Equinor ASA (EQNR) 2006 Q4 法說會逐字稿

--full-year 2006 presentation as it's delivered today [inaudible] in London. Before continuing we would like to dedicate a few minutes on [inaudible] [inaudible] three exits and well, they're, well, quite visible here. They will lead straight out into the street as the meeting point is out in front of the auditorium where you came in.

This morning at 8 o'clock a.m. Central European Time the fourth quarter-- the materials became available on our Web site, statoil.com and the presentations used today can be downloaded from that Web site.

As we are in a merger period, a merger process with Hydro, we're subject to the SEC's rule 425 on all communications in this period and please be aware of the disclaimers and cautionary statements that we have in the presentation and all material you can download from the Web site.

Today's presentation will be split in two -- first, the fourth quarter and full-year 2006, given by Statoil's President and CEO, Helge Lund, and Statoil's Chief Financial Officer, Eldar Saetre. After this presentation, Helge Lund will address the merger between Statoil and Hydro's oil and gas facilities. And finally, we will have a common Q&A for both presentations.

And with these few words of introduction, I will leave the floor to Statoil's President and Chief Executive Officer, Helge Lund.

Thank you, Lars, and welcome to all of you here in London and also those of you that are following Statoil on the 'Net throughout the world.

Let me, first, reflect a little bit on the environment that we are operating in now as speak. I believe that the fundamental challenge for the oil and gas industry is access to reserves as well from the Gulf of Mexico to the Persian Gulf, [inaudible] are getting [inaudible] and [inaudible] are harder to come by. On the NCS, Norwegian continental shelf, and elsewhere, I think new reserves require more effort and more stimulation than over.

And with the competing use of the world and where you stand depends a little bit on where you sit. On the Internet, the world has already hit the era of peak oil use. Google will return 1.2 million hits for a search on peak oil and at least peak oil community can seek comfort in the fact that one day they really will be right.

Others claim that this is the age of the MSEs, so the national oil companies and the suppliers. The MSEs they have the reserves and the cash. The suppliers have the technology and the know-how and most of the national oil companies they've dictated terms for access and [inaudible] take it or leave it. And they believe that suppliers are ready, able and willing to do the job if oil companies fail to take it.

Finally, there are people who argue that we now live in the age of super minus, lean/lean and with niche expertise they can outperform and outpace any major. They say the majors are knocked out, they're too big and intimidating for balanced partnerships and that the [inaudible] fields are gone, being small will make you big.

But lately, it's been my on-- to all of these views that I would argue that more than anything, we live in the age of complexity and cooperation. The oil industry has never, ever had to deal with more complexity. The oil industry has never been more dependent on cooperation and the oil industry has never been met with higher expectations with regards to solving the climate change issues.

At Statoil we are working from three strategic assumptions. [inaudible] are currently out of reach. Only collaboration with cheaper, cleaner and smarter energy production and the integrated companies will be crucial to meet growing energy demand. This is one of the reasons why we have proposed to merge the oil and gas division of Hydro with Statoil later this year.

As you will appreciate and as Lars has already mentioned, there are rules and regulations related to what we can say and not say about the upcoming merger, but I will allude to some aspects of the synergy potential of the merger after the presentation of the fourth quarter and 2006 highlights.

We're still in a period with relatively high price level, driven by increases-- increased demand and economic growth, as well as constrained production capacity and rather fragile capacity. The market is [inaudible] well illustrated by almost a 30% fall in the oil price since the summer.

OPEC's announced production cuts should cause the confidence in the sustainable global economy offered at high oil prices, but they still-- I'm sorry, related to the development in prices and markets. [inaudible] affects the industry with regard to making long-term investment decisions.

The current price environment influenced results [inaudible] on average, Statoil realized about 5% to 6%, $64.40 U.S. per barrel over the year and on the Statoil portfolio gas contracts, averaged realized gas price in 2006 was 1.91 Norwegian kroners per standard cubic meter of gas.

In a highly uncertain price environment, we have to be prepared for times with lower prices. Therefore, we maintain cost control, focus on capital discipline and are continuously improving to stay among the best performers in the industry.

In financial terms, 2006 has been the best year ever for Statoil. Also, operationally we have delivered strong results and strengthened our growth platform. We have a very high project and exploration activity, projecting future growth. We have further developed our international positions, particularly in Gulf of Mexico during 2006 and we have proven strong results in our mid and long-term businesses, both in natural gas and in manufacturing and marketing. In fact, in the M&M business we have reached our target of [inaudible] or 13% one year before [inaudible]

The fourth quarter 2006 yielded the best quarter in net results ever. The realized oil and gas prices have increased from 2005 but EBIT is down, primarily owing to a 9% decrease in oil and gas [inaudible], increased exploration activity and expenses and somewhat higher operational costs due to increased DD&A on the [inaudible], startup costs on new fields not fully in production yet, more maintenance and repairs on the-- particularly the older fields, as well as the general cost inflation in the industry.

The [inaudible] was more than 12 billion Norwegian kroners. The increase is partly due to lower tax rates and the positive results from financial items. The lower tax rate of 58% is mainly due to infrequent items of 2 billion Norwegian kroners and a relatively low tax on financial income. Adjusted for infrequent items, the average tax rate for the quarter was 65% and the earning of 5.58 Norwegian kroners per share is the highest ever.

The strong quarterly results throughout 2006 is reflected in our annual results. Results from operations came out at almost 117 billion Norwegian kroner. This is an increase of 23%, primarily due to higher oil and gas prices, as I already talked about. And the tax rate for 2006, for the year, was 66%.

Net financial items amounted to a gain of 4.8 billion Norwegian kroner in 2006 and this is mainly explained by a decrease in the exchange rate between Norwegian kroner and U.S. dollars leading to an adjustment of a debt held in dollars.

The board proposes the highest distribution to shareholders in Statoil's history. Subject to approval by the AGM, the total distribution to shareholders will be 10.67 Norwegian kroner per share for 2006. Of this, 9.12 is cash and the average distribution ratio [inaudible] will be 48%. And you will recall that we indicated a range between 45% and 50% throughout the period.

Despite the challenges related to production and the increases in cost and CapEx, we still delivered a highly competitive return on the capital employed and our ambition is to maintain a competitive ROACE position in the years to come with continued focus on profitability, cost and capital discipline.

In September, we guided on the production for 2006 of 1,140,000 barrels per day based on a $60 oil price. The actual production was 1,130,000 barrels per day and the average oil price for 2006 was $64.40 U.S. per barrel. Adjusted for the PSA effects at $60 per barrel, the production would have been 1,139,000, which is comparable with our earlier guidance from September.

We have during 2006 added production capacity from 9 new projects coming into operation, 5 at the NCS and 4 international projects starting production in 2006.

Like the rest of the industry, we have been faced with some operational challenges, both on our own as well as on partner-operated fields. This has affected production negatively during 2006, but we are constantly attacking production challenges and striving to all the time improve our cost performance in this area.

Our production target for 2007 remains at 1.3 million barrels per day. I would, however, like to underline that this is a challenging and stretch target, as exemplified by the recent production issues on Kvitebjorn field in Norway, as well as the partner-operated [inaudible] field in [inaudible].

The target is, however, achievable and it will depend on successful ramp-up of production from existing fields, new startups coming on stream as planned, natural gas sales at normal levels, as-- and getting profitable returns from a wide range of activities initiated on mature fields at the NCS. Overall, however, we are more likely to undershoot than overshoot the target of 1.3 million barrels per day.

Like the rest of the industry, Statoil is faced with the challenge of replacing reserves. Our ambition is to, over time, achieve a replacement ratio of 100%, on average. This year's 73% replacement of production is not satisfactory and it's mainly due to the timing of new projects-- project sanctioning.

Continued exploration, maturing of existing reserves and business development activities will be pursued aggressively to bring the replacement rate back up to above 100%. We are continuously maturing the portfolio of discoveries toward sanction and expect more than 20 projects to be sanctioned in 2007 and 2008.

We maintain our comprehensive exploration program, however, of course, it will take time and some work before exploration impacts the resources mature for the [1P] classification of reserves.

Statoil's 1P reserves are 4.2 billion barrels per year-end 2006. 60% is gas and the rest, 40%, is oil.

Looking at the exploration activities, they have been stepped up significantly throughout the year. In 2006 we participated in 37 completed wells and 4 exploration extensions -- all together 41. This is compared to the 12-well program in 2004 and 20 in 2005. We are stepping up significantly our efforts in exploration.

Last year we made 21 discoveries, 10 on the NCS and 11 internationally. And at year-end, 13 wells were ongoing.

I would like to underline that Statoil is by far the most active oil company on the Norwegian continental shelf. We have fulfilled our commitments and more throughout the years. Out of the 23 wells drilled on the NCS in 2006, Statoil participated in 21, of which 10 as an operator.

In the [inaudible] license realm, we were awarded 8 licenses, including 3 operatorships and the APA realm yielded 8 licenses, including 6 operatorships. We have a positive view on the NCS and encourage the government to license new and exciting areas for the companies to explore, particularly in the north.

Our international growth continues and internationally we have won exploration licenses in Indonesia, together with ConocoPhillips, in Egypt with Sonatrach and also in Angola with a range of partners. Additionally, we have acquired further high-quality assets in the Gulf of Mexico. We have an ambitious exploration program planned also for the year to come, both in Norway and outside Norway.

A few words on HSE and I think our strong efforts in this area paid off. The improvement in important indicators is encouraging. For the sixth consecutive year with improvement on these areas, incident frequency, I think we can conclude that our effort is paying off. Particularly in the areas of dropped objects and gas leaks we have made significant improvement throughout the last few years and particularly in 2006.

We are focused on safety by launching the safe behavior program. It focuses on the rights and the duty for the individual to openly reflect his or her views if safety is in any way compromised in a day-to-day operation. It started three years ago and it's still running and so far there have been more than 30,000 employees and employees with suppliers through this program.

The indicators show improvement and we're rated among the best in our industry as illustrated here by the Dow Jones Sustainability Index award as the best oil and gas company in the world in terms of sustainable operations. I think that indicates in this area that we are on the right track.

I will then hand over to CFO Eldar Saetre and he will take us a bit further into the numbers for the fourth quarter 2006 and the different business areas. Eldar?

Thank you, Helge. So I would like to start with some details on the E&P Norway business. The EBIT in E&P Norway for 2006 was a record high of 89.4 billion Norwegian kroner. In the fourth quarter, the EBIT fell to a level of 21.1 billion compared to 22.2 billion the year before.

Total liftings of oil and as were lower in the fourth quarter, both-- compared to last year. This was offset by higher prices, both on oil and in relation to the internal transfer price on gas.

The step-up in exploration activity has led to higher exploration costs and expenses of approximately 300 million Norwegian kroner to a level of 600 million Norwegian kroner in the fourth quarter.

The DD&A has also increased, as mentioned by Helge, by approximately 700 million compared to last year and this is due to asset retirement cost related issues and also changes in the portfolio of the producing assets, particularly related to the Kristin field.

Production costs per well have increased slightly, as expected, and I will return to this later in the presentation.

Looking then at the overall activity level in 2006 on the Norwegian continental shelf, five plans for development and operations were submitted to the authorities during the year and five development projects have also been put on stream. These were the Gimle, the Norne-K template, [inaudible], Oseberg west flank and [inaudible] fields. We have drilled a total of 17 wells from the Norwegian continental shelf and 4 extensions with approximately 50% discovery rate.

So, all in all, 2006 has been a very active year for Statoil on the NCS, demonstrating our strong belief in this oil and gas province.

So as earlier mentioned by Helge, we have experienced some production issues, especially related to some of the mature fields on the Norwegian continental shelf. So let me now elaborate on some of these issues, starting with an important reminder that we are mainly talking about delays for production and not decreased resources.

The production growth from 2006 to 2007 on NCS is basically depending on 4 factors. It's about drilling efficiency. It's about building up new production capacity. It's about getting new fields on stream and, finally, higher gas exports.

So, first, on the issue of drilling efficiency. Obviously, our most mature fields on NCS and, in particular, Statfjord and Gullfaks, experienced natural declines and they require a strong effort to compensate, as much as possible, for this development.

This decline was especially noticeable in 2006, the main reason being fewer production wells being drilled and set into production than was originally was planned for. The plan for 2006 was to drill 27 new wells on these two fields and only 9 were actually completed.

On Statfjord, the main reason for the lower number of wells related to capacity constraints in connection with the Statfjord late-life project. As you may recall, we made the decision to modify these three platforms on Statfjord and, at the same time, maintain high regulatory of production.

On the Gullfaks we had top-side equipment failure, which curbed our drilling progress. The [inaudible] at the long-reaching Gulltopp well were blocking a drilling unit for most of the year. It's also important to note that these platforms and these installations are actually getting older and the equipment is getting older, being run at a constantly high activity level.

So what kind of measures are we taking to improve the situation going forward? First of all, we have established as Helge mentioned, a quite comprehensive action plan to improve the drilling efficiency and also increase the capacity on all relevant platforms. This includes adding a third drilling crew on Gulltopp, which is now in place. We are currently also addressing a potentially upgrading of the drilling facilities on Gullfaks and, in addition, we are continuously hooking up satellite fields to the existing installations.

The second factor driving growth is coming from continued production buildups. As illustrated by the Kristin field, there's a lot of fields that have been put in production from 2005 to 2006 which will ramp up production during 2007. I mentioned the Kristin field, which is now anticipated to reach plateau production at the end of third quarter or during this summer.

Thirdly, growth is also reported by new fields coming on stream during 2007. Volve is coming on stream during the second quarter. [inaudible], as you know, will come into production in the fourth quarter and the Snohvit is planned for regular deliveries from 1st of December this year.

Finally, gas exports are also expected to increase somewhat, although this is very much depending on customer uptake, weather and market conditions in general.

It is important to note that all of these issues and measures were included in our revised production target for 2007, with the exception of the reduced production volumes from the Kvitebjorn and a somewhat further delay on the plateau production for Kristin.

So let me now look at the international E&P business. 2006 was, again, a record year for our international E&P business. We had almost 11 billion in EBIT results from the international E&P, which is up approximately 30% compared to 2005.

In the fourth quarter, international E&P had an EBIT of 1.3 billion against 0.8 billion in the same quarter last year, which is heavily influenced by the 2.2 billion impairment on the South Pars field in Iran.

Due to the step-up in exploration activity, we had exploration expenses of 1.3 billion versus 0.5 billion in the fourth quarter 2005. This number is also influenced by expensing of some previously capitalized exploration costs.

The production from E&P international was 164,000 barrels a day in the fourth quarter against 204,000 barrels a day in the fourth quarter '05. The lower production is entirely due to PSA production sharing effects.

Four new fields, adding approximately 140,000 barrels a day of new production capacity, were started in the fourth quarter. The ACG phase I in the east Azeri was completed ahead of schedule and came on stream in October last year. In Amenas, production sharing started in December. The [Dahlia SPSO] in Angola started in mid-December and finally, the first well from Shah Deniz was put in production, also, in mid-December. This well is currently shut down and we expect production to resume late in the first quarter.

In the fourth quarter we also further strengthened our positions in the deep water Gulf of Mexico through the acquisition of assets from Anadarko, increasing our shares in Big Foot, the Big Foot North, and also including the Knotty Head field.

Then I would like to summarize our unit production costs from our E&P business. The normalized production cost per barrel for 2006 at the $30 U.S. oil price was 25.6 Norwegian kroner per barrel, which is in line with previous guidance of below 26 Norwegian kroner.

As stated at our third quarter resource presentation, we have been revising our production cost target for 2007. Our new forecast is at 27 to 28 Norwegian kroner per barrel, compared to the previous target of 24 kroner per barrel. The main reason for the upward adjustment relates to the following issues.

First, the downward adjustment in our production target from 1.3 to-- excuse me, from 1.4 to 1.3 million barrels a day, partly explained by PSA effects. This accounts for almost 2 Norwegian kroners per barrel in production costs. Then we have seen, as mentioned by Helge, increased activity within maintenance and repair and also some cost inflation and finally, a NOX fee on the-- introduced on the Norwegian continental shelf from this year, explaining alone approximately [inaudible] barrels of the increase.

So let me now move to the natural gas business area. Again, 2006 was a record year, also for this business area, with an EBIT of 10 billion Norwegian kroner, an increase of almost 70%.

The average gas price in the fourth quarter was 2.01 Norwegian kroner per standard cubic meter and EBIT in the quarter was up 4% to 2.3 billion Norwegian kroner.

The gas resources are also increasingly reflecting the strong contributions from our gas trading activities. The value creation from our short-term optimization business is achieved via utilization of flexibility, both in the existing gas infrastructure and in our trading portfolio.

Our manufacturing and marketing business area has also now achieved their target of 30% normalized return on capital employed, which we launched, if I remember right, but in the capital markets day in 2004 and this is, as Helge mentioned, one year ahead of time and it's the result of a wide range of improvement efforts.

In the fourth quarter, manufacturing and marketing delivered an EBIT of 1.1 billion Norwegian kroner. Adjusted for the sale of Borealis in 2005 and the retail business in Ireland this year, this [inaudible] an EBIT down 700 million Norwegian kroner from fourth quarter 2005. The main reason for this is reduced refinery margin and an infrequent expense of approximately 300 million Norwegian kroner from implementing a new business model in energy and retail in Sweden.

Within manufacturing, the overall regularity in the processing facility is maintained at a very high level. Methanol prices were also at an all-time high at the end of 2006.

Oil trading delivered an EBIT of 400 million versus 500 million in the same quarter last year or in 2005.

Energy and retail continued to improve their earnings but profitability was affected negatively by the infrequent expense in Sweden, as I just mentioned.

Then to the corporate financials. Our net debt-to-capital ratio came out at 17%, which is somewhat higher than we have previously indicated and also higher than we saw in the third-- in the third quarter. The main reason for this development is related to cyclical variation in our accounts receivable versus payable and also the share buyback program, including an obligation versus the government and also higher pre-payment of estimated fourth quarter taxes on the 1st of October compared with actual earnings realized during the quarter.

Then a few comments to our investment program. As you know, we have a high-quality portfolio of investment opportunities, both in the NCS and internationally. Over the last three years we have made significant inorganic step-up, both in Algeria and in the Gulf of Mexico, giving an even stronger [inaudible] for international growth.

Our revised CapEx guiding for the period '05 to '07 is increased to a total of about 120 billion Norwegian kroner over this three-year period, excluding the purchase price related to Gulf of Mexico transactions. This level is somewhat higher than the previous guiding of 110 to 115 billion explained by the increased cost levels, changes in scope on some projects and followup investment following the Gulf of Mexico asset purchases. Our forecast for 2007 is, consequently, around 45 billion Norwegian kroner, again excluding acquisitions.

The dividend -- the total cash dividend for 2006 is proposed at 9 kroner and 12 ore, providing a direct yield of approximately 5.5%. Together with the share buyback program already exercised, this corresponds to a total distribution to shareholders of 10 kroner and 57 ore per share. This includes an ordinary dividend of 4 Norwegian kroner, a special dividend of 5.12 and the buybacks equaling 1.55 Norwegian kroner per share.

So subject to the AGM's approval on the 15th of May this year, this adds up to 57% of the net results for 2007 and a capital distribution since the IPO of 48%. This is in line with our dividend policy, as already mentioned by Helge.

So, Helge, this concludes my presentation, so I'll leave the summary to you.

Thank you, Eldar. Just to conclude on our guiding and the target for 2007, just repeat that we will continue with our ambitious exploration program and we expect exploration expenditures of about 8 billion Norwegian kroner this year and we expect the number of exploration wells to be drilled is between 35 and 40 wells and probably slightly more wells internationally than at the NCS.

CapEx, as Eldar has talked about already, will be about 120 billion Norwegian kroner for the period 2005 to 2007, excluding acquisitions. This is higher than the previous guiding, in part explained by cost increases and this will indicate a level of 45 billion Norwegian kroner for 2007.

Our 2007 production target remains at 1.3 million barrels, but we underline and recognize that the production target will be very challenging to reach, in particular in light of our ongoing operational challenges at, for instance, Kvitebjorn at the NCS and the Shah Deniz field in Azerbaijan.

As we have already discussed, we have adjusted our production cost target for 2007 to the area of between 27 and 28 Norwegian kroner per barrel.

[inaudible] this is the best annual net result for Statoil ever. However, of our high exploration and project activity, I believe we have significantly strengthened our international operations and the improvement program that we have run in operations at our downstream business is paying off, particularly in the manufacturing and marketing business. The fact that we have now higher quality in our operations is illustrated by the improved HSE results, which are important.

I will then talk a little bit about the synergies and there you can see the new name and logo of the new group. I'll come back to that later.

When the merger was announced on the 18th of December, we stressed that the main reason for the merger is to increase growth and ability to capture new opportunities. At that time we listed the following main synergy components -- complementary competencies, portfolios, larger operational and financial flexibility, more efficient use of technology, development expertise and R&D and finally, sharing our best practices.

If you go and look a bit more into detail, I believe that the costs-- or the synergies can be categorized in these three elements. Firstly, lower costs -- that means elimination of duplication and higher efficiency because of economies of scale. Secondly, improved performance by utilizing the best practice and deploying scarce resources and competencies more efficiently. And finally but not least, new growth opportunities because we have a better international competitive position, a larger portfolio to work with and stronger organizational and financial capacity.

In addition, the merger will, of course, impose some costs caused by the integration process itself, and-- but we believe that the synergy potential from the merger, as explained on the 18th December will be substantial.

However, for those of you that needed-- would like to put this into the spreadsheet, it will not be possible to isolate the different synergy elements separately from other cost and revenue elements in the financial statements. The main reason is that we aim to take out a significant share of the cost synergies to redirect the resources to areas facing scarcity of resources and growth potential.

This, together with the business dynamics, means that the base assumptions we have used to estimate synergies-- the synergy potential will change all the time. The estimated cost synergy and potential will, therefore, not appear in and will not be directly available from our published consolidated financial statements relating to future periods.

Let's look at the cost synergies more in detail and, as you know, the [inaudible] preclude us from doing any in-depth analysis of cost and other synergies at this stage. We're not allowed to look into each other's books and our current asset is, therefore, to a large degree, based on an analysis of our business, Statoil business, and an analysis performed by a consultant.

We have estimated a total cost synergy potential to equal around 4 billion Norwegian kroner per year before taxes. This potential, we believe, will be realized after some years, around 2009 or 2010, when the integration process is completed.

The tax rate that will be applied to these cost synergies is about 65%. Of course, the gross operating cost synergies are estimated to be significantly higher than 4 billion Norwegian kroner, but the gross synergies will, however, not only benefit new co, they will also benefit our partners through lower cost allocations in Statoil and Hydro operated joint ventures.

The cost synergies include increased efficiency in our direct operations, in our development and exploration activities and also, of course, in our administration and business support activities.

Some concrete examples -- we will eliminate duplicate activities in terms of corporate and unrestricted overhead, operational support and IT systems. We will also ensure more efficient exploration and business development activities. This will be achieved by eliminating parallel seismic and screening activities and optimizing the portfolio to ensure more efficient delivery of new resources. And, of course, we will also be more efficient in procurement, et cetera.

Of the 4 billion Norwegian kroner, the major part is expected to be a reduction in our present costs, while some will be reflected, also, in future CapEx. The merger allows us to do more and we will definitely will. Consequently, these synergies will be realized through several measures. For example, reduced external sourcing because of improved coordination and efficiency, renewed deployment of personnel in overlapping functions to other value-creating and growth-driven initiatives and redundant personnel will be handled through normal attrition and other measures to be discussed with the labor unions as we move forward. The further process of organizational design and future staffing will be [inaudible] in a dialogue with the labor representatives of the two companies.

The accretion potential of this transaction is, to a large extent, related to the possibility to increase the future growth and revenues of the new company. Therefore, we expect important revenue synergies in addition to the cost synergies just described and revenue synergies are, by their nature, difficult to quantify at this stage.

Improved performance, in part, will be achieved through sharing of each other's best practices and putting this knowledge effectively into practice and use. This is primarily relevant through fields and assets where we do not have common ownership shares. It also relevant in activities with high competence requirements within our trading and field development activities.

The potential of improved performance potential include the experience and practice within drilling and well activities. This includes releasing experienced drilling personnel to support the continuous drilling operations within our core area, integrated operations which both companies are working hard on and increased recovery efforts of oil and gas. This could contribute to higher [inaudible] and higher recovery rates all together.

So the more our experience [inaudible] in terms of core area management can be put into even more efficient use in the new company's portfolio, for example, in Gulf of Mexico.

Another example is the potential of sharing our relevant international experience and know-how. In particular, we think this is important in North Africa where Statoil is strong in Algeria and Hydro has a similar position in Libya and I believe we can also capture those benefits, for instance, in Brazil where both companies are building up strong organizations.

Looking at the last part of the synergy opportunity set and that is new growth opportunities and we expect that our capacity to pursue value-creating opportunities will be higher. We expect to be able to create even larger and more significant strategic growth opportunities than without the merger.

The main drivers for these synergies are increased organizational capabilities [inaudible] competence, increased financial and risk capacity and also that we can more-- work more in in as a Norwegian ticket in terms of pursuing interests and opportunities abroad.

Together we will be better able to compete for higher shares in large and/or more complex projects. This includes operatorships and more integrated value-chain projects and we believe that the number of potential opportunities that are available for us has increased-- or will increase after the merger.

We also believe that combining the two high-performing technology organizations puts us in an excellent position to create value through development and use of key future technologies. We believe that the new company's competitive position will be improved in resource-rich regions that are linked between the country of origin and the company that plays an important role. And with the combined portfolio, our ability to participate in strategic portfolio management to extract further value has increased.

Overall, this leads us to conclude that the merger also will deliver considerable synergies in terms of future value creation through new strategic opportunities.

This concludes-- concludes my presentation. Thank you for your attention and I think, then, we are ready to take a few questions.

We certainly are. Would you go to the microphone please? Thank you. We will now open for questions and in addition to our CEO and CFO, with me on the panel we also have the Senior Vice President for Corporate Planning and Control, [Mr. Torgrim Reitan].

Can you take the first question, Iain?

Hello, this is Iain Reid from UBS. Firstly, a question on production. When the NPD gave their forecast for 2007 production, they showed a number, particularly on the oil side, slightly lower than the so-called industry view and I presume the industry view must be 70% to 80% Statoil's view. And they said at the time, I believe, that the reason for that was due to some risk of further delay in drilling and also some risk of further socially related delays.

I wonder if you agree with the NPD's view of the risk downside? I know you've already said-- but if you'd be willing to, perhaps, quantify your view of what those risks might be versus the NPD's view?

And secondly, on exploration expense in international, you've got a very high number on this call at around 1.3 or 1.4 billion. Can you say how much of that was kind of one-off effects such as this expense of previously capitalized wells and perhaps [inaudible] as what you might regard as a run rate for international exploration expense?

And thirdly, could you update us on your view of whether you've be able to achieve merger accounting for the transaction? And what will your conversations have been [inaudible] 50/50 chance of getting merger accounting. Are you more optimistic or less so?

In response to the first question, as we have said earlier today, we have initiated a whole range of activities to improve the drilling performance on our mature fields. We were not happy with our performance in 2006 and I gave you the numbers in terms of how many wells we were able to complete compared to what we planned to do. We already now see some improvements from these plans and we believe that we will improve our efficiency in drilling on some of these fields in 2006. In addition-- in 2007.

In addition to that, we have ramp up of some of the fields that were put in production in 2005 and 2006, including the Kristin field, as well as new fields that [inaudible] the opportunities on the continental shelf again and we have not adjusted our targets that we have communicated to day, but we have indicated that there is more likely to undershoot than overshoot the target in [inaudible].

In terms of the delays and the performance in 2006 on the Norwegian continental shelf, we just repeat what we said today that it didn't mean we lost resources, but more related to efficiency in drilling in individual cases.

In terms of your second question, the question on exploration expenses in fourth quarter, I will again, not give you the detail, but perhaps-- they are associated with the expensed-- expenditures taken, in particular, in Brazil and Gulf of Mexico. Perhaps you have [inaudible] in detail and [inaudible]

Okay. I think you already mentioned the issue from the-- basically there is a step-up in exploration activity that is driving, also, the expense part of the exploration. But the 400 million is coming from capitalized exploration costs from previous periods, which is now being expensed and basically it's from the countries that you mentioned, Helge.

When it comes to the merger accounting, I can't recall actually having given you a percentage on that, but obviously it's an unclarified issue. So we're working-- still working on that and there is no conclusions on that, but hopefully we will have one in place prior to the final prospectus, really, in March.

I wonder if [inaudible] fourth quarter?

No, but there has been a signature bonus related to some of what has been expensed, but there was no specific payments in the fourth quarter, as such.

[inaudible]

The expense part-- the total expense part from previous quarter was approximately 400 million.

[inaudible]

I haven't got that number for you.

We have a question from the Internet that I'll take first and then I'll take you here from the-- from London. Can you give us -- that's from Jean-Philippe Lavenir in Societe Generale. Can you give us guidance regarding CapEx beyond 2007?

No. Really, I mean, that's something which we will come back to when we are ready for that and I think we have the overall picture, but we intend to grow the company and we see that the costs of growing-- each barrels and accessing barrels is increasing. So that's a general comment, but I mean it's the level of CapEx that we don't see as a decline coming into the future, but beyond that, any more specifics, we are not ready to talk about that yet.

We have to-- when we can talk about the business plan for the new company we can come back to you with a more detailed guiding on the next few years. I can not, at this stage, give you a date for our comprehensive capital market days, but I would assume that would be around year-end, assuming that everything goes according to plan over the next few months in the integration process and then we will cover this and other questions.

At the same that was an answer to [inaudible] question about when the capital market days were going to be. So, Colin, please.

Colin Smith from Dresdner Kleinwort. Just to come back on production again, your presentation indicates 240,000 barrels a day from international operations this year, which seems quite credible, but that implies you need about 100,000 barrels a day more in Norway, which seems to be verging on the incredible, given how much devolution you appeared to have suffered, particularly on the oil side, over some of your war horses.

Can you just say how it is possible to get to 1.3 or is it something like 1.225 or a more realistic estimate? And if it is, can you comment just on what that would do to your cost per barrel? Thank you.

Well, when it comes to the production target that I'm looking at and I would like to focus your attention on three or four outcomes. The first one is that we are successful in ramping up the fields that we put in production in 2005 and 2006. Secondly, that the new projects that we put on stream, including [inaudible] and all the [inaudible] fields are coming on stream when we anticipate. Thirdly, that we see, I would say, a normal gas sales and, finally, that all the activities that we have put in place in order to particularly address the drilling efficiency is paying off.

And our assessment is those factors are sort of up to standard. It is possible to reach the 1.3 million target, but based on experience we had in 2006 and the complexity of the [inaudible] issues, we thought it right today to give you some cautions that there are more risks on the downside than on the upside. [inaudible]

[inaudible] from HSBC. It's a question on gas. I wonder, given the uncertainty that people seem to have about Russian gas supplies now, whether you've seen any change in the attitude of European buyers to yourselves and, as part of that, whether you actually have the capacity or ability to increase your gas output, if it was required?

If you look at our plans, you have seen that we have a gas ambition where we are [inaudible] to increase our gas production over the next 10 years. And also that will concern the Norwegian continental shelf. We are in the process now with our partners to look into a huge new project called the [inaudible] development, where we are also assessing a new pipeline either to Great Britain or to continental Europe.

We believe, if it can be summed up [inaudible] that there have been also opportunities, also, for smaller fields further up the coast in Norway, because they can pipe into this new pipeline. So there are more potential in Norwegian gas. We have the growth potential and I can confirm that there is a significant interest from our clients throughout Europe to buy more Norwegian gas. I cannot speculate in the reasons for that. I cannot state that I feel that clients are appreciating the reliability of Norwegian gas.

I'll take questions from the Internet first. There are two similar questions, basically, one from [Barry Eldin] and the other one from [Emily Morris] at Dresdner Kleinwort. Can you discuss your decline rates of the Norwegian shelf, approximate levels, and are they increasing more rapidly than expected?

Yes, well, there's two set of decline rates. One is what we call the natural decline rate, or the decline rate which is coming from, basically, the behavior of the reservoirs when, sort of, we're getting into decline, then I'm assuming that we're able to drill all the capacity that we have, then there will be a natural decline rate. And we're talking about that in range of average of 4% to 5% annually, totaling both oil and gas, with a higher percentage on oil.

Now what we have seen this year -- or last year -- is that this has been sort of strengthened by our ability or not ability to drill the number of production wells that we have planned for. So there is an additional decline which is not sort of-- has nothing to do with the reservoir, as such, but with our ability to drill wells that can take up the volumes. That means for 2006 the decline has been higher than the natural decline should indicate.

Huw Williams from Cazenove?

[inaudible] from Cazenove. Just a couple of quick questions. The first one, to settle back on this issue of the risks to the production profile going forward, you've mentioned at least three areas which you can control in that profile for the year 2007 outlook, only one of which is-- so the fourth factor, which is the gas sales, which is maybe beyond your control. I just wonder if-- whether there are areas that you do worry that you can't control what's going on next year, if there are risks to that production profile, which is pretty much beyond your control? And if you can just give us a feel for how much that does concern through '07?

The second question is on Venezuela. Firstly, you've had a success with Plataforma Deltana. I don't know whether you can give an update on what's going on and what you've planned going forward?

Secondly, though, [inaudible] but there's an issue to do with [inaudible] and expansion and maybe you could give us an update on what's happening with [inaudible], please?

When it comes to what we can control and not control, I agree with you, we can probably not control the gas levels. We have more control over the progress and also the operational performance. However, we have seen that the industry in 2006 and perhaps, also partly, in 2005, have been not entirely under one company's control because you are dependent on available capacity and competence, also, from certain suppliers. And as the industry, as we see it, is running on full capacity, there are issues, also, related to those projects and business activities that bear on our results.

But we feel -- and I've tried to be very open on the issues and the challenges that we're facing -- we feel that we're starting to get a better impact from our drilling effort of the last 6 to 8 months, but there is still a lot of challenges in front of us.

When it comes to Venezuela, we are in the process of drilling the second well on Plataforma Deltana and we would like to continue to do that. When it comes to the [inaudible] project, of course, we have seen the complication from the president and also from other officials in Venezuela about the objective of having higher ownership stake in the heavy oil projects, including [inaudible]. We respect the Venezuelan authorities sort of ability to control their own national oil and gas reserves, but we also expect that they respect the agreement that they have entered into and we are in a dialogue with the officials on the [inaudible] project and other issues, but it's too early to conclude on what these negotiations or dialogue will [inaudible]. But we are, naturally, extremely focused on protecting our investments and our rights.

A question from Theepan, Morgan Stanley.

Yes, hi. It's Theepan from Morgan Stanley. Just three questions, actually. One just coming back to production for Q4 international, could you give us a little bit more detail on that PSA effect? I think was that primarily in Algeria?

The second question, just on CapEx and the increase for 2007, Eldar, do you mind just giving a breakdown in terms of the split between additional cost that you're seeing in the industry and also the additional CapEx from your Gulf of Mexico investment?

Finally, just a question on reserve replacement. I think you, yourselves, have sort of declared that it was a disappointing year for reserve replacement. Looking through the-- the breakdown there, it seems there was a particularly high contribution from sort of revisions/extension, so I was just wondering if there was any particular project that you would quote incremental reserves from?

And on that note, you've talked about a number of projects that you expect to be sanctioned in 2007 and 2008. I was just wondering whether you'd highlight some of the sort of key-- some of the investment decisions you may take this year? Thank you.

So on the PSA effects, basically we have a significant PSA effect within Algeria on the In Salah field with a quite big impact in the fourth quarter and then we have the [inaudible] field, the [inaudible] and also the [inaudible], now have come into that situation. So overall I think something like 40,000 barrels a day of PSA effects in the fourth quarter is the best indication.

You asked about the split of the CapEx increase. Basically, I haven't got an exact one for you, so don't-- but approximately I would say one third is related to the cost increases, as such, one third related to new fields coming in as a consequence of transactions that we have made and scope changes is the remaining. So that's an indication that I could give for you.

You asked about reserve replacement and new fields. There's a big contribution, obviously, from the fact that we are continuously developing our fields and drilling new wells and, thereby, defining increased acreage that we can define as SEC reserves. Mainly the new fields, that is, those coming into the portfolio this year is related to the [inaudible] field on Norway and the [inaudible] fields and also three smaller fields in Angola.

[inaudible] you have the [inaudible] field that [inaudible] is operating or planning, the other big partner in Norway. You have also the [inaudible] field up in the northern part of Norway and a whole range of other smaller and medium-size projects.

We'll take a question from the Internet and then Mark Bloomfield afterwards. The first one is from [inaudible] from Canadian in Oslo. The new unit production costs assume 1.3 million barrels per day in production, i.e., if production turns out to be lower than 1.3, will the unit costs be higher?

The unit cost is [inaudible] assuming 1.3 million, as we communicated earlier today, of production.

Mark?

It's Mark from Citigroup here. Just a quick question on resources. You've highlighted that you're a bit disappointed with the reserve replacement this year and part of that was due to timing.

I just wondered if you could say what you've added to the resource base and I think you had a prior target of about 1.2 billion barrels?

We're not communicating here on that target, but I can tell you in combination with the exploration successes we have and the acquisitions that we have done over the last few years, we are well on the well according to that direction that we indicated in 2004.

And that's a [inaudible] that was presented for-- at the end of 2007 and it's natural for us and we have sort of concluded that to come back and give some resource compared to the 1.2 billion assumption.

[inaudible]

Can I ask you about the-- the production costs, I mean, do you see an underlying inflation somewhere in the range of 5% of 10% per annum? And when you think about your [inaudible] in kroner synergy number, are we assuming that that rate of inflation decreases or given your new production costs, it could fall [inaudible]? And also if you think about production costs and CapEx inflation are you finding, say, in Norway where projects are not economical versus previous expectations?

Well, on the last one, we [inaudible] new projects due to the costs at this stage and the rest of the project, as you remember, has been-- apart from the [inaudible] project have been smaller projects that have extremely strong economics.

In terms of the [inaudible], that's a big project, 27 billion Norwegian kroner in CapEx all together and the combination of Statoil having quite a flexible resourcing strategies and the strategic partnership has been somewhat-- somewhat a surprise, really getting us-- even in this quite tough environment we are able to move forward with that project. So I think we have managed that quite well so far.

On the-- on the 4 billion question, the cost increase that we see gradually coming in, also, into our own operating cost numbers, [inaudible] so that's pure synergies from the merger in itself. So to the extent that there's continued industry cost pressure, that comes from that and it's not sort of reflected in the 4 billion number.

[inaudible]

[inaudible] Two short questions. Firstly, when you talk about a return to normal gas sales in 2007, can you tell us what were the negative effects of the weather and the like in 2006? And, if so, what was the rough order of magnitude of that effect?

And secondly, are we to believe one or two of the things mentioned in the press about the [inaudible] negotiations not being completely dead? Is there anything you can comment about your ongoing talks with Gazprom, if there any?

Well, we will not give you any numbers related to effects of mild weather, but I can just confirm that it's a rather [inaudible] and mild weather it will, of course, impact and it impacted us in the last [inaudible]

When it comes to the [inaudible] progress, we have received a letter from Gazprom inviting us to continue the discussions on [inaudible] and we are in the process of setting up a dialogue with Gazprom. But we have, all the time, a regular business development dialogue with Gazprom and other Russian companies as part of our day-to-day business.

Another question [inaudible] if we can find it. [inaudible] to its cost synergies, if you find the development costs [inaudible] what level of confidence can we have on your preliminary assessment of cost synergies for the merger if you're unable to look at Hydro's E&P books?

Well, we have worked under the limitations that we discussed earlier that we cannot, for competitive reasons, look into [inaudible] at this stage, but we think we have run reasonably good assumptions and because we are operating, basically, in the same basin, we have somewhat the same experiences. So we are reasonably confident that those numbers are good and will hold.

[inaudible] from [inaudible]. A couple of quick questions. You've been asked frequently about the international tax rate. It's still stubbornly above your previous guidance of 40%. Are you still happy with that level going forward?

And just taking a look at the 35 to 40 wells you're drilling in 2007, plan to drill, could you perhaps say what the 4 or 5 most exciting kind of impact wells are?

The tax part -- short answer is, the guiding part, is that, yes, we still believe-- although there is a pressure, if you put a direction, an upward pressure, on international taxation and we see that sort of being reflected in many countries that we're operating. We still believe that the 40-plus is a good level. This quarter it was heavily impacted by some exploration expenses that we did-- where we did-- we didn't account for the current tax benefit in relation to those. The expenses are still there, but the count didn't reflect them for accounting principles.

When we look at the-- some of the wells in order that you should follow, it's clear one well drilled by [inaudible]. And then there is one well drilled by Hydro at [inaudible] in the southern part of the North Sea and there is one well, I think, [inaudible] which may not-- it might stop and these are-- these three, I think, are the most sort of interesting wells to follow for the next year.

There could, also, be some coming up, probably more likely in 2008, in the Barents Sea that [inaudible] from the 19 licensing [inaudible] last year. In addition to that, we're eager to see the resource of the [inaudible] drilling in Algeria and we have a quite extensive drilling program, also, with partners in Gulf of Mexico.

I think those are the key indications.

We are-- actually we're out of time, but I'll take [inaudible], please.

Hello. It's Jason from ING. Just coming back on the tax rate, have you got an overall guidance for '07 on the tax rate, rather than just international?

And then secondly, maybe more of a [inaudible] question, if you really want to truly compete on the international stage, it's quite usual to have management teams in place in the international countries, rather than necessarily take the skill set that you have from Norway into new regions and I was just wondering whether you were looking to employ or develop skills in the countries where you are endeavoring to build new positions and diversify away from the Norwegian continental shelf, any difficulties that you may be facing with that [inaudible]?

I completely agree with your assumption and this is exactly the strategy. We have been building up a quite strong organization, already, in Gulf of Mexico by recruiting, also, in the local markets. We're doing the same in Brazil and Venezuela and North Africa and [inaudible] start a training program [inaudible] on people outside Norway. So this is exactly the direction that we're working on. We do not believe it's possible to run and develop successful international operations from Stavanger or Oslo, already.

And on the tax guidance, we haven't-- the only area where have guided is on the international one. We don't expect any-- we haven't seen any changes to the tax system in Norway except for the one that was done on the financial items, which basically were neutral to our part of the business. So I think you should look at it sort of the production split between the international and the Norwegian production as sort of the best guidance between the two, providing sort of an average tax rate, going forward.

Well, at this-- if there any more questions here, I'm afraid we are, actually, out of time. And I know that we have a couple of questions on the Internet that we haven't answered. I apologize for that, but we will make sure that you get your answers back on e-mail the same way. If there are other questions [inaudible], please call us at investor relations. We'll do everything we can to answer them.

Thank you very much. Goodbye.

Thank you.