英國石油 (BP) 2003 Q4 法說會逐字稿

Welcome to the BP presentation to the financial community conference call. I will now hand the call over to the Vice President of Investor Relations, Mr. Fergus McLeod. Please go ahead, sir.

Good afternoon to those of you listening in Europe and Asia, and good morning to those in the Americas. I would like to welcome you to BP's fourth quarter 2003 conference call. My name is Fergus McLeod, and I am BP's Head of Investor Relations. Joining me today are Group Chief Executive, John Browne and Byron Grote, our Chief Financial Officer.

Before we start, I would just like to draw your attention to two items. First of all, today's call will serve to slides that we will be using during this Webcast. If you're listening on the telephone, the slides are available to download from the investor center on our website, BP.com. Those of you on our e-mail list should already have received the slides. If you have not gotten those slides and would like to be placed on the list for future events, please do let us know.

Secondly, I would like to draw your attention to the first slide. We may make forward-looking statements, which are identified by the use of the words will, expect and similar phrases. Actual results may differ from these plans or forecasts for a number of reasons, such as those noted here. I would now like to introduce Lord Browne, BP's Group Chief Executive.

Ladies and gentlemen, it is a great pleasure to talk to you and to present BP's annual results for 2003. We're (indiscernible) this Webcast to give you both an overview and the relevant detail of our results. As usual, I would like to put our performance in the context of strategy, and then Byron will pull out the key aspects of the results. Naturally, there is only so much we can do in 1 1/2 hours, so we are going to invite you to a full update on the implementation of our strategy on March 29.

This time last year, my team and I had as many questions as answers about the forthcoming year. How would the implementation of our strategy endure in the face of a weak global economy, impending war in Iraq, continuing uncertainty of terrorism, increasingly complex regulation and a ground swell of anticorporate sentiment. I am pleased to say that BP rose convincingly to all these challenges. The group turned in one of the strongest performances in its history. We closed the year more secure than ever in our strategic direction. We maintained the strength of our assets presently in service, while layering in the investments in human and organizational capability for the future. Our financial result was up over 40 percent to $12.4 billion from $8.7 billion in '02. Our pro forma return on average capital employed improved from around 13 percent in '02 to around 16 (ph) percent in '03, reflecting improved margins and disciplined management of our revenue-generating assets. The sales of course achieved against a backdrop of stronger oil and gas prices, which were higher than most had forecast. During '03, underlying oil demand increased as the world moved out of recession and the economic boom in China continued. OPEC maintained adequate supply throughout the year despite disruptions in Venezuela and Iraq. Inventories remained low.

Many things went well for us, and I would like to point out some highlights. We concluded our transaction to purchase 50 percent of TNK-BP; they are the third largest oil producer in Russia, a country which is the world's most significant hydrocarbon producer (indiscernible) for today and for tomorrow. We more than replaced our production with new proven reserves at an organic rate of 122 (ph) percent. Including a joint venture and associated companies, and incorporating acquisitions and divestitures, this (indiscernible) rose 158 percent. This was the 11th year in a row in which we more than replaced our production, giving us the material for future growth. We participated in discoveries in Egypt, in Angola in Blocks 15 and 31, and the deepwater Gulf of Mexico, Chubalabells (ph) (indiscernible) and Puma. All projects in our new E&P profit centers are on track. For example, production has started in Angola at Jasmine and Shakumba, in Trinidad at Atlantic LNG Train 3 (ph), and in the Gulf of Mexico at Mikita. Construction is well advanced on the Israeli project; and the BTC pipeline is on track for start up in the first half of '05. Putting (ph) our production at over 3.6 million barrels a day was in line with the capacity indicator range we gave a year ago, albeit at the lower end of our expectations. I will talk more about this later. LNG volumes, produced from our equity gas, was up 42 percent from the previous year. We achieved a number of milestones, such as fast delivers in Tebnobaro (ph), Spain and Co-Point (ph), USA. These steps underpin continued expansion of our LNG business. We completed the integration of Salah (ph) into the refining and marketing segment with synergies ahead of our initial estimate. The anticipated synergies of 200 million a year pretax were exceeded by over $100 million, with more targeted to be delivered in '04. In oil products, our retail operations achieved the same-site annual volume growth of 0.5 percent and sales growth of 2.9 percent. Lubricant volume sales grew by 0.7 percent in the year, a strong performance against markets which appeared to decline by around 2 percent due to global recession. In North America, BP is the leading gas marketer, based on wholesale volumes with sales up 29 percent over '02. In petrochemicals, we continue to focus our investment in our core portfolio. The $2.7 billion Sekur (ph) joint venture in China was 50 percent complete by December and is well on track to begin commercial production in the summer of '05. Our focus on cost efficiency continues.

Our improved results was founded on cash flow from operations, which rose by 25 percent to $24.2 billion pretax before pension funding. Added to this, we generated $6.4 billion pre-tax from divestments. So how did we use this cash flow? Around $2.5 billion used to strengthen our pension funds; part of this was used to restore the health of our U.S. funds, which had been reduced in scale as beneficiaries withdrew lump sums following severance. Around $14 billion for organic capital expenditure, of which 70 percent was in the E&P segment and 7 percent in the cost of metosing (ph) business segment, that is refining and marketing, petrochemicals and gas powered renewables. $2.6 billion in acquisitions, notably the cash portion of the payment for our share of TNK-BP. $5.7 billion in dividends, which rose in dollar terms by $0.4 billion or 8 percent. $2 (ph) billion in stock buybacks. We were able, even after this expenditure, to keep year-end net debt at the same level as in '02. Overall, a year with some good achievements.

(Indiscernible) with perfection. And many are passes (ph) with our issues being typical or concerns being discussed. I would like to take a few minutes to talk about four of these, recognition of results, Russia, oil prices and upstream capital costs. Firstly, about the recognition of reserves. For our industry, the issue of how reserves are recognized and how much confidence investors can have in reserve estimates has become very topical. As I have indicated, our organic reserves replacement ratio last year was 122 percent. Over the past five years, it's been 153 percent. If we include the movements from portfolio activity and joint venture and associated companies, our reserves replacement ratio was 169 (ph) percent over five years. Over time, our reserves have revised up or down in the normal course of business, in the light of such things as further geological data, world performance, changes in commercial circumstances and advances in technology. BP has had a policy in place for over 15 years for the recognition of proven reserves. We recognize reserves in major projects on function (ph), that is at the final investment decision, and very rarely earlier. That is a very short time before planned sanction when a project has been confirmed as technically or commercially viable. In that last event, if the project has not sanctioned within the next calendar year, the reserves are removed. Oil (ph) reserves can't (ph) be recognized and new developments are attached to sanctions projects. Oil (ph) changes, at $25 million or more to reserves estimates proposed by our business units, require authorization by a central team, independent of those units. Reserves are reviewed on a quarterly basis through a process overseen and directed by senior management.

Our estimates are based on good faith judgments regarding the reasonable uncertainty of recovery, the standards set out by the SEC. As with oil standards, there is room for differing views and interpretations on a case-by-case basis. We consider our current process and methodology to be robust and well funded. In connection with a recent routine filing with the SEC, we received a number of questions on our 2002 Form 20-F (ph), of which a few related to reserves. As usual, we have responded. For details about '03 reserves, will of course be contained in our annual report, which is due to be issued in early March.

The second topical issue is Russia. I am asked if Russia is too risky a place for a long-term investment; whether what happened to Ucars (ph) is likely to happen to others; and that's been our experience over the past four months. Last October, we talked at length about the relative political risk in Russia, our long-term strategy beyond five years and our short-term plans. These remain unchanged. Our overall commitment, our focus on improving management systems and on the application of technology to increase profitable production is unaltered. Our short-term plans show improvement. I hope that we have given you enough information on this joint venture. We have talked about the balance of the group's failure. Russia may be the most notable recent transaction that we have concluded, but it's weight in our portfolio, appropriately measured on capital employed, is not disproportionate at 4 percent, based on the year-end balance sheet, or 9 (ph) percent, if we include the deferred share payments and the recently acquired interest Slavneft. The percentage of the goods (ph) production from Russia at the end of '03 was around 18 percent.

There are natural concerns following the Ucars affair. Again, we have no reason to believe that this will affect BP's ownership or standing in Russia. Nevertheless, I am sure that there will be unexpected twists and turns in the Russian oil and gas industry and we need actively to manage our position. We have made sure that we are not only represented at TNK-BP but as BP as well. We are the first significant foreign direct investor, an important point for Russia.

Finally, as you will see, the operations are proceeding well. Production from the assets has grown by 14 percent over last year, with much of the growth coming from better reserves management and application of technology. Plans are coming together for future developments beyond circle brown field activity. In the near term, we see the potential for higher production growth than previously envisaged. Transportation tariffs have risen, but this is not expected, and cost of revenues synergies are expected to mitigate the impact.

Thirdly, let me talk about the future path of oil prices. Oil prices are impossible to predict however on the short or long-term basis. There are many uncertainties. One is the stability of demand, which has been volatile and has grown by less than 1 percent per annum on average since '97. Another is the growing level of production in new capacity, both outside the control of OPEC and in some OPEC countries. It is true that unreasonable estimates, if OPEC continues to regard their role (ph) as one of restraining production to balance markets, their path may become more difficult over the next few years. But equally, there is a growing understanding in the well that energy supplies must be diverse and development should not be shut off by two low an oil price. Absorption of cash by OPEC rises on the back of growing populations. What does all this mean? There is no unique or absolutely accurate model. So I suppose the best thing to do is to go back in history to look at what has happened over the last 20 years, where at one time or another, (indiscernible) similar concerns (ph) prevailed. The stock price has, of course, been quite volatile. However, we do detailed financial planning over a five-year period. If we look at any 60 month, five-year period, you see that the average (indiscernible) oil price has never gone below $16 a barrel. The 2- year average has actually been almost $21 a barrel in nominal terms. The question, therefore, is what oil price to use for resource allocation to reflect the right balance between the customer facing business segments and the E&P segment? It's my view that it is quite reasonable to use $20 a barrel, always testing projects at $16 on the downside. Those are quite separate questions about financial planning.

At what price should BP broadly balance cash flows from divestitures and operations would (indiscernible)? There are two considerations. First, we believe it necessary to retain a sufficient cushion of debt capacity to see us through our period of $16 a barrel while not stretching gearing (ph) unreasonably. Second, as our base case, we now see cash flows balancing at around $20 a barrel over the next couple of years. Over time, production rises and capital expenditure declines so that the oil price in which cash flows balance is expected to fall below $20 a barrel. Why has our estimate of the balancing point moved from $16 a barrel to $20 a barrel? It is because we have moved (ph) our internal assumptions more closely based on recent experience in three areas, oil and gas differentials to market prices, petrochemical margins and the burden of pensions and benefits. This has, therefore, changed at least for the near term, the base case balancing point for financial planning to $20 a barrel in line with historical average oil prices.

Finally, let me talk about the amount of capital the industry is spending and whether or not capital costs in the E&P segment are rising. As this slide shows, if you look at the finding and development costs for the oil majors over a 20-year period, it seems there's little evidence of an enduring trend towards rising costs. There is some evidence of cyclicality, with increases coming as new provinces are opened. We may be entering one of those periods now, but this remains unclear. As for BP, our five-year rolling average funding and development costs have been around $4.10 a barrel, excluding joint venture and associated companies and the effects of acquisitions and divestitures. We expect our five-year average F&D costs to remain within the range of $4 to $5 barrel. Organic capital expenditure for BP as a whole is planned to come down by '05 to around 12 to $12.5 billion per annum, a level similar to that which was seen on average between '00 and '03. In the E&P segment, organic capital expenditure is expected to trend down to a rate of around 8 to $8.5 billion per annum, down from recent levels of 9 to $9.7 billion per annum. There are two reasons for this downward trend. Firstly, investment in pipelines, notably BTC and the Mardi Gras system in the Gulf of Mexico, and spending on ships for the transportation of Alaskan crude oil complete in '05. Secondly, a natural slowing of the pace of investment is expected to occur after the significant aggregate upfront costs involved in establishing the four new profit centers in the deepwater Gulf of Mexico, Azerbaijan, Angola and Trinidad. You will see the beginning of this trend this year.

Let me now make some comments about the performance of the business segment in '03. Byron will, of course, deal in a moment more with the detailed results for the quarter and for the year. First, exploration and production. It is perhaps worthwhile to step back for a moment and reflect on the meaning of the different numbers that are talked about in relation to production. Firstly, there is actual delivery. The oil majors' track record in this matter has been uneven, as this chart shows. Secondly, there are forecasts. The track record of promulgating forecasts with annual production growth rates has been somewhat mixed. These are particularly sensitive to such things as project start-up times and decline rates at existing producing assets. There have been no exceptions. Thirdly, there are explanations. This is more difficult than it might appear because of the complexity in finding a stable basis against which to measure growth, since so many acquisitions and divestitures have taken place and because the price of oil affects volumes produced. For BP, our production in the fourth quarter was 3.9 (ph) million barrels a day, and for the full year, 3.6 million barrels a day. Last February, we said that our underlying production, corrected for the impact of acquisitions and divestitures, would grow at zero to 3 (ph) percent over '02. We estimate that it has grown by 0.5 percent, in spite of our production having been reduced by around 40,000 barrels a day, as a result of the price impact on volumes from PSCs (ph), which now in aggregate represent about 10 percent of our production. We regard this outcome as satisfactory, albeit not spectacular. Decline rates of existing producing assets are in line with our forecasts. We are now particularly focusing on improving operational up-time in our North Sea operations.

How are the indicators for the future developing? For '04, when all the challenges in the portfolio are included, the indications for production capacity of last February are still satisfactory. Our presently expected outcome is at the lower end of the range. We expect production capacity from our present portfolio of assets to increase to over 4 million barrels a day this year, an increase of more than 10 percent on '03 production of 3.6 million barrels a day. This estimate is of course subject to revision in the event of further portfolio changes, and as we gain more experience with our Russian interest. The longer-term indications for production capacity that we gave you last year, adjusted appropriately for portfolio changes, remain sound. We will update you on progress in more depth in March.

Upstream capital expenditure for '03 was $9.7 billion. This is below the 9.8 to $10.2 billion range we indicated last year. '04 capital spending is expected to be around $9 billion, also below the range of 9.3 (ph) to $9.8 billion, which we shared last year. In spite of inflationary pressure, lifting costs, adjusted for the effect of movements in the environment, are in line with guidance given last February. We made a total of $5 billion in divestments in '03. During the fourth quarter, we completed the year's program with the sale of certain Algerian interests. Pretax pro forma return on capital over the past five years has averaged 29 percent, at an average oil price of $25 a barrel. In '03, it was 29 percent, but as an average oil price of $29 a barrel. Byron will talk about E&P's performance, with specific reference to the expected poorer than expected outturn for the fourth quarter.

Turning now to our other segments, gas and power. We are building this segment, which in BP's case should be regarded as the natural gas and NGL equivalent of oil products marketing. We are expanding, or are participating in scale in our target markets, in particular we are expanding LNG. We taxed pro forma return on capital with 14 percent in '03; and over the past five years, it's averaged 16 percent.

Refining and marketing, over the last five years, pretax pro forma return on capital has averaged 19 percent, and last year it was 15 percent. In '03, performance has been underpinned by our continued focus on capturing expanding margin with improved cost efficiency. Access to customers continued to grow over the year with the launch of new products in our fuels and lubricants markets and the ongoing rollout of the BP Connect stores, particularly in the UK and the USA. We continue to improve this offer, and will roll it out further in the coming year.

Our manufacturing portfolio performed well, with the availability for the whole portfolio again approximating 95 percent. In the USA, our portfolio is top quartile, as measured by third party rankings and continues to improve as we completed our clean fuels investments. In Europe, availability was also strong, and our performance was underpinned by a continued focus on reducing the cost of goods sold. We continue to look for ways to improve this portfolio, which is not as good competitively as our U.S.-based one.

Petrochemical, our pretax pro forma return on capital in the segment has been about 6 percent over the last five years. 2003 is not significantly out of line at 5 percent. We've kept the level of capital employed relatively constant, and are continuing to improve the operating characteristics of the segment in the face of very poor average industry margins. Recent weak margins are the consequence of higher import costs, gas and (indiscernible) energy and sluggish demands. (Indiscernible) expect demand to pick up as economic growth improves, we cannot rely upon this alone and we continue to take action on our portfolio investment choices and costs. We are doing a lot to identify the appropriate level of participation and the right portfolio for BP in this segment. This is evidenced by our divestment program and by our focus on investment in our advantage products.

Stepping back from these observations, the question is how do they affect us? BP is now in sufficient scale and within its chosen sectors, diverse enough to be able to average through so many of the consequences of world changes and events. We are able to take the day-to-day volatility and provide a degree of stability not least in our approach to dividends and our enactment of strategy. Return from capital are important, measured in both profit and cash terms. After applying estimates for corrections for oil and gas prices and other exogenous factors, our focus is to at least maintain the terms planned. Our drive and ambition is to improve them. Our internal estimate is that, on average, returns are at least flat looking through three years back and three years forward. But there annual diversions (ph), as capital is spent, and in the near-term, a growing proportion of it does not yet generate revenue. We have expanded our capital employed base, and we plan to continue to do so, given the strength of our opportunity set. Capital employed on average, for the next three years, is estimated to be 15 percent higher than the average for the last three years. In terms of the specifics for '04, we expect to spend organic CAPEX of around $13.5 billion and make divestments of around 3 to $4 billion. The details by segment are shown in the chart you can see, which relates these indicators to history.

The last item I want to cover is how we intend to utilize the cash we expect to generate. I have spoken on previous occasions about the board's philosophy on dividends, and this remains unchanged. The consequence of this philosophy is illustrated on this chart of our dividend history. It shows that the five-year record of dividend growth is around 5 percent per annum and the 20 year track record is around 7 percent per annum. This is a track record of which we are proud and it will inevitably inform (ph) our future thinking. Our financial framework has always given us a basis for a disciplined balance between distribution and re-investment. Since the completion of the ARCO acquisition, we have repurchased 774 million shares for $6 billion, reducing the number of shares issued by 2.5 percent in just under four years. While at the same time, we have been building up the scale of the group. Our planned investment program over the next two years is designed to leave us in the gearing (ph) range of 25 to 30 percent or $20 a barrel, leaving headroom if oil prices were to go back to $16 a barrel. This will give us the capacity to buy back stock, all other things being appropriate, when prices are above $20 a barrel. In this context, we are re-starting our buyback program. Going forward, we will report back on the total number of shares purchased each quarter. Thank you for listening to me. Now, let me hand it over to Byron to go through the details of the results. Byron?

Thank you, John. I would now like to focus on our financial and operating results for the fourth quarter and the full year. I will also note some forthcoming changes in the way we present our results starting in 2004. This slide summarizes quarterly prices and margins on the left and annual figures on the right. I will focus on the quarterly figures. Our average liquids realization, which includes both oil and NGLs, exceeded $27 per barrel. This was up around $2.50 compared with the fourth quarter of last year and also, up slightly compared with Q3. Our fourth quarter average natural gas realization of $3.18 per thousand cubic feet showed a similar increase. Taking oil and gas together, our average realized hydrocarbon price was 3 percent higher than in the third quarter and 10 percent higher than the fourth quarter of last year. The fourth quarter refining indicator margin of $3.14 per barrel was down by nearly a third compared with the prior quarter, but above last year's fourth quarter. Our specific refinery configurations allowed us to mitigate much of the fourth quarter decline. Although not shown, retail fuel margins were midway between the stronger margins in 3Q and the relatively weak margins in the fourth quarter of last year. Overall, gas room (ph) trading conditions remained above historic average levels, with periodic pressures from crude market tightness and recovering product inventories. Petrochemicals margins remained squeezed by the rise in feedstock prices. The provisional fourth-quarter industry indicator margin, of $114 per ton, is comparable to the full-year average. However, this dollar-based indicator margin did not fully reflect the weak situation in Europe, where 14 (ph) margins came under pressure from dollar-denominated product and the effect of a strong Euro on our cost base. As shown on the right, 2003 realizations and indicator margins were higher than in 2002 across all lines of business. Helped by these favorable market conditions, we generated record financial results in 2003.

This slide shows key results for the fourth quarter and full year. I will again focus on the quarterly results shown on the top of the slide. Our pro forma result of $2.7 billion was up slightly compared to the fourth quarter of last year. Our replacement cost profit, which includes special items and acquisition impacts, was 1.8 billion, up 7 percent. Our historic profit of $2 billion was more than triple the fourth quarter 2002 result. Strong underlying cash flows continued in the quarter. The reported decline of 44 percent reflects working capital increases, but masks the underlying improvement. We reported a $2.5 billion working capital build in 4Q '03 compared with a $900 million working capital release (ph) in 4Q '02. Two major elements drove the 2003 figure. First, we made $1.6 billion of discretionary contributions into our pension funds during the quarter. Under UK GAAP, this cash outflow is shown as an increase in debtors. Secondly, the normal 4Q peak in German excise tax payments was higher in 2003 than in 2002, and is shown as a reduction in creditors. This cash outflow reverses in the first quarter. Excluding these working capital affects, cash from operations, in fact, rose by 13 percent between periods. I should also note that the UK GAAP operating cash flow figures shown here do not include dividends from joint ventures such as TNK-BP, which are reported separately. The 0.25 cent per share dividend increase announced today brought our fourth-quarter dividend to 6.75 cents per ordinary share, up 8 percent compared with the fourth quarter of 2002. The full-year comparison, summarized on the lower part of this slide, is even stronger. Our full-year pro forma result of $12.4 billion and replacement costs result of 9.5 billion, are both records for the Company. Our operating cash flow was $21.7 billion after more than $2.5 billion of pension contributions. This supported an 8 percent dividend increase for the year, in line with the long-term track record that John discussed earlier.

This slide shows BP's pro forma return on capital employed relative to our principal competitors. All results are calculated using a consistent approach. Our returns remain competitive with those of our peers, within a band driven by the industry price and margin cycle that is evident from the chart. There's also a small negative foreign exchange impact, since around 20 percent of our capital employed is kept in currencies other than the U.S. dollar, mainly the Euro and the Sterling. The strength of these currencies versus the dollar has increased our capital base by nearly $4 billion since year-end 2002. This reduced our return on capital employed by around a half a percentage point. Our 16 percent return for 2003 reflects the negative for. ex. impact as well as the significant capital we are investing in our portfolio of new upstream profit centers that will contribute increasingly to the bottom line over the next several years. This slide shows the main factors driving the $3.7 billion improvement in our pro forma result. The full-year comparison reflects a continuation of the trends that I have mentioned in prior quarters. Higher prices and margins are clearly the dominant factor, with post tax benefits of 4.5 billion. Compared with last year, we benefited by around $1.3 billion from higher oil prices, $1.8 billion from higher gas prices, and $1.3 billion from higher refining and marketing margins. Appreciation of other currencies against the dollar increased both our revenues and costs. The overall impact was small, given the scale of the currency movement, increasing cash from operations by around $100 million and depreciation by around $250 million, a net, $150 million negative. The impact varied by segment, indicating the natural hedge inherent across our businesses. Our 2003 result also reflected disposal impacts of around $400 million in exploration and production and $200 million in the other segments. This was partially offset by $300 million incremental earnings contribution from TNK-BP, yielding a net portfolio-related reduction of around $300 million. Higher depreciation, depletion and amortization charges, adjusted for currency changes, reduced our 2003 result by $750 million compared with 2002. Adding the $250 million for. ex. impact on depreciation that I indicated earlier, our annual DD&A charges increased by $1 billion post tax. I should emphasize that this is pro forma depreciation and thus excludes amortization of our acquisitions and impairment affects. Of course, these higher DD&A charges have no impact on our cash generation. The remaining item of around $350 million has a number of components. It includes incremental pension and retiree medical costs of around $300 million post tax, consistent with the full-year expectations I have discussed previously. It also includes incremental 2003 charges for environmental and litigation provisions and other onetime items noted in our SEA (ph), which total $150 million post tax. Offsetting these items, we saw continued benefits from lower interest expense and lower effective tax rates, which increased our 2003 result by more than $300 million, as well as $500 million increase from underlying volume and cost improvements across all our operations.

I would like to offer a deeper perspective into our fourth-quarter results in exploration/production, which, as highlighted in our stock exchange announcement, reflected a number of unique factors. Our fourth-quarter production was up by more than 9 percent on 4Q '02. As noted previously, our average hydrocarbon realization was up 10 percent, around $2 per barrel of oil equivalent. Despite this, our fourth quarter pretax result in exploration/production was essentially flat between the years. There are three main reasons for this. First, the improvement in realizations was partially offset by two environmental factors each around $100 million. These are the swings from positive to negative, unrealized profit in stock, UPS, adjustments in the U.S., as set out in our stock exchange announcement, and the impact of the weaker dollar on our cost structure, notably in the North Sea and Canada. This currency impact was split around 50-50 between cash and non-cash costs, and forms part of the small overall for. ex. impact I noted earlier. Secondly, we had a number of onetime impairment and litigation provisions in 4Q that amounted to $150 million overall, mostly in the U.S. Lastly, the higher depreciation rates and pension charges that we have seen throughout 2003 continued in 4Q, reducing quarter-on-quarter pretax income by $200 million. These changes were partially offset by a net $100 million benefit from higher volumes. This mainly reflects the contribution from TNK-BP, which in 4Q more than offset the impact of the $5 billion of E&P disposals completed during 2003.

Our 2003 results included a full fourth quarter's contribution from our 50 percent interest in TNK-BP compared with only 33 days in the third quarter. This slide summarizes the key results, and shows the impact of scaling up our partial third quarter to a full-quarter equivalent for ease of comparison. You will recall that we account for TNK-BP on the basis of estimated results for the current quarter with an adjustment in the following quarter once actuals are received. The 4Q results include a $5 million increase in income in respect of Q3 actuals. After accounting for the deferred consideration to be paid over the next three years, our fourth-quarter result includes $253 million of net income from TNK-BP. This is down 14 percent compared with the full third quarter equivalent of $293 million.

Before I come to the reasons for this, let me briefly summarize trading conditions in Russia during 4Q. Milder weather meant that the normal seasonal restrictions on water born- shipments and exports were less severe than expected. This allowed Russian domestic prices to increase slightly compared with the third quarter, in parallel with increasing export prices. TNK-BP actively channeled volumes to the domestic market, where similar net frac. prices could be realized at the margin. So the crude exports fell from 60 percent in 3Q to slightly above 50 percent in 4Q. TNK-BP continued to refine around 30 percent of its production, with product exports of around 15 percent.

Looking at the BP results, higher realized prices of around $1 per barrel from Q3 to Q4 generated an estimated $40 million net income improvement. Higher export duties effectively offset this. Since these duties are linked to oil prices but lag by three months, the oil price increase in 3Q drove the duties higher in 4Q. In addition, higher transportation costs decreased net income by over $30 million, much of it due to rail tariff increases. Volume growth continued. TNK-BP's oil production was up over 2 percent compared with the full 3Q equivalent. We continue to see immediate benefits from TNK-BP's focus on optimizing operations in existing fields. During the fourth quarter, we received nearly $300 million of cash from TNK-BP. This represents our share of the dividends on first-half results. As this dividend reflects results from periods prior to the transaction closing, were reported as an offset to the acquisition costs. In mid-January, we closed the transaction to include our partner's 50 percent share of Slavneft into TNK-BP. This involved a cash payment of $1.4 billion. Later this year, we expect to receive our share of pre-closing Slavneft dividends, which will reduce the net acquisition costs to around 1.35 billion. Overall, we continue to be very pleased with the progress we are seeing from our investments in Russia.

The pro forma results are before special and exceptional items. This slide provides a longer-term perspective in this area. Last year, these items totaled a net pre-tax charge of around $270 million. Looking at the longer-term trend, it's clear that we are moving from an era of significant portfolio and restructuring activity into an era of maximizing delivery from the base that we've established. This slide sets out a number of accounting and policy changes we intend to implement in 2004 and beyond. First, beginning in 2004, we will discontinue separating special and exceptional items from our pro forma result. This will make our result more comparable with others, who have started including such items in their headline result. However, this shift also makes everybody's results more volatile. To help you better understand our underlying operational performance, we will continue providing information on disposal gains and losses, consistent with UK GAAP, as well as major non-recurring or timing items. Also in 2004, we'll adopt the new UK accounting standard for pension and benefit reporting, referred to as FRS 17, which we've reported as supplemental information on our annual accounts since 2001. This change is optional, but encouraged by the UK authorities. It's also consistent with the new international financial reporting standard proposed for 2005. In addition, our 2004 accounts will reflect recent changes in UK law, related to the reporting of shares held by employee share ownership programs. Had we made the FRS 17 and ESOP changes in 2003 rather than in 2004, we would have shown $200 million higher earnings and reduction in capital in capital employed of around $5.5 billion. This would have increased our ROCHE (ph) by around 1.5 percentage points and our gearing by just under 2 points. Fergus and I will provide further information on the 2004 changes in the first half of March after we publish our annual report. We will also show a longer-term historical perspective and our five-year financial and operating information report in April.

Looking ahead to 2005, we expect international financial reporting standard to bring still further changes. All of the changes noted here impact earnings but have no cash effect. Given the pace of change in financial reporting over the next few years, and provide stability through the transition, we will continue to emphasize underlying cash flow and basic performance drivers, such as volumes, operating efficiency and cost. As John mentioned at the beginning of today's call, our long-standing financial framework includes balancing sources and uses of cash over the business cycle. Our 25 to 35 percent gearing band gives us flexibility to sustain our business strategies under a range of market conditions. As shown here, we ended 2004 with 24 percent gearing, up from 23 percent in Q3. Gearing remained under our target band for the entire year. We would expect it to be within the band at year-end due to pension funding, the normal fourth-quarter peak in tax payments and the Slavneft transaction. But as I noted earlier, Slavneft closed in January. We expect strong cash flows in early 2004. In addition to continued favorable energy prices, the fourth quarter German excise tax outflow I mentioned earlier will reverse. And having made significant contributions to strengthen our funded pension schemes in 2003, we intend to follow a regular pattern of funding, under which planned contributions would reduce to about $400 million in 2004. Finally, the $1.4 billion invested for Slavneft in January was more than offset by the $1.65 billion received from the sale of our interest in PetroChina, plus over 700 more from the sale of our Insinopec (ph) shares announced this morning. Given all these factors, we are well positioned to resume share buybacks while keeping gearing in the lower half of our target range. That concludes our prepared remarks. We would now be pleased to take your questions over the phone or the Internet.

(OPERATOR INSTRUCTIONS). Neil Perry, UBS.

I've got two quick questions. One really to Byron, and that is, on that slide you showed about the 4Q versus 4Q E&P results, and you broke down the volume effect and price effect and so forth. The volume effect seems to have been slightly less than the UPS negative, so perhaps slightly less than 100 million, despite the fact that you increased (indiscernible) by about 9 percentage. So you've got about a 2.5 percent uplift in operating income from a 9 percent increase in volumes. Could you comment in a little bit more detail on why that is so small? Secondly, one for John, please -- there has been talk about tax changes in Russia. Could you reflect on what's going on there, particularly in light of the assurances you had from Putey (ph) when you did the deal?

I will take the first question. We have mix effects occurring in the fourth quarter, as a result of the acquisition and divestment activity year-on-year. You will note that we sold a number of North Sea and U.S. assets and counterbalancing that, we have the additional production, primarily from TNK-BP. The net-backs between those two sources are different. We have always noted that TNK-BP would have slightly lower net backs than the rest of our portfolio. So I believe that explains the difference that you are looking for.

Okay. But it shouldn't -- sorry. The difference shouldn't be so substantial in the future, given that you will not be losing UK and U.S. volumes to replace them with Russian volumes in the future?

Correct. We would have a more stable portfolio. So as you look at it quarter-on-quarter in the future, you should not see the sort of change that you're noticing in 4Q.

As to Russia, the first thing that is actually happening is enforcement, that is to say, people are expected to pay the taxes as indicated in the code to date. We have been very uncertain during our ownership of TNK-BP to do just that, and to specifically decline veto any schemes that would be regarded as, in any way on the edge of the law. That is actually what is happening and we've always planned to do that. There has been a lot of talk about taxes. There are, of course, progressive taxes already. That is to say the percentage of tax goes up as the oil price goes up. But what the government will do remains to be seen, I think. Thirdly, there are some cost increases, which I alluded to and so did Byron, primarily tariffs and primarily to do with rail transportation. Some of these are being offset to a degree by the cost and synergy activity we are putting in place. So that I think is the sum and size of the answer I can give you.

Steve Pfeifer, Merrill Lynch.

A have a question related to the BP decision to increase the normalized oil price to $20. Obviously, based on the higher finding and development costs from the majors, as in the case of non-OPEc supply costs. And I actually agree with that. But there are many out there that believe that that type of an oil price would lead to increasing non-OPEC supply and OPEC reducing market share and oil prices ultimately getting back to $16 Brent. How do you respond to that? And specifically when you look at the IA forecast, which I think is faulty, but I would be interested in your view. The IA forecast is forecasting an acceleration in non-OPEC supply in 2004. I would be interested in BP's view on the IA forecast, non-OPEC supply outlook; and perhaps a little more information building on that non-OPEC supply cost curve, which is really I guess predicated on the F&D costs from the majors?

First, I want to separate all the points out if I could. Changing our priming (ph) base from $16 to $20, I don't believe would have any impact at all on the supply from non-OPEC. I think it takes quite a lot more than that, and principally, it is reserves of course that drive it. It's certainly true short-term. If you look at, as I said in my remarks, if you look at '04, there is only I think on consensus forecast, a little bit of room for OPEC to grow between '03 and 04, but only a little bit of room. That's because of decisions which have been made some time ago, actually quite a long time ago, to build up production in Angola and other places around the world, and also, the Russian increases, which in the end, must mitigate as a whole. So I think this is not actually to do with this price. I think in the end, there is a limit to what non-OPEC can do. But decisions have already been made, which I think make OPEC's task of restraining production, which is what they believe their task is, a little bit more difficult as time goes by. Having said that, they have been through periods where it's always been difficult. The last 20 years is a very good reflection of that. The price, I think, has never dropped below 16; and I think the average is more like 21. I think for resource allocation, it's very important to use $20 a barrel to reflect the right balance between the customer facing businesses in the upstream. And I think for financial planning, maintaining a very low gearing -- second half, lower half of our band -- planning at $20, seeing that cash balance price come down after a couple of years, doing stock buybacks when all other things being appropriate, the price of oil is above $20, is, I think, a pretty secure position to take.

I had one follow-up question in terms of the CAPEX outlook. If you do indeed move from 16 Brent to 20 Brent, does that change the attractiveness of the investment places like onshore U.S. or the North Sea, where under a lower price forecast, would be quite difficult to recycle capital there, but at a bit higher price dec. (ph) -- does it make those areas a bit more attractive?

Very marginally, I would say, very, very marginally.

Perhaps we will take a question from the web now. We have Barry Alan. Barry's question is, given the continuing low returns in the chemicals business and the potential of extended higher feedstock prices, can we be more specific as to plans to right-size the business the next five years in order for the segment to earn its cost of capital?

I think if you look at the returns, as I've said over the last five years, they have averaged about 6 percent. Many commentators seem to say that since so few people have put in big investments in petrochemicals, that actually demand and capacity will better meet each other as time goes by. Higher feedstock prices, look to be on the cards at least for a little while, and they will certainly squeeze margins. So we are not going to hang around waiting to be helped by the environment. And what we're doing is we are looking to see how we can really focus on the part of the business, and have actually done really rather well over the last five years compared with those which are rather sluggish, and have taken the returns down. So that is something we're doing at the moment. We are beginning to see that unfold step-by-step. Nothing of that takes away of course from our concentration on operating performance. But this is not something I think we can sit around and just hope for the best on.

Jeremy Elden, Lehman Brothers.

Could you tell us two quick things, firstly on the production level. You have indicated your hopes for production capacity in 2004. Can you tell us what the production capacity as opposed to the actual output was in 2003? Secondly, taking a medium to long-term view, can you give any sense as to how much of your CAPEX or what proportion of your CAPEX you think is underlying, denominated in dollars? I know in the short term it all is, and how much is denominated in other currencies?

My own view of this question of production capacity and production indication is it is simply a question of up-time. And in the upstream or up-time, it is around about 89 percent I think, if I've got the number correct. There is some of that, and that is actually where the production comes out. Capacity is always higher, because we always have little problems with making sure the capacity is filled. But we do have the capacity to be able to produce rather more. I think our -- so that is, I think, our situation. We are trying to improve our up-time, and that is where we are. When we talk about next year, we try and say this is the central estimate of the growth. And you can see that from the actions we are taking. We can answer further questions on that if you would like. To the dollars and Sterling and other currencies?

Our capital program, if we look at 2004 -- and I think it's a pretty typical year, would have about 10 percent of the expenditures in Sterling and about 10 percent of the expenditures Euro-based. So we have 20 percent of capital that is non-dollar-denominated.

Would that apply over the medium-term, once you -- aren't (ph) thinking if you may well have contracts with European-based contractors who signed a contract in dollars, but you know the next one will be for a different amount of dollars if the dollar has moved against the Euro?

If you presume, let's look at the sensitivity of this, if 20 percent of the cost base is non dollar-denominated, a 10 percent move is still only 2 percent of the capital expenditure. So against a $13 billion base you are only talking about $250 million impact, even with the 10 percent currency impact. We hedge as an organization our nondollar exposures net to the group on an annualized basis. So we are protected against any further movements in 2004.

Okay that's great. Thanks.

The only other point I think we would want to make is on the ops. efficiency, as John pointed out, the group averaged 89 percent. But I'm, sure we all noticed that the North Sea numbers, you saw that in the fourth quarter -- production, where it's not as good as we had hoped, in the latter part of '03. So I think there's room to travel on that in '04 and beyond. Moving back to the U.S., we've got a question from Fadel Gheit at Oppenheimer.

I have a question on the DD&A. What is the unit DD&A right now in TNK and BP, as a whole?

The unit DD&A rate for BP -- and remember we have acquisition premium associated with that, is $3.60 in TNK-BP.

And what is for the Company as a whole? I am trying to figure out if BP systemwide DD&A, unit DD&A, is much greater than TNK, and it appears to be much higher than TNK?

The year as a whole is $4.40 for BP overall in E&P.

Did you want to go through that in more detail, because bearing in mind there are of course effects due to acquisition, amortization and goodwill associated with the acquisition of ARCO, we can do that offline. Coming back to Europe, I think, can we take a question from Pascal Akzangang.

I have three quick questions, the first is regarding Russia. Earlier the TNK-BP announced an increase CAPEX plan in 2004 from 1 billion to $1.3 billion with higher production forecast for 2004. That's about 12 percent. and a medium-term target of 6 to 7 percent. Do you confirm this new target, because earlier last year, you said you were looking at 5 percent in the medium-term. Could you tell us, if the 12 percent in 2004 is system able to prediction, or if it is more something opportunistic? (indiscernible), Angola, you announced the (indiscernible). Could you perhaps tell us in how many sites (ph) you forecast the development of (indiscernible), the CAPEX involved and the capacity of the projects? Coming back to the $20 per barrel resource allocation, could you confirm us that it has nothing to do with how you define the absolute level of CAPEX? And that in fact, this $20 per barrel was already being applied when you affected (ph) about 70 percent of your CAPEX in the E&P? The fourth question is regarding Miller, your rights (ph) form impairment on the Miller field in the UK, despite these are gas fields in the UK, does it mean that you're looking to dispose this field?

Let me answer some of those questions, and I think we will get back to you on the more detailed answers. In Russia, these statements made by TNK-BP are all statements made by TNK-BP. What we actually include in our plans is a more conservative approach, to what they're planning to do. We are waiting to make sure that their planning systems mature over time before we're prepared to accept all of the things that they are planning to do. So we certainly confirm that CAPEX will be up a bit in Russia. That's probably a good thing. That's about the future, as well as today. Production, certainly, will be higher, but the level we are assuming is a little but lower than what Russia is planning on. The $20 a barrel -- let me take the next one while I hope Byron will answer the question on Angola and greater Plutonio -- it is not changing the level of CAPEX. Actually as you can see and my remarks I indicated, the level of CAPEX is coming down. It has to do with the phasing of the upfront costs of our new profit centers and actually is due with the investment infrastructure, principally pipelines that we're making at the moment. Our long-run CAPEX for the group should be around 12 to $12.5 billion, which certainly will give us a cash balancing point probably below $20 a barrel. Right now, I think, for the next two years, for financial planning, we are saying we're happy to be balanced at $20 a barrel. This is plenty of headroom as consensus seems to indicate, prices are going to be higher than $20 for us to buy back stock. And we certainly have plenty of debt capacity to see us through an extended period of $16. So that's basically it. And then there are two questions on greater Plutonio and Miller. And Byron can answer those questions.

On greater Plutonio, the project itself is a $1.9 billion project. As far as miller goes, from the tone of your question, I was left with the impression that you thought it was a disposal. But this is a field that we are going to decommission, because there is a gas injection plan that we had previously thought would be successful, but I upon further review, we are not going to progress it.

We will come back to you with more detail if you are interested in terms of what specific assumptions we have made about TNK-BP and Slavneft and what we said about 2004 volumes. Now I would like to go on to the U.S. Fred Leuffer from Bear Stearns.

I have two questions. First, you have the finding and development costs for 2003, excluding acquisitions and divestitures, that are associated with that 122 percent reserve replacement. And secondly, do you care to comment on the growth in underlying production capacity beyond '04?

Byron is preparing to answer the F&D question. Gross underlying production capacity is in line with the indicators we gave you in February '03. We don't see any changes in those whatsoever, out to '07, which is where we gave you the indicators. So nothing has changed at all. What has changed, of course, is the difficulty of actually getting it on a basis which we are now configured, given the acquisitions and divestitures we have made. But the underlying has not changed. And we don't expect that will change either. We will give you a lot more color and detail on that on March 29 of this year.

On F&D costs, they average $6.32 in 2003. I recognize this is a higher number than BP has had in the recent past. But it is reflective that things don't necessarily occur perfectly in a 12 month calendar period. And therefore, the five-year average numbers that John was talking about before, looking across a period of time of $4 to $5, we believe continues to be an appropriate range to project, as you look forward in 2004 and beyond.

Can I confirm that I answered the question on production? Or would you like to know something more about '04?

Well John, I am really thinking about post '04. And again, the problem which you've acknowledged is the change in the base has been so significant and (indiscernible) quarter-by-quarter. What I am really looking for is a growth rate in capacity beyond '04?

I think our quote was that given there is a range -- and I will just say that and caution you there is a range of the number based on the details and indications we gave you -- we said that setting aside the range, this meant a growth rate of around 5 percent between '03 and '07. I think the best way to treat this is to actually look at the detailed buildup we gave you for projects which go in here, principally the new profit centers, all of which through appear to be on track, and the underlying decline in the negative -- the heritage assets, which is pretty well on track.

Irene Himona (ph), Morgan Stanley.

May I ask the, first of all, a quick question on the pension debt. If Byron to clarify for us, where do we stand at the end of '03, is that fully dealt with? And is there any impact looking forward? Next, if I can ask a couple of questions, John please. John, you mentioned that after correcting for the oil price with the 5 percent annual production growth, where actually in the next three years is likely to be flat versus the last three years, despite a 15 percent rise in capital employed. May I ask what percentage of the capital employed was in-service in '03? And how you see that changing in three year's time? My second question, going forward, you will discontinue reporting special separately. You referred to IFRS. Will you continue to report Deraci (ph) on a pro forma basis?

Byron, why don't you handle the first and third of those questions. Can you do that?

Fine. Our funded pensions in the U.S. and the UK are -- they are the biggest ones we have around the world. In the UK, it's more than 100 percent funded. In the U.S., there is still a deficit, but it's a relatively small deficit, and that is the background to the comments that I made, which are that we plan to now begin a very modest regular contribution to our funded plans. The reason why it's not at a surplus position in the United States as well is because of course during the year, interest rates trended down although they went up a bit at the back side of the year. So year-on-year, liabilities increased as a consequence of that. As far as how we're going to show return on capital employed, I would like to -- we will do it on a pro forma basis and the actual mechanics associated with that is something that I will share with you, either in the early part of March when I go through a number of the changes that we will have in our reporting, or I will take you through it in the latter part of March, as part of the lighter analyst presentation. But you will get to actually see it in motion at that time.

I am going to give, probably, more details of this question of capital in service not in service, in March. But let me give you a brief answer now. And we can probably fill it up in a bit more detail with a phone call. Capital not in-service as a percentage of the total capital employed rises. So not only does the capital employed rise, but so does the capital not in-service, at least over '03 to 04. And '03 is higher than '02. As time goes by, this amount drops, so you can see the compensating effects of capital not in service. So we can provide more details in March.

Very approximately, and I think it's 15 percent or so. But as John said, it's something we want to talk about in March the 29th, so it's probably best not to go into any more detail at this point. Staying in the UK, Mark Yassi (ph), Merrill Lynch.

You mentioned in your comments that the SEC had made some inquiries about 2002 reserve exclosures. Can you may be give a little more detail on that? Secondly, Byron can you maybe again comment a little bit more on this German tax situation? Can we confirm that paid tax twice in 2003 in the first quarter and fourth quarter to get this reversal? And can you tell us the order of magnitude of that tax charge, tax payment?

The inquiries from the SEC are by way of routine. On our 2002 Form 20 F, in relation to a shelf debt registration. Normally I think it's the case that the SEC review large corporations on a rotating basis. The last time we were reviewed was three years ago. We answered a variety of questions. all of which we have responded to as a matter of routine.

As far as the excise tax goes, this is nothing new for BP. It's been around since we first had operations in Germany. But it's clearly grown in magnitude as a consequence of the Vaba (ph) transaction. The German authorities collect their excise tax with about a 60-day lag, and this then shortens up the 30 days during the fourth quarter. So what you find is that you have an extra month's payment in the fourth quarter and then, one month's less payment in the first quarter. It's about $1 billion a month, and therefore, it's $1 billion more in 4Q and 1 billion less than average in the first quarter of the year. And that is clearly a major contributor to 4Q, 1Q cash flow as it shows up in our accounts.

Al Anton, Fort Tyler.

A couple questions on your key projects, one, Azerbaijan, you mentioned in the release today that the BTC pipeline is on schedule for the first half of 2005. We hear a lot about environmental concerns and things along the line. Are they pretty well-settled? Are you confident there will be no delays? The second one (indiscernible) a question before on Angola, you've had discoveries on four blocks offshore, two operated and two where you are partners. I wonder if there is any slowdown on the part of the government? There have been reports from time to time that things are pretty slow in approval and so forth. And how do you see that progressing? If you could possibly give us a feel for the oncoming production and how it will build up since that's quite significant in your future plans?

In Azerbaijan, the offshore project is 83 percent complete. And the BTC pipeline is well over half built. And we really do expect it to be commissioned and producing oil to Jahan (ph) in the first half of 2005. The environmental concerns, we are in a lot of discussion about the environment, which has been reflected in the way in which we intend to operate this pipeline, the way in which we are building it, and the enormous number of people who have looked at the processes and procedures we've got in place to make sure that it is environmentally sound. All of these were reflected in the considerations of the IFC (ph) and the EBRD when they have agreed now to finance the pipeline. And all of that is completed. So that that provides financing for the state interest involved in building the pipeline. So I think all of that is now past us. And we are proceeding with construction of the pipeline with diligent haste.

Angola, I think that there is a lot of discoveries in Angola, first of all. As I've remarked in my remarks, even last year, we discovered significant quantities in Block 31, as well as the three blocks under development 15, 17 and 18. One, I think, has to take a prudent view as to the rate at which the government will be able to handle the proposals in front of them. And that's exactly what we are doing. And indeed, there is a very cautious approach, I think, in making sure that the fields are developed carefully and everything is scrutinized. We have actually got authorization today to contract our Block 18 greater Plutonio, and that is all approved today.

But going forward, I think we should expect a measured pace. We have, in course, to sort out the problem of associated gas and to resolve finally with the Angola government, how that will be collected and how it will be preserved as a valuable commodity for the Angola government, probably through an LNG scheme. So all of these things, I think, will take time, and certainly, in our consideration of what's going on in production, we are certainly taking quite a cautious view on the rate of which things will be approved.

Neil McMann, Sanford Bernstein.

First of all, I think I speak for many people who would like to see more visibility when it comes to your reoccurring one-off items that seem to crop up in the numbers, either as costs or specials. Maybe if you could talk through your guidance from the numbers you reported in 2003 to see, should we be backing in any of those one-offs into reoccurring costs in 2004? That's the first point. The second one is, your change in accounting, does that mean that pro forma accounting is going to go pretty soon? And have you considered just taking -- writing off the goodwill and getting back to a clean basis? And the third point is, could you give us any guidance around the major projects which are coming on in 2004, roughly around the timing of when they are going to appear after the year?

We are certainly sympathetic to your desire to be able to segment out things that are once-off and things that are recurring. And that will be part of what we attempt to provide you, as part of this movement to eliminate specials because on the margin, it's increasingly difficult to segment out those things that are 100 percent once-off from those things that occur periodically. We are toying with various ways in which we can provide you a clear layout for your analysis. As far as pro forma goes, we will continue to report with the acquisition premium that we paid for Burmah Castrol and ARCO, eliminated from the results, on the basis that that allows the comparability with our major competitors. If IFRS comes in and provides a vehicle to allow clear comparability without that, then we will adjust accordingly. But at this stage, since those standards are not 100 percent clear, it is our intention to continue along the pro forma line that I indicated in my response to an earlier question.

The major part that's coming on stream in '04 is as follows -- our expectations, Holstein (ph) in the Gulf of Mexico in the fourth quarter; to Zamba (ph) A in Angola in the fourth quarter; in Salah, and this is in Algeria; and Northresh (ph) Shelf Train (ph) 4, both in the fourth quarter; and Claire (ph), which is part of the UK North Sea, also in the fourth quarter.

Maybe one further things, on the one-offs. Would you consider 2003 a normal year? And maybe just the various points throughout 2003 that would not made it a normal year, just thinking going forward?

The increase in depreciation will be with us going forward. The higher pensions and benefit costs that we have seen will be with us going forward. And in fact, we would expect yet another increment on that in the coming -- in 2004. The things that we have labeled as specifically as once-offs indeed are once-offs. And as far as foreign exchange, which was one of the other elements I described, this is really up to you to decide whether or not the dollar is going to recover or weaken from where it is today. If it continues to weaken, then there will be some incremental costs associated with it. But as I related in my remarks, we do have a natural hedge here. So to the extent that there are adverse effects, they tend to be noncash charges as opposed to reflected in the underlying ability of the firm to generate cash.

I would just like to comment and say I think there were a lot of very unusual effects in '03, some of which will still continue in '04 but not beyond. Plus I think the weighted divestments that we have made this year is not something that you should expect us to do again. Secondly, there have obviously been these very large swings in foreign exchange. Thirdly, capital built up and it is still not in service. And this is the push that we are trying to make to make sure that we get all these projects an on time, so that all of this capital which is laid in, begins actually to produce. We're going through this period where we are determined to make this happen, but it's not actually happened yet. So there are a lot of things I think which are slightly unusual in addition to the funding that we have made for the pension fund, which I don't believe will be reoccurring -- primarily resulted from the withdraw of capital amounts in our U.S. fund. Of course, it was it was very beneficial for beneficiaries to do this, where they worked with actually a very low discount rate. The actual discount rate that they could withdraw funds from the pension fund from, under the contracts we've had with heritage members of our company, was far lower than the discount rate that we actually have to use to capitalize the funds. So it was very beneficial for them to draw out the lump sums to generate annuity. I don't expect that's going to happen again either.

Great. Just seeing that OPEC has cut production again. Will that influence your production in the first few quarters of the year?

It won't affect our production that much. I don't know quite what is going to happen to our productions from Edward Duffy, which is one of our OPEC sources; it is pretty well the only one. So that may be up and down but let's see. And of course, the price remains high, then there is a little bit of an impact, not huge for BP, but it's just enough to be annoying, of high prices reducing production from PSCs. But overall, of course, it will make sure that cash flows remain very strong, and that's a good thing.

Bert Van Hougenheiser, Bank Survey.

Most of my questions have been answered. A few remain. I understand you come back on the reserve replacement medium-term in March. But could you still give us some sort of inkling, given your current production outlook, what sort of bandwidth you expect within the next four or five years? Secondly is a follow-up on the pension question. Is it right to assume that your total pension charge on the P&L will sort of level out between somewhat more in the U.S. and somewhat less in the UK? And finally, in view of the fact that you had seven of the last eight quarters in the UK, an underlying loss in the refining and marting (ph), which I suppose is a marketing issue, what sort of remedies do you foresee? How do you envisage your strategy to go forward there?

I will ask Byron to talk about the pension charge if he could, please.

The P&L impact, as I mentioned earlier, will be negative on a year-on-year basis. The charges will be going up. A lot of it is driven by interest rates. But the charges will be going up year-on-year on both the methodology that we have been using, as well as on an FRS-17 basis. If I look year-to-year, even with the transition, they will go up. I will provide more information about that during the course of our investor presentation in March. But order of magnitude, you should expect charges to be up $1 to $200 million year-on-year.

We will talk more about reserves, because we can bend the numbers around on reserves from replacement. My view, based on our advise from the E&P people, is that reserves replacement will exceed 100 percent, excluding the replacement that we may say in TNK-BP. We haven't actually factored anything in for that yet. And I think we want to see how that develops. The UK side is complicated. There are costs of course for headquarters and things like that in the UK numbers. It also includes the acquisition amortization of Castrol as well. Actually, the refining and marketing business in the UK is going very much better. We've taken a very strong approach in reorganizing in particular the retail business, reducing its costs, changing the format of our offer, and adding new products. And that's had quite a big turnaround year-on-year. Maybe this is something we should be more transparent about. And we will certainly take that and think about it.

Can I come back to my answer. My answer is correct, but it's speaking to the change from one pension's accounting methodology to another. And recognizing the confusion that all this is likely to provide, I will take people through this during the course of the discussion that is scheduled in early March. You will be able to see just how things are falling through with respect to the conversion to FRS-17.

J.J. Traynor, Deutsche Bank.

A couple of questions, firstly, with respect to the dividend policy, you used to describe the dividends as a function of earnings as they would be around $16 oil prices. I wondered, in light of your shift in (indiscernible) oil prices, could you just make some comments on what the dividend policy actually is now? A year ago, you described a set of projects that earned mid teens returns at mid teens oil prices; is that still the right analysis? Do you think it's possible to find projects of that sort of profitability again in the future? That question really is with regards to the world outside of Russia.

I think our dividend policy pretty well is unchanged. I said I think, and I am not quoting from any document of the board, look at earnings in the past, earnings in the future and sustainable earnings based on our analysis of what underlying earnings are. We're very reluctant to go through that in detail, because it's a very internal calculation. Basically, JJ, I think, think about the $20 business as this. First, actually, it's the price which is the average, and we think it's a sound price to plan on. But actually for internal calculation purposes, while we may have put the price of oil up, we've actually reflected very much more on our present experience on differentials. So we have said for internal purposes, we think differentials will stay as they are today, even though the price of oil will drop it. We have also reflected on the present state of petrochemicals, not only in an imaginary state, which might be better in the future. And we've also reflected on today's understanding of pensions and benefits with the increases in medical costs in the U.S. and so forth, all of which are big factors. When you put all that in, that's actually the way we think about it. So the dividend policy has not changed. The Board will look at the calculations on underlying earnings and factor that into their consideration. It's a judgmental, it's not a calculation call.

As to mid teens returns at mid teens prices, again, I think these will be available, but only if and only if I think the best hydrocarbon deposits are worked on. Right now, I think we're building these new basins -- Angola, Azerbaijan, still in the Gulf of Mexico, I think we'll find that incremental projects around those will still have good returns of this nature. As indeed, some of the principal projects have very strong returns even at very, very low oil prices. There is no reason I think to change our view that if you look at it over the last 30 years, the range of returns you get from Halasco (ph) in the North sea, still in aggregate per basin, are available for the basins that we are in, excluding Russia.

Just to go back a touch on the dividend there, I appreciate you don't want to share the calculations with us. But previously, a proportion of earnings is $16. Now a proportion of earnings is $20. What does that mean to the payout ratio in that calculation?

I think the Board is quite satisfied that the payout ratio is appropriate in that calculation, which is around 60 percent.

Right.

John Wright, Citigroup.

A couple of questions, first of all you have given some indications for 2004 volumes. Can you say if that includes Slavneft? And if it does, at what level? Secondly, you've highlighted the startup of Holstein and expect it in Q4. Could you give us an update on the other three deepwater projects, how they are progressing and when the startup dates are expected?

I will certainly give an update on the other projects for '05 in a moment. In our guidance for production in '04, we have presumed that Slavneft is going to produce at 75,000 barrels a day on average, our share of it, for the year as a whole. So that's what we have added into our calculation. The project, as we go forward, will take a little while to talk about. The bottom line is eventually there is no change from what we said in February '03. Most of that, of course, is on track for our end of '04 startup, and that is working well. The rest of the discoveries in the Gulf of Mexico begin in '05. So Thunder Horse begins then. Mad Dog is expected early '05, Atlantis (ph) will be in the middle of '06. So that is the Gulf of Mexico. I could carry on around the world. But I have a feeling that we will do this at another time.

The plan actually John is after the March 29 strategy update, we'll update that list of major projects that we shared with you in February 2003. So you'll have full details at that point.

Colin Smith, CSFB.

Most of my questions have been answered, but a quick one, can you put some quantities around what share buybacks you might expect to buy? And if you are looking for an oil price, why don't we take $25 a per barrel across the year?

I am going to leave you to do that, Colin, if you don't mind. I think we are going to be very strict with ourselves. We are going to report stock buybacks after the fact not before the fact. And I think our guidance, as best as we can give you, which is when the price of oil is over $20, all other things being appropriate, you should see us buy back stock.

Could I ask a slightly different question then? Would you expect to at least neutralize the amount of stock issuance you get on the next tranche of the TNK-BP payment?

It very much depends on the price of oil as we go forward. One of the reasons -- there were many reasons that we made the consideration to do it part cash and part shares, part of which is that was the only way to do the deal. We wanted to make sure we retained some hold over our consideration for a little while. But also, it does risk hedge if the price of oil went down dramatically, which we don't think it will. But that was a minor consideration in our heads there. So I would expect if the price of oil is appropriate, naturally we will be taking the -- we will offsetting the dilution for those shares.

One follow-up on that. You've obviously just achieved a fair degree of disposals from your trainees' (ph) interests. You wouldn't care to be a little bit more firm about neutralizing stock issuance in that context?

I'm sorry, I think I've said everything I can say.

Ron Oster, AG Edwards.

To clarify on the onetime items that you covered on the upstream that were not categorized as the special items, I believe the total was 550 million. Could you clarify if that was pretax or after-tax? And secondly, you mentioned synergies associated with TNK-BP will partially offset higher transportation costs. Has this changed your view of the accretiveness of the deal? And if you could give us an update there? Finally, if you could give us any further clarification on timing issues associated with this year's high F&D costs, if you might tell us what projects had an impact on that number?

I could start off by clarifying the point about the unusual elements in the fourth quarter upstream results. Those numbers were all described on a pre-income tax basis. They are laid out in the slide that is in Byron's presentation. I will be happy to go through the numbers with you if you want to do that, we can do that off the line. They are on the slide. They are on a pretax basis.

The F&D costs obviously are quite high because of two things. One is CAPEX is quite high, even in the exploration and development part of the CAPEX. And secondly -- and that's naturally what's controlling it. The five year backward looking rolling average was $4.10.

My other question was regarding the accretiveness of the TNK-BP joint venture?

I said in my remarks that it was accretive, and it would be accretive even if we took all of the capital, including the deferred consideration and applied it to the earnings. So it shins the bar every which way you look.

Tim Whitaker, Lehman Brothers.

I have a question about your reserves portfolio. Could you confirm whether you have any uncontracted gas reserves booked outside the U.S. or the UK? And if so, which fields they are? Also, in light of your booking policy related to sanction, could you say which unsanctioned projects are currently booked and what proportion of total reserves they are?

On the second point, I think to the best of my knowledge, we don't have any unsanctioned projects booked at this moment in time. So that is that. On gas, I think the only exception is -- I am trying to think, I can't actually think of an exception. We can certainly get back to you. We have contracted those gas reserves that we have -- have been contracted, except of course, the Trinidad, which we regard as really part of the U.S. market. It being (ph) so approximate at (ph) its (ph) LNG to the U.S. market.

Could I ask one more question? You've talked about the oil price at $20 as sort of a point oil price. But could you discuss how you treat to look forward the dollar exchange rate in your assumptions?

Forecasting exchange rates is very dangerous. I mean we try and use for planning purposes, a steady exchange rate, which is based on our view of purchasing parity, basically.

If I can add, as a group, our ability to generate cash is not influenced materially by changes in the exchange rate. And I spoke to our capital spending, which was also primarily dollar-denominated. So as a dollar based company, with very limited foreign exchange exposures, you should presume that it has only a very, very minor impact on our overall financial framework.

So when you have a funding (ph) cost this year of $6.30, and you say your long run expectation is 4 to $5 per barrel, you're not presuming any movement in the exchange rate from current levels to achieve that?

There would be --

I think this is -- I see what you're trying to say. We take -- it's basically assuming -- if it's a five-year rolling average, then it's a five-year rolling exchange rate. That's really what it is.

Finally, I think in the UK, Jason Kenney.

You highlighted around 18 percent of BP's Q4 production came from Russia. Is it possible to highlight the percent contribution from to other key profit centers, namely, Trinidad and the U.S. deep water?

We do have those numbers. They actually will of course be published in our Athland (ph) OI. I think probably the best thing is we need to call you back on that one. I will do that later on this afternoon.

Right, well it's been a long conference call, but I know there has been a lot to talk about. I think we will call it a day there. I think we have taken all the questions. As usual, the investor relations team is ready to answer your questions at any time, so please do call us or drop us an e-mail.

Thank you very much ladies and gentlemen. We will see you soon.