埃尼石油 (E) 2007 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. And welcome to the Eni 2007 3Q results conference call hosted by Marco Mangiagalli, CFO. My name is Wendy and I'll be your coordinator for this conference. (OPERATOR INSTRUCTION) I will now hand you over to your host, Mr. Marco Mangiagalli, to begin today's conference. Thank you.

Thank you, Wendy. Good afternoon, ladies and gentlemen. And welcome to this conference call during which I comment on the 2007 third quarter results and business trends. At the end of the presentation, together with Stefano who is here with me and who will be in a position to update you on the recent developments in the upstream division, we'll be pleased to answer to your questions.

Let me start with a quick overview of the trading environment. The third quarter of '07 the Brent prices strengthened averaging $74.9 per barrel and increasing by approximately 8% compared to the third quarter of 2006.

In Refining, our third quarter indicator margin fell by approximately 5%. The margins realized by our own refineries were, however, significantly weaker due to the narrowing of light/heavy crude differential.

Finally, the euro showed an appreciation of 8% versus the U.S. dollar compared to the same period of last year.

As usual, I would like to remind you that our results are affected by several issues including the seasonal factor affecting the demand for natural gas and petroleum products used for residential heating, the demand for which is highest in the first quarter of the year, the coldest months, and lowest in the third quarter, the warmest months. Therefore, Eni's operating profit and change in net debt in the first nine months cannot be extrapolated for the full year.

Having said this, let us now comment on the results. Adjusted net profit for the third quarter amounted to EUR1.89b, a decrease of approximately 28% compared to the same period of '06. This result mainly reflects a 17% decrease in the adjusted operating profit, as well as the higher adjusted tax rate which was 53% compared to the 48.8% for the same period of last year.

Adjusted operating profit amounted to EUR4.2b, a decrease of 17% compared to the third quarter of 2006. This result mainly reflects the weaker results in the upstream and downstream oil businesses. It's worth mentioning that Engineering and Construction posted a 46% adjusted operating profit increase.

Moving to our business segment in the E&P hydrocarbon production in the third quarter usually affected by maintenance activities totaled 1,659,000 boe per day, a decline of 2.9% versus the corresponding period in 2006. This decline is the result of the price effect, the disruptions in Nigeria, the Cats pipeline shutdown, the depletion of mature fields mainly in Italy and U.K. and the lower entitlements in certain production sharing agreements. These negative effects were partially offset by the contribution of the assets acquired in the Gulf of Mexico and Congo.

Turning to the first nine months of 2007, daily hydrocarbon production decreased by 2.9% averaging 1,710,000 boe. It's worth mentioning that the bulk of the scheduled maintenance activity has been substantially completed and during October, production accounted for approximately 1,780,000 boe per day. Having said that, I can confirm that despite the disruption in Nigeria and the U.K. and the impact of Venezuela, assuming an average Brent price in 2007 of $55 per barrel, which you might remember was our planning reference, our production is expected to be substantially in line with 2006.

Third quarter reported operating profit for the E&P division amounted to EUR3.3b, down 18% year on year. On an adjusted basis, operating profit declined by around 19% on a like for like basis. And this decrease is mainly due to the appreciation of the euro versus the dollar, lower production sold, increased exploration expenses, higher operating costs and DD&A also as a result of sector specific inflation. These negative effects were partially offset by the higher realization prices denominated in U.S. dollars.

In the Gas and Power division, overall gas volume sold, both consolidated and associated, increased by approximately 5% in the third quarter of 2007 totaling approximately 19 bcm. Gas sales in Italy, including self-consumption, increased to 11.5 bcm as a result of higher volume sold to wholesalers. This positive trend was partially offset by lower sales to industrial and power generation customers. International gas sales rose by approximately 6% reaching 7.6 bcm and this was mainly a result of higher gas volume sold in our target market.

The first none months of 2007 overall Italian gas demand reached approximately 59 bcm with a year on year decrease of 3.7%. In the same period Eni's domestic gas sales decreased by 3.6% mainly as a result of the mild weather conditions. International gas sales in the first nine months of 2007 totaled 26 bcm. This was broadly flat compared with the same period of 2006.

Turning to the Gas and Power division's financial results, reported operating profit for the third quarter amounted to EUR590m in line with the corresponding period of 2006. Third quarter result includes the negative impact of special items including EUR19m mainly related to redundancy incentives and to environmental provisions. In addition, we accounted for an inventory gain of EUR28m. Adjusted operating profit amounted to EUR581m, down approximately 6% from the same period in 2006. G&P adjusted pro forma EBITDA for the third quarter of 2007 amounted to EUR797m. This compares to the EUR882m in 2006.

Let me now elaborate on the business segment. Supply and Marketing decreased by 22%. This performance was primarily due to the mismatch between purchase and sales prices that has affected essentially the sales to thermoelectric users. This negative effect was partially offset by higher volumes sold which were up 5%. The regulated business generated EUR215m, up 11% versus the third quarter of 2006. This trend is due to the increased operating profit on Snam Rete Gas and also to the increased ownership resulting from the now completed buyback program of the Company. Powergen's EBITDA accounted for EUR80m.

Let me remind you that starting from the third quarter of 2007 the Powergen segment only comprises the tolling activity since marketing activities have been moved to the Supply and Marketing segment in accordance with our objective of developing a dual offering strategy.

If we look at the first nine months of 2007, overall adjusted pro forma EBITDA increased by approximately 4% versus the corresponding period of 2006. Basically it's the result of improved regulatory framework and despite the lower gas volumes sold, transported, and distributed due to the mild winter. Furthermore, the results of the first nine months of 2007 has been negatively affected by the unfavorable trend in energy parameters recorded in the third quarter.

Let me now turn to the R&M division. 2007 third quarter reported operating profit totaled EUR282m, up 13% compared to the same period of 2006. The result includes a negative special items for EUR56m mainly related to environmental provisions and redundancy incentives. In addition, we accounted for an inventory gain of EUR219m. On an adjusted basis, the operating profit decreased by approximately 67% compared to the same period of 2006. This reflects weaker refining margins mainly as a result of the narrowing of the differential between light and heavy oil, as well as the appreciation of the euro against the dollar. Marketing's 2007 third quarter pro forma was substantially in line with the same period of 2006.

As far as other businesses are concerned in the third quarter of 2007, the Petrochemicals division posted an adjusted operating profit of EUR30m. This decrease versus the same period of 2006 was mainly due to lower base chemical margin resulting from a higher feedstock cost. The adjusted operating profit for the Oil Field Services and the Engineering business totaled EUR211m in the third quarter of 2007, up 46% versus the same period of last year. This achievement was attributable to higher results in both onshore and offshore construction activities.

Looking at our cash flow this slide compares our sources and uses of cash for the first nine months of 2006 and 2007. Operating cash flow of EUR13b and divestments totaling EUR0.6b partially funded EUR6.9b of organic capital spending at EUR8.7b of acquisition. Furthermore, shareholder distributions amounted to EUR3.4b out of which dividend payment exceeded EUR2.6b. As a result of the significant investment and the cash returned to shareholders our net financial debt as at the end of September increased to EUR11.4b and our debt to equity ratio was equal to 0.26.

Let me underline that assuming a $15 per barrel scenario, again the reference for us, the net debt to equity ratio would be in the range of 0.3, 0.4 at year end depending on whether Gazprom exercises the options on the 20% stake in Gazprom Neft and on the 51% stake in the former Yukos gas assets.

Finally, let me comment on CapEx. In the first nine months of 2007 capital expenditure amounted to EUR6.9b representing an increase of approximately 42% compared to the same period of last year. This was mainly due to higher expenditures in all our core businesses. Particularly upstream showed a 40% increase mainly as a consequence of higher exploration expenses in the gas from Mexico, Egypt, Norway and Brazil, as well as increased development activity in Congo, Egypt, Italy and Angola. It's worth mentioning that the increase is also the result of the recent acquisitions in Gulf of Mexico and Congo.

Engineering and Oil Field Services showed a 104% increase related to the construction of two new FPSO units and other vessels. Gas and Power's higher CapEx are related to the upgrading of the Italian and International transportation network. And finally R&M posted a 48% CapEx increase referred to the ongoing refinery upgrading program. For the full year we expect to post an overall CapEx of approximately EUR10.5b.

Thank you for your attention and now we'll be pleased to answer your questions.

Thank you. (OPERATOR INSTRUCTION) Our first question comes through from the line of Theepan Jothilingam from Morgan Stanley. Please go ahead.

Hi, good afternoon, Marco. Just three questions, actually, a couple of on volumes. Firstly I just wanted to understand whether you could give an indication of the contribution of the acquisitions you've made this year to the 2007 volume number?

Secondly whether you were in a position to give any guidance on 2008? If not, if you could highlight where you think the key growth areas would be?

The second question again just on Nigeria, I was just wondering whether you could give an indication of what the total disruption is at the moment to Eni's production in the country? And there has been discussion about potential change in fiscal terms. I was wondering whether that had any implications for Brass LNG or whether you had an update there?

And finally just the third question was just on your strategy for growth. You've made a number of acquisitions already this year. I think you've put forward a potential bid at the moment on the table. Could you just talk a little bit about the criteria you're looking at for acquisition and for growth? Thank you.

I think Stefano.

You said three questions, there are many more. I think volume contribution to production coming from the acquisition, in the third quarter the contribution is 77,000 barrels of oil per day. So this is the contribution on the quarter. If you wish to have an indication on the full year I would say that should account around 45,000 barrels per day.

Then the second, then you were asking about the, I think you asked the situation in Nigeria. The impact again on the quarter is the one we mentioned. It's the 25,000 barrels per day in the third quarter. What is the total impact? It's certainly higher because this is what we have identified as the additional and unexpected impact. Currently, we produce around 130,000 barrels per day. I would say that in normal circumstances we would expect to have something like roughly 50,000 barrels of oil production more from Nigeria.

In terms of fiscal terms, fiscal terms in Nigeria then there was just, it was just a vague statement. I think it is difficult to anticipate out of the statement what might be the eventual impact in fiscal terms so it is extremely difficult to make a judgment. What I can tell you is that the fiscality related to the Brass LNG will be not a hydrocarbon related fiscality but will be a fiscality devised on purpose. So it follows a different treatment.

You referred then to acquisition and I would say that what has been so far the criteria on which we have based the acquisitions we have made, those are the criteria we have always referred to in terms of materiality of the acquisition, in terms of strategic presence in the country, in terms of synergies which we retain, we can extract. Obviously great importance is associated with whether we are operator or not. From the financial point of view you know that we base all the acquisitions on the strict financial disciplines to which is based on the application of a scenario which for the acquisition we have made, is the $40 long term plus a four year evaluation close to what is the forward curve for the first four years, as I said. So basically this has been the criteria.

In terms of obviously other operations which you might have been hearing, we are not at all in a position to make any comment whatsoever at this stage.

Great, thanks very much for that.

Thank you. Our next question comes from the line of Lucy Haskins from Lehman Brothers. Please go ahead.

Good afternoon. I think one of the things which we've vaguely touched on in terms of the questions earlier was any potential guidance you could give us in terms of volume for 2008. And perhaps secondary to that is in extreme oil price environments as perhaps we are enjoying at present are there any more acute POC effects than your current guidance has indicated?

And the final question from my perspective, I would also like to ask what the reserve or placement impact may be if we were to see oil prices go at this kind of level for the year end given your EPS exposures?

Quite frankly it was not by chance that I was not addressing 2008, because --

I was afraid you'd say that.

I'm sure you know that we are right now in the process of drafting our new four year plan which starts with the 2008 budget. So I think we'll be precise and we'll give you all the background and all the information once we come out with the four year plan.

In terms of reserve and placement, I'm afraid the comment is the same [one].

In terms of PSA effect you were referring to more acute effects coming from PSA. I think there are and we confirm for 2007 the guidance of 2,000 barrels per day of production per dollar of scenario. In a permanent high scenario what we see happening is that we see a number of contractual triggers basically related to the desaturation of the coast oil in a number of contracts. And I would specifically refer to the PSC in Angola related to Block 15 where we have -- we hit a trigger like the one I'm referring to and this impacts on the basis of the full year in 2007 impacts for about 15,000 barrels of production over the full year. And the same applies to the Australian contract to by then where the impact is around 6,000/7,000 barrels of oil equivalent per day.

Thanks.

Thank you. Our next question comes from the line of Neil McMahon from Sanford Bernstein. Please go ahead.

Hi, two questions, I think for Stefano. First of all, really on your new Libyan contract, various press reports suggested that even though there was a substantial increase in the terms of the contract in terms of length, could you go into any way that we should adjust our models for the financial component and the returns of those contracts? I'm presuming knowing the Libyan's are pretty smart at oil investing that your terms didn't get any easier. And then I've got a follow up question as well. Thanks.

Okay. In terms of mentioning specific components in the PSC you know that we don't disclose these values. But what I can say is that all in all the Libyan agreement reflects a real win/win situation whereby we get the extension of course in exchange for some contractual adjustments which in a way provides the trigger for a significant number of new investments to be realized. Which means that resources which are in the area which we already detail, they may become, obviously through the whole process for the final investment decision, will become reserves of the various categories and finally total reserves.

We have disclosed the total amount of investment which is 100% of $28b. I would say that in particular this referred to the expansion of capacity for the green stream for about 3b bcm of gas, which of course implies that we need to invest some money in upstream development. And on top of that we will develop the sufficient gas reserves to cover the building of an LNG train which will account for about 5 more bcm of gas to be exposed via LNG. So I think rather than being specific on contractual terms you can make a judgment yourself on the importance of the agreement which we have just finalized with the Libyans.

In terms of timing, the timing which we have set is about three years to come to a final investment decision for the building of the LNG and then the time of construction integration of supply for about 20 years.

Okay, thanks for that explanation. Secondly, I couldn't leave without a question on Kashagan. Really it's a number of questions and maybe you could confirm or refute some of the numbers that have been out there in the press or from the Kazakhstani government in terms of the total cost for the full field over the life of the field being more than $130.

$130b, $130b referring to that figure.

Yes, I'm sure you would love it if it was $130m. But also I'm presuming if it's that sort of magnitude it means the full field ramp up will be well beyond 2020. And also maybe if you could tell us as we have pretty much no knowledge what is going on behind the scenes, is it likely that the state will have a greater share in this field so that it can progress forward?

Okay, let me try to give you a little bit of a picture on how things are evolving. October 22, of this month, we signed what we consider a very important memorandum of understanding which formally avoids the deadline of the 60 days which were contractually allowed for the amicable resolution of the dispute. And at the same time established a number of parameters around which the negotiation will take place in order to define what is the complete resolution of the dispute and also provides a certain framework within which the discussion will take place.

As you may imagine, we are not in a position to disclose the framework and we're not prepared to disclose the parameters around which the discussion will take place. But I think it is very important that with the signature of the MOU we have resolved the issue of the 60 days. We are currently through an intense round of negotiations. We are working with the counterpart as a consortium and all in all we are confident that we shall manage to resolve the dispute.

What is extremely important and this is associated of course with the signature of the MOU is that the work of the site they continue uninterrupted, which initially was something which was questioned. So the work has continued and the project is progressing.

In terms of costings, the figures which have been mentioned on the press, the $136b which you referred to, they are an evaluation of the total cost for full field development plus the cost for G&A and services plus all the operating costs throughout the life of the contract until 2041. So this is really a broad figure which I don't think gives any guidance whatsoever on the amount of CapEx required for the full field development.

There is, of course, an ongoing process within the venture which is in the direction of making the conceptual design for the full field development. After the conceptual design a proper front end engineering and design will be launched and the view is that we should be in a position to make a final investment decision for the full field by the end of 2009. So up to that moment there will be no further indication on the total CapEx for full field development. Of course we maintain that $19b is the cost for our tranche one and two of the experimental program and the end of 2010 is the date for the start up of production.

Great, thanks very much.

Thank you. Our next question comes from the line of Iain Reid from UBS. Please go ahead.

Hi, gentlemen. One question on Gas and Power and one on E&P. On the Gas and Power market I think you mentioned when you were talking about Snam Rete gas that after the completion of the buyback program you had an increased interest in that. I wondered if you can say what the new interest is?

Well, yes, sorry. Go ahead, Iain.

No, I'll follow up with a second question after that.

Well, if you want they bought back 10% of their own share capital so we moved from 50% which we owned before to 55% as a consequence of that.

Okay, fine. Thanks very much. Secondly, Stefano, can I ask you a bit more of a detailed question Brass LNG. It's obviously been delayed for some months now. Can you tell us what the likely date of the FID is going to be and why this delay is ongoing? There may be obvious reasons for that but is there any contractual or cost reason? And maybe you could update us on what you think the total costs of the development will be, and if you can split that into liquefaction and the offshore development.

Okay. Brass, as you quite accurately said, Iain, has been heavily affected by the security situation in the Niger Delta. We -- what you will see appearing on the price is the fact that we are starting some preparatory works on site which I think is the first tangible sign that things are starting all over again. We are, as you know, we are working on the finalization of the front end engineering and design and we expect the final investment decision, during the -- let's say at the end of the first quarter of 2008. So all in all, of course this is based on a security situation which is satisfactory from the point of view of doing physical work, which at the moment we are experiencing. While, I have to say that in other sites the situation seems to be slightly different. But all in all, the -- we have a strong perception that after elections the situation is moving towards a higher degree of stability. Should that be confirmed, be maintained we will go ahead with the scheme as mentioned.

In terms of the costing, we will update you at the time of final investment decisions. That is the right time for announcing what is the total value of investment. Maybe, at this stage what I can add is that we expect the first LNG cargo in 2012.

All right. Thank you very much.

Your next question comes from the line of Alastair Syme, from Merrill Lynch. Please go ahead.

Hello Marco and Stefano. Can I get two questions on -- actually, one on gas and power and one on E&P? On gas and power would you be prepared to guide on full year '07 EBIT, as you look into the fourth quarter?

And on E&P, if you just talk a wee bit about cost inflation and what you saw the unit production costs at in the quarter?

Yes, I address the gas and power guidance. At EBIT level we are projecting it something in the range of EUR3.8b, EUR3.9b which is -- the EBITDA would be at 4.8, 4.9, in line with last year's results and in spite of a probably worse general situation.

Can I ask, sorry to interject, can I ask what the year is -- sort of look at the deltas this year in terms of currency and gas sales volumes, how they might have impacted on that number?

Well, yes, but it would be a little bit complicate to address it. If you want, Alastair, at -- on a quarter-basis we can say that, and we have now to go at the different business segments relevant to the G&P division. The EBITDA adjusted pro forma was slightly less than EUR800b, EUR797b which means roughly EUR85b less than last year's quarter and the supply and marketing posted a minus 77 because of the scenario and the regulated activities increased by 22 and this is because primarily of the new way to remunerate investment in the Snam Rete Gas activity. The Powergen had a minus 14, which is a consequence of the move. You might remember that we have moved marketing activity from -- also for electricity, from our Eni Power subsidiaries to the Gas and Power division and this is the reason of the lower contribution of Powergen, because that contribution in terms of marketing is under the Gas and Power division. And last, the international transportation, which is the fourth business segment we normally report to is, I would say in line. That is, there is a EUR16m reduction versus a 234 overall, contribution in terms of EBITDA.

Alastair, you ask on inflation impact. I would say that we still see the cost going up in general terms. And you know that we make normally, a distinction. There are costs which continue arising while others they seem to show some sign of declining and the difference is between talking about equipment is between the more sophisticated drilling equipment and the more conventional one.

In terms of specific impact on the cost, if we refer to operating costs, we have -- we project a cost per barrel for the full year 2007 around $4.08 a barrel, versus a $4.1 the year before, which is the combination of inflation. We were covering all the maintenance actives. But it's also impacted by the acquisition, which implies a higher operating cost, in particular I am referring to The Gulf of Mexico.

In terms of the DD&A, I would say that we project for 2007 around $7.3 a barrel versus $6.6 in 2006, which is basically again, the result of all the ongoing activities but is also impacted by the contribution of the acquisition in -- for the months on which the acquisition impacted the DD&A.

Okay. Thank you very much.

Thank you. Our next question comes from the line of Barry MacCarthy of ABM Amro. Please go ahead.

Thank you. Good afternoon. It's a question on refining and marketing, if you can say by how much your effective refining margin changed in the quarter? I see you give some changes in the benchmark margin, but it looks as though the effective margin narrowed somewhat more than the benchmark would indicate which would hopefully explain the large decline in the operating profit there.

Yes, I will try to elaborate on that. I have to check whether it is, yes, let's say that the benchmark margin in the third quarter of '07 decreased by 5% in dollars and by 12% in euro, while in Italy they decreased by 23% in dollar and 28% in euro. So, you can attach the difference to the strong decrease differential between light and heavy crude. The Brent/euro price differential decreased from 5.7 in the third quarter of '06 to $3.22 per barrel in the third quarter '07, which means a reduction of 44% barely, which is affective -- affecting the competitive advantage of the more complex refineries which, I mean, the kind of refineries which we have.

Okay, that's great thank you.

Thank you. Our next question comes from the line of Gordon Gray from JP Morgan. Please go ahead.

Thanks. Good afternoon gentlemen, a couple of quick questions on E&P if I could. The first one is, with a few months of track record now, if you could comment on the Congo assets and how you've -- whether you've had any surprises, positive or negative, relative to your first impressions?

And the second one was whether you could give us a bit more background on the licenses you recently acquired in The Gulf of Mexico and how that fits in with the recent Dominion acquisition and your broader U.S. Gulf strategy?

Yes, Gordon, in terms of track record I would say it's a bit, as you may understand, is a bit early. It's just four months that we are taking control of the Congolese asset. We are at the moment concentrated much more on HSE aspects and particularly on the different approach which we have on these issues with -- so we are in the process of training people. We are in the process of devising and designing the changes to the hardware which makes the equipment in line with our requirements. And of course, at the same time we have started the review of the design of the water injection to which we attach a very high importance, as you know. We will need the -- obviously, the results of the first well of water injection. We will then be in a position to make a proper design of the final configuration of the water injection. So I would say that probably going ahead in an orderly fashion we'll be in a position to make a judgment some time during the course of 2009.

Okay.

In terms of the license, the 26 additional licenses, which we have acquired during the recent round, I have to say that first of all we are quite pleased with the outcome. These are all areas which we had carefully investigated and which we consider very attractive to us. And in this respect I have to say that we have found in the Dominion organization, in particular in the people involved, in charge for the exploration, a lot of value, which we quite frankly which we did not expect. They were much ahead of us in terms of depth of the investigation they had done. So once we have combined these two organizations I would say this has been the first positive, unexpected, outcome of the combination. So in a nutshell we are quite pleased with what we have acquired. They perfectly fit with the combined portfolio of our leases and Dominion leases and we are carefully analyzing all the commitments which we are making so that -- to be possibly sure that by the time that we need to drill the wells we should have the equipment duly available.

That's great, thank you.

Thank you, our next question comes from the line of James Hubbard from Deutsche Bank. Please go ahead.

Thank you. Just two questions. Firstly, are you reviewing your Iranian investments given the public statements by some large funds over the last couple of weeks, that they are going to be selling down?

Can you speak a bit louder, sorry.

Is that a bit better. Question number one, are you looking again at your Iranian investments and operations given that a couple of large funds have announced recently that they will be selling down their station companies that have large investments in the country? Does that also -- do you feel any pressure from that at all?

And then secondly, could you just tell me what the next step in the timeline is for South Stream? What we can expect to see happening there over the next couple of years and when?

In terms of the Iranian, the Iranian operation, I am sure you are aware that we are active in the country since the beginning of this decade and we have four buyback contracts. Three out of four they have seen the completion of the investment phase and we are just in the phase of recovering through the production the investment and getting the upside, the profit basically, while we are completing the development of [Darquaid]. In particular the second phase of Darquaid. So I would say that at this stage we are continuing the operation. On one side, recovering the investment and on Darquaid in particular, completing the second phase. So at this stage this is the situation. These are all the commitments we have in the country.

Next in this regard, the next step in the South Stream, we are in a very preliminary phase. The feasibility study began already. We expect the outcome to be available let's say September and wait and see then if the outcome will be possible, will begin to work on the more precise engineering development.

Okay. Thank you.

Thank you. Our next question comes from the line of Michele Della Vigna from Goldman Sachs. Please go ahead.

Hello. I would like to ask a follow up question on your activities in Libya. If you wanted to increase gas production there by about 8 bcm, per annum on 20 years that would mean around 160 bcm. Now, I was wondering how much of these reserves have already been identified and how much of it is instead left to exploration at this point?

And then on another gas project in North Africa, the second train of Damietta. I just wondered, given the intensive exploration you have had there over the past years at what point are you in terms of coverage of gas required for a second train there and how much more do you need to find?

In terms of the Libyan agreement, as I had the opportunity to say earlier on addressing another question, we are talking of gas resources coming from an area which we already detain. So there are no new areas to be had there. And these are volumes which are not reserves which are resources which we have already identified. Obviously through the work of the development of the basis scheme for the exploitation of the gas they would like to be transformed from resources to reserves. But they are all well identified and they are all within areas which already retain in terms of contractual rights.

As far as the second train in Damietta, we have duly identified all the volumes needed for the second train in Damietta and we are in the final process of having this approved by the Egyptian government. Obviously when I say we I refer not only to Eni, but to Eni and the other partners in the venture, in particular I would say BP.

If I may add, of course you are aware that the requirement for the country is not only to have the gas sufficient volume for the export, but also to have sufficient volumes for the domestic. And to have also at least an additional volumes available which might be in the form of P3, or exploration resources plus, what they call the future generations. So these are all the volumes which have been identified.

Thanks.

Thank you. Our next question comes from the line of Colin Smith from Dresdner Kleinwort Bank. Please go ahead.

Good afternoon gentlemen. Can we just talk about Dominion and Congo again? As I recall, Dominion was about 74,000 barrels a day and it completed pretty much at the beginning of the quarter and [Embundi] was about 50 to 60,000 barrels a day, so combined one might have expected something closer to 100,000 barrels a day than the 77,000 you've got from portfolio changes in the quarter. Was there anything else going on in the portfolio changes, or can you just comment on where you think volumes for both Dominion and Embundi will be in Q4, a little bit more directly?

And my second question was just on Libya, again, with the move to EPSA-4 terms, will that make any noticeable difference to the volumes or the profit that we might expect to see from your Libya operations from the beginning of next year?

Okay, in terms of contribution from Dominion I think I can give you what we expect to be the contribution of the fourth quarter of 2007, for Dominion. And this is in the range of 80,000 barrels per day which together with the existing production brings the overall U.S.A. production to 110,000 barrels oil equivalent there, a day. This is of course takes into account the ramp up of the independent hub which is going ahead according to plan and I would say in a fairly satisfactory manner.

In terms of the Congolese asset, I think as we have the opportunity to say already, being in the process of reviewing the -- all the production schemes and layout. We are currently likely reducing production in order also to reduce the amount of gas which is flare. So at the moment we have a production which is, for our part, for our component, about 15,000 barrels per day.

Then, you were asking about the immediate impact, beginning of 2008. No, there is no immediate impact in terms of production. In terms of reserve, there again we will give you an update once we announce the overall reserves.

Can I just have a further question on Embundi? I think you mentioned earlier on in the call that you would be, you're drilling a well and you would have a better idea from 2009. Does that mean Embundi production, your share is going to be around about the 15 to 20,000 barrels a day level through 2008, is that your expectation?

No, I think it is too early. As I said, the beginning of my reply was that we only took control of the asset in the last four months. So we are still in a learning process so I would not make any specific commitment on what is the expected production in 2008. The reference is not to a single well, to the injection mechanism, which we need to test. We need to make an initial testing of how the system works. So to drive the -- what is the final design of the overall injection scheme. So at this stage I think I would rather prefer to remain to with what we have done.

Okay, thanks very much.

Thank you. Our next question comes from the line of Huw Williams from Bear Stearns. Please go ahead.

Thank you very much. And good afternoon gentlemen. Just two quick upstream questions. First, whether you could just update us on any progress or developments in Russia on the projects which you secured following the asset swap earlier this year?

And then secondly, if you could give us an update on what's going on in terms of other developments or further exploration at the Goliath prospect up in Norway?

Okay. As far as Russia we have got control of the asset after the auction, April 4th. We are in the process of setting up the operational organization and again, taking control of the existing assets which are obviously very limited. And there again, the first attention has been drawn by the HSE requirement. And we are in the process of bringing the wells to the sufficient level of safety. At the same time we are planning a seismic campaign. So to have a full knowledge of what we are talking about and we are looking at the status of the investment which has been started at the time of the bankruptcy. And I would say that the initial outcome is that the equipment which was half way built, it was designed and built according to Western standards, so something which is more than acceptable to us. So we are devising as well, what is the best way to utilize some of these investments already made.

At the same time of course we are setting up all the negotiating team which needs to come to the final assessment of the gas sale contract which as you may appreciate will be the criteria for defining the scheme of the development and indeed the return on the investment as well.

In terms of Goliath, things are progressing in accordance with the program. We are -- we have a final investment decision which is expected in August of 2008. Everything is moving in the right direction so we expect to have the final investment decision in 2008 and then to move on with the development.

You know that we have established, we have signed the contract for the utilization of this [Carabao-8] for all these developing wells, so the critical equipment is already ensured.

That's great. Thank you. And then just one quick follow up on Russia is, what should we be looking out for in terms of a timeframe for the further guidepost as to progress on this project?

It's very premature, but I think we already said that we would expect some sort of early production in 2011, and sort of a more substantial production in 2015, 2016.

Thank you very much.

Thank you. That was our final question so I will now hand you back to the host to conclude today's conference call. Thank you.

Thank you everybody for joining us. We are looking forward to meeting you on the next occasion. Bye bye.