Good morning, everyone, and welcome to Noble Energy’s Fourth Quarter and Year End 2008 Earnings Call. As a reminder, today’s call is being recorded. At this time, I would like to turn things over to Mr. David Larson. Please go ahead, sir.
Thanks, Dana. Good morning, everyone. Welcome to Noble Energy's fourth quarter and year-end 2008 earnings conference call, and again thank you for joining us. I'd like to start out with a few introductions. On the call today with me we have Chuck Davidson, Chairman and CEO; Chris Tong, CFO; Dave Stover, Chief Operating Officer.
We hope everyone has seen both releases we issued this morning, one announcing our fourth quarter and full year results, and the other covering our preliminary 2009 plans. The agenda for the call today includes some opening comments from Chuck. Chris will then provide a little more detail on the items affecting the results for the quarter and also talk about 2009 guidance. Dave will finish up the call with a discussion of our year-end reserves, operating highlights for the quarter, and give us a quick look at our programs for next year.
We will leave plenty of time for Q&A but we will try to wrap up the call in less than an hour. Should you have any questions that don’t get answered or have time to be responded to on the call, I encourage you to call Brad Whitmarsh or myself and we will do the best to answer them for you. Later today we expect to be filing our 10-K with the SEC and it will also be available on our website at www.nobleenergyinc.com.
I want to remind everyone that this conference call does contain 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 here today. You should read our full disclosures on forward-looking statements in our latest news release and the SEC filings for a discussion of the risk factors that influence our business.
We will reference several and certain non-GAAP financial measures today such as adjusted net income or discretionary cash flow on the call. When we refer to these items, it is because we believe they are good metrics to use in evaluating the company’s performance. Be sure to see the reconciliations in our earnings release.
With that, let me turn the call over to Chuck.
Thanks, David, and good morning everyone. I want to start out first of all by mentioning a few items looking back at 2008 and some of our key accomplishments during that period before then going in and spending some time talking about our plans for 2009, and how these plans are really setting up Noble Energy for the future.
2008 was clearly a year of extremes for ourselves, our industry, and the broader economic environment. Certainly for us, it was a year of many accomplishments, some of them which are of great significance and that will impact us for many years to come. It was a year of record earnings, discretionary cash flow and production, where volumes were up 8% over 2007 despite some of the impacts that we saw late in 2008 from hurricanes in the Gulf of Mexico, and longer than expected maintenance impacts from our West Africa operations.
I have been in the industry for some time now and I really can't remember a year that had the kind of commodity price volatility that we have experienced in 2008, especially on the oil price side, which of course as you know rose very rapidly early in the year and then dramatically fell driven by a collapsing economy and excess supply. These lower commodity prices and a struggling economy present us and our industry with some great challenges as we enter into 2009.
Capital spending for us grew in 2008, but still remains within our cash flow as we remain focused on executing only the best projects in the portfolio. We passed by several opportunities earlier in the year when prices were high as we believe they were too costly based on our longer-term view of commodity prices, and now looking back, that was the right thing for us to do. As a result, we ended the year with a strong balance sheet that included over $1 billion in cash on hand and a year-end debt to book cap ratio in the mid 20s.
Our drilling programs remained active during 2008 with the majority of our activity coming in our northern regions led by the Wattenberg field. As prices began to decline in the second half of the year, we lowered our level of activity in certain programs, primarily those that were more sensitive to lower US gas prices. At this time last year, I told you that 2007 was the most significant year in our history regarding our exploration program. And it looks like I will be able to repeat that again in 2008, as we continue with tremendous exploration successes past year with multiple discoveries in Equatorial Guinea, and our largest discovery to date in the deep-water Gulf of Mexico at Gunflint. And then in early 2009, we announced what appears to be the largest exploration discovery in our company's history at Tamar, offshore Israel.
As we look at just the last two years including Tamar and its updated gross mean resources estimated to be five trillion cubic feet, Noble has discovered net to us approximately 600 million barrels of oil equivalent from our exploration program. To put that in context, that is nearly 70% of our current proven reserves. Nearly all of these resources are as of yet unbooked in our proven reserve numbers, so we have some substantial upside to our current reserves for the future.
Our reserve replacement ratio for 2008 excluding negative price revisions represented about 147% of production and Dave will talk more about our reserve data in just a few minutes. But I wanted to specifically mention that we spent somewhere around $750 million in 2008 on exploration, which represented about 32% of our total costs incurred. This is a significant commitment which is certainly positioning us for tremendous long-term growth potential for Noble Energy.
I do believe we have Noble Energy positioned well. First, we have a solid and diversified portfolio of assets. We have been able to allocate capital among a variety of areas in the US and international and make minimal re-investments to maintain them. Second, we have put in place over the last several years a number of business processes that are really designed to help us excel in this industry. Probably, the most obvious and most visible of these today is our exploration process, where we continue to fine tune it, and which now has delivered a string of outstanding discoveries.
Only with a best in class exploration process could you ever take on an exploration program such as ours. The rewards of doing so if backed by the proper process are obvious. On the investment side of our business, we continue to maintain a very disciplined approach. We tell us everyday as we allocate capital, it is all about returns. And finally the last attribute which I mentioned earlier and that is having a strong balance sheet.
We have all been recently reminded just how important financial strength and flexibility is to a company's well being. Fortunately we’ve diligently improved the balance sheet over the past few years and all of this is allowing us to be focused on positioning Noble Energy for the future and I think that is what hopefully you will take away from this call today.
We announced that we're starting out 2009 with a capital budget of around $1.6 billion. It is a very significant program, but it was designed with a lot of flexibility. We expect to manage the program plus or minus 10 or 15% depending on market conditions and the outlook for our business. In 2009, we expect to invest about 40% of our capital in the long-term growth areas. These are projects that are not driving production this year or next, but instead are preparing us for growth in 3, 4, or 5 years or even longer out. I think this is the one thing that will differentiate Noble Energy from many other companies this year, and that is our ability to continue investing in long-term growth opportunities.
It is pretty exciting to think what we have in front of us, three hugely important projects that will certainly have the capability of transforming Noble Energy. These include expanding the best opportunity set, now with 11 successful wells, including the last ten in a row, all essentially in the last two years, also includes a very significant deep water Gulf of Mexico discovery at Gunflint and of course most recently, our Tamar success at Israel.
Going back to the beginning of 2008 when we announced our exploration program for the year, we noted that it included three significant test. These included West Tapir and Surinam, Gunflint in the deep-water Gulf of Mexico and Tamar. And I noted at that time that if we had one success out of the three then we probably would have achieved expected results. As you look at sum of just the total three projects, the chances of success totaled just under one. Surinam was dry but not only did both Gunflint and Tamar hit, but the initial results far exceeded pre-drill expectations, clearly stellar results in our book that will have a significant impact on our company for many many years into the future.
Let me just take a minute to say he few things on Tamar, and Dave will certainly be talking some more later. There is a lot of excitement within our company, our partners and the country of Israel resulting from this discovery, and that excitement is certainly understandable. The impact of the discovery on all the involved parties will be substantial. This is a very unexplored part of the world, with the nearest well penetration to Tamar being approximately 6 miles away. But I think stay tuned as there will be much more information coming, but suffice it to say we're very excited with the results thus far and we have protected the upside with ownership in various licenses in the region that totaled nearly 3 million acres gross.
To me this is a great time to invest in longer-term opportunities. We can take advantage of a decreasing cost environment. Currently we have major sub sea and FPSO feed studies underway for Benita, our initial oil discovery in EG. I can’t think of a better time to be looking to contract and build an FPSO when prices are declining and shipyard spaces plentiful.
Investing in so much success would not even be thinkable if not for our strong existing asset base, most here in the US as well as in the international, assets that require lower maintenance cost, capital and are very low in costs, and as a result, throw off a lot of cash flow. However, it is not our plan to melt these assets to get through these difficult environment. Our base 2009 plan allocate sufficient capital to maintain them, but growth I would say especially with US gas assets will have to wait for better days and better commodity environments.
Onshore in the US we have been careful in moving capital around. When you look at the Rockies, Wattenberg is a solid asset and very low cost with a good balance of both lipids as well as natural gas, and we are also continuing to get our costs down there. In the Piceance and Tri-State areas, we have pulled rigs down in response to the market. Our acreage there is well positioned, was acquired at very low cost, and it isn't going anywhere. So we will be back in the market looks more in our favor.
Regardless of what the projects economics is saying now, it is not the right time to accelerate gas production into this over supplied US market. Therefore, with our diversified portfolio, we're redeploying capital, and it is nice to have multiple choices. Whenever you have choices, it allows you to improve returns, and it is critical that we fund only the best things and defer things that don't make sense in the current environment.
This year's exploration activity is going to have plenty of excitement as we will allocate a full 20% of our capital to exploration. We will leverage our huge success at Tamar by drilling to additional wells in Israel, one to appraise Tamar and one to test the second prospect called Dalit. In West Africa, just last Friday, we reported the discovery of Carmen, which is our first oil discovery in Block O in Equatorial Guinea. And in the deep-water Gulf of Mexico this year, we will be testing two or three prospects, including Santa Cruz, which is the drilling right now.
With our excellent processes backed by great results and a huge prospect inventory, I believe that investors will start to recognize the value of our exploration portfolio. As I mentioned earlier, 2009 is not the year to be pushing near term production growth. With our scaled back drilling program in the US onshore as well as declines in the Gulf of Mexico, we expect volumes overall to be up just slightly from 2008 levels. But in our view, that is okay in this current environment.
In summary, we are pleased with where we have Noble Energy positioned and we are truly excited about the future of the company. Without question, we are starting out 2009 with a challenging environment, which will certainly present both obstacles and opportunities for us. We are beginning the year very cautious, we will be monitoring the markets closely, but without a doubt, I know the team here is Noble Energy is well up the task to deal with it.
So with that, let me turn the call over to Chris who is going to provide more details on the quarter's financial results as well as our guidance for 2009.
Thank you, Chuck, and good morning, everyone. Hopefully you have had a chance to read through the earnings release and the accompanying tables as well as our 2009 guidance that we released earlier this morning. So I will focus my comments on what I consider to be some of the more noteworthy items.
Let us start with the earnings release. Adjusted net income for the quarter was $163 million or $0.91 per share diluted. And for the year, we reported record adjusted net income of $1.26 billion or $7.05 per share diluted. There were two items that impacted adjusted earnings for the quarter that we have included on schedule 1 of the earnings release. The most significant adjustment is an unrealized mark to market gain of $283 million after-tax, which represents the change in the value of our commodity hedges at year-end since the end of the third quarter. Since this amount represents perspective future gains assuming forward prices remain as estimated at the end of 2008, we exclude these amounts in determining adjusted net earnings.
The second adjustment on the schedule represents asset impairments, which were also likely driven by lowering year-end prices, resulting in us recording property impairments of $141 million after-tax. Most of our impairments were in domestic properties. Discretionary cash flow for the quarter was $439 million, bringing our total for the year to a record $2.4 billion which exceeded our 2008 capital expenditures of $2.26 billion. As a reminder, CapEx included a $300 million asset acquisition.
As we look at our fourth quarter results compared to the same period last year, lower commodity prices were the primary driver of lower revenues, adjusted earnings and discretionary cash flow, despite the increased volumes of 4%. Our realized crude oil and natural gas prices were down 40% and 32% respectively versus the fourth quarter of last year. Sales volumes for the quarter were 208000 barrels of oil equivalent per day while domestic volumes were up 3% in the same period last year, largely due to record northern region volumes. We continue to see temporary infrastructure related shut-ins due to hurricanes Gustav and Ike which reduced our fourth quarter 2008 volumes on average by about 9000 barrels of oil equivalent per day.
Total international volumes were up 8% versus the fourth quarter of 2007 after adjusting for the Argentina assets sold earlier in 2008. Volume growth in Israel continued resulting from strong natural gas demand period over period. And West Africa volumes were up from the fourth quarter of 2007, primarily resulting from third-party maintenance downtime in the 2007 period.
For the fourth quarter of 2008, West Africa volumes were reduced approximately 30 million cubic feet per day resulting from longer than expected by pipeline maintenance at Alba. Despite the impact of the lost volumes in West Africa and the deep-water Gulf of Mexico, total volumes averaged 215,000 barrels of oil equivalent per day for the year, a new annual record for the company, and up over 9% from 2007 after adjusting for the Argentina asset sale. For the year, we ended at the midpoint of our production guidance.
Let us now turn to cost. In particular I thought I would mention how we performed for the year as compared to our annual guidance metrics. As you may recall, we initially issued guidance at this time last year and provided one update in May of 2008. For oil and gas operating cost, we guided to the high end of the range of between $4.20 and $4.70 per BOE. And our annual number came out to be right at the high-end. DD&A of $10.05 per BOE came in below the end the end of our guidance, principally due to the final production mix for the year.
By the way, I want to continue to remind you that when we talk about per barrel unit cost, we consider all volumes including our equity method volumes from the LPG plant. Exploration expense for the year was below our estimated range due to a very successful exploration program in 2008. The fourth quarter number also benefited from the success of Tamar in Israel. General and administrative expenses came in as we had guided and interest expense was in the low end for the year. On an adjusted earning basis, our full-year effective tax rate was 33%, and of our full-year tax liability, 43% was deferred.
Looking now at the balance sheet, we remain focused on maintaining strong liquidity position and keeping our leverage modest. Cash balance was $1.1 billion at the end of the year. As a reminder, the majority of this cash is held in international. Most of our international funds are expected to remain overseas and be available for future upcoming capital programs in West Africa and Israel.
Total debt at the end of the quarter was $2.3 billion, which is an increase year over year of approximately $390 million. Our cash balances also grew during the period by $480 million. So net debt actually decreased $90 million. At the end of the year we still had almost $500 million in the remaining committed availability under our revolving credit facility, which has a current maturity date of December 2012. Debt to cap at the end of the year was 26% and once you factor in the cash balances, our debt to cap net of cash was only 15%.
I would now like to discuss our 2009 guidance which as I mentioned earlier was issued this morning. As with last year, we are providing guidance on a number of fronts, including production and all major cost items. As Chuck mentioned, our 2009 capital budget has been initially established at $1.6 billion. Although the amount may be adjusted upon or down 15% depending on the economic conditions and opportunities throughout the year. This compares to capital spending of $2 billion last year if you exclude property acquisitions.
The geographic allocation has been modified from last year. In fact, international expenditures are up 15% from 2008 and are expected to represent 30% of the 2009 capital program. We are de-emphasizing the domestic natural gas drilling in the near term and focusing our dollars on longer-term growth opportunities where 40% of our budget is allocated, including projects in the deep-water Gulf of Mexico, Israel and West Africa.
Our ability to fund the 2009 capital budgets is supported by our strong cash flow aided by beneficial hedge positions and as applicable our large cash balance. Overall, we anticipate annual volumes to be in the 212,000 to 220,000 barrels of oil equivalent per day range. We have done our best to estimate total volumes but there are multiple moving pieces and several uncertainties as we face 2009. Buys in the US are anticipated to decline slightly year over year as a result of ongoing hurricane shut-ins, natural declines in deep water Gulf of Mexico, and reduced drilling activity.
Our quarterly volume range guidance assumes that Ticonderoga in the deep-water Gulf of Mexico will come back online in the second quarter after infrastructure repairs are completed resulting in anticipated increased volumes over the first quarter 2009 levels.
Internationally, we anticipate continued growth resulting from strength in natural gas sales in Israel, additional wells in North Sea, and increased natural gas sales in West Africa, due to lower facility and 3rd-party maintenance downtime. We still have some uncertainty in our Israeli volumes with specific regards to seasonal demand, outside sources of gas in the market and the ultimate timing of the Hagit power plant which should see some significant volumes in the fourth quarter of 2009.
As far as expenses are concerned, we estimate that our per unit cost for LOE and DD&A will be up a little bit from the 2008 levels, lots of moving pieces here too on the cost side, so I’ll just point out a couple of things. For LOE, we expect to see some unit rate increases because of West Africa maintenance projects in the first part of the year. On the DD&A side, increased volumes and scoots associated with Dumbarton phase II expansion are a major contributor. Obviously, the mix of volumes produced has a large impact on our per unit cost, and they will move around quarterly. The ranges for these costs are relatively consistent with what we ended the year. We think it will take a good part of the year to really see cost coming down as a large portion of these costs for us is service and supply oriented.
Exploration expense is expected to be somewhat higher than 2008 which is a great year for the company in terms of our exploration success. We will likely be testing a couple of Wells in deep-water Gulf of Mexico, one or two in West Africa, and we had two more wells on schedule for Israel. In addition, seismic expenditures are up a bit resulting from additional work in Israel. We expect G&A will increase slightly, primarily due to the project teams that we are building in the deepwater Gulf of Mexico, West Africa and Israel.
We also provided guidance on our estimated tax rate a split between current deferred based on adjusted earnings. Obviously, commodity prices and the amount of intangibles drilling cost have a significant influence on these items. We estimate that for 2009, our effective tax rate will be between 30% and 34%, with 35% to 45% deferred. One other schedule that we have included in our guidance release is the roll off of the mark to market value in some of the commodity items when we converted to mark to market accounting with effect from January 1 of 2008. This conversion resulted in us recording a deferred revenue loss that is reclassified to earnings over the same time period as our hedge covenants. For 2009, the deferred revenue loss is $57 million, virtually all allocated towards crude oil. This will be reflected as a reduction in our realized price. All of the hedge gains and losses will be recognized in the period they occur through the gain loss and commodity derivatives line below our operating income line.
Another schedule attached to our guidance release lists our current oil and natural gas hedges for 2009 and 2010. For 2009, we have approximately 35% of our worldwide crude oil production hedged at a minimum of nearly $82 per barrel. As for gas, nearly 70% of our 2009 anticipated production is hedged or marketed under long-term pricing arrangements. Our natural gas hedges are applicable to US volumes with an average minimum price of $8.90 per MCF.
That concludes the financial review. I would now like to turn it over to Dave.
Thanks, Chris, and good morning, everyone. I would like to start off commenting on our year-end 2008 reserves of 864 million barrels of oil equivalent. We reported reserve replacement of 147% from discovery, extensions, performance revisions and acquisitions. With a 59% to 41% US versus international mix, and an overall 36% liquids component, we liked the balance and diverse nature of our reserve portfolio.
Excluding negative reserve revisions due to low commodity prices totaling 47 million barrels equivalent, reserve additions were 115 million barrels of oil equivalent. Over 70% of these additions came from the US with the majority coming from the execution of our low risk development onshore at Wattenberg, Piceance and various other programs. As we look at our organic onshore US program, drill bit F&D excluding the revisions was slightly under $15 per barrel oil equivalent or 250 per thousand cubic feet equivalent.
On the international side, the majority of the additions came from the Elba field in Equatorial Guinea as well as in China at the CDX field. Our total average cost of these reserve additions, excluding the negative price revisions, was $20.38 per barrel oil equivalent or $2.40 per thousand cubic feet equivalent. Included in our cost incurred was over $750 million in exploration investments for multiple projects around the world. Because of our portfolio with a significant portion of our capital programs committed to long-term growth through exploration, we were many times unable to book identified resources at the time of discovery. Examples of our significant and unbooked resources discovered over the last couple years include our multiple discoveries in West Africa, Gunflint in the deep-water Gulf of Mexico and now Tamar offshore Israel. In fact if you look at the total of the unbooked resources discovered over the last two years, we have found approximately 600 million barrels equivalent net to Noble Energy.
Now we will review a few fourth quarter highlights as well as take a quick look at our 2009 programs. Let us start with the onshore US assets, which comprise about 50% of our preliminary 2009 capital program compared to 60% in 2008, excluding our western Oklahoma acquisition last year. As we stated in our earnings release, our Northern region operations reported record quarterly production in the fourth quarter, producing 83,000 barrels equivalent per day, 35% of which was crude oil and natural gas liquids.
Northern region total volumes were up 6% over the same period last year led primarily by continued success in our low risk development programs at Wattenberg and Piceance. We will continue to move forward select onshore development programs while restricting capital from several of our US gas plays until commodity prices recover. Our most active onshore program will continue to be in the Wattenberg field with its low cost structure and balance of liquid and gas production. We have started the year with a six-rig program in this field but we will revisit the size of this program as we approach spring crop season and have a chance to further evaluate the economic environment.
Currently we are drilling our first Niobrara horizontal well and expect to drill more of these projects during the year. Our fourth quarter volumes at Wattenberg were impacted late in December by a third party processing plant fire which has resulted in a shot in of approximately 25 million cubic feet per day equivalent of our production. We have seen partial recovery earlier this month but full recovery is not anticipated until early May.
In the Piceance Basin, we have lowered our rig count over the last several months to our current level of two fit for purpose rig down from four to five rigs last year. We are paying careful attention to the commodities markets and we made redeploy at least one of these rigs elsewhere in the portfolio as the year develops. We have deferred our drilling activity in the Tri-State Niobrara area and instead are concentrating on high grade and future locations from our seismic data.
We have made additional cutbacks in other onshore programs as well. In the second quarter, we will bring a rig into East Texas to drill some Haynesville tests on our acreage. Throughout the year, we will continue to test a few new concept ideas in both our existing and new US resource plays. Again our main focus onshore in the US is capital flexibility, continuing to improve our efficiencies, and working with our vendors and service providers to realize cost to better reflect the current economic environment.
We expect to average around 8 operated onshore rigs during the first half of 2009, which is less than half of 2008 activity during the same time period. In the deep-water Gulf of Mexico, our Raton gas development came online late in the fourth quarter and has ramp up to over 34 million cubic feet per day and about 600 barrels of oil per day. We continue to be impacted by downtime resulting from hurricanes Gustav and hike. In the last couple of weeks, we have seen about 1500 barrels of oil equivalent per day net come back from of our Lost Ark and Lorean [ph] properties.
Our latest third-party estimate on Ticonderoga is that it should be returned to production sometime in the second quarter depending on restoration of the gas export lines. We anticipate spending about 20% of our 2009 capital budget in the deep-water Gulf of Mexico. A significant portion will be allocated to high impact exploration where we intend to participate in at least two exploration wells. Right now, we are drilling our Santa Cruz prospect which is a nice tie in candidate to 2007 Isabela discovery. We operate this prospect with a 26% working interest and a chance of success of approximately 50%. We're actually drilling this prospect a little earlier in the year than we anticipated, but we were able to pick up a rig at a reduced rate from another operator, so we have accelerated the plan. Results from this well should be known in the second quarter.
At Tortuga, we decided not to pursue development of the secondary objective we discovered last year. With the lease expiration at year-end 2008 in the current environment along with our partner we elected not to submit a development plan to hold as block. Plans to appraise Gunflint, our largest discovery in the deep-water Gulf of Mexico and moving forward, we are currently acquiring wide azimuth seismic data to aid in preparing for an appraisal well, either late this year or early in 2010 based on rig timing.
Now let us move to international. In West Africa, our fourth quarter volumes were impacted by about 30 million cubic feet per day from longer than expected downtime resulting from pipeline maintenance at the Alba field. The pipeline maintenance has been completed and operations back running at full capacity since early January. Development plans at Benita continue where we're getting closer to sanctioning the project. Our plans are being reviewed with our partners and the EG government and we anticipate going to our Board for approval by midyear. As we mentioned before, we have gone out for bids with several firms on an FPSO design, we hope to issue that contract immediately following sanction. The rig that we're currently using in Israel is scheduled to come back to us in early 2010 to start the Benita development. We will likely pick up another rig to assist in the development during 2010 and 2011.
Late in 2008, we initiated drilling on our prospect named Carman on Block O offshore Equatorial Guinea. Here we were targeting similar lower Miocene sands that we identified in the Diega oil discovery on Block I. Initial results indicate 26 feet of net oil pay and 13 feet of net gas pay. This is again another other deposit of data point for our West Africa where we now have been successful in 11 of our 12 wells drilled. Carmen is our first oil discovery in Block O and we will be re-calibrating seismic to identify other similar opportunities. Carmen looks to be a nice tie in candidate as we progress the Benita oil development for first production in 2012.
In the North Sea, our second phase of development on Dumbarton continued. However, there is no drilling activity in the last quarter due to delayed arrival of the drilling rigs from its previous assignments. The rig arrived in the field in late January and has commenced an infill well on Dumbarton before moving on to Lochranza to drill two production wells. The rig will be released in mid 2009 to allow the sub sea construction work associated with Lochranza development to commence. Production from the two Dumbarton infill wells drilled earlier in 2008 started at the end of the third quarter 2008. The higher gross liquid rate associated with the two new wells reduced the performance from some of the phase 1 wells. However, the new facility that has been installed in 2009 associated with Lochranza will allow the Dumbarton well to be flowed more optimally.
Early production from the Dumbarton infill well currently being drilled is anticipated in the second quarter of 2009 as a result of having already installed the tree and necessary jumpers last year. Commencement of gas export is also expected in the second quarter which will allow an additional well to be converted back to production later in the year.
Now turning to Israel, we ended 2008 with some very strong volumes, up about 20% from the fourth quarter of 2007. The results from the Tamar well, our largest discovery ever, are very exciting for our company. At Tamar, we tested a limited 59 foot section of the over 460 foot net pay interval and flowed at 30 million cubic feet per day restricted by test facilities. Our internal performance modeling suggests this well could produce at a rate of over 150 million cubic feet per day.
One of the unknowns we had prior to drilling Tamar was the rock quality that we might encounter in this very unexplored basin. We're extremely encouraged by the results to date. It is a little early to be talking about development scenario but based on initial indications, this doesn't look to be a very complex project, but will be quite large in scale. The technology to develop this project prospect at this water depth has been implemented in the Gulf of Mexico and we are pulling a team together to drive this project forward to help meet the growing market demand.
As a reminder, the gross mean resource potential shall at Tamar is estimated to be five trillion cubic feet or according to one analyst the equivalent of 833 Haynesville wells. In addition to reservoir’s success, the drilling performance and execution was outstanding, with cost and timing at or below AFB targets despite operating in relatively unknown conditions.
We're moving to drill our second prospect covered by 3D that is drill ready. While Dalit is a smaller prospect with gross mean resources of about 500 billion cubic feet, it is in shallower water and is much closer to shore. It has a 40% chance of success. Drilling operations should take about two months after which the rig will return to Tamar to drill a key appraisal well that should help us better define the resources in the structure. As a reminder, we have a very substantial acreage position in this basin with over 1.5 million net acres and multiple other leads. In addition to these two wells, we will be working with our various partners to define a 3-D program to evaluate the other leads in the area.
2009 is certain to be an interesting year. The year we will be focused on progressing our large operated projects in West Africa, Israel and the deep-water Gulf of Mexico, while maintaining flexibility in our onshore US development program. We will remain focused on things we can control, such as driving cost down, improving our operational performance and redeploying capital to the best projects. Overall, we feel very fortunate to have the ability to invest in a diverse mix of significant projects and an exploration program that has been hitting on all cylinders.
At this time, Dana, we would like to go ahead and open the call to questions.
(Operator instructions). And we will go first today to Michael Jacobs with Tudor, Pickering, Holt.
Michael Jacobs – Tudor, Pickering, Holt
Good morning, everybody.
Good morning, Michael.
Michael Jacobs – Tudor, Pickering, Holt
Chuck, just thinking about your exploration success over the last three years, can you offer some color on when you expect to sanction major projects and book reserves over the next three years and potentially quantify what bookings could look like through 2012?
Well let me just give you just a broad guideline in terms of where we see things going and also maybe a little bit of a discussion on how reserves get booked for these projects. The first one that is up for sanction is Benita and as we discussed hopefully by midyear we will have that sanctioned by the company partners and the government. That leads to initial reserve booking but especially in these international projects, you will see initial bookings that are based on the data you have at hand and then as you see performance you will continue to add resources and moving them into proven reserves. So our view is on many of these especially where we’ve drilled top of structure, got good seismic data, but at least under the SEC guidelines that we have been operating under for many of the past years, we would say that we will make some initial bookings that will continue to increase over a period of I would say at least two to four years following initial production.
So again in West Africa, I think that will be the key project. We will have some tiebacks that at some point will be sanctioned into Benita. Keep in mind there is Diega and that we just mentioned the Carmen discovery, those are likely to follow, we wait for the initial project and then move those on. The gas projects, we have spaced out, and we would not expect any of those to sanction – I'm talking about the gas projects in West Africa, we wouldn't expect those to sanction in 2009. Again those are going to be later years and that will depend on how we put together the development plan, whether we decide for instance to cycle one of those projects, to strip out liquids, in which case we would book the liquids but not the gas. And then later as the market is in place for the gas and there is an outlook for the gas, we would sanction that part of the project and book it.
If you look at Gunflint, Gunflint is waiting on appraisals. And as mentioned, we have been gathering some additional seismic and our anticipation is that it will not sanction until probably the best will be 2010 because we have got to wait for the appraisal work, it is a very significant prospect. We have got a very nice well on it, but it is sizable and we need to understand the limits before we move forward with the development there, because it can – depending on its size, it can clearly affect the project and how we proceed.
And in Tamar, again that will be a project that we will book at the time of sanction. But again I would anticipate given the size of that field that it will also be another one that reserves will come on as you produce it and as the market is confirmed. So there is, in all these cases, there is a lot of flexibility on the schedule. But I think in realty, we're going to see is, as Dave and I mentioned, we have got about 600 million barrels of exploration resource discoveries net our interest that we have now added up over the last couple of years and those would certainly hope to see flow on the books probably over at least the next five years or so. So it is going to be quite a process as we move those on.
Michael Jacobs – Tudor, Pickering, Holt
Great, thanks. Thanks for that. Moving on to Israel, and Dave talked about a relatively simple development scenario for Tamar, can you offer some context on how you develop a 5 TCF discovery offshore Israel in terms of number of wells and facility ready size required if you were to draw some of the simple apologies to similar discoveries?
I will soon let Dave add in on that, but the key is having high reservoir quality is natural gas and as a result – and keep in mind that for sub sea developments, we're not that far from either the shore or other infrastructure. So the most simplest would be sub sea completions flowing back to tie in to the market or potentially even to a Mari-B. But as you go to larger sizes and scale, I think it starts to get a little bit more complicated, and that is quite honestly where we need to see do some appraisal work, and see how we go forward, because you could put a floating structure out there to bring the wells back and then move it to market. You could take sub sea wells or shallow waters, then combine it and do some minimal processing and then deliver it to the market. So there is a lot of options, the key though is this is a high quality reservoir as we indicated the initial well. We think once it is completed and connected up, it could flow in excess of 150 million a day. So it means that you really got to be looking at deliverability your market take, and that is what will drive your well. Dave, I…
No. I agree Chuck. I think the main thing here and we talked about it as being one of the big unknowns going into this was just the flow capability and just the obvious permeability and flow capacity that we are seeing really help a lot and will really help us as we get another test, another appraisal as we step out a little bit and see how the reservoir looks at a little distance also. But I mean the main thing that Chuck talked about too, the nice piece here is, you have a couple of different ways to go here. We can either tie in to shore or we also have the existing fields capacity down at Mari-B that timing could work out pretty good. You also have the ability to take some gas down in that direction too. So all things said, we are very encouraged with what we’ve seen so far and anxious to get another appraisal test.
Michael Jacobs – Tudor, Pickering, Holt
Great thanks. I would like to sneak in a third question if I could, you have now tested a deeper oil play (inaudible) offshore West Africa you have found (inaudible) are you seeing anything different on seismic in comparison to your 2007, 2008 program, and does it open up a deeper trend where you drill other prospects?
I think the one thing that it does do is some of the things that maybe didn't jump out at us is bright on seismic that you weren't sure where they wet, where they thin, or could there possibly be oil? Now we are starting to see some encouragement in some of these things that weren’t as obvious so to speak a little dimmer type amplitudes are now perspective. So that helps us in going back and re-look and recalibrate some of our programs and help guide us to looking at some things that may be weren’t off the top of the radar screen before.
Michael Jacobs – Tudor, Pickering, Holt
And are you going to drill anything between Diega and Carmen?
No, I think that is – we will have to see in terms of as go forward. I think that is going to be dependent on the interpretation of the seismic and whether or not we see that there is another opportunity in between them. Right now we're viewing those and we view Carmen as a separate opportunity, and we went into it thinking that there were some chance that there was some may be some of this oil pay involved in there and it was successful. But it is much more difficult to interpret with these dimmer amplitudes in the middle or lower Miocene interval. So we're not as quick to just try to jump in and start drilling everything that looks like it is a little bright spot on the seismic. We have to do quite a bit of work.
Michael Jacobs – Tudor, Pickering, Holt
Thank you very much.
And we will take our next question from David Kistler at Simmons & Company.
David Kistler – Simmons & Company
Good morning guys.
David Kistler – Simmons & Company
Hi. Real quickly with the adjustment to production this year, how does that impact your longer term goal of 6% to 10%, maybe can you give us a little color as to what you're thinking about for 2010 and even 2011?
Well, we are still trying to roll all that through. So we have not given any new guidance for 2010 or 2011. We're going to have to see first of all how some of these large projects move forward and how they build on. And quite honestly I am just looking to see on the pace of the recovery of the North American market, I think it is premature right now to speculate on how quickly for instance the North American gas market may recover. In our case there is no question we have pulled down capital from North America gas drilling and we will keep it down until we see that that market is recovering. So it is kind of dependent – I'm telling you my view is it is depending on the market right now.
David Kistler – Simmons & Company
Okay. That is helpful. Building on that a little bit, and looking at North America, your attractive balance sheet, as commodity prices are pretty soft and we are seeing that reflected in valuations of the equities, doers that whet your appetite or how do you guys think a little bit differently about M&A in this environment and the possibility of doing a decent size deal in the US as you have done in the past?
Well I think when you look – for us when we look at asset acquisitions or M&A, we just have to continue to measure those against the other opportunities that we have in our portfolio. I would say that – we have always said in the past that perhaps adding another area in the US would be positive for us and we will look to see if the values move back within range, they moved away from us in 2008. We mentioned several times in the past that it was – they look too costly based on our view of the market, but perhaps they will move back in. And yes, we are certainly open to something like that, but it is not – I would say it is not a huge issue with us. We have more than enough on our platter right now in terms of major projects and growth vehicles that go forward for several years. And so we're going to stay focused on some of these projects, which have very high indicative returns in the current environment – even in the current environment that we're seeing today, and could position us to take advantage of a stronger environment two or three years out. So it is all about balancing it and judging these opportunities against each other.
David Kistler – Simmons & Company
Right. And thinking about the opportunities you have in front of you and kind of the longer-term investments that you are making, what sort of a price factor you are using on those at this point? Obviously, you mentioned could strengthen over time, but kind of curious what you're using for your base as you work through those longer-term projects?
On the longer-term projects, we are still thinking long-term oil prices that are kind of in the 60s to 70s. I mean we test them at lower prices as well but think in terms of 60s and 70s as longer-term prices. I haven't figured out yet where to recalibrate US gas prices right now. I'm very - I guess we are still a little concerned about the amount of supply we have had, and of course we have coupled our growing supply against a very weak economy. So I think we're all trying to recalibrate that, understand what a good target for longer-term US gas. Our international gas of course is almost always coupled to other contracts and for instance in Israel it is tied more to world oil prices there than anything else.
David Kistler – Simmons & Company
Right. And then one just last question, on the reserves that were impacted by negative price related revisions, can you talk about what commodity price would actually bring those back on to the books?
I think for any increase that another $10 oil price or $1 gas, you will start to recover some. I mean the reality is, if you looked back at it, and you used the average price as the new methodology would have shown, we wouldn't have lost any of it per se. So you know for every $10 of oil and $1 of gas you start to get a decent chunk back.
David Kistler – Simmons & Company
I just would add is I don't think it was more of a continuous fall off. There were some properties that they had a fairly-- they had maybe a higher threshold but I don't think there was any of it just sort fell off a cliff, there’s some magic. I think the real key is, as Dave said is, that as prices recover, you will see that come back. But then again we all know we have a different methodology that will be dealing with that in 2009, so you’ll probably never get the chance to see what the opposite is.
David Kistler – Simmons & Company
Great. Well, thank you guys very much for those clarifications. I appreciate it.
And we will take our next question from Brian Singer with Goldman Sachs.
Brian Singer – Goldman Sachs
Thank you. Good morning.
Brian Singer – Goldman Sachs
Actually somewhat following up on some of the comments on price regimes, when you look at the huge potential in Israel now, how should we think about things from a pricing perspective? Do you see room for renegotiation versus where your previous contract was and how – what are you seeing, I guess somewhat separately in terms of there is really demand for natural gas and the supply and demand balance there?
Well, you almost have to look at it pre-and post-Tamar. When we look at our existing production and sales in Israel, we had already seen higher prices on a portion of production. Keep in mind that the initial contract in Israel was only for a portion of our reserves. And as a result of that, in fact, about 25% of it was not contacted originally. So what we have been doing since then is as global prices increased, we have been working with customers and clearly our primary customer to sell incremental gas, and those have been at prices that were in some instances substantially above the base contract. But again they were tied to basically oil prices. So as oil prices moved up, our gas price moved up, and you can see that in terms of our average realized price in Israel, that have moved up over the last year. So going forward, I think the real question will be, with the size of discovery as Tamar as to how we want to look at the market and what the true market demand is going to be for that, and that will set the pace of development, and I think really sort of reopen discussions about how to price it. So those are obviously sensitive negotiations and I don't want to speculate on what we're looking for out of them prior to getting into those discussions. But I think at the same time, it’s clearly got the ability to expand market demand in Israel. There is no question that with this kind of supply capacity, it is going to open up some additional markets there, additional demand. And we have got more exploration to do. There is no question that we see other opportunities there. We're moving to another one right now at Dalit and that again will tell us where it goes. But again think of it as gas market that is tied to liquid prices. Think about it in terms of a broader Mediterranean market because there is some connection with Egypt and in Egypt generally you see prices that are currently in the $4 range, maybe a little bit above that. But again that’s kind of the market that we are in and then there is the tie to oil prices as you move forward. But Tamar is of such size and scale that it will be marketable really as an independent source and we will work with all the customers in the region to see what’s the best value for that.
Brian Singer – Goldman Sachs
Great. Thank you. And secondly, just going back to North America, are there pricing points for both oil and natural gas at which there could be a further reduction in both drilling or in holding back on production from existing wells?
Well, I guess putting aside the last part which you referred to, I think curtailments, we are not curtailing production, but we are obviously curtailing development activity because of just seeing what returns. It is a continuous process. I think – keep in mind Dave’s comment, in the Piceance Basin, we have two fit for purpose rigs there, but depending on conditions, we could take one or more of those out of there, and I think those, that is a good example if we see further declines in gas prices and netbacks to the Rockies. That would be a question, and also the reference to what we do as we get into the crop season in Wattenberg. We have some flexibility to move some things around there. On the oil side of it, some of our oil development right now are things like in the deep water Gulf of Mexico and we don't have as much sensitivity there. We have looked in our West Africa, this is I know outside the US, but that project is very resilient to downsides and prices. So we see that moving forward as well. But everyday we look at that and we re-calibrate and look at the programs, because while oil appears to have settled in at some point and maybe it'll return to a stronger market later in the year, but we have not seen any indications that natural gas has reached really an equilibrium point in our view.
Brian Singer – Goldman Sachs
Right. Thank you.
And we will take our next question from Irene Haas with Canaccord Adams.
Irene Haas – Canaccord Adams
Guys, two questions. Firstly, what is your breakeven economics in the Tri-State area and Piceance? And secondarily, a little color on your Equatorial Guinea gas business, methanol as such, and phase II Alba, how sensitive are these two business lines to sort of global economy? Are you seeing any sort of pricing weakness?
I will start at the backend with Equatorial Guinea and then maybe Dave can just comment a little bit on Tri-State. But in Equatorial Guinea, keep in mind, our methanol business there is a very low cost business. Methanol for us is fueled by natural gas, it is sold into the methanol plants at $0.25. And so the plant has always been considered one of the lowest cost producers in the world. Now the impact financially of course is that methanol prices as you would expect have declined substantially based on global economy. We're still generating margin, but it is doesn't generate as much cash as what it did a year ago, but it is floating against commodity prices. But for the methanol business, we don't really – again it is a low-cost business, and our prices are going to swing with oil prices. On the Alba Field, that field is extremely low cost. So we see strong margins, has a low DD&A rate, low operating cost, and as a result again it has got very good margins. It is just that those margins shrink in a lower price world. Keep in mind that goes into the Brent market and Brent pricing has actually been a premium to WTI sometimes, is $6, $7, $8 a barrel about West Texas. So our international oil production has actually seen strong realization than we have in the US. I will let Dave just talk a little bit about our view on Tri-State.
Yes. I think when you mentioned, Irene, the Tri-State and Piceance piece, again if you're looking at strictly cash flow of existing production, I mean that breakeven is very low. That is down a dollar an MCF type piece. When you are actually looking at capital investment and breakeven for capital investment type pieces, the Tri-State, I think we would like to get back up in at $6 to $7 an MCF type price or above to really expand that program. The other part about both these areas, there is some better areas in each of those deals that still look fairly good at this $5 to $6 range, but those are more limited in aerial size. I think what we would really like to see is the $6 to $7 or above type price and it is really when do you see that coming back that will drive when we really get very active in those programs again.
Irene Haas – Canaccord Adams
And Mr. Larsen, I will turn the call back over to you, sir.
Okay. Thanks very much. I know we have run over our hour timeslot here, and we just want to keep everybody on schedule for their long day today. So we will end the call here today and I would just like to thank everybody again for joining us and we appreciate all the interest that you have in Noble Energy. Thank you.
Thank you, sir. And that does conclude today's conference call, thank you for your participation. You may disconnect at this time.
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