follow on, on, on that with the current unrest in Egypt, how is that impacting the overall picture there?

Charles Davidson

Sure, maybe just to start out, for those who are not familiar with the – on the taxation issues in Israel, a committee that was assembled has made a preliminary recommendation and then they came out with the final recommendation just in the beginning of the year which the Prime Minister and the cabinet supported. It still has to go through the Knesset and so that’s a legislative process that is underway. The final recommendation the committee did make some improvements from their preliminary recommendation, I think most notably is it reduced the impact on Tamar, both in terms of the overall taxation that would be on Tamar as well as preserving a lot of the near-term. And what I mean near-term, I’m talking about the first seven to eight years of cash flow from Tamar.

So I think that was some welcome enhancements, but we still have to wait for the Knesset to go through this process. We are still moving the Tamar project forward. Dave talked a lot about the progress we’re making there. I think the – certainly, as we’ve seen the unrest in Egypt, in the Middle East more recently, it just demonstrates to everyone, ourselves and those in Israel, about how important Tamar is and how much value it will have as it comes on stream in just a couple of years. So as a result, I think everyone recognizes that the discoveries we’ve made there are adding tremendous value, and certainly, energy security to Israel. And in Egypt, Egypt did have to suspend their gas sales to Israel as a result of an explosion on their pipeline. Our expectation is that they will likely be able to resume those sales in a few weeks. However, in the meantime, our Mari-B facility did pick up the entire load and we are now supplying all the gas needs of Israel through Mari-B.

Dave Kistler – Simmons & Company

Great. That’s very helpful. Maybe hopping over to the Gulf of Mexico real quickly, interesting that you budgeted about 10% of the budget for deepwater Gulf of Mexico. I wanted to just kind of get your sense on how that environment’s improving. You indicated you resubmitted permits for two of the wells and have another one coming in soon. Past experiences had permits go back and forth as many as seven times? Can you just kind of give us your latest thoughts on how working through that system has been and where you see it in the evolution of maybe moving to just suspended wells that you’re going after now to ultimately raw expiration wells?

Charles Davidson

Well, I’ll start and Dave can fill in on that. First of all, we have made, I think, a lot of progress on the, what I call the re-permitting of those suspended wells, and it has been an interim process. We’ve gone back and forth a number of times, and I think it’s a learning process on the part of the government as they interpret the new requirements and make sure that they are getting the information needed so that they can be comfortable in approving these permits. And I do feel that we are getting close on the permit applications for the wells that have, that were suspended, especially Santiago, which is our lead permit well. It’s taking a lot of work. The permit volume is huge, but again, our teams have done a great job of working through all the issues from well design to containment to spill response to rig enhancements and rig verification of the capabilities, so it’s moving forward on that well.

I have less certainty about new wells that go beyond say the suspended wells because those, according to the notifications we’ve gotten, will require individual environmental assessments. That process is still being defined. That will take time, and as a result I think we will move into that process, but it will be slower, and it’s harder to forecast when they will be in a position to issue those permits.

Dave Kistler – Simmons & Company

Well, Chuck, thank you very much for that color. It’s very helpful.

Charles Davidson

You bet, Dave.

Operator

We’ll move onto our next question from Leo Mariani with RBC.

Leo Mariani – RBC

Good morning, guys. A couple quick questions here for you, in terms of your 2011 U.S. production guidance, you guys are talking up 2%. It sounds like you’re expecting deepwater to be down. Are you guys still expecting Galapagos and South Raton to contribute kind of at the end of the third quarter, early fourth quarter when those projects come online?

Dave Stover

Yeah, Leo. When you look at the U.S. guidance, kind of the three pieces there, you look at deepwater. That’ll probably be down 25 to 30%. We really don’t have much impact in there for Galapagos or South Raton. Those would be in kind of at the end of the year right now is the basic assumption. Then underneath that you have your decline in your basic gas outside of Wattenberg profile. That’s probably down about 10% or so, and then you have the growth from the Central DJ Basin, which is kind of double digit 10% to 15% growth. So that’s kind of how the whole U.S. piece fits together.

Leo Mariani – RBC

Great. That’s great color there. Okay. I guess kind of jumping over to international I guess you guys are saying you’re up 4% on the year. It sounds like Israel is going to be up Equatorial Guinea is going to be up. Are you expecting North Sea to be down at all? I understand – I think you guys have brought some wells on recently, just trying to get some color there on that.

Charles Davidson

Yeah. I think you’re right on target there. I think North Sea will be down somewhat from first quarter – first half of the year to second half of the year. But Equatorial Guinea will be up some. We had some maintenance down time last year that impacted 2010, so we’ll start to get some of that back. And then just a continued growth in Israel we expect to help push that up a little bit.

Leo Mariani – RBC

Gotcha. Okay. I guess with respect to Ecuador, are you folks expected to get any kind of monetary compensation from that contract? How are you guys thinking about that?

Ken Fisher

Well, clearly we expect to be – get and receive some compensation for the termination of the PFC, there’s a couple of options there. But what was reported near the end of last year, we’ve been in discussions with the government and hopefully we’ll resolve it through a – basically a sale in compensation for the assets.

Leo Mariani – RBC

Gotcha. Okay. In terms of the Niobrara, I think you guys had a couple of wells you put on pump about a quarter or so ago. Just curious to see if you have any update in sort of how some of those wells that were outside of Wattenberg were performing while on pump.

Charles Davidson

No. I think the couple – the first couple that we have just in Northern Colorado, those look like economic wells. They’ve kind of flattened out once we put them on artificial lift. And they’re still lining out, getting those set up. I think the real next interesting point for us will be getting the next three wells drilled and completed up there because we’re making some changes in our completions. I think we’ve really learned a lot. And like I mentioned earlier, we’re really focusing on how to make sure we bust this matrix up and get the biggest contribution out of the matrix up there.

Leo Mariani – RBC

All right. Thanks a lot, guys.

Operator

Moving on to our next question, we’ll take Irene Haas with Wunderlich.

Irene Haas – Wunderlich

Yeah. Hi. Following on the Wattenberg, Niobrara, just wondering, the Gemini type wells, how many more horizontal wells can you kind of thread into each of the sections, the 640 acre? And there’s been some talk about actually shutting down the vertical well and re-developing part of the core as horizontal. And maybe some color on that?

Dave Stover

Yes, Irene, it’s a good question and it’s one we’re still sorting through ourselves as to what’s the right mix of horizontal and vertical wells and what’s going to be the actual drainage that we see from these horizontal wells. I mean what we’re starting out with the assumption that we’ll end up with kind of four wells per section on a horizontal basis and at the same time mix in a vertical program. So we’re going to keep both programs going here this year as we get some more information and we’ll continue to look at that and tweak that as we go. I mean the main thing we’re looking at is what kind of recoveries are we really getting in each section. I mean we’ve talked about before the low recovery on vertical well, where it’s under 8% or so. When you just look at four wells per section on horizontal, you’re still only looking at about 5% from that. So, there’s still a huge prize there to continue to optimize how we recover this. So I think that’s what we’ll be continuing to try and learn and adjust as we go.

Irene Haas – Wunderlich

Okay. Great thank you.

David Larson

And I think also as we get more information on the Gemini type wells, but I think so far it’s safe to say we’ve not seen interference between the existing vertical wells and the horizontal wells. So that just adds to the credibility that you can – you’ve got a lot of untapped potential in – within Wattenberg even in the areas that have been developed.

Irene Haas – Wunderlich

Could this end up being sort of a time (indiscernible) type scenario where each year you go in and you just find out you can down space some more.

Dave Stover

Well, I guess we’ve been doing that for a couple of decades already on Wattenberg. So we’re still learning.

Irene Haas – Wunderlich

Great. Thanks.

Dave Stover

Thank you.

Operator

And we’ll now take our next question with Dan McSpirit from BMO Capital Markets.

Dan McSpirit – BMO Capital Markets

Folks, good morning, and thank you for taking my questions. How many vertical wells will be drilled in 2011, this year, to the Niobrara?

Charles Davidson

Yeah, well, when you look at our vertical program it’ll be approximately 500 wells, Dan, and that includes a mix of a number of them. While most all of them will go through the Niobrara, some of them will be combinations of Codell/Niobrara; some will be J-sand wells still.

Dan McSpirit – BMO Capital Markets

Okay, and at what point are the horizontals drilled in the Niobrara greater than the verticals? That is at what point what year is it – should we expect a crossover to occur?

Dave Stover

Yeah, I, I don’t think we’re at a point in being able to predict that yet.

Dan McSpirit – BMO Capital Markets

Okay.

Charles Davidson

I mean part of it has to be what – the Codell which has been the bread and butter at the Wattenberg field is – I think the date we drilled one well, one horizontal well in the Codell, but it’s, you know, you still have to understand how best to develop the Codell. So it’s I think right now our view is that we’ll continue to have a mix, and that mix will change over time. But as Dave says, we really can’t forecast right now the exact trend on that.

Dan McSpirit – BMO Capital Markets

I understand. Understand and I guess on the subject of Codell, you consider that a separate and distinct reservoir even drilled on a horizontal basis I assume. Do you get any contribution at all for the Codell when putting the Niobrara on a horizontal basis?

Charles Davidson

I think from – and very limited knowledge at this point. I don’t think we’re seeing a contribution really from the Codell yet. I think that speaks to the whole continued learning process, how do we best drill horizontal wells out here in this 200 to 300-foot section, especially when you get – again, you go back to the recovery of this and how do we continue to look at improving recovery vertically on a horizontal basis and placement of the horizontal wells out here. And I think that’s something we’ll continue to understand and work on as we move forward.

Dan McSpirit – BMO Capital Markets

Understand. And one last one if I could, can you tell us anything about your activity in Montana, specifically, Sweet Grass County, Montana, and even more specifically, the Sweet Pea well that you’re drilling there in terms of targeted formation, your land position in Montana, plans going forward?

Charles Davidson

Yes. That’s the area we talked about. We got a couple of hundred thousand acres and we’ve drilled one, two wells up there, just starting completion activity. They’re vertical wells. So far, we’re just drilling some vertical wells for information at this point, and then we’ll adjust and set out a program from there based on what we learn. I mean we’re way early in that process. Again, what we’re focusing on is the probably the gas condensate portion and the oil portion of the potential play up there.

Dan McSpirit – BMO Capital Markets

Very good. Thank you very much.

Charles Davidson

Thanks, Dan.

Operator

We move on to our next question from David Heikkinen with Tudor Pickering Holt.

David Heikkinen – Tudor Pickering Holt

Good morning, guys. As I think about your guidance for this year, you gave a lot of good details on kind of regional expectations. Can you talk about what events drive the range of outcomes in each region? Are there any specific events or just a kind of statistical outcome?

Dave Stover

Well, I mean when you think about some of the bigger drivers, in deepwater for example, it’s the underlying decline that’s the biggest piece. And then you’re getting into the timing of new projects. And right now we’re not assuming we’re going to see much impact from the new projects rolling into 2011, big impact in 2012, obviously. If you look at Israel, which is another one that fluctuates dramatically even from quarter to quarter on seasonality and assumptions that what are they taking from Egypt or what aren’t they and seasonal and weather patterns and so forth, that has a big drive. That probably has the biggest float.

David Heikkinen – Tudor Pickering Holt

Okay. And then as you think about the kind of setup for going into 2012, can you just talk about timing of each major project? Again, just give us an update on expected setup for Tamar and then Aseng and then Alen?

Charles Davidson

Well, I think if you start, first of all, the assumption would be at the beginning of 2012, you’d be seeing, as Dave said, the full effects of Galapagos and South Raton in the deepwater of Gulf of Mexico. Those, backend of this year into early 2012, moving into closer the mid part of 2012, we’ve got a same targeted come-up as to about 17,000 barrels a day of net production. Again, that’s right on track.

For Tamar, we have pushed it back to where we say it’s commissioning in late 2012, and then, depending on that commissioning process, it should be ready to produce then in very early 2013. And right now, just to finish up that period of time, we would show Alen at late 2013. Now coming on, again, that’s about 18,000 barrels a day net.

So, that’s kind of the major projects. Now, along the way, if for instance like a Santiago is successful, then that can be added to the Galapagos development and that would piece in. But that kind of gives you the kind of big chunks. Anything else to add on that, Dave?

Dave Stover

No, that’s right on point, Chuck.

David Heikkinen – Tudor Pickering Holt

And as you think about the path of capital spending with each of those major projects, I know the ramp isn’t out there, can you just talk about where you are from an international cash flow and the domestic cash flow and how you’re thinking about allocating capital and just kind of the methodology applications and that as your international continues to grow?

Ken Fisher

Sure. This is Ken Fisher. We communicated consistent with what we said at the Analysts Meeting that will be spend at about 2.6 billion a year for the next few years, about 40% on major projects, about 20% on expiration and the remainder then to maintain and the near term opportunities in the portfolio. We lead the year in very strong position from a debt and cap metrics and liquidity standpoint. Most of our cash is CFC cash and that’s available to fund, same in Alen and Tamar and ultimately Leviathan. And as you – as was mentioned, when we start to see the ramp up in production in 2012, as what was just discussed, you’ll start to see that strong cash generation from that particularly the liquids projects in West Africa and the cash flows as Tamar grows – comes online and grows in 2013. So we feel well positioned to be able to fund the program and to be essentially cash generative as these projects come online. We continue to work to be in a conservative position and keep the investment grade. So I think we feel good.

David Heikkinen – Tudor Pickering Holt

And as you think about production from each of those international projects, so take Leviathan, Tamar, all the Brent tied on an oil price I would assume, is that a fair way to think about them?

Charles Davidson

Generally in Israel the pricing certainly that we have – to go to the electric utility, the big utility there has had an index off from Brent and other liquid fuels. And so we expect that to be the case. It’s not a one for one obviously, but it’s a – it allows us to see upside as just like we’re seeing today from Mari-B as a result of stronger Brent prices.

David Heikkinen – Tudor Pickering Holt

So do you have and expectation for WTI in France?

Charles Davidson

Yeah. Just let me finish on that for a minute.

David Heikkinen – Tudor Pickering Holt

Yeah. Sorry.

Dave Stover

You added at the end Leviathan as a reference. But with Leviathan I guess I would just say that Leviathan is a – is going to be a whole different marketing concept and I think it’s too early to say just exactly how it would be priced. So I kind of limit my comments to the existing Mari-B and Tamar when we talk about Brent indexes.

David Heikkinen – Tudor Pickering Holt

That’s fair. I can’t get you to commit to LNG is what you’re telling me. So – thanks, guys.

Dave Stover

Thank you.

Operator

We’ll now move on to Rehan Rashid with FBR Capital Markets.

Rehan Rashid – FBR Capital Markets

Morning. Just two road questions, one on the offshore France, maybe a little bit more details there. And second on Niobrara, choking it back, is that something that we should expect going forward? And geologically speaking, what’s driving that?

Dave Stover

In the offshore France, we picked up a position this past year of about a couple million acres where we’ve got a little over 70% interest and we’re shooting a fairly wide regional 2D program now to help us identify where we may want to go in and pinpoint additional 3D leading to future drilling down the road. So that’s kind of the status of that. The reference to restricted rate on Niobrara, I think you’re talking about that Hanscom (ph) well. That was just initially as we were producing up casing there and we had it kind of on a choke restrict rate to control velocities on that until we could go ahead and put tubing in the well and get that set up for normal flow, so that was just an isolated situation there.

Rehan Rashid – FBR Capital Markets

Thank you.

Operator

Moving on, we’ll take our next question from John Herrlin with Societe Generale.

John Herrlin – Societe Generale

Yeah. Hi. Just a quick one on Tamar, you listed what you booked in your release. It said you still have about 40% left to go in terms of the overall net exposure.

Dave Stover

John, that’s correct, and by the way, it’s great to hear your voice on the call.

John Herrlin – Societe Generale

Thanks.

Charles Davidson

Yeah. We have, based on the analysis that we’ve done at Tamar, we looked at the initial booking area, and again, that’s based on our two wells and the fault blocks that they penetrated or that are connected with them, and we would expect that as we carry out our development work at Tamar, we will then prove up some of the additional volumes. So that was kind of the methodology. We carefully went through that with our internal teams as well as Netherland, Sewell that does our reserve audits, and we’re very comfortable in that type of approach.

John Herrlin – Societe Generale

Super. Thanks, Chuck.

Charles Davidson

Thank you, John.

Operator

At this time, we have no further questions. I’d like to turn the call back over to our speakers for any additional or closing remarks.

David Larson

Yeah. I’d like to thank everybody and appreciate their interest in Noble Energy, and have a nice day.

Operator

Ladies and gentlemen, that does conclude today’s conference call. Thank you for attending.

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