Oct 04 - 3rd Quarter O4 Results

Source Press Release
Company Royal Dutch Shell 
Tags Financial & Operating Data
Date October 06, 2004
THIRD QUARTER  $ million  NINE MONTHS 
2004  2003  %     2004  2003  %  
  As restated        As restated   
5,397  2,453  +120   Net income *  14,058  10,579  +33  
990   (140)    Estimated current cost of supplies (CCS) adjustment for Oil Products segment - see note 2  1,594   (522)   
4,407  2,593  +70   CCS earnings *  12,464  11,101  +12  
-   -   

* includes:

Special credits/(charges) – see note 3

 
-   1,036   
-   -    Asset retirement obligations – see note 1  -   255   
THIRD QUARTER    NINE MONTHS 
2004  2003      2004  2003   
  As restated    Summary indicators    As restated   
6,241  5,177    Cash from operations ($ million)  18,851  17,290   
7,508  4,594    Cash from operations excluding working capital movements ($ million)  20,464  15,923   
3,507  3,638    Capital investment ($ million)  9,810  9,777   
      Return on Average Capital Employed on a Net income basis (%) – see note 4  17.4%  15.6%   
3,608  3,666    Upstream production (thousand boe/d)  3,749  3,876   
      Segment earnings($ million)       
2,405  2,039    Exploration and Production  7,086  7,053   
272  65    Gas & Power  1,135  2,023   
1,555  880    Oil Products (CCS basis)  4,233  2,911   
577  30    Chemicals  1,130  145   
(402)  (421)    Other segments/Corporate/Minority Interests  (1,120)  (1,031)   

On a net income basis, Royal Dutch basic earnings per share (EPS) were euro 1.31 ($1.60), and Shell Transport basic EPS were 12.5p. On a CCS basis, Royal Dutch basic EPS were euro 1.07 ($1.31) and Shell Transport basic EPS were 10.2p.

  The earnings in the third quarter 2004 contained the following items over $50 million:

  • Exploration and Production results included a $183 million charge related to the mark-to-market valuation of certain UK gas contracts.
  • In Oil Products divestment gains of some $131 million were partly offset by other net charges resulting in a total gain of $50 million

Key features of the third quarter 2004 and reserves update

Record net income and strong earnings and cash generation reflect high hydrocarbon price realisations and strong margins and asset utilisation in Oil Products and Chemicals. Oil and gas prices increased but the quarter saw crude differentials widening. Hydrocarbon production year on year was unchanged after taking into account divestments, and LNG volumes continued to grow. Gross divestment proceeds for 2004 are expected to exceed $4.8 billion.

 The outlook for 2004 production (3.7-3.8 million boe/d) and 2004-2006 gross divestment proceeds ($10-$12 billion) is unchanged. Capital investment expectation for 2004 is lowered to around $14 billion. The company has also provided an update on reserves.

 Jeroen van der Veer, Chief Executive, said: “These are again satisfactory results, and I am pleased with the progress we're making. I am of course disappointed that the more rigorous review and audit process we have put in place has identified potential proved reserves reductions. In the face of significant changes, I am committed to delivering competitive performance, and our executive committee is clearly focused on the many challenges ahead.”

  • Reported net income of $5,397 million was more than double the earnings in the same period last year.
  • The Group’s CCS earnings (i.e. on an estimated current cost of supplies basis for the Oil Products segment earnings) for the quarter of $4,407 million were 70% higher than the same period last year. Earnings reflected higher hydrocarbon realisations, strong LNG and Gas-to-Liquids earnings offset by lower other income in Gas & Power, and higher Downstream earnings in Oil Products and Chemicals.
  • Exploration and Production segment earnings of $2,405 million were 18% higher than a year ago. Earnings included a $183 million charge related to the mark-to-market valuation of certain long-term UK gas supply contracts. Higher oil realisations (39%) and gas realisations (7%) were partly offset by the impact of hurricanes in the Gulf of Mexico and higher costs.
  • Hydrocarbon production was 3,608 thousand barrels oil equivalent (boe) per day. Excluding the impact of divestments of 63 thousand boe per day, total production was unchanged versus the same quarter last year. Production for 2004 is expected to be 3.7 to 3.8 million boe per day subject to price effects on production entitlements and the restart of shut-in Gulf of Mexico production.
  • The Group remains reasonably confident of achieving 100% SEC proved reserves replacement over the next 5 years (2004 to 2008 averaged). Since completion of the 2003 Annual Reports and Accounts and as previously announced, the Group has followed through on its plans to launch an extensive and detailed programme of audit and assurance related to SEC proved reserves. This includes professional staff retraining (involving some 3000 Shell and joint venture staff) and use of external reserves experts in the reserves auditing process. The Group also has greatly increased its proved reserve audit resource and the depth of reserve audits. Implementation of these enhanced reserves audit procedures is underway in preparation for publication of its 2004 Annual Reports and Accounts and the Group has now conducted audits of approximately 8 billion barrels of oil equivalent (boe) of the Group’s reported proved reserves of 14.35 billion boe at 31 December 2003. Preliminary reports from the field and audit teams suggest that reductions to Shell’s 31 December 2003 proved reserves are likely to be appropriate. At this point, the amounts and timings of the adjustments are part of the ongoing review process, which includes further assessment and challenge by relevant operational teams, the reserves committee, the executive committee and the Group Audit Committee to arrive at a conclusion. The volume adjustment currently under consideration is approximately 900 million boe. The definitive figures, including the related impact on reserve replacement ratios, standardised measure of discounted cash flows and financial statements, will be provided upon completion of the annual process in early 2005.
  • Gas & Power segment earnings were $272 million compared to $65 million a year ago, which included net charges of some $230 million. Earnings reflected LNG volume growth and higher prices, and higher Gas-to-Liquids performance, offset by lower Marketing and Trading earnings.
  • Oil Products CCS segment earnings were $1,555 million compared to $880 million a year ago. Earnings reflected increased refining intake and higher global refining margins partly offset by lower marketing earnings mainly due to weaker market conditions in the USA.
  • Chemicals segment earnings were $577 million compared to $30 million the same quarter last year. Earnings benefited from volume growth, improved operating rates and higher margins.
  • For the quarter cash flow from operating activities was $6.2 billion inclusive of a working capital increase of almost $1.3 billion. This cash, together with divestment proceeds ($0.8 billion), was mainly used for capital expenditure of $3.0 billion and distributions to Parent Companies of $3.9 billion to fund dividends and share buy backs. Cash and cash equivalents rose by $0.2 billion and debt increased by $0.3 billion.
  • At the end of the quarter the debt ratio was 16.3% compared to 22.1% a year ago; cash and cash equivalents amounted to $2.6 billion.
  • Capital investment for the quarter was $3.1 billion, excluding the minority share in Sakhalin of $0.4 billion, versus $3.4 billion a year ago. Year to date capital investment was $8.7 billion excluding the minority share of Sakhalin of $1.1 billion.
  • Gross proceeds from divestments for the quarter were $0.8 billion and comprised various items including the divestment of downstream assets in Japan and Malaysia. Year to date proceeds total $2.8 billion. Further proceeds of some $2 billion, are expected to be received later this year depending on the timing of regulatory approvals.
  • $3.0 billion dividends were paid to shareholders during the quarter. Royal Dutch and Shell Transport continued their share buy back programmes for the year. Shares purchases for cancellation and to underpin the employee share option schemes were made for a combined total of $1.0 billion in the quarter, bringing the year to date total to $1.7 billion.

Group investments and portfolio developments

Upstream portfolio developments were:

Additional oil sands acreage was acquired in Canada and exploration acreage was expanded through new license awards in the UK, Brazil and the Gulf of Mexico. Exploration discoveries were made in Russia, Gabon, Brunei and Malaysia, with successful appraisals in Kazakhstan, Malaysia and the Gulf of Mexico.

Progress continues with the unconventional resources portfolio in North America. Shell Canada outlined the growth plans for Athabasca Oil Sands (Shell Canada share 60%), expecting to increase production to between 270,000 and 290,000 barrels per day by 2010.

In Malaysia gas production started in the Jintan field (Shell share 37.5%), offshore Sarawak. First oil production from the Glider field (Shell share 75%) in the Gulf of Mexico was announced in the quarter. Glider is a subsea tieback to the Brutus production platform. In October, the commencement of gas production from the Goldeneye gas condensate field (Shell share 49%) in the North Sea was announced.

Building the integrated gas portfolio, Nigeria LNG Ltd (NLNG), Shell share 26%, took the final investment decision for LNG train 6 with expected start up in 2007 and a capacity of 4 million tonnes per annum (mtpa). Shell has purchased 3 mtpa of LNG from train 6 to supply North American and European markets. Total NLNG capacity will be 22 mtpa of LNG and 5 mtpa of natural gas liquids and the Shell upstream joint venture in Nigeria will in total supply some 1,900 million standard cubic feet per day (Shell share 30%) of gas to NLNG.

The Australian North West Shelf LNG (NWS) venture (Shell share 22%), started production from LNG train 4 (capacity 4.2 mtpa) bringing NWS operational capacity to 12 mtpa of LNG and some 5 mtpa of natural gas liquids. NWS signed an LNG supply agreement with Kansai Electric Power Company of Japan for 0.5 mtpa starting in 2009, increasing to some 0.9 mtpa in 2015, through 2023. In Oman Shell has taken an 11% indirect interest in the Qalhat LNG project with a capacity of 3.3 mtpa to start up around end 2005.

In October, Shell signed an agreement with Sempra for 50% of the capacity of a new LNG import terminal in Baja California, Mexico. The terminal will have a capacity of 1 billion cubic feet of gas per day (7.5 mtpa LNG) and is expected to become operational in 2008. Shell also holds rights to 50% of any future capacity expansions. Through this capacity Shell will supply gas to Mexican and US markets partly from the Sakhalin II LNG project (Shell share 55%) in Russia through a supply agreement for 37 million tonnes of LNG over a 20-year period starting in 2008.

Shell agreed the sale of its 16.67% interest in gas wholesale and transmission companies Distrigas SA and  Fluxys SA in Belgium, which is expected to close in the fourth quarter 2004 and divested from the German utility company Avacon AG.

Downstream continued implementation of the Group’s strategy for reshaping the portfolio.

Shell and BASF announced the review of strategic alternatives regarding their polyolefins joint venture Basell (Shell share 50%). The options being reviewed by the shareholders include the sale of their stakes and an equity market transaction.

Shell commenced a review of strategic options for its Liquid Petroleum Gas (LPG) distribution and marketing business. The process is at a very preliminary stage.

A conditional sales agreement was signed for Shell’s entire 64% interest in the Rayong refinery in Thailand, and is expected to close in the fourth quarter eliminating the Group’s consolidated debt for this refinery.

The sale of part of Shell’s interest in Showa Shell Sekiyu K.K in Japan to  Saudi Aramco was completed during the quarter reducing the interest from 50% to about 40%. Arrangements are in place for  Saudi Aramco to acquire an additional 5% from Shell subject to certain conditions.

The retail and commercial businesses in Peru were sold and, in Malaysia, Shell completed the sale of about one third of its holdings in a refining company (remaining Shell share 51%). A sale agreement was signed for the retail and commercial fuels businesses in Spain, which is expected to complete in the fourth quarter.

In October the sale of the Mid-Continent and Mid-West refined products pipeline systems as well as the retail and commercial fuels business in Portugal were completed.

Restructuring of the retail network in the USA and Europe progressed. From the start of the program, a total of 5,800 sites have been rebranded from Texaco to Shell in the USA and some 5,300 Shell sites re-imaged. This reflects completion of some 90% of the program.

Earnings by segment 

Exploration and Production

THIRD QUARTER  $ million  NINE MONTHS 
2004  2003  %     2004  2003  %  
  As restated        As restated   
2,405  2,039  +18   Segment earnings *  7,086  7,053   
     

* includes:

Asset retirement obligations - see note 1

 
  255   
2,279  2,393  -5   Crude oil production (thousand b/d)  2,283  2,380  -4  
7,706  7,379  +4   Natural gas production available for sale (million scf/d)  8,505  8,676  -2  

Third quartersegment earnings of $2,405 million were 18% higher than a year ago. Earnings included a $183 million charge related to the mark-to-market valuations of certain long-term UK gas supply contracts. 

Earnings benefited from the impact of higher hydrocarbon prices, partly offset by an increase in effective tax and royalties as well as the impact of hurricanes in the Gulf of Mexico. Earnings were further impacted by increases in costs from a weaker US dollar, higher depreciation rates and higher production costs. 

Liquids realisations were 39% higher than last year versus an increase in both Brent and WTI of around 45%. Gas realisations in the USA increased by 20% versus an increase in Henry Hub of 12%. Outside the USA gas realisations rose by 5%. 

The increase in the effective tax rate is mainly driven by the impact of higher oil and gas prices on certain production contracts, various net tax credits a year ago and an increase in the tax burden in Denmark. At current prices, and relative to the same period a year ago, the overall impact of the changes in Denmark is a charge to earnings of some $250 million for the quarter. 

Hurricanes in the Gulf of Mexico have caused production downtime and damaged some offshore facilities. The estimated impact on Exploration and Production earnings from the cost of repairs in the third quarter is some $20 million. 

Hydrocarbon production was 3,608 thousand boe per day. Excluding the impact of divestments of 63 thousand boe per day, total hydrocarbon production was unchanged versus the same quarter last year. 

Production benefited from new fields mainly in the USA, Malaysia and the UK as well as the ramp-up of fields mainly in Brazil and Canada, totalling approximately 210 thousand boe per day compared to a year ago. These were offset by some 180 thousand boe per day due to field declines, mainly in the USA, North Sea and Oman. Further decreases in production were caused by hurricanes in the Gulf of Mexico (54 thousand boe per day) and shut downs in the North Sea (58 thousand boe per day) compared to a year ago. 
  Capital investment of $2.1 billion, excluding the minority share of Sakhalin, was similar to a year ago and included exploration expense of $0.3 billion.

Gas and Power:

THIRD QUARTER  $ million  NINE MONTHS 
2004  2003  %     2004  2003  %  
272  65  +318   Segment earnings *  1,135  2,023  -44  
-   -   

* includes:

Special credits/(charges) – see note 3

 
-   1,036   
2.44  2.31  +6   Equity LNG sales volume (million tonnes)  7.39  6.86    +8  

Third quartersegment earnings of $272 million compared with earnings of $65 million, including net charges of some $230 million a year ago. LNG earnings reflected 6% growth in volumes, including the Malaysia Tiga LNG volume ramp up and Nigeria LNG Train 3 now operating at plateau, and higher realised LNG prices. Earnings from the Gas-to-Liquids plant in Malaysia were also higher due to higher prices and volumes following debottlenecking and high availability. These were offset by lower Marketing and Trading earnings.

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