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Executives

David R. Larson - Vice President of Investor Relations

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

David L. Stover - President and Chief Operating Officer

Analysts

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Robert S. Morris - Citigroup Inc, Research Division

John P. Herrlin - Societe Generale Cross Asset Research

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

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

John Malone - Global Hunter Securities, LLC, Research Division

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

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

Paul Crovo

Noble Energy (NBL) Q4 2011 Earnings Call February 9, 2012 10:00 AM ET

Operator

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

David R. Larson

Thanks, Celia. Good morning, everyone. Welcome to Noble Energy's Fourth Quarter and Year-End 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 2 news releases, one covering the fourth quarter and full-year earnings, and the second one was for our 2012 guidance. Later today, we expect to be filing our 10-K with the SEC, and it will be available on our website.

The agenda for today will include -- will begin with Chuck discussing final fourth quarter 2011 results and then will highlight our capital and guidance expectations for 2012. Dave will then give some detailed overview of our operational programs, including a summary of year-end reserves and a breakdown of our expected activity levels for the current year. We will leave time for Q&A at the end and plan to wrap up the call in less than an hour. [Operator Instructions] Should you have any questions that we don't get to this morning, please don't hesitate to give us a call, and we'll do the best we can answering 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 periods to differ materially from what we discuss today. You should read our full disclosures on forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business.

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

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

Charles D. Davidson

Thanks, David, and good morning, everyone. I'm going to start out with a brief wrap-up on 2011 and then go into an overview of our plans for this year. As David said, Dave Stover will follow up with the operational highlights, as well as details on our planned work in each of our 5 core areas in 2012.

I have to say up front that 2012 is the year that certainly I've been waiting for, and I think I can speak for the rest of the Noble Energy team as well on that. You can see early indications why when you look at our fourth quarter results, results that included the start-up of Aseng, the first of many major projects that we're pursuing globally; it also included the first contributions from our newly added Marcellus Joint Venture; and another quarter, actually our third quarter in a row, of record DJ Basin production, driven by outstanding horizontal Niobrara results; and finally, the announcement just before the end of the year of yet another major gas discovery in the Eastern Mediterranean, in Cyprus.

All great results but not the only reasons I'm excited about 2012. This year marks the beginning of a multi-year period of growth for Noble Energy, driven by major projects and programs in each of our 5 core areas. As we announced at our Analyst Day back in November, we now expect the annual production growth over the next 5 years to average 17% per year. On a debt adjusted per share basis, we expect not only production but cash flow and reserves to grow at double-digit rates over the next 5 years.

Starting in 2012, we begin realizing the benefits from multiple years of exploration success and the strength, balance and diversity of our portfolio. The early start-up of Aseng offshore Equatorial Guinea clearly demonstrated our ability to deliver on projects of significant magnitude. Projects of this scale would not have been possible for us several years ago, but they're well within our capabilities today, both technically and financially. Our exceptional project execution, whether in the international deepwater such as Aseng or onshore U.S. such as the Wattenberg horizontal Niobrara, now parallels our best-in-class exploration program and gives us good reason to be confident about our future growth.

With Aseng now onstream and Galapagos ready to go shortly in 2012, Tamar in early 2013, Alen in late 2013, followed by many other developments, our major exploration discoveries are now turning into real production, cash flow and profitable growth with growing margins.

While our guidance for 2012 suggests strong overall growth this year of 13%, the real headline is that with Aseng, Galapagos and the Niobrara, we expect growth in oil production this year of 40% over 2011. At today's oil prices, that will drive real value growth, and that really gets us excited.

2012 -- excuse me, 2011 was a year in which Noble Energy experienced many unique achievements. Early in the year, we received the first post-moratorium drilling permit in the Gulf of Mexico, which resulted in the discovery of Santiago. Our Eastern Mediterranean portfolio was expanded through exploration, especially with the sizable discovery offshore Cyprus, and enhanced through our successful appraisals of Tamar and Leviathan. With the Tanin discovery announcement recently, we've now discovered approximately 35 trillion cubic feet of gross mean resources in the greater Levant Basin.

In our horizontal Niobrara program, we doubled our activity in 2011, which allowed us to de-risk the Wattenberg Niobrara resources and to extend the field's economic area by over 60%. We've also added a fifth core area to our portfolio through the joint venture with CONSOL Energy in the Marcellus, one of the lowest cost domestic gas plays, which further deepens and diversifies our global project inventory. And I'll talk more about the Marcellus later, as will Dave.

As you can see, we accomplished a tremendous amount in 2011, and we did it while maintaining our financial discipline and strong returns. We further enhanced our liquidity and lengthened our debt maturities by successfully completing 2 public debt offerings. Our most recent debt offering included a 10-year $1 billion unsecured note at a very favorable interest rate of 4.15%. We ended the year with a liquidity of $4.5 billion, $1.5 billion in cash and equivalents and $3 billion available on our new credit facility.

Our press release also included a summary on year-end proven reserves. We ended the year with record reserves of over 1.2 billion barrels of oil equivalent, an increase of 11% from last year. All-in replacement of production totaled approximately 245%. Major reserve additions were in the Marcellus, the DJ Basin and Tamar offshore Israel. We still have another 3.3 billion barrels of oil equivalent of discovered unbooked resources, a majority of which we expect to convert to proved reserves over the next several years.

I will be reporting in our 10-K and SEC 10 valuation for year-end 2011 of $13.3 billion. That's an increase of just over 45% from last year. The increase was driven by our Marcellus acquisition, additional reserves from Niobrara and Tamar and higher oil prices. In the past 2 years, our SEC 10 value has climbed from $4.9 billion at the end of 2009 to the $13.3 billion at the end of last year, representing an increase of nearly 170% over the 2-year period. Although not a perfect measure, this increase does indicate the tremendous progress we're making in shifting unproven resources to proven reserves and the completion of major projects, all of which leads to growth and value in our company.

In the fourth quarter, our performance was demonstrated by strong metrics. Adjusted net income for the fourth quarter was $211 million or $1.18 per share diluted. After removing adjustment items, including an asset impairment charge and an unrealized loss on commodity derivative hedges. As noted in our press release, the fourth quarter included $41 million of other operating costs, mostly due to the disposal of surplus inventory and reserves for legal settlements. The quarter also included $22 million of deferred compensation charges. All of these were essentially non-cash charges. Discretionary cash flow for the quarter was $677 million.

The asset impairment charges totaled $620 million and relate to various non-core onshore U.S. dry gas assets. They are a result of declining domestic natural gas prices that are in areas such as Piceance and Tri-State. These assets have received limited investment dollars as we have continued to focus our investment programs, primarily on oil or liquids-rich opportunities rather than the dry gas regions.

Sales volumes for the quarter averaged a record 233,000 barrels of oil equivalent per day, which was an 8% increase over the fourth quarter 2010, excluding volumes from Ecuador, which we exited in 2011. Oil production was up 11% over the prior year's quarter, driven by the early start-up at Aseng and growth in the horizontal Niobrara.

Revenue for the quarter was $985 million. That's up 25% from the fourth quarter of last year. The revenue growth was almost entirely driven by our liquid sales, which were supported by higher volumes and strong prices. The stronger oil volumes, coupled with their increased prices, helped grow margins even though we had higher lease operating expense and DD&A rates. Our full-year sales volumes were 222,000 barrels of oil equivalent per day, at the high end of the adjusted guidance we provided last quarter and a record in terms of annual sales volumes for the company.

Our capital plan for 2012 is set at $3.5 billion, which is slightly below the outlook we gave at our analyst conference in November. In this dynamic environment, there are quite a few moving pieces, and we continue to reallocate capital to the best projects in our diverse portfolio. Over 50% of the capital spending supports developments of our onshore U.S. properties.

In Marcellus, our economics are fully aligned with our partner, CONSOL Energy, in the current low price natural gas environment, and we share a similar returns-based approach in capital allocation. We have jointly decided to slow the pace of development in the dry gas regions of the field, and as a result have cut around 40 wells from the original 2012 drilling plan. Dave will give you more details later.

The reduction in the Marcellus drilling, coupled with the fact that the deal's low-gas price circuit breaker was tripped, which deferred the drilling promote this year, has reduced Noble Energy's net 2012 investment in the Marcellus by approximately $250 million. Noble Energy has reallocated a portion of this capital with a higher return horizontal Niobrara program to Wattenberg.

We continue to transition more of our vertical Wattenberg development to horizontal drilling, which offers better recoveries and returns. We are at full development mode in this field, while we continue to expand our program into Northern Colorado. And again, Dave will provide you some specific data points that attest to the size and scope of our operations there.

The next largest segment of our capital program comprises our international portfolio and accounts for approximately 40% of our planned investment in 2012. The funds there largely support the development work on Tamar and Alen, as well as continued exploration in the Eastern Mediterranean and West Africa.

And in our final area, the Deepwater Gulf of Mexico, we'll invest approximately 7% of our capital in both development and exploration programs.

Overall, our exploration encompasses about 16% of this year's capital program. The exploration program remained a big driver of our success, and we actively search for material opportunities with running room. The targeted exploration and appraisal wells are the primary mechanism by which we build our pipeline of future development projects. We tend to -- we intend to drill exploration wells in West Africa, Eastern Mediterranean and the Gulf of Mexico this year. We believe our core areas have significant growth potential, but we will also continue our efforts as a global explorer to look for other attractive opportunities as well.

Our 2012 sales volume guidance ranges from 244,000 to 256,000 barrels of oil equivalent. The midpoint of this range represent a 13% growth from 2011. This is very close to what we presented in November, with the only significant difference being we trimmed our outlook for Mari-B in Israel due to the high depletion that we experienced there last year.

The increased crude and condensate production is expected to account for 95% of our growth this year as we will have a full year of production from Aseng, new crude production from South Raton and Galapagos in the Gulf of Mexico and growing crude and condensate production from the DJ Basin in 2012. The overall liquids growth is expected to change our product mix to approximately 46% crude condensate and natural gas liquids, 31% natural gas and 23% international gas. This split does not account for any anticipated divestments of our non-core U.S. onshore assets.

Overall, we expect domestic volumes to be up over 20% from 2011, driven by the DJ Basin and Marcellus. Total international growth will be 3%, with Aseng volumes being partially offset by planned downtime at the Alba offshore Equatorial Guinea and reduced production at Mari-B offshore Israel. We had anticipated depletion at Mari-B, but we did not expect to produce at such high rates in 2011. Mari-B production in 2011 was much higher than our plan projected as the field was called on to replace volumes that Israel was unable to import from Egypt for most of the year.

In order to conserve deliverability for the peak summer demand period and to bridge these dwindling Mari-B gas supplies to early 2013 when Tamar is expected to come onstream, we'll be reducing the field's production for the remainder of the first quarter and the second quarter this year. In addition, we're working hard to develop alternate sources of natural gas for Israel until such time as Tamar comes online.

The growth that we have planned and worked for over the last several years is now in progress, and each of our core areas is making significant contributions. Our diversification has again proven its value as we continue to navigate the challenges of the environment. Our goal remains to continue building long-term sustainable growth, growth that is creating value for our investors. Our opportunities set remains large, diverse, but it's also matched by the capabilities we've built within the company and the disciplined capital allocation approach we employ.

Dave will now give you the operational highlights and more details on our plans for 2012.

David L. Stover

Thinks, Chuck. I will start with a review of our reserves at the end of 2011 before discussing our operations and planned activity for 2012.

As Chuck mentioned, we reported total proved reserves of over 1.2 billion barrels of oil equivalent, an increase of 11% from the end of 2010. U.S. reserves made up 47% of the total, with the remaining 53% from our international locations. The reserve additions for the year replaced 244% of our annual production.

In the U.S., net additions of 120 million barrels of oil equivalent replaced 279% of U.S. production. Additions were mostly related to the acquisition and development in Marcellus and by our continued development in Wattenberg. Downward reserve revisions were associated with a decrease of undeveloped vertical locations in the DJ Basin due to our continuing transition from vertical to horizontal drilling and a further reduction of activity in dry gas areas due to low -- sustained low gas prices.

Our horizontal reserve bookings in the Niobrara and Marcellus programs reflect only the specific wells already being worked by our teams and result in less than 2 years' worth of horizontal drilling booked for both programs.

Internationally, net additions of 78 million barrels of oil equivalent replaced 205% of our sales. These additions were mainly a result of the Tamar drilling program, where we penetrated a third fault block, proving additional reserves.

As you may recall, we reported in November that our net risk resource inventory was approximately 7.4 billion barrels of oil equivalent. Of that amount, 3.3 billion barrels was discovered unbooked. We expect the majority of this inventory of discovered unbooked resources to be converted into proved reserves over the next 5 years.

I will now focus on our operations and plans for each of our core areas beginning with our U.S. programs. In the DJ Basin, we produced 66,000 barrels of oil equivalent per day in the fourth quarter, with 57% liquids content. This is our third consecutive quarter of record volumes, with production up 16% and oil production up 20% year-over-year.

At year end, our horizontal Niobrara program produced 17,000 barrels of oil equivalent per day net, a four-fold increase from year-end 2010. With 95 producing horizontal wells at the end of 2011, our average estimated ultimate recovery or EUR is over 310,000 barrels of oil equivalent, with liquid content currently averaging 65%. The more recent 18 wells we referenced in November continue to produce significantly better than our earlier wells, and we estimate their average EUR to be above 350,000 of oil equivalent, with similar liquid content.

We now have over 6 months of production data from our 9,100-foot extended-reach lateral well in Northeastern Wattenberg. The production profile is tracking a tight curve indicative of an EUR above 750,000 barrels of oil equivalent, with 84% liquids. Building on that success, our plans for 2012 call for drilling approximately 10 to 12 extended-reach laterals across our 400,000 acre position in the Wattenberg field.

In 2011, we drilled over 85 horizontal Niobrara wells, and our top performing rigs are now averaging less than 10 days from spud to rig release. We're currently running 5 horizontal rigs in the Wattenberg field, and we'll add 2 additional horizontal rigs over the next few months, one this month and one in April. Our plan is to operate these 7 drilling rigs, primarily in Wattenberg, throughout the year and to take delivery of 2 additional new-build rigs for the horizontal program in the fourth quarter of this year.

In November, you may recall we discussed doubling our horizontal rig count over the next couple of years, but we have now accelerated that plan to reach 9 rigs in the basin by the end of this year. As a result, we expect to double our horizontal activity from 2010 and drill over 170 horizontal Niobrara wells -- from 2011 and drill over 170 Niobrara wells in 2012, focusing in the more oil-prone areas of the play. To accommodate the increase in horizontal activity, we plan to drill approximately 200 fewer vertical wells in Wattenberg this year.

With the accelerated horizontal activity levels and the improved drill times, we have ramped up our horizontal completion operations from 2 wells per month in early 2011 to approximately 10 wells per month at the end of the year. Our focus over the last several months has been to ensure that we can execute at these higher levels of activity. One result is the formation of a water management team that's procured long-term water supplies that will support our 2012 activity level.

In the Wells Ranch area, we have installed water storage and transportation lines that both reduce truck traffic and also ensure adequate water supply for our operations. In addition, we have secured frac sand and pumping services to accommodate the new levels of activity.

Concerning the Wattenberg horizontal Niobrara 80-acre pilot test program, an EcoNode concept that we announced in November, the well completions are under way on the initial pad and the EcoNode is being commissioned for start-up.

Of the 9 wells in the pilot project, 8 have been drilled in the B bench of the Niobrara, spaced as close as 300 feet apart. The remaining well is in C bench, less than 100 feet below the B interval. So we've previously discussed, this pilot is designed to increase Niobrara recovery while reducing our surface footprint, and we expect to share results from this project as we progress through the year.

I also want to mention that we recently spud a horizontal Codell well in the Wattenberg field, and we'll be testing and monitoring results over the next several months.

With respect to capital spending, our plans are to invest $1.25 billion in the DJ Basin, with most of these funds supporting our horizontal program of over 170 wells. In addition to the developments in Wattenberg, we plan to use one of the horizontal rigs in Northern Colorado. This rig will continue the appraisal and delineation of our 220,000-acre position in this area. Thus far, we have been encouraged by the results, which we will share with you later in the year.

Shifting over to Marcellus, our second U.S. onshore core area, we reported production of 74 million cubic feet per day for the fourth quarter. Results are running above our acquisition model and production has more than doubled since the announcement of the joint venture in August. The joint venture placed 21 wells online in the fourth quarter, with average 15 days stabilized production rates of 5 million cubic feet per day and production tracking EUR curves of 5 billion to 6 billion cubic feet per well. Drilling completion costs remain around $5 million per well.

For the joint venture agreement, the carry is suspended until Henry Hub natural gas price rises above $4 per million Btu for 3 consecutive months. As a result, our economics are aligned with our partner, CONSOL Energy, as we make investment decisions in the low natural gas price environment.

The strong performance of the wells in the CONSOL-operated Southwest Pennsylvania dry gas area confirms that development in this area continues to be economically attractive at the current strip prices. The Southwest Pennsylvania drilling program for 2012 also benefits from an average net revenue interest of over 95%.

The joint venture acreage is predominantly held by production, which allows for flexibility in scheduling the timing and location of development. The partners have agreed to defer drilling in the dry gas areas outside of Southwestern Pennsylvania and Northwest West Virginia. The impact on the schedule is around 40 fewer wells than our original plan. In order to respond rapidly to the rising gas prices, the joint venture will continue the land and permitting activities at the originally planned level. Doing so will allow us to build up a strong inventory of drillable locations.

Without the carry we have approximately $500 million allocated to our Marcellus program, which includes the drilling of 39 wells in Noble-operated white gas area and 60 wells in the CONSOL-operated areas. The capital program also provides for additional infrastructure development in the wet gas area to support the 2013 drilling schedule.

Last month, Noble Energy took over operatorship of our first rig in the wet gas area, and we intend to add 2 more rigs in the wet gas area in the second half of 2012. By the end of the year, we expect to operate 3 rigs in the wet gas area, while CONSOL operates 3 rigs in the dry gas areas. We have opened our office in Canonsburg and have allocated staff to this important project. Initial production from the wet gas area should begin in the second quarter of 2012.

Moving offshore to our operations in the Deepwater Gulf of Mexico. We expect production from South Raton to begin before the end of the first quarter and from Galapagos by the end of the second quarter. Our operated portion of the Galapagos project is essentially complete. However, the host platform operator has indicated that concurrent maintenance activities will delay the completion of final topsides work into the second quarter. Following the completion of the third-party maintenance on the platform, we'll have access to finish the work necessary to commission the project. All other significant subsea development and topsides work has been completed, and production will begin following the commissioning of the topsides facilities.

We have allocated $250 million to the Gulf of Mexico for 2012, with approximately 80% supporting our exploration and appraisal work. The first Gunflint appraisal well is drilling ahead with the ENSCO 8501 rig, and we expect to reach total depth in the second quarter. As we look forward in 2012, we're evaluating several exploration and appraisal opportunities for our remaining time on the ENSCO 8501 and our 4-month slot with the ENSCO 8505 rig during the second half of the year. We have filed permits -- We have filed for the permits for our 2012 program and anticipate obtaining these permits in a timely manner.

Moving from the U.S. to international, I'll begin with West Africa. Our Aseng project offshore Equatorial Guinea began producing in November, 7 months ahead of original schedule and 13% under our budget. According to a review by an independent consulting firm, this overall performance was near top quartile in schedule and near top decile in subsea scope costs when compared to a data set of major West Africa project performance.

Before the end of the year, we lifted 3 cargoes each, between 600,000 and 900,000 barrels of oil gross, at a price essentially equal to Brent, which was better than we initially expected. The strong reservoir performance has allowed us to increase the production rate from 50,000 to 55,000 barrels of oil per day, with 99% run time. The FPSO has available capacity, and we're evaluating a further increase in production to 60,000 barrels of oil per day by the end of the first quarter.

We intend to invest $500 million this year in West Africa, with 80% dedicated to development activities. Our development focus has shifted to the Alen project, which remains on budget and on schedule for first production in the fourth quarter of 2013. All subsea trees have been installed, and subsea fabrication is ahead of schedule. The production and injection wells are on schedule to be completed in the first half of 2012 by the Atwood Aurora jack-up rig and the Atwood Hunter rig, respectively.

Carla, our recent oil discovery below the Alen field in Block O, is being integrated into our development plans alongside Diega. Finally, we plan to drill at least one exploration well offshore Cameroon in the Tilapia PSC.

In the Eastern Mediterranean, we had an exceptional quarter. We announced the natural gas discovery offshore Cyprus, with an estimated gross mean resource of 7 trillion cubic feet. The appraisal well at Leviathan, drilled more than 6 miles from the initial discovery well, confirmed the continuous reservoir and increased the gross mean resource estimate to 17 trillion cubic feet. The gross mean resource estimate of Tamar was also increased after successful appraisal. Overall, including the Tanin results announced this week, we now have discovered approximately 35 trillion cubic feet gross of new gas resource -- reserves resources from this region.

The Mari-B field has produced since 2004. And in 2011, it produced at historically high rates to satisfy Israel's natural gas demand while Egyptian imports remained offline. The field has performed well as we accelerated production but, as Chuck mentioned, is experiencing some advanced depletion as a result. Going forward, we will be decreasing Mari-B production over the rest of the first quarter and the second quarter to conserve deliverability for the upcoming summer peak demand period and to maximize gas recovery from the reservoir.

In addition, we're actively pursuing 2 initiatives to enhance deliverability of natural gas from the Mari-B facility until Tamar production comes online. The first is the ongoing development of the nearby Noa field, which is expected to add 100 million cubic feet per day of deliverability in the third quarter of this year. We have drilled 2 wells, which will be completed early in the summer, with the Sedco Express rig. The second initiative is an evaluation of an additional untested area near Mari-B, called Pinnacles, which may be able to contribute additional deliverability. Pending partner approval, the ENSCO 5006 rig is available to begin drilling at Pinnacles well this quarter.

Noble Energy is a long-term partner of the State of Israel, and we remain committed to working with them to provide as much gas as possible until Tamar is brought online. I've referred to our Tanin discovery, which we announced this week. With the gross mean resource of 1.2 trillion cubic feet, this is our fourth Eastern Mediterranean discovery over 1 trillion cubic feet gross in the last 3 years.

We are now 6 for 6 with our exploration program in the Levant Basin and continue to diversify the area's gas supply base. The deep oil test at Leviathan is under way with the Noble Corporation Homer Ferrington rig. As we indicated in November, the deep oil gross mean potential on our acreage in the basin is estimated at 3.7 billion barrels of oil equivalent spread over multiple prospects. We expect results from this 15% chance factor Leviathan deep oil test in the second quarter.

Development drilling will continue at Tamar with the Transocean Sedco Express rig, and final well completions are scheduled for the fourth quarter of 2012. Pipeline installation is essentially complete, and the project is on budget and on schedule to begin commissioning late this year and start up early in the second quarter of 2013. The expansion of the Ashdod onshore receiving terminal is also under way. The capital program supporting our activity in the Eastern Mediterranean is around $750 million.

The negotiation of a Tamar gas contract with Israel Electric Corporation continues to progress. In the past month, we have signed 4 contracts for the delivery of over 1.1 trillion cubic feet of natural grass gross with other gas purchasers in Israel and expect to sign more as we move closer to first production. Pre-FEED studies have been initiated to analyze floating LNG as an export option for Tamar and Dalit and to evaluate LNG plant locations for potential exports from the massive Leviathan field. Additionally, we're working with our advisers to help us identify and select a strategic partner or partners for the development of Leviathan gas.

Now let me touch upon the guidance we issued this morning for 2012. We presented a full-year sales range of 244,000 to 256,000 barrels of oil equivalent per day, with volumes in the first quarter expected to range from 228,000 to 238,000 barrels of oil equivalent per day. Although the midpoint of first quarter 2012 volumes is expected to be fairly flat with the fourth quarter 2011, the production this quarter should be a higher value mix than we had in the fourth quarter.

Compared to fourth quarter 2011, crude and condensate production is expected to increase around 17%, and gas production is expected to decrease about 8% as we start ramping down Mari-B to conserve for the summer months and the Alba field experiences the first 2 of 4 weeks' planned maintenance. For the year, I anticipate the volume profile to stay fairly flat through the first half and grow significantly in the third quarter as we increase production through the Mari-B facility, complete maintenance at Alba, see the full benefit of new projects in the Gulf of Mexico and continue to grow our horizontal Niobrara and Marcellus volumes.

Lease operating expense will follow the inverse trend of volumes, with LOE per barrel equivalent closer to the higher end of guidance during the first half of the year and near the bottom end of guidance the second half of the year.

When you compare 2012 to 2011, you can see the impact of focusing on our 5 core areas. Our overall gas production is expected to stay fairly flat, as our Marcellus increase will more than offset the reduced volumes from Israel and Equatorial Guinea. This means our total company volume growth will be driven by an expected 40% increase in crude and condensate sales for 2012 compared to 2011. This high-value gross will be contributed 60% from a full year at Aseng, 25% from our horizontal Niobrara program and 15% from our new Deepwater Gulf of Mexico production.

With Aseng now online, a couple of new Deepwater Gulf of Mexico projects starting up the first half of this year, our 2 core onshore U.S. programs ramping up and continued significant exploration success in the Eastern Mediterranean, we are right on track for delivering the 5-year outlook we reviewed at our November Analyst Day. Our current appraisal well at Gunflint and our deep Leviathan oil test provide additional excitement for the coming months.

With that, Celia, let's open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from David Kistler with Simmons & Company.

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

Real quickly, in Israel, given kind of the vast resource potential that you have discovered there, or really Eastern Mediterranean, do you think about maybe entering into a joint venture or monetizing a piece of it is to accelerate the present value of those assets?

Charles D. Davidson

Well, I think right now, as Dave mentioned, we've -- we're beginning to look at the options there and part of it is the exploring how we might bring in another partner into the development that can provide some additional capabilities. And clearly, the thinking is, is by doing that, we can accelerate the development of these big assets. We have, as you know, a fairly high working interest on the Cyprus opportunity at 70%, which is well about what we have of the Israel side. So there's certainly maybe some opportunities for us to accommodate, along with our partners, an additional partner that would probably have an interest in obtaining some of the upstream interest, as well as participating in a midstream project as well. So I guess, the answer to the question is, is we're open to all options to try to accelerate value here.

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

Okay, that's helpful. I appreciate it. And then maybe just one more in Israel. Can you talk a little bit about the contracts you signed? What that means from more of a daily production value and when those kind of start and the prices around those contracts?

Charles D. Davidson

Well, I think right now, we -- the safest things is for us to stick with the original script, which gave the overall gross amount that was committed under the contract and the dollar value on it. They -- all of them do have some various mechanisms for escalation. The ones that we have entered into already have formulas that are tied to the public utilities' tariffs that's there in Israel. And of course, that will adjust as we go forward. That's -- we've made some estimates of how that might move. But that's kind of a guess at this point. But there -- again, we're continuing to contract volumes out of Tamar. The big contract with IEC, I think, we continue to make progress and we're waiting on just the final approval from our customer there.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

With the better rates that you're seeing or expecting out of Aseng in Equatorial Guinea, do you attribute this to achieving a greater recovery rate of oil in place or depleting the reservoir more quickly? And are there any implications for how you’re thinking about Alen?

Charles D. Davidson

Well, I think, number one, the better production rates are clearly due to the -- we've got a very high-quality reservoir there, and we've got very good completions. It's far too early to say what any implications might be on recovery. Although in the past, we have said that on our reserve bookings, there is some possibility that because we saw some positive things as we develop the field, that we'll monitor for performance and there's certainly a reasonable chance that we'll be able to increase our proven reserves estimate in the field later this year. So too early to tell, but everything is working very well. And maybe Dave wants to add a couple of more things on that.

David L. Stover

Yes, if you recall, Brian, these producers are all horizontal wells. So that the plan from the beginning was to start them at 50 and then slowly increase them up to probably holding them no greater than 60,000 barrels a per day. And that will allow us to still hold a fairly flat production profile at that rate for over one year or so. And then, as Chuck mentioned, we'll look back at the end of the year and see how performance has gone and reevaluate reserves at that time.

Brian Singer - Goldman Sachs Group Inc., Research Division

And in the U.S., in the Wattenberg field, do you anticipate any midstream or downstream bottlenecks at all, or should we expect that the trajectory of your growth be pretty consistent over the course of the year?

Charles D. Davidson

No, I think the key up there is continuing to plan ahead for that, make sure you've got your plans in place a couple of years out. I think Ted talked in November and we mentioned, I think, even at the last call some of the expansion plans up there with DCP on their facilities and how they're working with us to stay up with us, especially with the increased activity levels. I know there's some new plans for some NGL lines out of the area too that we're in discussions with. So when we look at the outlook, we look at the whole midstream piece that's seasoned up with what we've got planned there. The other component is we're continuing to move more and more into the oil portion but which alleviates any timing pressures on the gas part of it, and that matches up well with our plans with the downstream, midstream companies.

David L. Stover

I think I'd also add, Brian, that on the oil side, we've continued to expand the markets that we go to. So in the past, we were perhaps going to 2 markets. I think now we're touching on maybe 5 different customer outlets in the area, so that's helping on the oil side as well. Because, as Dave pointed out, while we've managed around any gas bottlenecks by moving into the oil part of the field, we've got a -- we're starting to move a tremendous amount of oil out of Wattenberg. So it's a -- we've got everyone working on every piece of the logistics.

Operator

And we'll go next to Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

First, a quick question on the Marcellus. The 630,000-acre position, how much of that is in the dry gas? And is there any concerns of acreage explorations as you slow that portion of the drilling down?

David L. Stover

I mean, the beauty of the position out there is how much of this is held by production. There's a large component too that will essentially feed acreage, which contributes to the high interest, that net revenue. Again, I mean, it's highly unusual to have areas where you can drill with 95% net revenue interest like we're focusing on right now in the dry gas area. So we don't see issues with anything as far as any concern of acreage loss or anything like that with any adjustment in the program.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

And the carry, I know it comes back after gas goes over 4. But is there any time frame over which the carry would expire regardless of the gas place or did it simply get carried forward?

David L. Stover

It just keeps moving out in time.

Operator

And we'll go next to Leo Mariani with RBC.

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

You talked about your Mari-B production in the first half of '12 being curtailed in order to leave some more room for kind of peak summer season. Could you guys quantify that at all in terms of where you think it could be in the first half of '12 versus the second half of '12?

Charles D. Davidson

Well, I think, we look at it on a gross basis. I'll tell you what, I'm going to let Dave go through it because we can get a lot of moving pieces here, because we're going to be adding a Noa project in the third quarter.

David L. Stover

Yes, and essentially what we're doing is we're ramping down through the first quarter, which we talked about. So we're ramping down probably about 50 million a day per month for a few months until we get into a number we're comfortable with for the second quarter, and then we'll ramp back up starting in the third quarter to meet some of the summer season, along with bringing on something like Noa. But I think when you look out in the summer period, you're looking at numbers probably closer in that 400 million to 450 million a day total Israel gas production that we're delivering. And then I would expect it would fall back off in the fourth quarter.

Charles D. Davidson

And that's reflected in our guidance. But we just want to make sure that everyone understands that we just don't have the ability to go back up to that 600 million that we saw in 2011. That really pulled a lot of volume out of the reservoir. So we're trying to provide as much deliverability as we can for our customers in the summer months, knowing that Mari-B and even with Noa is not likely to come anywhere close to the deliverability we had last year.

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

That's very helpful. Just jumping over to the Niobrara here. Obviously, you guys had a -- it sounds like a very stout well in your first long lateral well there. Just trying to get a sense of what the well cost there is on the long lateral compared to your normal wells. I guess, you said your last 18 horizontals were from more of a normalized lateral were sort of 350 Mboe wells. Just wanted to get a well cost comparison and whether or not you guys think you're seeing a huge benefit in terms of added value from that program?

David L. Stover

Yes, when you looked at our average and what we've been running on our normal horizontal wells, they're right about that 4.7 million drilling complete. I think what we showed in November for that long lateral was around 7.5 million. So you see that there's potential efficiency improvements and optimization with the long laterals. And really, the effort on that, I think, we even indicated potentially with those type numbers 20% improvement in F&D and just take that straight up at least. What we're really focusing, the next tests on the long lateral really in the more oil-prone windows up in those northeastern part of the field and so forth where you don't have quite as many vertical wells. It gives us more ability to maneuver those to start with.

Operator

And we'll go next to Bob Morris with Citi.

Robert S. Morris - Citigroup Inc, Research Division

Dave, on the reserve write-down that you took up in the Rockies for the vertical wells, knowing that those were PUDs with associated hydrocarbons. Why didn't you just swap those out for horizontal PUDs, just to keep the reserves the same?

David L. Stover

Well, if you remember, a large portion of our vertical reserve component is Codell and in some cases, even J-Sand. So the big portion of that is really taking that -- those vertical well, Codell and J PUDs, off the books and not assuming that we're going to re-drill those on a vertical basis within the 5 years. We've not allocated any horizontal reserves to Codell at this point. As I mentioned earlier, we're just starting to test and drill our first true Codell horizontal well. And so we'll revisit Codell horizontal at the end of this year.

Robert S. Morris - Citigroup Inc, Research Division

I think, it's not really price related, it's just the fact that you're not going to drill those in the next 5 years now?

David L. Stover

Yes, we're are just not assuming we're going to really drill those in the next 5 years.

Charles D. Davidson

And just to re-emphasize a point that Dave made on our horizontal bookings, both in the Niobrara and the Marcellus, we're just looking those that the teams are working right now, which really only works to about a 2-year inventory. So we're not pressing the envelope at all on our horizontal bookings. So I think when you take a look at the combination of those factors is why it's prudent to put those Codell resources into the unproven category for now until we firm up the plans for the future for either for horizontal drilling in the Codell or the drilling of vertical Codell wells later.

Robert S. Morris - Citigroup Inc, Research Division

Okay. So you would expect that perhaps next year, book a lot of offsets on the horizontal side?

Charles D. Davidson

I think we will. We do expect to continue to book offsets on the horizontal, but I think we're going to be very careful and manage a plan that's based on location our teams are working on.

David L. Stover

I mean, activity level, we're drilling twice as many this year.

Operator

We'll go next the John Herrlin with Société Générale.

John P. Herrlin - Societe Generale Cross Asset Research

Could you give a postmortem on the well in Cameroon, what happened?

David L. Stover

Basically, that prospect we didn't see reservoir. And I mean, that was one of the primary risks that we identified pre-drill.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Next one for me is just on the DJ. They had a lot of snow recently. Should we expect any sort of weather-related delays? Did you have any freeze-offs, anything like that?

David L. Stover

I mean, there's always a little bit of impact. But we haven't seen a big impact from that. I mean, the team has done a good job of preparing for winter and we haven't had big long sustained. If you remember a couple of years ago, we had probably 3 storms one week after another that had a big impact. And hopefully, we won't see that type of thing. But a short storm, they're able to weather most of that impact.

Charles D. Davidson

I would say that when we look at our January performance, it was outstanding in terms of the amount of oil that we moved there in the field. So there will be some -- there will always be some little winter upsets, but we certainly -- we think, we've factored that into how we've outlined and guided for the first quarter.

Operator

We'll go next to Bob Brackett with Bernstein Research.

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

I had a question on the Leviathan appraisal program. How many wells do you think you'll ultimately need, and what's your timeline for certainty on the results? And specifically, if you get a negative result in the deep oil test, does that condemn the concept or would you then go back and find a different prospect to test that oil concept?

Charles D. Davidson

Between Dave and I, we'll try to cover that. I think in terms of the Leviathan appraisal, we've now -- we have 2 wells. Certainly, there will be probably 1 to 2 more over time. And that will continue to narrow it down although this a very big resource, so it will never get down to a perfect number. I guess, what we'll do is just narrow the range. But certainly, the appraisal that we had last year helped a lot. And as you know, it actually allowed us to move the discovered gross mean resources up a bit. As far as the deep test, we see a number of structures in this basin. Not all of them may have been formed the same way, and so there is some differences in the prospects. So this is very low chance of success to start with. But I would say that there's still a possibility that if we did not find something at Leviathan, depending on what we found there, we could be encouraged to test one of those other prospects in the basin as well.

Operator

We'll go next to Irene Haas with Wunderlich Securities.

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

The Marcellus, wondering sort of you working the wet gas portion, and can you update me on which county you're working on and also, sort of your longer term plan infrastructure and such? I know you guys always think ahead. And then secondarily, what's your view on U.S. dry gas? How long can you and your partners sort of kind of stay back and wait for recovery?

David L. Stover

Yes, Irene, let me take the first part of that. We're operating in Marshall County, West Virginia, and we anticipate we'll stay in West Virginia all year this year. And as I mentioned earlier, we have additional money in there or some money in the program this year for preparing for additional acceleration as we get the other couple rigs in, and then that will lead into a potentially larger program in the wet gas area next year. But all of that right now for this year, and I would anticipate beginning of next year, will be in the West Virginia portion.

Charles D. Davidson

And I think as far as how long can we wait it out. Again, because this is not a situation where we have to hold acreage, it's all basically held by production, mostly held by production, that I think we have a lot of patience here. We've got a particular area that Dave talked about that's got some very high net revenue interest, and we've seen some very high quality there in Southwestern Pennsylvania. We still see some good returns to drill there. But as far as the other areas, we'll just plan with our partner to continue to monitor the gas market and see if it turns around. It just doesn't make sense in those other areas to be drilling there right now.

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

What's your internal view? How long would this sort of gas surplus last?

Charles D. Davidson

Ah, the crystal ball. I can't tell. And quite honestly, I, like all of you, are waiting to see what the gas production is in the U.S. and how it matches up with demand and how the weather evolves. My sense is that we have to go through a full season here. And we're basically looking at trying to guess at where we'll end up with gas and storage in the fall and look at what the actual production volumes are in the country. So it's -- I don't see it as something that will turn around immediately. I think we're going to have to go through several months in a season to see where both demand and supply go.

Operator

We'll go next to John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just taking a little bit more in Mari-B, just to be clear. So you're talking about 2 options, Noa, obviously, you're going to have with and then an evaluation of Pinnacles. Are those mutually exclusive? And when you talked about getting up to, I think you quoted a 400 to 450 number later in the year for the Israel summer demand, is that -- that's including Noa but not including for Pinnacles, correct?

David L. Stover

It would include the possibility of gas from both of those, John.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. So all right, fair enough. And then just quickly, Cyprus. Can you give any guidance on what you think fiscal terms are going to like there? Are they going to be similar to Israel?

Charles D. Davidson

Well, it's basically a production sharing agreement, and we're under a confidentiality with the government on disclosure.

Operator

We'll go next to David Heikkinen with Tudor, Pickering, Holt.

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

Can you give us the status of asset sales or timing or any thoughts around them?

Charles D. Davidson

Yes, we kicked that process off, David, and we should be opening up some data here to folks in the next month or so. We'll start with probably some oil production in Permian and some oil production in Kansas and also some of our Granite Wash production. Those would probably be the first components that we'll have out the door. So I think we'll just be kicking that process off here in earnest over the next couple of months here, by the end of the quarter or so.

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

Okay. And then results at Aseng sound encouraging. What drives the wide range of crude and condensate volume guidance for '12?

Charles D. Davidson

Well, I think what we just look at -- we put in a number of factors and we've got -- you have to keep in mind, we've got a downtime factored in at Alba. And anytime you take facilities down, that can swing the liquid volumes. And we try to look at variances on our growth of the Niobrara. And so we just try to -- in the end, try to put a reasonable range and try to accommodate things like if you've got any type of unusual downtime or weather.

David L. Stover

Especially in the Deepwater Gulf.

Charles D. Davidson

I think also, the other point is that we noted that Galapagos was a little later than we originally expected. And any time you don't have a project that hasn't started up, you need to put a range around that, a sensitivity around it because of issues on start-ups. So those are the big drivers.

Operator

We'll go next to Michael Hall with Robert W. Baird.

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

Just curious, can you remind me, I guess, where are your NGL volumes out of the DJ Index, too, from a pricing standpoint? Are you guys getting Conway or MBOE [ph] type prices?

Charles D. Davidson

Yes, we're -- right now, the NGLs out of the Wattenberg area are going to Conway.

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

Okay. And then how much of the -- I don't know if you have this, but how much of the NGL barrel is ethane?

Charles D. Davidson

Yes, we actually...

David L. Stover

About 1/3, I think.

Charles D. Davidson

Yes, it's about -- about 1/3 of it is ethane, and then the rest is in heavier liquids.

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

Okay. And then last one for me on the Niobrara. How much of the acreage position there do you think has potentially perspective for the long lateral development? I'm just trying to get a sense for, is there any constraints from leasehold and land ownership or legacy wells?

David L. Stover

I don't have a number at my fingertip. I'd say, we'll probably have a better idea later in the year after we finish these next 10 to 12. I will say, we are going to start more in that. If you go back to those areas, we had high GLR and then the core that was a much larger picture than the higher GLR. It's kind of a core with low GLR and then an extension area. It would be those latter 2 areas that we'll really concentrate the long laterals first.

Charles D. Davidson

I think also is that if they continue to be very successful, there could be opportunities to go beyond just where we have contiguous acreage but actually start forming partnerships where you either trade acreage or you bring others in so that you can form adjacent sections. So that's a lot of land work that it takes to do something like that, but that's some other options as well.

Operator

And our final question comes from Paul Crovo with PNC Capital Advisors.

Paul Crovo

Quick question about Aseng. You had indicated that you could possibly be bumping production up to 60,000 by the end of the first quarter, and I was wondering whether or not that was built into your full year 2012 production guidance?

Charles D. Davidson

Yes. That assumption is built into our overall guidance, yes. It's part of the range that we provided for production and for oil.

David R. Larson

So this is David Larson again. We've reached our one-hour limit here on the phone call, and I want to be -- stay on schedule for us, as well as you guys out there in the market. So I just want to end by saying, I want to thank everyone for their interest in Noble Energy. Eric and I will be available to answer any questions that you may have that we didn't get to today, but I hope everyone has a good day.

Operator

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

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