Edgar Filing: BHP BILLITON LTD

Year ended June 30,

(‘000 carats)

Diamonds

EKATI Diamond Mine (Canada)

Form 20-F

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.

FORM 20-F

(Mark One)

¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED JUNE 30, 2003

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES AND EXCHANGE ACT OF 1934

Commission file number: 001-09526		Commission file number: 001-31714

BHP BILLITON LIMITED (ABN 49 004 028 077)		BHP BILLITON PLC (REG NO. 3106209)
(Exact name of Registrant as specified in its charter)		(Exact name of Registrant as specified in its charter)

VICTORIA, AUSTRALIA		ENGLAND AND WALES
(Jurisdiction of incorporation or organisation)		(Jurisdiction of incorporation or organisation)

180 LONSDALE STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA		NEATHOUSE PLACE, VICTORIA, LONDON, UNITED KINGDOM
(Address of principal executive offices)		(Address of principal executive offices)

Securities registered or to be registered

pursuant to section 12 (b) of the Act.

Title of each class	Name of each exchange on which registered	Title of each class	Name of each exchange on which registered
American Depositary Shares*	New York Stock Exchange	American Depositary Shares*	New York Stock Exchange

Ordinary Shares**	New York Stock Exchange	Ordinary Shares, nominal value US$0.50 each**	New York Stock Exchange

*	Evidenced by American Depositary Receipts. Each American Depositary Receipt represents two ordinary shares of BHP Billiton Limited or BHP Billiton Plc, as the case may be.

**	Not for trading, but only in connection with the listing of the applicable American Depositary Shares.

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

		BHP Billiton Limited		BHP Billiton Plc
Fully Paid Ordinary Shares		3,747,687,775		2,468,147,002

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No ¨

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 ¨ Item 18 x

CONTENTS

		Page
FORWARD LOOKING STATEMENTS		3
GLOSSARY OF TERMS		4
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	7
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	8
ITEM 3.	KEY INFORMATION	9
ITEM 4.	INFORMATION ON THE COMPANY	17
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	96
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	124
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	153
ITEM 8.	FINANCIAL INFORMATION	155
ITEM 9.	THE OFFER AND LISTING	158
ITEM 10.	ADDITIONAL INFORMATION	161
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	173
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	173
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	174
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	174
ITEM 15.	CONTROLS AND PROCEDURES	174
ITEM 16.	AUDIT COMMITTEE FINANCIAL EXPERT, CODE OF ETHICS AND PRINCIPAL ACCOUNTANT FEES AND SERVICES	174
ITEM 17.	FINANCIAL STATEMENTS	175
ITEM 18.	FINANCIAL STATEMENTS	175
ITEM 19.	EXHIBITS	175

In this annual report, the terms we, our, us, BHP Billiton and BHP Billiton Group refer to BHP Billiton Limited and BHP Billiton Plc, together with their respective subsidiaries. BHP Billiton Plc Group refers to the group that is BHP Billiton Plc and its subsidiary companies. BHP Billiton Limited Group refers to the group that is BHP Billiton Limited and its subsidiary companies. BHP Billiton Plc refers to the parent entity that was formerly Billiton Plc before the implementation of the DLC structure and BHP Billiton Limited refers to the parent entity that was formerly BHP Limited before the DLC structure.

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FORWARD LOOKING STATEMENTS

This annual report contains forward-looking statements, including statements regarding:

•

estimated reserves;

•

plans, strategies and objectives of management;

•

closure or divestment of certain operations or facilities (including associated costs);

•

anticipated production or construction commencement dates;

•

expected costs or production output;

•

the anticipated productive lives of projects, mines and facilities;

•

contingent liabilities; and

•

the combination of the operations of BHP Billiton Plc and BHP Billiton Limited through the implementation of the DLC structure.

These forward-looking statements are not guarantees or predictions of future performance, and involve known and unknown risks, uncertainties and other factors, many of which are beyond our control, and which may cause actual results to differ materially from those expressed in the statements contained in this annual report.

For example, our future revenues from our operations, projects or mines described in this annual report will be based, in part, upon the market price of the minerals, metals or petroleum produced, which may vary significantly from current levels. These variations, if materially adverse, may affect the timing of the feasibility of the development of a particular project, or the expansion of certain facilities or mines. Other factors that may affect the actual construction or production commencement dates, costs or production output and anticipated lives of operations, mines or facilities include our ability to profitably produce and transport the minerals, petroleum and/or metals extracted to applicable markets, the impact of foreign currency exchange rates on the market prices of the minerals, petroleum or metals we produce, activities of government authorities in certain of the countries where we are exploring or developing these projects, facilities or mines, including increases in taxes, changes in environmental and other regulations and political uncertainty and other factors identified in the desciption of the risk factors in Item 3D. We cannot assure you that our estimated economically recoverable reserve figures, closure or divestment of such operations or facilities, including associated costs, actual production or commencement dates, cost or production output, or anticipated lives of the projects, mines and facilities discussed in this annual report will not differ materially from the statements contained in this annual report.

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GLOSSARY OF TERMS

Technical Terms

In the context of ADSs and listed investments, the term “quoted” means “traded” on the relevant exchange.

We refer in this annual report to tonnes, each of which equals 1000 kilograms, approximately 2,205 pounds or 1.102 short tons. Measures of distance referred to in this annual report are stated in kilometres, each of which equals approximately 0.62 miles, or in metres, each of which equals approximately 3.28 feet.

ADS means American Depositary Share

Brownfield project means the expansion of an existing operation.

Coal Reserves has the same meaning as ore reserves, but specifically concern coal.

Coking Coal, by virtue of its carbonisation properties, is used in the manufacture of coke, which is used in the steelmaking process.

Crude oil is a mixture of hydrocarbons that exist in liquid form in natural underground reservoirs, and remain liquid at atmospheric pressure after being produced at the well head and passing through surface separating facilities.

Condensate is a mixture of hydrocarbons which exist in gaseous form in natural underground reservoirs, but which condense to form a liquid at atmospheric conditions.

Direct reduced iron (DRI) is metallic iron formed by removing oxygen from iron ore without the formation of, or passage through, a smelting phase. DRI can be used as feedstock for steel production.

DLC merger means the merger between BHP Billiton Limited and BHP Billiton Plc, on June 29, 2001.

Dry gas is a mixture of hydrocarbon gases, inerts and other gases that are in the gaseous phase at pipeline conditions with no free liquids at operating conditions. It is principally composed of methane, ethane and low levels of propanes and butanes depending upon processing and pipeline specifications.

Energy coal is used as a fuel source in electrical power generation, cement manufacture and various industrial applications. Energy coal may also be referred to as steam or thermal coal.

Ethane, where sold separately, is largely ethane gas that has been liquified through pressurisation. One tonne of ethane is approximately equivalent to 26.8 thousand cubic feet of gas.

Federal unit is a combination of two or more US Minerals Management Service (“MMS”) defined blocks approved by MMS in circumstances where it can be demonstrated that the blocks are part of the same geological formation.

Green field project means the development of a new project.

Gigajoules = 1,000,000,000 joules (where joules is a measure of energy).

Heap leaching is the process by which a soluble mineral can be economically recovered by dissolution from ore piled in a heap.

Hot briquetted iron (HBI) is densified direct reduced iron where the densification is carried out at a temperature greater than 650 degrees Celsius. The resultant product has density greater than 5g/cm3. HBI can be used as feedstock for steel production.

Leaching is the process by which a soluble mineral can be economically recovered from ore by dissolution.

Liquified natural gas (LNG) consists largely of methane that has been liquified through chilling and pressurisation. One tonne of LNG is approximately equivalent to 45.9 thousand cubic feet of natural gas.

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Liquified petroleum gas (LPG) consists of propane and butane and a small amount (less than 2%) of ethane that has been liquified through pressurisation. One tonne of LPG is approximately equivalent to 11.6 barrels.

Marketable Coal Reserves represents beneficiated or otherwise enhanced coal product and should be read in conjunction with, but not instead of, reports of coal reserves.

Megajoules = 1,000,000 joules (where joules is a measure of energy).

Metallurgical coal is a broader term than coking coal which includes all coals used in steelmaking, such as coal used for the Pulverised Coal Injection (PCI) process.

Oil and gas reserves mean those quantities of oil and gas that which are anticipated to be legally and commercially recoverable from known accumulations as of the date of the reserve estimate.

Ore reserves are that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Petajoules = 1,000,000,000,000,000 joules (where joules is a measure of energy).

Petroleum coke is a residue from the refining of heavy fraction oil into light fraction oil.

Probable ore reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degrees of assurance, although lower than that for proven (measured) reserves, is high enough to assure continuity between points of observation.

Proved ore reserves are the reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings on drill holes; grade and/or quality are computed from the results of detailed samplings and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.

Recoverable coal reserves are the combination of the proved and probable ore reserves which specifically concern coal.

Take or pay means an obligation on a customer to pay for an agreed minimum quantity of a commodity even if it fails to “take” that agreed minimum quantity.

Terajoules = 1,000,000,000,000 joules (where joules is a measure of energy).

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Financial Terms

UK Terminology	US equivalent	Australian equivalent

Shareholders’ Funds	Stockholders’ Equity	Total Equity

Called up share capital	Subscribed Capital Stock	Contributed Equity

Ordinary Shares	Common Stock	Ordinary Shares

Profit and Loss Account	Retained Earnings	Retained Profits

	Appropriated Surplus	Reserve, e.g. General Reserve. Forms part of Shareholders’ Equity

Share Premium Account	Paid-in Surplus	Share Premium Reserve

Provision – accrued liability, i.e., not part of Total Equity	Reserve – can represent either part of Stockholders’ Equity, accrued liability or estimated depletion in the cost of an asset	Provision – accrued liability, i.e., not part of Total Equity

Tangible Fixed Assets	Property, Plant and Equipment	Property, Plant and Equipment

Bonus Issue	Stock Dividend	Bonus Issue

Subsidiary	Subsidiary	Controlled Entity

Turnover	Sales Revenue	Sales Revenue

Depreciation	Depreciation and depletion	Depreciation

Profit for the financial year (attributable profit)	Net income	Net profit attributable to members

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IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

ITEM 1.

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

A.	Directors and Senior Management

Not applicable.

B.	Advisers

Not applicable.

C.	Auditors

Not applicable.

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OFFER STATISTICS AND EXPECTED TIMETABLE

ITEM 2.

OFFER STATISTICS AND EXPECTED TIMETABLE

A.	Offer Statistics

Not applicable.

B.	Method and Expected Timetable

Not applicable.

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KEY INFORMATION

ITEM 3.

KEY INFORMATION

A.	Selected Financial Data

Set forth below is selected consolidated financial information for (i) the BHP Billiton Group, which reflects the combined operations of both the BHP Billiton Limited Group and the BHP Billiton Plc Group, and (ii) the BHP Billiton Plc Group as a separate, stand-alone group. BHP Billiton Limited and BHP Billiton Plc each reports, as its primary financial statements under the requirements of the US Securities and Exchange Commission, the BHP Billiton Group’s consolidated financial statements prepared in accordance with generally accepted accounting principles in the United Kingdom and presented in US dollars. These financial statements account for the dual listed company structure as a business combination and accordingly consolidate BHP Billiton Limited, BHP Billiton Plc and their respective subsidiaries for all periods presented. Under UK GAAP, the DLC structure has been accounted for under the ‘pooling-of-interests’ method as though the DLC structure had been effective and the two groups had operated as one enterprise throughout the periods presented. The selected consolidated financial information for the BHP Billiton Plc Group on a stand-alone basis has been derived from the BHP Billiton Plc Group Consolidated Financial Statements, presented in US dollars and prepared in accordance with accounting policies that are in compliance with UK GAAP, except that these financial statements have been prepared as if the DLC merger had not occurred.

Under UK GAAP, the DLC structure has been accounted for as a merger (pooling of interests) in accordance with UK Financial Reporting Standard 6: Acquisitions and Mergers. Under US GAAP, the DLC structure is accounted for as a purchase business combination with the BHP Billiton Limited Group acquiring the BHP Billiton Plc Group on June 29, 2001. In a merger or a combination, the assets, liabilities and equity of the BHP Billiton Plc Group and the BHP Billiton Limited Group are combined at their respective book values as determined under UK GAAP. Under US GAAP, the reconciliation of shareholders’ equity includes the purchase adjustments required to recognise the BHP Billiton Plc Group assets and liabilities at their fair values, and to record goodwill.

BHP Billiton Limited’s independent chartered accountant in Australia for the year ended June 30, 2001 was Arthur Andersen. On June 15, 2002, Arthur Andersen LLP, Arthur Andersen’s US affiliated firm, was convicted by a jury in Houston, Texas on a single charge of obstructing justice in connection with its actions regarding Enron Corp. As of August 31, 2002, Arthur Andersen LLP ceased to practice before the SEC. As a US listed company, BHP Billiton Limited is required to file with the SEC annual financial statements audited by its independent certified public accountant. The SEC has said that it will continue accepting financial statements audited or reviewed by Arthur Andersen so long as Arthur Andersen is able to make certain representations to us. Although the financial statements of BHP Billiton Limited for the year ended June 30, 2001 are not included in this annual report, we have included the audit opinion of Arthur Andersen in this annual report because the audit opinion of PricewaterhouseCoopers for the BHP Billiton Group for the year ended June 30, 2001 insofar as it relates to amounts included in respect of BHP Billiton Limited has expressed reliance on the audit opinion of Arthur Andersen. In connection with its audit of the BHP Billiton Limited financial statements for the year ended June 30, 2001 and the revision to note 50 of such financial statements, which is dated March 22, 2002, included in this annual report, Arthur Andersen has made the representations to us that are required by the SEC. In the future, our access to the capital markets and our ability to make timely SEC filings could be impaired if the SEC ceases accepting financial statements audited by Arthur Andersen or if Arthur Andersen becomes unable to make the required representations to us. Further, it is possible that events arising out of the indictment may adversely affect the ability of Arthur Andersen to satisfy any claims arising from its provision of auditing and other services to us, including claims that may arise out of Arthur Andersen’s prior audit of our financial statements.

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BHP Billiton Group

The selected consolidated financial information for the BHP Billiton Group set forth below as at and for the fiscal years ended June 30, 2003, 2002 and 2001 should be read in conjunction with, and is qualified in its entirety by reference to, the audited BHP Billiton Group Annual Financial Statements and the accompanying notes included in this annual report.

	Year ended June 30,
Consolidated Profit and Loss Account	2003		2002		2001		2000
	(US$ millions except per share data)
*Amounts in accordance with UK GAAP*
Group turnover – total		15,608		15,906		17,789		17,415
Group turnover – from continuing operations		15,608		13,562		14,771		12,744
Operating profit (including share of profit of joint ventures and associates)
- including exceptional items – total		3,412		2,943		2,825		2,182
- excluding exceptional items – from continuing operations		3,412		2,984		3,284		2,485
- including exceptional items – from continuing operations		3,412		2,873		2,612		1,790
Net profit before minority interests
- including exceptional items		1,941		1,737		1,252		1,527
Net profit attributable to members
- including exceptional items		1,901		1,690		1,529		1,506
Dividends provided for or paid		900		784		754		788
Number of Ordinary Shares (millions)^(a)
- at period end		6,216		6,044		6,023		5,817
- weighted average		6,207		6,029		5,944		5,725
- weighted average diluted		6,222		6,042		5,973		5,736
Per Ordinary Share:^(a)
- Net profit attributable to members
Including exceptional items
- Basic	US$	0.31	US$	0.28	US$	0.26	US$	0.26
- Diluted	US$	0.31	US$	0.28	US$	0.26	US$	0.26
-Dividends provided for or paid – BHP Billiton Plc	US$	0.145	US$	0.130	US$	0.120	US$	0.113
-Dividends provided for or paid – BHP Billiton Limited	US$	0.145	US$	0.130	A$	0.247	A$	0.247

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	Year ended June 30,
Consolidated Profit and Loss Account	2003		2002			2001		2000
	(US$ millions except per share data)
*Amounts in accordance with US GAAP*^(c)(d)
Sales revenue – from continuing operations		15,608		13,552			8,100		7,467
Other income – from continuing operations		223		321			516		268
Operating income – from continuing operations		2,698		1,969			629		14
Net income – total		1,581		1,249			882		400
Net income – from continuing operations		1,576		1,513			718		257
Net (loss)/income – from discontinued operations		5		(264	)		136		143

Per Ordinary Share^(a):

Net income attributable to members
Basic – from continuing operations	US$	0.25	US$	0.25		US$	0.20	US$	0.07
Diluted – from continuing operations	US$	0.25	US$	0.25		US$	0.20	US$	0.07
Basic – from discontinued operations		—	US$	(0.04	)	US$	0.04	US$	0.04
Diluted – from discontinued operations		—	US$	(0.04	)	US$	0.04	US$	0.04
Basic – total	US$	0.25	US$	0.21		US$	0.24	US$	0.11
Diluted – total	US$	0.25	US$	0.21		US$	0.24	US$	0.11
Per ADS:
Net income attributable to members
Basic – total	US$	0.50	US$	0.42		US$	0.48	US$	0.22
Diluted – total	US$	0.50	US$	0.42		US$	0.48	US$	0.22

	At June 30,
Balance Sheet	2003		2002			2001		2000
	(US$ millions)
*Amounts in accordance with UK GAAP*
Total assets		28,365		29,552			28,028		27,335
Total non-current portion of interest bearing liabilities^(b)		6,288		5,534			6,521		5,040
Contributed equity		3,537		4,895			4,791		5,356
Equity attributable to members		12,013		12,356			11,340		11,036

*Amounts in accordance with US GAAP*^(c)(d)
Total assets – total		35,001		35,795			35,232		17,698
Total assets – of continuing operations		35,001		33,023			32,562		13,046
Total non-current portion of interest bearing liabilities – total		6,414		6,350			6,607		3,501
Total non-current portion of interest bearing liabilities – of continuing operations		6,414		6,296			6,544		3,412
Equity attributable to members		16,832		17,147			16,602		6,333

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(a)

The calculation of the number of ordinary shares used in the computation of basic earnings per share is the aggregate of the weighted average number of ordinary shares outstanding during the period of BHP Billiton Plc and BHP Billiton Limited after deduction of the number of shares held by the Billiton share repurchase scheme and the Billiton Employee Share Ownership Trust and adjusting for the BHP Billiton Limited bonus share issue. Included in the calculation of fully diluted earnings per share are the BHP Billiton Limited options and partly paid shares and the BHP Billiton Plc executive share awards.

(b)	Includes limited recourse finance and finance leases not repayable within 12 months.

(c)

As discussed in ‘Note 33. US Generally Accepted Accounting Principles disclosures’ in the attached 2003 BHP Billiton Group Annual Financial Statements, the Group changed its methods of accounting for goodwill and employee stock-based compensation, refer footnotes (D) and (R) respectively, under US GAAP in the year ended June 30, 2003.

(d)

The US GAAP consolidated financial information for the BHP Billiton Group set forth below as at and for the year ended May 31, 1999 has been derived from the audited consolidated financial statements, prepared in Australian dollars, of the BHP Billiton Limited Group (the predecessor to the BHP Billiton Group) and converted to US dollars from Australian dollars at a US$/A$ rate of 0.6232 for the year ended May 31, 1999 and a rate of 0.6509 at May 31, 1999.

	Year ended May 31, 1999
	(US$ millions except per share data)
Sales revenue		11,984
Net loss attributable to members		(1,165	)
Per ordinary share:
- Net loss attributable to members
- Basic	US$	(0.33	)
- Diluted	US$	(0.33	)
- Dividends provided for or paid
- As declared	US$	0.318
- As declared, adjusted for the bonus issue	US$	0.154
Per ADS:
- Net loss attributable to members
- Basic	US$	(0.66	)
- Diluted	US$	(0.66	)
- Dividends provided for or paid
- As declared	US$	0.636
- As declared, adjusted for the bonus issue	US$	0.308

	As at May 31, 1999
	(US$ millions)
Total assets		21,271
Total non-current portion of interest bearing liabilities		6,471
Equity attributable to members		6,509

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BHP Billiton Plc Group

The selected consolidated financial information for the BHP Billiton Plc Group for the period July 1, 2000 to June 28, 2001 and the two years ended June 30, 2000 set forth below has been derived from the audited consolidated financial statements for the BHP Billiton Plc Group included in this annual report and should be read in conjunction with, and is qualified in its entirety by reference to, those financial statements, including the accompanying notes.

	Period ended June 28, 2001		Year ended June 30,
Consolidated Profit and Loss Account	Period ended June 28, 2001		2000		1999
	(US$ millions)
*Amounts in Accordance with UK GAAP*
Group turnover		7,333		5,550		5,174
Net profit before minority interest
- excluding exceptional items		706		607		430
- including exceptional items		587		607		430
Net profit attributable to members of BHP Billiton Plc
- excluding exceptional items		693		566		382
- including exceptional items		608		566		382
Dividends provided for or paid		278		232		218
Number of Ordinary Shares (millions)
- at period end		2,319		2,138		2,138
- weighted average		2,255		2,076		2,108
- weighted average diluted		2,269		2,076		2,108
Per Ordinary Share^(a):
Net profit attributable to members of BHP Billiton Plc
Excluding exceptionals^(b)
Basic	US$	0.31	US$	0.27	US$	0.18
Diluted	US$	0.31	US$	0.27	US$	0.18
Including exceptionals
Basic	US$	0.27	US$	0.27	US$	0.18
Diluted	US$	0.27	US$	0.27	US$	0.18
Dividends provided for or paid
US$ per share – as declared	US$	0.120	US$	0.113	US$	0.105

*Amounts in Accordance with US GAAP*
Sales revenue		7,333		5,550		5,174
Profit from ordinary activities before taxation and borrowing		988		927		675
Net income, attributable to members of BHP Billiton Plc		482		528		341
Per Ordinary Share:
Net income, attributable to members
Basic	US$	0.21	$	0.25	$	0.16
Diluted	US$	0.21	$	0.25	$	0.16
Dividends provided for or paid
US$ per share – as declared	US$	0.120	US$	0.113	US$	0.105

(a)	Based upon the weighted average number of shares on issue.

(b)

While the presentation of earnings per share excluding exceptional items is acceptable under UK GAAP, this presentation is not permitted under US GAAP. Profit and earnings per share before exceptional items are not measures of financial performance under US GAAP and should not be considered an alternative to, or more meaningful than income from operations, net income or cash flows as defined by US GAAP as a measurement of the BHP Billiton Group’s profitability or liquidity. All registrants do not calculate profit and earnings per share before exceptional items in the same manner, and accordingly, profit and earnings per share before exceptional items may not be comparable with other registrants. Refer to note 2 of the BHP Billiton Plc Group’s financial statements for details of exceptional items that have been excluded.

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Currency of presentation

The BHP Billiton Group publishes its consolidated financial statements in US dollars. The financial statements of the BHP Billiton Plc Group included in this annual report are published in US dollars.

B.	Capitalisation and Indebtedness

Not applicable.

C.	Reasons for the Offer and Use of Proceeds

Not applicable.

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D.	Risk Factors

We believe that, because of the international scope of our operations and the industries in which we are engaged, numerous factors have an effect on our results and operations. The following describes the material risks that could affect us.

Fluctuations in commodity prices may negatively impact the BHP Billiton Group’s results

The prices we obtain for our oil, gas, minerals and other commodities are determined by, or linked to, prices in world markets, which have historically been subject to substantial variations because of fluctuations in supply and demand. We expect that volatility in prices for most of our commodities will continue for the foreseeable future. This volatility creates the risk that our operating results will be materially and adversely affected by unforeseen declines in the prevailing prices of our products.

Our profits may be negatively affected by currency exchange rate fluctuations

Our assets, earnings and cash flows are influenced by a wide variety of currencies due to the geographic diversity of the countries in which we operate. Fluctuations in the exchange rate of those currencies may have a significant impact on our financial results. The US dollar is the currency in which the majority of our sales are denominated. Operating costs are influenced by the currencies of those countries where our mines and processing plants are located and also by those currencies in which the costs of imported equipment and services are determined. The Australian dollar, South African rand and US dollar are the most important currencies influencing our operating costs. Given the dominant role of the US currency in our affairs, the US dollar is the currency in which the BHP Billiton Group measures its financial performance. It is also the natural currency for borrowing and for holding surplus cash. An exception to this is our borrowings denominated in South African rand, which at June 30, 2003 was approximately 9% of our total debt on a UK GAAP basis. This view-based strategy is based on the historical depreciation of the South African rand against the US dollar and the interest rate differential between the two currencies. We do not generally believe that active currency hedging provides long-term benefits to our shareholders. We may consider currency protection measures appropriate in specific commercial circumstances, subject to strict limits established by our Boards. Therefore, in any particular year, currency fluctuations may have a significant impact on our financial results.

Our losses due to legacy foreign currency hedging amounted to US$86 million, US$305 million and US$381 million in the years ended June 30, 2003, 2002 and 2001, respectively.

Failure to discover new reserves or enhance existing reserves could negatively affect the BHP Billiton Group’s results and financial condition

Because a substantial portion of our revenues and profits are related to our oil and gas and minerals operations, our results and financial conditions are directly related to the success of our exploration efforts and our ability to replace existing reserves. A failure in our ability to discover new reserves or enhance existing reserves in sufficient quantities to maintain or grow the current level of our reserves could negatively affect our results and financial conditions.

We may have fewer mineral, oil or gas reserves than our estimates indicate

Our reserves estimations may change substantially if new information subsequently becomes available. Fluctuations in the price of commodities, variation in production costs or different recovery rates may ultimately result in our estimated reserves being revised. If such a revision were to indicate a substantial reduction in proven or probable reserves at one or more of our major projects, it could negatively affect our results, financial condition and prospects.

Compliance with health, safety and environment regulations may impose burdensome costs

The nature of the industries in which we operate means that our activities are highly regulated by health, safety and environmental laws. As regulatory standards and expectations are constantly developing, we may be exposed to increased litigation, compliance costs and unforeseen environmental remediation expenses. The December 1997 Kyoto Protocol established a set of emission targets for developed countries that have ratified the Protocol. It is uncertain at this stage how the Kyoto Protocol will affect our operations and our customers. There is a risk that the Kyoto Protocol may negatively impact our operations and our financial results. We may also be exposed to increased operational costs due to the costs and lost worker’s time associated with the HIV/AIDS infection rate of our Southern African workforce. These compliance costs, litigation expenses, remediation expenses and operational costs could negatively affect our financial results.

Land tenure disputes may negatively impact the BHP Billiton Group’s operations

We operate in several countries where ownership of land is uncertain, and where disputes may arise in relation to ownership. These disputes cannot always be predicted, and hence there is a risk that this may cause disruption to some of our mining projects and prevent our development of new projects.

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In Australia, the Native Title Act (1993) provides for the establishment and recognition of native title under certain circumstances. Like land ownership disputes, native title could materially and adversely affect our new or existing projects.

In South Africa, the Extension of Security of Tenure Act (1997) prevents evictions from taking place in the absence of a court order. Occupiers who reside on the owner’s land, with the requisite consent of the owner, have rights to remain in occupation unless they breach their statutory obligations as occupiers. A process exists for long-term occupiers to enjoy life long tenure. However, the legislation provides for the option of provision of suitable alternative land for occupation. Furthermore, the Restitution of Land Rights Act (1994) permits dispossessed communities to reclaim land but only where such dispossession occurred after 1913 and as a consequence of a discriminatory practice or law. Both these Acts could materially and adversely affect new or existing projects of the BHP Billiton Group.

Actions by governments in the countries in which we operate could have a negative impact on our operations and results

Our operations could be adversely affected by government actions such as controls on imports, exports and prices, new forms of taxation, and increased government regulation in the countries in which we operate or service customers. We also could be adversely affected by regulatory inquiries into our business practices, such as the ongoing investigation of the copper concentrate market by the European Commission and the US and Canadian authorities.

Additional risks associated with emerging markets may negatively impact some of the BHP Billiton Group’s operations

We operate in emerging markets which may involve additional risks that could have an adverse impact upon the profitability of an operation. These risks could include civil unrest, nationalisation, re-negotiation or nullification of existing contracts, leases, permits or other agreements, and changes in laws and policy as well as other unforeseeable risks. If one or more of these risks occurs at one of our major projects, it could have a negative effect on our operating results or financial condition.

We may not be able to integrate successfully our acquired businesses

We have grown our business in part through acquisitions and expect that some of our future growth will stem from acquisitions. There are numerous risks encountered in business combinations and we may not be able to successfully integrate acquired businesses or generate the cost savings and synergies anticipated, which could negatively affect our financial condition and results of operations.

We may not recover our investments in exploration and new mining and oil and gas projects

There is a risk that we will not be able to recoup the funds we spend identifying new mining and oil and gas properties through our exploration program. Increasing requirements relating to regulatory, environmental and social approvals can potentially result in significant delays in construction and may adversely impact upon the economics of new mining and oil and gas properties, the expansion of existing operations and our results of operations.

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INFORMATION ON THE COMPANY

ITEM 4.

INFORMATION ON THE COMPANY

A.	History and Development of BHP Billiton

Background

We are one of the world’s largest diversified resources groups with a combined market capitalisation of approximately US$35 billion as of June 30, 2003 and combined revenues of US$17.5 billion for the year ended June 30, 2003. We hold industry leader or near-leader positions in a range of products, including:

•

world’s largest exporter of metallurgical coal for the steel industry;

•

world’s second largest exporter of energy coal;

•

world’s third largest producer of iron ore;

•

world’s fourth largest producer of copper;

•

Western world’s fourth largest producer of primary aluminium; and

•

world’s largest producer of manganese and chrome ferroalloys.

We also have substantial interests in oil, gas, liquefied natural gas, nickel, diamonds, silver and titanium minerals.

BHP Billiton Limited is incorporated under the name “BHP Billiton Limited” and is registered in Australia with ABN number 49 004 028 077. BHP Billiton Limited was incorporated on August 13, 1885 under the name of The Broken Hill Proprietary Company Limited.

BHP Billiton Plc is incorporated under the name “BHP Billiton Plc” and is registered in the United Kingdom with Company number 3196209. BHP Billiton Plc was incorporated on May 9, 1996.

On March 19, 2001, we announced that the Directors of BHP Limited and Billiton Plc had agreed to form a Dual Listed Companies structure to establish a diversified global resource group to be called BHP Billiton. The implementation of the DLC structure was completed on June 29, 2001. BHP Limited changed its name to BHP Billiton Limited and Billiton Plc changed its name to BHP Billiton Plc.

BHP Billiton Limited and BHP Billiton Plc are run by a unified Board and management team, with headquarters in Melbourne, Australia, and with a significant corporate management centre in London. The existing primary listings on the London and Australian stock exchanges continue to be maintained, as is the secondary listing of BHP Billiton Plc on the Johannesburg and Paris stock exchanges. On June 25, 2003 BHP Billiton Plc listed its sponsored American Depositary Receipts security on the New York Stock Exchange and BHP Billiton now maintains an American Depositary Receipt listing of both BHP Billiton Limited and BHP Billiton Plc on the New York Stock Exchange.

The shareholders of BHP Billiton Limited and BHP Billiton Plc take key decisions on matters affecting the combined group through a procedure in which the shareholders of both companies have equal voting rights per share. Accordingly, shareholders of BHP Billiton Limited and BHP Billiton Plc effectively have an interest in a single group combining all of the assets of both companies with a unified Board of Directors and management. Should any future corporate action benefit shareholders in only one of the two companies, an appropriate action will be taken to ensure parity between BHP Billiton Limited and BHP Billiton Plc shares.

Further information on the DLC structure is included in Item 4C of this annual report.

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We have grouped our major operating assets into the following Customer Sector Groups:

•

Petroleum (oil, gas and liquefied natural gas);

•

Aluminium (aluminium and alumina);

•

Base Metals (copper, silver, zinc and lead);

•

Carbon Steel Materials (metallurgical coal, iron ore and manganese);

•

Diamonds and Specialty Products (diamonds, titanium minerals and metals distribution);

•

Energy Coal (energy coal); and

•

Stainless Steel Materials (nickel metal, and chrome and nickel ferroalloys).

The table below sets forth the contribution to combined turnover and profit (before tax) of each of these customer sector groups for the three years ended June 30, 2003.

	Turnover
	Year ended June 30
	2003		2002		2001
	(US$ millions)
Group including share of joint ventures and associates
Petroleum	3,264		2,815		3,361
Aluminium	3,386		2,857		2,971
Base Metals	1,954		1,821		1,719
Carbon Steel Materials	3,714		3,306		3,349
Diamonds and Specialty Products	1,485		1,480		1,318
Energy Coal	2,089		1,919		1,982
Stainless Steel Materials	1,106		868		994
Steel (discontinued operations)⁽¹⁾	—		2,550		3,220
Group and unallocated items⁽¹⁾	1,014		730		749
Intersegment	(506	)	(568	)	(584	)

Total	17,506		17,778		19,079


	Profit before tax
	Year ended June 30,
	2003		2002		2001
	(US$ millions)
Group including share of joint ventures and associates
Petroleum	1,178		1,073		1,407
Aluminium	581		492		523
Base Metals	286		192		452
Carbon Steel Materials	1,045		1,084		918
Diamonds and Specialty Products	299		272		188
Energy Coal	190		536		382
Stainless Steel Materials	150		3		72
Steel (discontinued operations)⁽¹⁾	—		86		218
Group and unallocated items⁽¹⁾	(248	)	(550	)	(555	)
Exceptional items	(19	)	(212	)	(1,066	)
Net interest	(537	)	(249	)	(476	)

Total	2,925		2,727		2,063

(1)	The Group’s Steel business was demerged in July 2002 and is disclosed as discontinued operations. Comparatives have been stated accordingly.

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The table below sets forth the contribution to combined turnover and net profit (before tax and net interest) by geographic origin for the three years ended June 30, 2003.

	Turnover
	Year ended June 30,
	2003		2002	2001
	(US$ millions)
Geographic origin
Australia	6,527		5,842	5,854
Europe	2,792		2,049	1,907
North America	2,186		2,143	1,909
South America	2,733		2,255	2,350
Southern Africa	3,147		2,696	3,107
Rest of World	121		243	738
Discontinued operations⁽¹⁾	—		2,550	3,214

Total	17,506		17,778	19,079


	Profit before tax and net interest
	Year ended June 30,
	2003		2002	2001
	(US$ millions)
Geographic origin
Australia	1,890		1,549	1,456
Europe	259		233	191
North America	188		22	127
South America	576		301	444
Southern Africa	558		712	498
Rest of World	10		73	(395	)
Discontinued operations⁽¹⁾	(19	)	86	218

Total	3,462		2,976	2,539

(1)	The Group’s Steel business was demerged in July 2002 and is disclosed as discontinued operations. Comparatives have been stated accordingly.

The table below sets forth the analysis of combined turnover by geographic market for the three years ended June 30, 2003.

	Turnover
	Year ended June 30,
	2003	2002	2001
	(US$ millions)
Geographic market
Australia	1,775	1,442	1,434
Europe	5,582	4,430	4,139
Japan	2,393	2,078	2,531
South Korea	1,203	1,068	906
Other Asia	2,388	1,998	1,857
North America	2,389	2,344	2,603
Southern Africa	944	936	1,159
Rest of World	832	932	1,236
Discontinued operations⁽¹⁾	—	2,550	3,214

Total	17,506	17,778	19,079

(1)	The Group’s Steel business was demerged in July 2002 and is disclosed as discontinued operations. Comparatives have been stated accordingly.

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The ore reserves tabulated are all held within existing, fully permitted mining tenements. The BHP Billiton Group’s minerals leases are of sufficient duration (or convey a legal right to renew for sufficient duration) to enable all reserves on the leased properties to be mined in accordance with current production schedules. Ore reserves are presented in the accompanying tables subdivided for each of the Customer Sector Groups.

All of the ore reserve figures presented are reported in 100% terms, and represent estimates at June 30, 2003. All tonnes and grade information has been estimated more precisely than the rounded numbers that are reported, hence small differences may be present in the totals.

As the reported reserves contained in this annual report have been reported based on historical average commodity prices in accordance with Industry Guide 7, they differ in some respects from the reserves we report in our home jurisdictions of Australia and the UK. Those jurisdictions require the use of the Australasian Code for reporting of Mineral Resources and Ore Reserves, September 1999 (the JORC Code), which contemplates the use of reasonable investment assumptions in calculating reserve estimates.

Reserves are estimated based on prices reflecting current economic conditions determined by reference to the three year historical average for each commodity. The prices used to estimate the reserves contained in this annual report are as follows:

		Price
		US$
Copper		0.74/lb
Zinc		0.41/lb
Nickel		3.19/lb
Aluminium (used for Alumina)		1,426/t
Alumina (12.75% of Aluminium)		182/t
Silver		4.63/oz
Lead		0.21/lb
Gold		292/oz

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B. Business Overview

Petroleum

Our principal activities in the petroleum sector are oil and natural gas exploration, production and development in Australia, the United Kingdom, the United States, Algeria, Trinidad and Tobago, Pakistan and Bolivia and exploration interests in the United States, Australia, Trinidad and Tobago, Pakistan, Brunei Darussalam, South Africa, Brazil and Gabon.

Operating Assets

Australia/Asia

In Australia we source production from Bass Strait, the North West Shelf, the Laminaria and Corallina oil fields and the Griffin Project.

Bass Strait

The Bass Strait oil and gas fields are located in the Gippsland Basin, offshore southern Australia. First production commenced in 1968. We have a 50% interest in the Bass Strait fields, Esso Australia Resources Pty Ltd (Esso Australia) has the other 50% and acts as operator. Production from most of the fields is subject to an overriding 2.5% royalty payable to Oil Basins Limited.

Most crude oil and condensate is dispatched from the fields to refineries in the State of Victoria, while the balance is sold elsewhere in Australia or overseas. Gross oil production during 2002-2003 averaged 133,000 barrels per day.

Most of the natural gas produced is sold to Gascor for on-sale to retailers for distribution throughout Victoria to meet its residential and commercial gas requirements. The contract is due to expire on 31 December 2009 or the depletion of the outstanding contractual volumes.

In April 2001, together with Esso Australia, we signed a long-term supply agreement with Duke Energy International for the introduction of approximately 51 million cubic feet of natural gas per day to Tasmania. Deliveries commenced in late 2002. This followed a long-term gas transport agreement we and Esso Australia signed with Duke Energy International in December 1998 for the transportation of Bass Strait natural gas to New South Wales.

In 2002 we signed Memorandums of Understanding with TXU Australia and AGL Wholesale for collectively over 0.7Tcf of long-term gas sales (BHPB share) from 2004.

During 2002-2003, total gas production averaged approximately 550 million cubic feet per day (gross). LPG (liquefied petroleum gases) and ethane extracted from the natural gas are sold in Australia and overseas. During 2002–2003, LPG production averaged 2,900 tonnes per day (gross) and ethane production averaged 530 tonnes per day (gross).

In December 2002, we, together with Esso Australia, completed the construction of a fourth Bass Strait gas pipeline from the Bream field into the joint venture’s Gippsland production network.

We continue to pursue a strategy of seeking additional reserves in the Bass Strait in order to enhance existing production levels with high value incremental developments. We and our joint venture partner Esso Australia, have completed processing, and are currently interpreting, the largest three-dimensional seismic survey ever completed in Bass Strait. The 3,900-square kilometre survey covered all of the joint venture’s northern oil and gas fields, and was designed to identify hydrocarbon targets over a range of geological horizons.

North West Shelf

We are a participant in the North West Shelf Project, an unincorporated joint venture of six participants, operated by Woodside Energy Ltd. The project was developed in two major phases: the domestic gas phase, which supplies gas to the Western Australia domestic market; and the LNG phase, which supplies LNG (liquefied natural gas) to Japan. The project also produces crude oil, condensate and LPG, primarily for export.

The domestic gas participants are Woodside Petroleum (50%), BP Developments Australia Pty Ltd (16.67%), Chevron Texaco Australia Pty Ltd (16.67%), our wholly-owned subsidiary BHP Billiton Petroleum (North West Shelf) Pty Ltd (8.33%) and Shell Development (Australia) Pty Ltd (8.33%). When domestic gas sales exceed 500 million cubic feet per day, ownership of the incremental gas is shared equally between all domestic gas participants and Japan Australia LNG (MIMI) Pty Ltd (jointly owned by Mitsubishi Corporation and Mitsui & Co), with each participant holding a 16.67% share. Participants in the LNG phase include the domestic gas participants and Japan Australia LNG (MIMI), each with a 16.67% interest.

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The onshore gas treatment plant is located at Withnell Bay on the Burrup Peninsula, 1,200 kilometres north of Perth, Western Australia and is supplied by the offshore North Rankin, Goodwyn, Perseus and Echo-Yodel gas and condensate fields. Production from the North Rankin and Perseus fields is through the North Rankin A platform, which has the capacity to produce 1,800 million cubic feet per day of gas and 40,000 barrels per day of condensate. Production from the Goodwyn and Echo-Yodel fields is through the Goodwyn A platform, which has the capacity to produce 1,400 million cubic feet per day of gas and 110,000 barrels per day of condensate (not concurrently). Production from these fields meets current contractual requirements for the domestic gas and LNG phases of the project. Plans are in place to develop the Angel field, and a group of smaller static resources, to meet future market requirements.

The North West Shelf domestic gas plant has a capacity of six hundred million cubic feet per day. The gas is delivered via pipeline to customers in Western Australia under long-term agreements. Production of domestic gas in 2002–2003 averaged 500 million cubic feet per day (gross).

The existing three-train LNG plant produces on average 21,750 tonnes of LNG per day, or 7.5 million tonnes per annum. The project sells approximately 7 million tonnes of LNG per year under long-term contracts to Japanese buyers. These contracts are due to expire in 2009. Additional spot sales are also made to the USA and Asia, depending on plant and shipping availability. Production for 2002-2003 averaged 22,030 tonnes per day (gross); this was due to higher LNG demand in Japan and Korea coinciding with ship chartering opportunities.

Construction of a fourth liquefaction train and offshore trunkline to support an expansion of the existing LNG business commenced in calendar year 2001. The expansion involves the construction of a 4.2 million tonnes per year liquefaction processing train and a 42-inch gas trunkline to be installed over a distance of 135 kilometres from the existing production platforms to the onshore processing plant. We expect first commercial production from the new facilities during calendar year 2004. The project has also ordered an additional LNG carrier to deliver some of the sales volumes associated with the expansion project. Our share of costs of the fourth liquefaction processing train, the pipeline and the additional carrier is expected to be approximately US$274 million.

Sales arrangements underpinning the expansion are in place with six Japanese gas and power companies for the supply of up to 3.9 million tonnes per year of LNG, for contracted periods of between 20 years and 30 years.

In October 2002, the North West Shelf joint venture participants signed Sales and Purchase agreements with the Guangdong LNG Project, for the purchase and supply of LNG from the North West Shelf. This is China’s first LNG project and involves the construction of an LNG import terminal and high-pressure gas pipeline in two phases. The agreements were signed by the six North West Shelf LNG Sellers and cover the supply of approximately 3.3 million tonnes of LNG per year to Phase One of the Guangdong LNG Project for a period of 25 years expected to start in 2006. The agreements are subject to certain conditions precedent, including Chinese Government approvals, buyer financing arrangements and arrangements between the LNG buyer and natural gas end-buyers.

Following execution of the Guangdong LNG sales and purchase agreements, further agreements were signed in May 2003 with a subsidiary company of the China National Offshore Oil Corporation (CNOOC) in regard to equity participation by CNOOC in the North West Shelf Project. Under these agreements CNOOC will pay each of the NWS Venture participants approximately US$58 million to take up a 5.3% interest in titles to NWS Project raw gas reserves. CNOOC will also have a 25% interest in a new joint venture (BHPB share 12.5%) to be set up within NWS to supply LNG to Guangdong and will have rights to process its gas and associated products through NWS offshore and onshore infrastructure on payment of a tariff. Completion of this transaction is subject to regulatory and other approvals as well as satisfaction of a number of conditions precedent. The NWS Project and various Chinese shipping companies are currently finalising arrangements for the establishment of ship owning and ship management companies for LNG transport to China. Two or three LNG ships will be required to service the China trade route.

During 2002-2003, we also concluded the following LNG sales contracts with new customers in Japan and Korea:

•

In January 2003, we executed a binding sales and purchase agreement with Shizuoka Gas for a total of 3 million tonnes of LNG to be delivered over the full term of a 24 year agreement commencing in 2005; and

•

In March 2003, we executed a sales and purchase agreement with Korea Gas Corporation for the sale of approximately 480,000 tonnnes of LNG per year for a term of 7 years commencing in late 2003.

•

In September 2003 we signed a heads of agreement with The Kansai Electric Power Company Inc., an existing Japanese customer, for long-term LNG supply of 500,000 tonnes of LNG a year between 2009 and 2014 and 925,000 tonnes of LNG a year between 2015 and 2023.

Condensate is separated from the natural gas in the onhore plant. Condensate production during 2002-2003 averaged 115,000 barrels per day (gross).

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LPG production began in November 1995 and production in 2002–2003 was 2,200 tonnes per day (gross). We have a 16.67% interest in the LPG production.

The project’s crude oil production is from the Wanaea, Cossack, Lambert and Hermes oil fields which are located about 30 kilometres north east of the North Rankin field. The oil is produced to a floating production storage and offloading unit, the Cossack Pioneer and production averaged 112,000 barrels of oil per day (gross) in 2002–2003. We have a 16.67% working interest in oil production.

Laminaria and Corallina

We are a participant in the Laminaria and Corallina joint venture with Woodside Energy Ltd and Shell Development (Australia) Pty Ltd. Woodside Energy Ltd is the operator of the venture. The Laminaria and Corallina fields are located in the Timor Sea, about 550 kilometres north-west of Darwin and 160 kilometres south of Timor in production licenses AC/L5 and WA-18-L. The Laminaria field was discovered in 1994 and the Corallina field in 1995. We have a 32.6125% working interest in the Laminaria oil field, with Woodside holding a 44.925% interest and Shell holding a 22.4625% interest. We have a 25% interest in the Corallina oil field, Woodside has a 50% interest and Shell has a 25% interest.

A floating production storage and offloading unit, the Northern Endeavour, produces the oil from these fields.

In 2002–2003, production from the Northern Endeavour averaged 71,000 barrels of oil per day (gross) and is expected to decline sharply in future years.

Carnarvon Basin

We are the operator of the Griffin oil and gas project, which includes the Griffin, Chinook and Scindian fields in the Carnarvon Basin, offshore Western Australia. We hold a 45% interest in the project, Mobil Exploration and Producing Australia Pty Ltd holds a 35% interest and Inpex Alpha Ltd holds the remaining 20% interest.

The Griffin project first produced oil through its floating production storage and offloading facility, the Griffin Venture, in January 1994. Production for 2002-2003 averaged 24,000 barrels per day of oil (gross).

We pipe natural gas to shore, where it is exported directly into a pipeline and sold under long-term contracts. Gas production in 2002-2003 averaged 22 million standard cubic feet per day (gross).

Pakistan

We are the operator of the Zamzama onshore gas project in the Dadu Block in the Sindh Province of Pakistan. We hold a 38.5% working interest in the project, ENI Pakistan (M) Ltd holds 17.75%, PKP Exploration Ltd (a jointly owned company between Kufpec and Premier Oil) holds 18.75% and the government of Pakistan holds the remaining 25% interest.

In 1998, we discovered gas in the Zamzama-1 well under the Dadu exploration permit. After a single well appraisal program identified commercial reserves we commenced production in March 2001 from Zamzama 1 and 2 wells through an extended well test (EWT) phase. For 2002-2003 production averaged 85 million cubic feet per day of gas (gross) and 500 barrels per day of condensate (gross).

In March 2002, we and our partners approved the Phase 1 development of the Zamzama gas field. This followed the Dadu joint venture signing the two gas sales and purchase agreements with the government of Pakistan, Sui Southern Gas Company and Sui Northern Gas Pipelines Company Limited. The agreements cover the supply of up to 320 million cubic feet per day of gas over the expected field life of 20 years. In April 2002, the government of Pakistan granted the Dadu joint venture a 20-year development and production license for the full field development of the Zamzama discovery.

The Phase 1 development consists of two additional processing trains, which are located on the existing EWT plant site, and a minimum of three additional development wells. First gas from the Phase 1 development commenced in July 2003 and our share of capital expenditure for this phase was less than the original budgeted amount of US$40 million.

Americas

Gulf of Mexico

Our Gulf of Mexico production is sourced from six producing assets: Typhoon, Boris, West Cameron 76, Green Canyon 18/Ewing Bank 988, Green Canyon 60 and Genesis.

We have a 50% working interest in the Typhoon oil and gas development, located in Green Canyon Blocks 236 and 237. Chevron Texaco has the other 50% working interest and is the operator. The field is located in 600 metres of water approximately 100

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kilometres off the coast of Louisiana, and was our first deepwater Gulf of Mexico development. The field consists of four subsea wells tied back to a local host mini tension leg platform. First production was in July 2001; peak production of approximately 38,600 barrels of oil and 50 million cubic feet of gas per day was reached in April 2002.

We also have a 50% working interest in and operate the Boris oil discovery in Green Canyon Block 282 adjacent to the Typhoon field. Boris was developed as a tie-back to the Typhoon production facility. Production commenced from the first well, Boris-1, in February 2003 and from the second well, Boris-2, in September 2003.

In 2002-2003, production from Typhoon and Boris fields through the Typhoon facility averaged 23,000 barrels per day of oil and 34 million cubic feet of gas (gross).

We also have a 33.8-78.8% working interest in and act as the operator of the West Cameron 76 gas field, a 25% working interest in the Green Canyon 18/Ewing Bank 988 oil field (operated by ExxonMobil) and a 45% working interest in the Green Canyon 60 field (also operated by ExxonMobil). Additionally, in September 2000, we purchased a 4.95% working interest in the Chevron Texaco operated Genesis oil field in Green Canyon blocks 160, 161 and 205. In total, our net share of production from these four properties during 2002-2003 was 3,600 barrels of oil and 32 million cubic feet of gas per day.

Bolivia

In July 1994, we acquired a 50% working interest in the Mamore exploration block in Bolivia, including the Surubi oil field, from Maxus Bolivia Inc, whose ultimate parent is Repsol of Spain. Production from the Surubi oil field began in 1993. The Paloma field was discovered in 1995, and the Bloque Bajo field was discovered in 1996. Gas sales from the block commenced in the second half of calendar year 1999. Gross production from these fields was 8,800 barrels per day of oil and 15 million cubic feet per day of gas in 2002–2003.

Europe/Africa/Middle East

Our petroleum production activities in the United Kingdom are based in the Irish Sea and the North Sea. The Liverpool Bay Development in the Irish Sea is our largest operated asset. We also have an interest in the Bruce oil and gas field and an interest in the Keith oil field, both in the North Sea.

Liverpool Bay

We are the operator of the Liverpool Bay oil and gas development, located off the North West coast of England, in which we have a 46.1% working interest. Other participants in the joint venture are Eni ULX Limited, which has a 45% interest, and Eni UK Limited, which has an 8.9% interest. The venture began first production of oil and gas in 1996. Oil production is from the Douglas and Lennox fields. Contracted long-term gas sales to Powergen are from the Hamilton, Hamilton North and Hamilton East gas fields.

The venture completed its third infill drilling campaign in 2003 with the completion of three oil development wells, one of which developed the Douglas West field.

Production during 2002–2003 averaged 52,000 barrels per day of oil and 230 million cubic feet per day of gas (gross).

Bruce / Keith

The Bruce field is located approximately 380 kilometres north-east of Aberdeen in the northern North Sea. We have a 16% interest in the field, which is operated by BP. The integrated oil, gas and LPG development concept for the field has been developed in three phases. During 2002-2003, our gas sales contracts with Centrica and Corby were cancelled and other sales arrangements established. This allowed reserves to be produced without restriction to gas demand and contractual constraints.

Gross production from the Bruce field during 2002–2003 averaged 28,000 barrels per day of oil, 570 million cubic feet per day of gas and 1,600 tonnes per day of LPG.

We also have a 31.83% interest in the Keith field, lying adjacent to the Bruce field in block 9/8a. The Keith field was developed by a tieback to the Bruce platform facilities. In 2002-2003, production from Keith averaged 2,700 barrels per day of oil and 4 million cubic feet per day of gas (gross).

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Exploration and Development

Australia/Asia

Minerva Development

We have a 90% working interest in and act as the operator of the Minerva development that is currently being constructed in southern Victoria.

In 1993, we discovered the Minerva gas field in the Otway Basin and in March 2002 signed a take or pay Sales Agreement with Pelican Point Power Limited (a wholly owned subsidiary of International Power plc) to provide gas into South Australia via a new pipeline. We approved the development of the Minerva field in May 2002. Our share of approved capital expenditure is US$123 million, however, total expected capital expenditure is under review.

Minerva is a natural gas field with a small amount of condensate. A single flowline will transport the gas to the coast, through a subterranean shore crossing to an onshore gas processing facility where liquids will be removed prior to exporting the gas to South Australia. The gas plant, when completed, will have a gross design capacity of 139 million cubic feet of gas per day and 600 barrels of condensate per day.

Coal Bed Methane Development

Our Petroleum and Energy Coal Customer Sector Group’s have a combined 50% interest in the Moranbah Gas Project which is operated by CH4 Pty Ltd. CH4 is an unlisted company, majority owned and controlled by Macquarie Bank Limited. The project, which is situated in within the Queensland Bowen Basin coalfields, will utilise resources in Petroleum Lease (PL) 191 and Petroleum Lease Application (PLA) 196. The project comprises the extraction of coal bed methane from surface-to-seam wells using drilling techniques developed by us and CH4.

We and CH4 have signed a Gas Supply Agreement with the Queensland Power Trading Corporation, owned by the Queensland Government, for delivery of up to a maximum of 290 billion cubic feet (gross) over 15 years, with a take-or-pay quantity of 8 billion cubic feet per annum (gross) for the first 10 years.

Under the May 2000 Project Agreement with CH4, we will receive a revenue royalty on any gas sales plus an option to invest up to 50% in any project developed by CH4. This option has been exercised for the Moranbah Gas Project. Our share of the capital cost of this project is expected to be approximately US$38 million.

Australian Exploration

We are the operator of WA-255-P, holding a 50% working interest, which is located in the prospective Southern Exmouth Basin. We acquired over 1,000 square kilometres of 3-D seismic data in 2001 covering a portion of the WA-255-P permit and have drilled four exploration wells during the first half of calendar year 2003. One of the wells, Stybarrow-1, encountered a 23 metre gross oil column. Stybarrow-2, targetting the same geological feature, encountered a 22 metre gross oil column. Another well, Skiddaw-1, confirmed that the northerly extension of the Laverda field extends a small way into WA-255-P. Evaluation of these encouraging results and other exploration prospects is ongoing.

In 1999, Woodside discovered the Vincent oil field in its 100% held WA-271-P permit. Almost half of this field is now recognised to extend into WA-155-P Part 1, a permit that we operate and in which we have a 39.999% interest. In July 2003, we drilled the Ravensworth-1 exploration well, which targeted another geological feature and encountered a 37 metre gross oil column.

The Coniston-1 discovery , located in block WA-255-P and recognised as extending into WA-155-P Part 1, is currently considered sub-commercial, although this could be revised following successful development of other nearby discoveries such as Vincent.

We also have a 16.67% non-operated interest in the WA-10-R permit offshore Western Australia. In May 2003 the Egret-3 well was completed in this permit and encountered a 29 metre gross oil column and a small gas cap. Egret-2 was drilled in 1988 and encountered a 43 metre oil column in the north of the field. Based upon the results from Egret-2 and 3, the prospect is deemed commercial for further appraisal. An appraisal program is being planned by us and our partners.

We are the operator, holding a 50% interest, in WA-301-P, WA-303-P, WA-304-P and WA-305-P. These permits are located in the Outer Browse basin, a deep water, frontier exploration area. In April 2003 Maginnis-1 was drilled in WA-302-P. In May 2003 we acquired a 510-square kilometer 3D seismic survey on the border of WA-303-P and Wa-304-P. Evaluation of the well and seismic results is ongoing.

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Brunei Exploration

On January 29, 2002 the government of Brunei Darussalam awarded Block J to a joint venture of us (25% working interest), Total (60% working interest) and Amerada Hess Corporation (15% working interest). The award was subject to negotiating a production sharing contract. This was executed in March 2003. The Government of Malaysia have claimed that this block forms part of their territorial waters and has awarded the same acreage to a competing joint venture. The dispute is unresolved.

Americas

Gulf of Mexico

We expanded our presence in the deepwater Gulf of Mexico in the early 1990’s, with the majority of our current deepwater and ultra-deepwater leaseholds acquired at government sales in 1995 and 1996. At June 30, 2003, our deepwater portfolio consisted of 295 leases, making us one of the largest lease-holders in water depths greater than 1,500 feet. Additionally, we acquired 33 leases on the shelf in the Gulf of Mexico in 2003, with water depths ranging from 75 to 125 feet, as we initiated a deep gas exploration strategy. Our shelf inventory consists of 43 leases as of June 30, 2003.

As part of our strategy to efficiently allocate exploration expenditure and to increase our prospect inventory, we have entered into several joint venture arrangements with companies active in the deepwater of the Gulf of Mexico.

Mad Dog Development

The initial Mad Dog discovery well, in the Green Canyon area of the Atwater Foldbelt, was drilled in December 1998 followed by the drilling of three appraisal wells between 1999 and 2001. In February 2002, we and our partners sanctioned Mad Dog for development. Our share of capital expenditure up to US$335 million has been approved. The final expenditure will depend on the number of development wells needed to optimise the production of reserves.

The development plan includes the utilisation of a truss SPAR facility with an integrated drilling rig, which will be capable of operating in water depths of 4,500 feet. First production is expected by the end of calendar year 2004, with production at full design capacity expected to occur within 12 months. Nameplate capacity will be 80,000 barrels of oil per day and 40 million cubic feet of gas per day (gross).

We hold a 23.9% working interest in Mad Dog with partners BP (60.5%), the designated operator, and Unocal (15.6%).

Atlantis Development

The initial Atlantis discovery in the Green Canyon area was drilled in 1998. During calendar years 2000 and 2001 we drilled two more wells, each with major sidetracks, on the Atlantis structure. Both wells encountered significant oil bearing sands.

In February 2003 we approved a total of US$1.1 billion as full funding for the development of the Atlantis oil and gas reserves. First oil is expected from the field in the third quarter of calendar year 2006.

Located in 4,400-7,100 feet of water, Atlantis will be developed using a moored semi-submersible production facility with up to 20 subsea wells. Nameplate capacity will be 150,000 barrels of oil per day and 180 million cubic feet of gas per day (gross).

We have a 44% working interest in Atlantis. BP is the operator of the field and holds the remaining 56% interest.

Transportation Development

In February 2002, we took equity ownership in two limited liability companies that will transport hydrocarbons from Mad Dog, Atlantis and future discoveries in the proximity. The pipelines are part of a new system being built in the Southern Green Canyon area.

We acquired a 25% interest in the Caesar oil pipeline and a 22% interest in the Cleopatra gas pipeline. Our share of capital costs approved by the Board for this project is US$132 million.

The Caesar pipeline will have a design capacity of at least 450,000 barrels of oil per day and Cleopatra will have a capacity of 500 million cubic feet of gas per day. These pipelines will link with other pipelines already existing, or to be constructed, to transport product to the United States mainland.

Cascade – Walker Ridge Exploration

As the operator, in June 2002, we drilled and completed an exploration well on the Cascade prospect and encountered an encouraging hydrocarbon column. The well was drilled in waters approximately 8,200 feet deep to a total depth of 27,979 feet.

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Further drilling will be necessary to determine the size of the find. We expect to drill a second Cascade well in the first half of calendar year 2004. We own a 50% working interest in Cascade, with Petrobras and Devon Energy Corporation each holding a 25% interest.

Shenzi – Green Canyon Exploration

As the operator, we drilled and completed an exploration well on the Shenzi prospect in December 2002. The well was drilled in 4,400 feet of water and encountered a gross hydrocarbon column of 465 feet with 140 feet of net pay. We are planning to drill a Shenzi-2 appraisal well in late–calendar year 2003 to further evaluate the size of the field.

We own a 44% working interest in Shenzi, with Amerada Hess and BP each owning a 28% working interest.

Chinook – Walker Ridge Exploration

As the operator, we drilled and made an oil discovery with our second exploration well on the Chinook prospect in the ultra-deepwater Gulf of Mexico in June 2003. The well was drilled in water depths of approximately 8,830 feet and encountered a gross hydrocarbon column of 620 feet with 260 feet of net pay. Further evaluation will be necessary and more appraisal will be required before we can be definitive about the scale of the resource.

We own a 40% working interest in Chinook, with Petrobras America owning a 30% interest with Amerada Hess and Total each owning a 15% interest.

Neptune Exploration

In 1995, we farmed into the Neptune prospect, which was previously operated by BP, and drilled the discovery well, Neptune-1. A subsequent appraisal well, Neptune-2, was drilled in 1998 and abandoned after recovering hydrocarbon samples.

Subsequent to acquiring BP’s interest with partners Woodside and Marathon, we, as operator, drilled and completed the Neptune-3 appraisal well and encountered an encouraging hydrocarbon column. The fourth appraisal well on the prospect was drilled in December 2002 which was non-commercial and has been temporarily plugged and abandoned.

We recently successfully negotiated a promoted arrangement to farmout a portion of our interest in the Neptune prospect to Maxus (US) Exploration Company, whose ultimate parent is Repsol of Spain. As a result of this arrangement, our working interest has decreased from 50% to 35%. Other partners’ working interests are Marathon Oil Company (30%), Woodside Petroleum Ltd (20%) and Maxus (15%).

Continuing as the operator, in July 2003 we drilled the Neptune-5 well and encountered a gross hydrocarbon column of nearly 1,200 feet, with more than 500 total vertical feet of net oil pay, and further appraisal and development planning activities are continuing on the Neptune prospect.

Other Significant Gulf of Mexico Exploration Joint Venture Agreements

Other significant agreements in the Gulf of Mexico include:

Vortex Prospect (Atwater Valley) – We participated in a gas discovery on the Vortex Prospect in 8,344 feet of water in the Atwater Valley area during 2002-2003. The well was drilled to a total depth of 21,140 feet and sidetracked to a depth of 19,330 feet. We operate this prospect with a 33.34% working interest. Our partners are Kerr-McGee and Devon who each own a 33.33% working interest. We and our partners are assessing development options of this discovery.

Deep Gas Exploration (West Cameron, East Cameron, Vermillion Areas) – In 2002-2003, we entered into a joint venture agreement with Newfield, to explore deep gas on the shelf of the Gulf of Mexico. We own a 55% working interest in these jointly owned leases and act as operator. Newfield owns the remaining 45% working interest. We are acquiring additional seismic data and will be maturing these leads in the near term while monitoring planned industry drilling activity in this trend.

Trinidad and Tobago

Angostura Development

We began exploring in Trinidad and Tobago in Block 2(c) in April 1996, signing the country’s first Production Sharing Contract (PSC) under a new fiscal regime. During the six-year exploration phase of the PSC, we drilled four exploration and three appraisal wells, discovering significant oil and gas resources within a large faulted structure known as the Greater Angostura Structure

In March 2003, we committed to the development of the first phase of the Angostura integrated oil and gas development located in Block 2 (c), approximately 24 miles (38.5 km) east of the island of Trinidad. In the first phase of the development, oil will be produced from three wellhead protector platforms via flowlines to a steel jacket central production platform. Associated gas will be

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reinjected. Water depths are approximately 40 metres and the development utilises proven shallow-water technology. First oil production is scheduled for December 2004. Gas commercialisation (Phase 2) will commence approximately four to nine years after first oil, depending on reservoir performance.

Capital expenditure for the first phase of the Angostura integrated development is expected to be around US$726 million (gross), US$327 million net to BHP Billiton.

We are the operator of the Greater Angostura development and own a 45% working interest. Other participants are Total (30% working interest); and Talisman Energy (25% working interest).

Trinidad and Tobago Exploration

In April 2002, we were awarded the Angostura development area of approximately 100 square kilometres and exploration retention rights for the remaining 160 square kilometre area in south Block 2(c). We have a 64.28% working interest with Talisman Energy holding the remaining 35.72% interest in the exploration retention area. The second of the two commitment wells in this area is being drilled.

In October 2001, Trinidad and Tobago’s Ministry of Energy and Energy Industries announced the award of exploration Block 3(a) to a consortium of BHP Billiton (30% working interest and operator), Talisman Energy (30% working interest), BG International (30% working interest), and Total (10% working interest). The PSC was signed on April 22, 2002. Block 3(a) is located 40 km off the east coast of Trinidad in water depths ranging from 30 to 91 metres and comprises 612 square kilometres adjacent to east of Block 2(c). The Joint Venture commenced the minimum work program with the acquisition of the Emerald 3D seismic survey in 2002- 2003. The survey will be completed in late calendar year 2003. Under the PSC, six wells must be drilled in the first three-year phase of the PSC’s exploration period.

Brazil Exploration

In June 2002, we were successful in bidding for block BM-C-24 that covers 603 square kilometres offshore Brazil . We have a 100% interest in the block. The concession contract was signed in September 2002.

Europe/Africa/Middle East

Algeria

ROD Integrated Development

In Algeria, we hold a 45% working interest in Blocks 401a and 402a under a production sharing contract with the Algerian state oil company SONATRACH. Under the terms of the contract the Algerian government has contracted the development and extraction of the resources whilst retaining title to these resources. The blocks are located 900 kilometres southeast of Algiers, near the Tunisian border.

An integrated plan to develop the ROD, SFNE, BSF, RDB and RERN oil fields (and a subsequent exploration discovery – RAR) partly located in Blocks 401a and 402a has been sanctioned by the Algerian government. The largest two of the fields, ROD and SFNE, extends into the neighbouring Block 403 operated by AGIP and SONATRACH. An agreement has been put in place to govern unitisation of the ROD and SFNE fields, the sharing of specified costs, operatorship and commercial arrangements for the development This agreement leaves us with a 38.75% share of costs in the unit. We have subsequently agreed with AGIP to amend this unitisation agreement with the result that, formally, we shall have a 36.04% share of costs when such an amendment is officially sanctioned by the Algerian authorities. We, together with AGIP, have implemented this revised cost sharing arrangement under the understanding that formal sanction will follow.

The fields are being developed through a new dedicated processing train, which will be built at the existing BRN production facility on Block 403 operated by AGIP and SONATRACH. From there, the venture will export oil through the established pipeline infrastructure to terminals located on the Algerian coast. The associated gas will be re-injected underground. We estimate that our share of the US$500 million development costs will be approximately US$190 million.

We and SONATRACH are the members of the joint operating entity which is undertaking the development. Operations will be conducted by the existing BRN joint operating entity comprising SONATRACH and AGIP. First production from the fields is expected in the first half of calendar year 2004, with an estimated gross peak production rate of 80,000 barrels of oil per day

Ohanet Development

We signed a Risk Service Contract (RSC) with SONATRACH for the development of four gas and condensate reservoirs in the Ohanet region of Algeria on July 2, 2000. Ohanet is located in the Illizi province of Algeria, approximately 1,300 kilometres

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southeast of Algiers and 100 kilometres west of Libya. The Algerian government formally approved the RSC on November 12, 2000. Production is scheduled to begin in late calendar year 2003 and we expect that peak liquids production will be approximately 58,000 barrels per day (gross).

We have an effective 45% working interest in the venture. The other participants are Japan Ohanet Oil & Gas Co Ltd (30%), Woodside Energy (Algeria) Pty Ltd (15%) and Petrofac Resources (Ohanet) LLC (10%). We estimate that the total cost of developing the Ohanet reservoirs will be approximately US$1 billion and that our share of this cost will be US$464 million.

The terms of the RSC specify that the total production from the fields is the property of SONATRACH. The foreign participants in the venture bear the total cost of developing the Ohanet reservoirs, and in return, will recover their investment, together with an agreed fixed profit consideration from liquids production, over a target eight-year period from the start of production. This eight-year period can be extended for up to four years under certain conditions.

The monetary entitlement will be translated into volumes of condensate, butane and propane that will be lifted from export ports on the Algerian coast. These volumes will be determined based on prices posted by SONATRACH.

Gabon Exploration

We hold a 40.12% interest in the Tolo block, situated offshore in the North Gabon Basin. As the operator we drilled one well that was plugged and abandoned. Having satisfied our commitments in Gabon, we are executing an exit strategy.

South Africa

In May 2002, we entered into a farm-in agreement with Global Energy Holdings to acquire a 90% operated working interest in deepwater exploration Block 3B/4B, offshore South Africa.

Marketing

Oil and Condensate

Our global trading and marketing teams based in Houston and Singapore manage the marketing and risk associated with our crude oil, condensate, LPG and petroleum products. We use a combination of floating price short term and long term contracts in both domestic and export markets. The global crude oil and products trading and marketing team forms part of the wider BHP Billiton Group marketing function.

LNG

As part of our expansion plans, we participate with the other North West Shelf joint venture partners in a marketing organisation, NWS Australia LNG, established to market LNG produced from Australian gas resources to overseas buyers. Along with our joint venture partners, we are actively pursuing opportunities in Japan, China, Taiwan and Korea.

LPG

We market our entitlements of LPG produced from the Bass Strait and North West Shelf projects mainly through term contracts with domestic Australian wholesalers of LPG and international LPG end users. Some spot sales are made when LPG produced exceeds our term commitments.

Reserves

The table below details our oil, condensate, LPG and gas reserves, estimated at June 30, 2003, 2002, and 2001 with a reconciliation of the changes in each year. Our reserves have been calculated using the economic interest method and represent our net interest volumes after deduction of applicable royalty, fuel and flare volumes. Our reserves have been subjected to economic tests specified in Statement of Financial Accounting Standard 69 to demonstrate their commerciality under prices and costs existing at the time of the estimates. Our reserves include quantities of oil, condensate and LPG which will be produced under several production and risk sharing arrangements that involve us in upstream risks and rewards but do not transfer ownership of the products to us. At June 30, 2003, approximately 19% (2002: 17 %, 2001: 14 % ) of proved developed and undeveloped oil, condensate and LPG reserves, and nil amount (2002: nil, 2001: nil) of natural gas reserves are attributed to those arrangements. Our reserves also include volumes calculated by probabilistic aggregation of an area level for fields that share common infrastructure. These aggregation procedures result in enterprise-wide proved reserve volumes, which may not be realised upon divestment on an individual property basis.

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Proved Developed and Undeveloped Oil, Condensate and LPG Reserves⁽¹⁾	Australia/Asia		Americas		Europe/Africa/ Middle East		Total
	(millions of barrels)
Reserves at June 30, 2000	438.3		28.6		90.1		557.0

Improved Recovery	0.4		—		—		0.4
Revisions to previous estimates	5.3		0.5		0.5		6.3
Extension, Discoveries and Other	4.4		67.6		74.1		146.1
Purchases and Sales	(0.9	)	3.8		(18.3	)	(15.4	)
Production⁽²⁾	(70.7	)	(4.2	)	(12.2	)	(87.1	)

Total changes	(61.5	)	67.7		44.1		50.3

Reserves at June 30, 2001	376.8		96.3		134.2		607.3

Improved Recovery	—		—		—		—
Revisions to previous estimates	12.1		3.2		(11.0	)	4.3
Extension, Discoveries and Other	3.4		70.2		—		73.6
Purchases and Sales	—		—		—		—
Production⁽²⁾	(63.3	)	(9.0	)	(14.3	)	(86.6	)

Total changes	(47.8	)	64.4		(25.3	)	(8.7	)

Reserves at June 30, 2002	329.0		160.7		108.9		598.6

Improved Recovery	0.0		0.0		0.1		0.1
Revisions to previous estimates	52.2		(12.2	)	12.2		52.2
Extensions, Discoveries and Other	0.5		10.1		3.9		14.5
Purchases and sales	0.0		0.0		0.0		0.0
Production ⁽²⁾	(55.1	)	(6.6	)	(11.7	)	(73.4	)

Total changes	(2.4	)	(8.7	)	4.5		(6.6	)

Reserves at June 30 2003	326.6		152.0		113.4		592.0	⁽³⁾

Proved Developed Oil, Condensate and LPG Reserves	Australia/Asia	Americas	Europe/Africa/ Middle East	Total
	(millions of barrels)
Reserves at June 30, 2000	334.2	11.3	46.3	391.8
Reserves at June 30, 2001	268.6	9.4	40.9	318.9
Reserves at June 30, 2002	233.1	15.9	30.2	279.2
Reserves at June 30, 2003	227.8	9.9	24.5	262.2

(1)	In Bass Strait, the North West Shelf and the North Sea, LPG is extracted separately from crude oil and natural gas.

(2)	Production for reserves reconciliation differs slightly from marketable production due to timing of sales and corrections to previous estimates.

(3)	Total proved oil, condensate and LPG reserves include 20.9 million barrels derived from probabilistic aggregation procedures.

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Proved Developed and Undeveloped Natural Gas Reserves	Australia/Asia⁽¹⁾		Americas		Europe/Africa/ Middle East		Total
	(billions of cubic feet)
Reserves at June 30, 2000	4,142.9		142.4		705.0		4,990.3

Improved Recovery	—		—		—		—
Revisions to previous estimates	72.8		(26.4	)	(43.9	)	2.5
Extension, Discoveries and Other	32.9		38.5		—		71.4
Purchases and Sales	—		6.1		—		6.1
Production⁽²⁾	(170.2	)	(21.5	)	(67.1	)	(258.8	)

Total changes	(64.5	)	(3.3	)	(111.0	)	(178.8	)

Reserves at June 30, 2001	4,078.4		139.1		594.0		4,811.5

Improved Recovery	—		—		—		—
Revisions to previous estimates	3.9		2.7		(35.8	)	(29.2	)
Extension, Discoveries and Other	605.9		37.3		—		643.2
Purchases and Sales	—		—		—		—
Production⁽²⁾	(187.4	)	(25.1	)	(69.0	)	(281.5	)

Total changes	422.4		14.9		(104.8	)	332.5

Reserves at June 30, 2002	4,500.8		154.0		489.2		5,144.0	⁽³⁾

Improved Recovery	0.0		0.0		16.7		16.7
Revisions to previous estimates	404.1		4.9		(7.0	)	402.0
Extensions, Discoveries and Other	188.9		10.2		0.0		199.1
Purchases and Sales	0.0		0.0		0.0		0.0
Production⁽²⁾	(189.2	)	(21.8	)	(79.9	)	(290.9	)

Total Changes	403.8		(6.7	)	(70.2	)	326.9

Reserves at June 30, 2003⁽³⁾	4,904.6		147.3		419.0		5,470.9

Proved Developed Gas Reserves	Australia/Asia	Americas	Europe/Africa/ Middle East	Total
	(billions of cubic feet)
Reserves at June 30, 2000	2,437.0	125.9	522.4	3,085.3
Reserves at June 30, 2001	2,303.2	84.6	550.2	2,938.0
Reserves at June 30, 2002	2,455.1	79.9	481.9	3,016.9
Reserves at June 30, 2003	2,560.4	64.8	397.1	3,022.3

(1)	Production for Australia includes gas sold as LNG.

(2)	Production for reserves differs slightly from marketable production due to timing of sales and corrections to previous estimates.

(3)	Total proved natural gas reserves include 233.2 billion cubic feet derived from probabilistic aggregation procedures.

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Production

The table below details our historical net crude oil and condensate, natural gas, LNG, LPG and ethane production by region for the three years ended June 30, 2003. We have shown volumes and tonnages of marketable production, after deduction of applicable royalties, fuel and flare. We have included in the table average production costs per unit of production and average sales prices for oil and condensate and natural gas for each of those periods.

	Year ended June 30,
	2003	2002	2001
Crude Oil and Condensate Production
(millions of barrels)
Australia/Asia	48.0	56.2	64.3
Americas	7.1	9.0	3.7
Europe/Africa/Middle East	10.8	13.3	11.1

Total	65.9	78.5	79.1

Natural Gas Production⁽¹⁾
(billions of cubic feet)
Australia/Asia	126.4	126.0	115.5
Americas	20.6	25.2	21.3
Europe/Africa/Middle East	72.2	72.7	68.3

Total	219.2	223.9	205.1

Liquefied Natural Gas (LNG) Production⁽²⁾
(thousand tonnes)
Australia/Asia (leasehold production)	1,349	1,298.8	1,241.8

Liquefied Petroleum Gas (LPG) Production⁽³⁾
(thousand tonnes)
Australia/Asia (leasehold production)	644.2	612.0	582.1
Europe/Africa/Middle East (leasehold production)	98.9	85.6	91.5

Total	743.1	697.6	673.6

Ethane Production
(thousand tonnes)
Australia/Asia (leasehold production)	94.9	87.1	67.4
Average Sales Price
Oil and Condensate (US$ per barrel)⁽⁴⁾	28.14	22.58	29.39
Natural gas (US$ per thousand cubic feet)	2.21	1.84	1.73
Average Production Cost⁽⁵⁾
US$ per barrel of oil equivalent (including resource rent tax and other indirect taxes)	8.01	5.83	8.19
US$ per barrel of oil equivalent (excluding resource rent tax and other indirect taxes)	3.55	2.38	2.48

(1)	Natural gas production figures exclude gas sold as LNG or ethane.

(2)	LNG consists primarily of liquefied methane.

(3)	LPG consists primarily of liquefied propane and butane.

(4)	Oil and condensate prices net of commodity hedging were US$28.14 for 2002-2003, US$22.58 for 2001-2002, and US$28.04 for 2000-2001.

(5)

Average production costs include direct and indirect production costs relating to the production and transportation of hydrocarbons to the point of sale. This includes shipping where applicable. Average production costs have been shown including and excluding resource rent tax and other indirect taxes and duties. The average production cost also include the foreign exchange affect of translating local currency denominated costs and indirect taxes into US$.

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Regulatory and Fiscal Terms

Australia

Oil and natural gas belong to the government and rights to explore and produce oil and natural gas are granted by the relevant State, Territory or Commonwealth Government of Australia. The Commonwealth Government has legislative responsibility for Australian offshore petroleum exploration and production beyond the three-mile territorial sea limit, which encompasses the area of most relevance to us in Australia. Our operations in this area are governed by the Petroleum (Submerged Lands) Act 1967 (PSLA). Within the three-mile limit, petroleum operations are governed by the adjacent State or Northern Territory legislation that is similar to the PSLA. Most production licenses we hold in the North West Shelf, Bass Strait and Timor Sea regions have been issued under the PSLA.

An exploration permit authorises the holder to explore for, but not produce, petroleum in the area that is the subject of the permit. Offshore exploration permits are awarded based on either cash bidding or work program bidding for an initial period of six years. The holder of a permit granted under the work program bidding system is required to complete a minimum guaranteed dry-hole work program for the first three years of the permit and secondary work program for the subsequent three years. Under the cash bidding system, permits are awarded to the highest cash bidder and applicants are not required to submit exploration programs.

Exploration permits may be renewed for five-year periods in respect of half the number of blocks contained within the existing permit. A production license may be applied for after a discovery is made. It authorises the licensee to recover petroleum and explore for petroleum in the license area for a term of 21 years with rights of renewal for successive periods of 21 years.

The expiry dates of our existing production licenses in Australia are as follows:

License Name	Field	Expiry Date
VIC/L1-2	Barracouta, Whiptail, Tarwhine and Whiting	August 24, 2009
VIC/L3-4	Marlin, Batfish and Turrum	August 24, 2009
VIC/L5-6	Halibut, Mackerel, Yellowtail and Gudgeon	September 19, 2010
VIC/L7-8	KingfFish	September 19, 2010
VIC/L9	Tuna	July 12, 2016
VIC/L10	Snapper, Moonfish and Sweetlips	May 28, 2018
VIC/L11	Flounder	May 28, 2018
VIC/L13-14	Bream	December 15, 2006
VIC/L15-16	Dolphin	June 13, 2010
VIC/L17	Perch	June 13, 2010
VIC/L18	Seahorse	June 13, 2010
VIC/L19	West Fortescue	July 12, 2016
VIC/L20	Blackback/Terakihi	January 1, 2019
VIC/L22	Minerva	September 16,2023
WA-1-L to WA-6-L	North Rankin, Goodwin and Angel	September 29, 2022
WA-9-L	Wanaea and Cossack	April 11, 2012
WA-11-L	Wanaea	September 30, 2014
WA-16-L	Hermes and Lambert	September 11, 2018
AC/L5	Laminaria and Corallina	February 5, 2018
WA-18-L	Laminaria East	May 12, 2020
WA-10-L	Griffin, Chinook and Scindian	February 18, 2014

Secondary taxes – Australia

A petroleum resource rent tax applies to offshore areas, with the exception of the North West Shelf project. The North West Shelf project is subject to excise and royalty on oil production and royalty on LNG, domestic gas, LPG and condensate production.

The petroleum resource rent tax is assessed before company income tax and the amount of petroleum resource rent tax paid is a deduction for the purpose of calculating company income tax.

The petroleum resource rent tax is payable when project cash flows become positive, after taking into account all allowable exploration, development and operating costs, and after a stipulated return on the project has been achieved. Exploration expenditure has a stipulated return of 15% plus the Australian government long-term bond rate, and project expenditure has a stipulated return of 5% plus the long-term bond rate. The long-term bond rate for the year ended 30 June 2003 was 5.34%.

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Americas

Our current operations in the Americas principally fall under three separate fiscal regimes, namely, the United States, Bolivia and Trinidad and Tobago. In the United States, operations are predominantly in Federal offshore waters in the Gulf of Mexico. Revenues from this area carry royalty interests of 16.67% in water depths up to 400 metres and 12.5% in water depths greater than 400 metres. In addition, a 35% tax rate is also levied on taxable income. The United States Outer Continental Shelf Deep Water Royalty Relief Act 1995 authorises the US Secretary of the Interior to offer certain deepwater outer continental shelf tracts in the central and western Gulf of Mexico for lease with suspension of royalties. In addition to automatic royalty relief, the government can also grant royalty reduction or elimination at its discretion if a project warrants.

The lease conditions for our existing production in the Gulf of Mexico are such that each lease shall continue from the effective date, for the initial period, and for so long thereafter as oil or gas is produced from the leased area.

In December 2000, the US Minerals Management Service granted royalty relief up to 87.5 million barrels of oil equivalent produced from the Typhoon field, subject to commodity price ceilings. The Boris field also qualifies for royalty relief.

In Bolivia, a tax-royalty regime provides for a two-tier government take: existing hydrocarbons (pre-April 30, 1996) 50%; and new hydrocarbons (post-April 30, 1996) 18%. Of the 50% take on existing hydrocarbons, 13% is available to be reduced by the payment of corporate income tax. Production from all fields is subject to a surtax of 25% that is applicable in certain situations. The corporate income tax rate is 25% and there is a remittance tax of 12.5% on repatriated funds.

In January 2003, the new government in Bolivia issued a new Supreme Decree that altered the prices received by producers of crude oil. Specifically, this introduced a new export parity price reduction of US$4.50 per barrel (up from US$1.60 per barrel) and also required the price received to be based on a lagging 365-day average rather than the average crude oil price for the month prior to the sale month.

In Trinidad and Tobago, the production sharing contracts allow the contractor to recover its cost from 35%, in the case of oil, or 50%, in the case of gas, of the revenue from production in Block 2(c), Block 2(ab) and Block 3(a). The remaining production is deemed to be “profit crude oil” or “profit natural gas” which is split between the Government and contractor according to a formula based on daily production levels and the respective oil or natural gas prices. The government’s share of “profit crude oil” ranges from 50% to 80% for Blocks 2(ab) and 2(c) and from 53% to 83% for Block 3(a) from which Trinidadian taxes are paid on behalf of the contractor. The government’s share of “profit natural gas” ranges from 50% to 65% for all three Blocks from which the Trinidadian taxes are paid on behalf of the contractor.

United Kingdom

In the United Kingdom, the Crown owns all petroleum under land, the territorial sea and the UK Continental Shelf. A license is required for exploration or production. The Secretary of State for Trade and Industry is empowered to grant licenses, on conditions approved by the Secretary, and has wide powers of regulation of all aspects of exploration and production. The UK corporate tax rate, applicable to offshore Petroleum production, is 40% (30% primary tax plus a surcharge of 10%).

The expiry dates of our existing production licenses in the United Kingdom are as follows:

License Name	Block	Field (s)	Expiry date
P.710	110/13a and 110/13b	Douglas, Douglas West, Hamilton, Hamilton North and Hamilton East	July 18, 2007
P.791	110/15b	Lennox	June 12, 2009
P.099	110/14b	Lennox and Hamilton East	June 8, 2016
P.276	9/9b	Bruce	April 11, 2015
P.209	9/8a	Bruce and Keith	March 15, 2018
P.090	9/9a	Bruce	November 24, 2011

Algeria

Oil and gas are owned by the Algerian state. Mining licenses are granted to SONATRACH, the state-owned oil company. SONATRACH, in turn, is empowered by Algerian legislation to enter into contractual arrangements with non-Algerian enterprises covering the exploration and/or exploitation of oil and gas fields. Where the contractual form is either that of a production sharing or risk service contract, then the non-Algerian enterprise is liable to Algerian tax, but SONATRACH pays this on their behalf. The ROD integrated oil development partly located in Blocks 401a/402a is under a production sharing contract, and the Ohanet development is under a risk service contract.

The ROD production sharing contract allows the Contractor to recover its costs out of a maximum of 72.5% of the annual production of crude oil and natural gas liquids from the fields that are covered by the production sharing contract. The remaining

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production is split as between Sonatrach and the Contractor according to a formula based upon daily production levels.Sonatrach’s share of such production ranges from 56% to 78%, out of which Algerian taxes and royalty are paid on behalf of the Contractor, provided that the Contractor is not entitled to more than 49%, in aggregate, of the annual production of crude oil and natural gas liquids, except in calendar years 2004 and 2005. This may be adjusted in calendar year 2009.

With regard to Ohanet, the risk service contract provides that the Ohanet field shall be developed by the Contractor, the cost of which to be capped at approximately $US928 million (as may be adjusted). The Contractor is entitled to the reimbursement of the cost of development, operating costs and a level of remuneration set at 106.9% of the amount referred to above. These amounts are to be recovered out of a maximum of 49% of the annual production of LPG and condensate from the Ohanet field. Sonatrach is entitled to the remainder of the production, from which Algerian royalty and taxes are paid on behalf of the Contractor.

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Aluminium

Our Aluminium Customer Sector Group is principally involved in the production of aluminium and alumina.

Hillside

We own the Hillside aluminium smelter, which we commissioned between July 1995 and June 1996. Hillside is located in Richards Bay, 200 kilometres north of Durban, KwaZulu-Natal, South Africa. Hillside currently produces approximately 530,000 tonnes of aluminium per year using the Aluminium Pechiney AP30 technology. In February 2002, our Board of Directors approved an increase in Hillside’s production capacity by adding a third (half-size) potline, which is expected to add a further 132,000 tonnes per annum of primary aluminium capacity. First metal production from the new potline facilities is now expected in the fourth quarter of 2003 with full production expected in the first quarter of calendar year 2004. Expenditure to date remains in line with the budgeted US$449 million.

We mostly produce primary aluminium. We sell most of our primary aluminium in standard ingot form, principally to export markets in the Far East, Northern Europe and the United States. We also sell aluminium in liquid metal form to our Bayside operations, which casts it into products for the manufacture of aluminium value-added products such as alloy wheels.

We own all of Hillside’s property, plant and equipment, including the land on which it is located. In addition, we own silos, buildings and overland conveyors at Richards Bay Port which sit on leased land. Our lease is for ten years, which expires in 2009 and we have extension options. We have to reline the pots we use in our reduction process every five to six years. Our first relining cycle at Hillside is complete.

The principal raw materials required for our aluminium production operations at Hillside are alumina, petroleum coke, liquid pitch and electricity. Alumina requirements are sourced 50% from our Worsley business and 50% from Alcoa. We import approximately 195,000 tonnes per year of calcined petroleum coke from American suppliers and approximately 45,000 tonnes of liquid pitch each year primarily from Deza and D.C. Chemicals. We purchase our electricity from Eskom, the local state-owned power generation company under a long-term contract with pricing linked to the aluminium price on the London Metal Exchange.

Bayside

We own the Bayside aluminium smelter, which was commissioned in 1971. Bayside is located at Richards Bay, KwaZulu Natal, South Africa. Bayside currently produces approximately 180,000 tonnes of aluminium per year. The smelter uses Alusuisse pre-bake and Soderberg self-bake technologies.

We generate approximately 85% of our sales revenue from the domestic market, which consists of South Africa and the surrounding countries. Our main products include wheel rim alloy, for use in the manufacturing of vehicle rims, extrusion billets, for use in the building industry, rods, for use mainly as electrical cables, and rolling ingot, for use mainly in the production of aluminium sheeting.

The principal raw materials required for our aluminium production at Bayside are alumina, petroleum coke, liquid pitch and electricity. Our alumina is sourced approximately 50% from Worsley and 50% from Alcoa. We purchase approximately 70,000 tonnes per year of calcined petroleum coke from American suppliers and approximately 24,000 tonnes of liquid pitch each year from primarily Suprachem, a locally based manufacturer. We purchase our electricity from Eskom under a power supply agreement which links the cost of electricity to the aluminium price on the London Metal Exchange.

Mozal

We own a 47% interest in the Mozal aluminium smelter, which was commissioned in June 2000. The remaining interest in Mozal is owned by Mitsubishi, which owns a 25% interest, Industrial Development Company of South Africa Limited, which owns a 24% interest, and the government of Mozambique, which owns a 4% interest. The smelter is located in southern Mozambique, on the east coast of Southern Africa, 17 kilometres from Maputo. It is located approximately 5 kilometres from the nearest port facilities. The smelter uses the Aluminium Pechiney AP30 technology.

Mozal produced its first metal in June 2000 and has a nameplate design capacity of 250,000 tonnes per year. Our share of production for 2002-2003 was 134,000 tonnes. In June 2001 the joint venture approved an increase in Mozal’s production capacity by adding a second potline, effectively doubling Mozal’s production capacity. On 7 April 2003 the second potline cast first metal five months ahead of schedule. Final expansion costs are expected to be around US$665 million (US$313 million BHP Billiton share), well below the budget of US$860 million (US$405 million BHP Billiton share). The joint venture produces standard ingot. Based on our ownership interest, we are allocated 47% of Mozal’s total production. We export most of our share of Mozal’s production to Europe.

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The principal raw materials required for the aluminium production operations at Mozal are alumina, petroleum coke, liquid pitch and electricity. We furnish approximately 480,000 tonnes of alumina per year to Mozal, which represents its entire alumina requirements. This amount will double to 960,000 tonnes of alumina per year when the second potline becomes fully operational. We purchase most of our petroleum coke requirements from American suppliers. The joint venture purchases its electricity from the South African grid from Motraco, a joint venture between Elecricidade de Mozambique, Eskom and the Swaziland Electricity Board, under a power supply agreement which in the first 12 years is at a fixed tariff and thereafter is linked to the aluminium price on the London Metal Exchange.

Worsley

We increased our interest in the Worsley joint venture from 30% to 86% in January 2001. The Worsley joint venture is an integrated bauxite mining and alumina refining operation located in Western Australia. The other participants in the venture are Nissho Iwai Alumina Pty. Limited, which owns a 4% interest, and Kobe Alumina Associates (Australia) Pty Limited, which owns a 10% interest. The refinery is located approximately 55 kilometres southwest of Bunbury and the bauxite mining operation is linked to the refinery via a 51 kilometres overland conveyor.

The mine produces approximately 11 million tonnes of bauxite per year from extensive near surface deposits. The venture operates its mine on a 2,600 square kilometre mining lease. The joint venture was granted an initial 21-year lease by the Government of Western Australia in 1983, with two 21-year renewal options. There is a possibility the joint venture may benefit from a third 21-year renewal under renegotiated terms. At current production rates, the venture expects the mining life of the reserves at Worsley to be approximately 30 years.

The refinery, utilising the Bayer process, currently produces approximately 3.2 million tonnes of alumina per year, having reached this design output in April 2001 following the completion of a major expansion. The joint venture produces mostly metallurgical grade alumina, which is used as feedstock for aluminium smelting. Our share of alumina production at the refinery is approximately 2.7 million tonnes per year. Our alumina is railed to a shared berth facility at the port of Bunbury, and dispatched from there by ship directly to end-use customers.

The principal raw materials required for alumina production at Worsley, apart from bauxite, are caustic soda, natural gas used for calcinations and steam generation and coal for the power station. We currently source our caustic soda requirements from the Middle East and Japan. Supply agreements are usually negotiated for periods of two to three years, with pricing reviewed on a six monthly basis linked to industry published data. The power and steam needed by the refinery is provided by a venture owned onsite coal fired power station and a non-venture owned onsite gas fired power station. Coal for the power station is supplied from the nearby Collie colliery under a medium term contract at competitive rates while natural gas is piped in from the northwest of Western Australia.

Suriname

On August 4, 2003 we announced the restructuring of our mining joint venture arrangements with Suriname Aluminium Company, L.L.C (Suralco). Under the new arrangement BHP Billiton Maatschappij Suriname manages all mining operations while Suralco continues to manage the alumina refining in the restructured 45% (BHP Billiton)—55% (AWAC) venture. The arrangement consists of two unincorporated joint ventures, covering respectively the bauxite exploration & mining and the alumina refining activities. The mining joint venture exploits the Lelydorp and Coermotibo deposits, carries out exploration work and new mine development for future bauxite supply. The mining joint venture produces metallurgical grade bauxite, which is processed by the refining joint venture’s alumina plant at Paranam.

The Lelydorp III mine, an open pit mine located in the coastal plain of Suriname, is situated approximately 25 kilometres south of Paramaribo and 17 kilometres west of the Paranam Refinery. The mine has a nominal production capacity of 2.25 million tonnes per annum.

The Coermotibo operations, a surface strip mine located 150 km east of the Paranam refinery produces 1.9 million tons of metallurgical grade bauxite ore per annum. The ore is hauled to the Coermotibo crushing and loading facility and subsequently barged to the Paranam refinery.

Exploration and Exploitation rights

We hold exploitation licenses with respect to the Para and Kankantrie deposits. These licenses were recently extended to 2026. Suralco holds exploitation licenses over the current Lelydorp III deposit as well as over the bauxite deposits in the Coermotibo operations. Suralco also holds exploitation licences over the Browns mountain, Nassau mountain and Lely mountain deposits in southern Suriname. These licenses expire in 2032. Furthermore, BHP Billiton and Suralco jointly hold the exploration license over the Bakhuis region in western Suriname. The rights over this 2780 km² terrain were granted in August 2003 for a period of 2 years with options for extension.

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All the above mentioned bauxite rights were made available to the new mining joint venture.

The deposits contained in the above exploitation rights of both companies are currently being evaluated to determine the economically most attractive bauxite feed to the Paranam refinery after depletion of the Coermotibo and Lelydorp III deposits by 2007.

Refining joint venture

The refining joint venture operates an alumina refinery and port facilities located at Paranam, at the Suriname River. Alumina exports take place from the Paranam port.

The refining joint venture’s alumina plant is a low temperature plant which uses standard Bayer plant technology. The refinery produces approximately 1.95 million tonnes of alumina per year. Our share was 879,000 tonnes in 2002-2003.

In August 2003, we, along with Suralco, approved the expansion of the refinery by 250 000 metric tonnes per year to a capacity upon completion of approximately 2.2 million metric tonnes per year. The US$ 85 million expansion is targeted to be complete by July 2005.

All alumina produced is exported to Europe. The refinery has three thermal generators, which provide the steam and electricity necessary for the process. The generators run on fuel oil supplied by the local state oil company. Caustic soda used in the refinery process is imported from the United States.

Alumar

The Alumar Consortium (Alumar) is an unincorporated joint venture comprised of an alumina refinery, an aluminium smelter and support facilities. We own a 46.3% interest in the aluminium smelter and Alcoa Aluminio S.A. (Alcoa) owns the remaining 53.7%. We own a 36% interest in the alumina refinery, an affiliate of Alcan Aluminium Limited (Alcan) owns 10%, Alcoa owns 35.1%, and Abalco S.A. (owned 60% by Alcoa and 40% by Alumina Limited) owns the remaining 18.9% . The alumina and aluminium plants are integrated, located in the industrial district of São Luís, the capital of the state of Maranhão, in northern Brazil.

Total annual smelter production, using Alcoa technology, is approximately 380,000 tonnes of aluminium per year. Alumina arrives by conveyor from the adjoining refinery and electricity generated at the Tucuruí hydroelectric dam arrives via two transmission lines. We purchase our electric power requirements from Central Elétricas do Norte (Electronorte) under a long- term contract that will expire in 2004. Most of the production is standard ingots, and we sell a quarter of our share of the ingots to domestic customers with the balance sold on the export market.

The refinery began production in 1984. Subsequently it has been expanded several times. Total production has now reached approximately 1.3 million tonnes per year. The required raw materials, caustic soda, coal, and bauxite, are delivered by ship to the Alumar port. Our share of the alumina is allocated to the Alumar smelter and to the Valesul smelter. Approximately 10% of our production share is sold on the export market.

We own 14.8% of Mineraçao do Rio Norte S.A. (MRN), a Brazilian mining company jointly owned by affiliates of Alcoa, Alcan, Companhia Brasileira de Alumínio (CBA), Companhia Vale do Rio Doce (CVRD) and Norsk Hydro. MRN was incorporated and began its operations in 1967. MRN extracts, processes and supplies bauxite. We have long-term contracts with MRN to supply the Alumar refinery. In March 2000, the MRN board approved a US$220 million expansion of bauxite mining production from 11 million tonnes to 16.3 million tonnes per annum. The additional production started at the beginning of 2003. Currently, MRN has total ore reserves that would allow it to produce 16.3 million tonnes of bauxite per annum for approximately 8 years. The mine is actively pursuing an evaluation program of bauxite plateaus within the remaining lease area to establish the overall life of the project. MRN holds valid mining rights to all its reserves until exhaustion of the reserves.

During 2001-2002, we joined two consortia with the objective of participating in auctions being held by the Brazilian Electricity Regulatory Agency (ANEEL) for concessions to build and operate proposed Hydropower Plants. The first is made up of affiliates of Alcoa, CVRD, Votorantim and Camargo Correa Energia S.A. We own a 20.6% interest in this consortium. In 2001 the consortium won the auction for the Santa Isabel Baixa concession and later signed the concession contract. The Federal Environmental Agency (IBAMA) has declared the project not viable as presented, therefore the consortium has requested ANEEL to return the concession guarantees and to revoke the concession agreement.

Our partners in the second consortium are affiliates of Alcoa, CVRD, Tractebel and Camargo Correa Energia S.A. We own a 16.5% interest in this consortium. This consortium won the auction for the Estreito concession in July 2002 and the Estreito concession contract was signed in December 2002. We are awaiting further definition of requirements from IBAMA regarding environmental issues before the project can be progressed further. No further auctions are currently planned.

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Valesul Aluminio SA

We own a 45.5% joint venture interest in Valesul Aluminio SA, an aluminium smelter located in Rio de Janeiro, Brazil. The balance is held by the CVRD group. The port of Sepetiba is less than 40 kilometres away and the Port of Rio de Janeiro is less than 60 kilometres away.

Valesul began production in 1981. It currently produces approximately 93,000 tonnes of aluminium per year based on P19 Reynolds technology. The Valesul cast house can supply a wide range of aluminium products for the extrusion, cable and automotive industries. The vast majority of alloys, ingots and billets are sold domestically to independent fabricators. A small portion is exported. With respect to required raw materials, alumina arrives by ship while petroleum coke and liquid pitch arrive by truck. Valesul owns four small hydroelectric stations and has an 8% effective participation in the Maesa hydroelectric consortium which operates the Machadinho hydroelectric plant. Since Machadinho reached full operation in July 2002, Valesul only draws power from the grid during the off-peak period.

Reserves and Production

The table below details our bauxite-ore reserves in metric tonnes, and are presented in 100% terms as estimated at June 30, 2003.

	Proved Ore Reserve^{(1)(2)(3)(4)(7)}		Probable Ore Reserve⁽^1)(2)(3)(4)		Total Ore Reserve		BHP Billiton Interest %
Deposit	Tonnes (millions)	Grade %Alumina	Tonnes (millions)	Grade %Alumina	Tonnes (millions)	Grade %Alumina	BHP Billiton Interest %
Australia⁽⁵⁾Worsley	314	30.7	12	30.9	326	30.7	86
Suriname⁽⁵⁾Lelydorp	9.3	52.5	—	—	9.3	52.5	76
Brazil⁽⁶⁾
MRN Crude	171	—	—	—	171	—	14.8
MRN Washed	122	50.5	—	—	122	50.5	14.8

(1)	Mine dilution and recovery are included in the reserve statements for each deposit.

(2)	Alumina as available alumina.

(3)	Approximate drill hole spacings used to classify the reserves are:

	Proven Ore Reserves	Probable Ore Reserves
Worsley	100m or less grid spacing	200m or less grid spacing

Lelydorp	61m x 61m	No reserve quoted in this category

MRN	200m grid spacing or less with mining and metallurgical characterisation (test pit/bulk sample) plus a reliable suite of chemical and size distribution data	No reserve quoted in this category

(4)	Third party reserve audits have not been conducted on our reserves for the purposes of this annual report.

(5)

Worsley Alumina Pty Ltd (Worsley) and Lelydorp reserve tonnages are quoted on a dry basis. Note that our interest in the Lelydorp operation has, subsequent to June 30, 2003, dropped to 45% in exchange for a 45% interest in the Moengo-Coermotibo operation as discussed in the Aluminium description of business.

(6)	Mineracao Rio de Norte washed reserve tonnages and grades are quoted on a nominal 5% moisture content basis.

(7)	Aluminium price used to test the economic viability of the ore reserves is US$1,426 per tonne.

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The table below details our alumina and aluminium production for the three years ended June 30, 2003. Production data shown is our share unless otherwise stated.

	BHP Billiton Group Interest		BHP Billiton Group Share of Production
			Year ended June 30,
			2003	2002	2001
			(thousands of tonnes)
Alumina⁽¹⁾
- Worsley⁽²⁾	86	%	2,742	2,696	1,632
- Suriname	45	%	879	850	852
- Alumar	36	%	471	396	454

Total			4,092	3,942	2,938

Aluminium⁽¹⁾
- Hillside	100	%	534	502	498
- Bayside	100	%	185	174	178
- Mozal⁽³⁾	47	%	134	127	93
- Alumar	46.3	%	178	152	172
- Valesul	45.5	%	43	37	43

Total			1,074	992	984

(1)	These were operations of the BHP Billiton Plc Group prior to the DLC merger with the BHP Billiton Limited Group on June 29, 2001.

(2)	Our interest in Worsley increased from 30% to 86% effective January 2001.

(3)	Mozal produced its first metal in June 2000 and achieved full commissioning of its 250,000 tonnes per annum capacity in December 2000.

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Regulatory and Fiscal Terms

Australia - Western Australia

In Western Australia, minerals in the ground belong to the government, and rights to mine are granted by the state. The Worsley joint venture operates under a State Agreement made under the Alumina Refinery (Worsley) Agreement Act 1973 (as amended). The Worsley joint venturers are permitted, under the State Agreement, to explore for and mine bauxite and to refine it into alumina.

South African Mining Charter

For a discussion of the South African mining charter refer to the discussion in relation to “Business Description – Carbon Steel Materials – Regulatory and Fiscal Terms – South African Mining Charter”.

Market Conditions

The aluminium market remained weak in 2002-2003, reflecting the ongoing market surplus. Concerns about the rate of new smelter capacity additions weighed on market sentiment, despite the recovery in global demand from the weak levels in calendar year 2002. Involuntary smelter closures due to high power prices or low power availability, a shortage of aluminium scrap in the US and strong Chinese domestic consumption have combined to improve market prospects.

The smelter grade alumina market recovered strongly. The spot free-on-board alumina price more than doubled from $140/t at the end of calendar year 2002 to $300/t by mid calendar year 2003. This development mainly reflects increased demand due to large smelter capacity additions in China and elsewhere. Spot alumina sales account for about 20% of the third party market with the bulk of sales being tied up in long-term contracts. With industry utilisation at historically high levels, and large ongoing expansion in smelting capacity, the prospects for alumina appear sound.

The diverging prospects for aluminium and alumina reflect their different industry structures and underlying economics.

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Base metals

Our Base Metals Customer Sector Group is comprised of our assets and interests in copper, silver, lead, zinc and gold. We provide base metals concentrates to smelters worldwide and copper cathodes to rod and brass mills and casting plants.

Copper

We are one of the world’s top four producers of copper. The Escondida copper mine in northern Chile is the world’s largest and one of the lowest-cost sources of copper. Our other key Base Metals assets include the Cerro Colorado copper mine in northern Chile, the Tintaya copper mine and Antamina copper and zinc operations in Peru, and the Cannington silver, lead and zinc mine in Australia. We also have a number of greenfield and brownfield expansion opportunities.

In December 2002, we announced that we would continue our program of demand-based production in the Base Metals Group originally announced in November 2001. During calendar year 2003, we will target an annualised production rate of 1.05 million tonnes of copper at our Escondida mine (150,000 tonnes of cathode and 900,000 tonnes of copper contained in concentrate), and 34,000 tonnes of cathode at our Tintaya mine. Installed capacity at Escondida is 1.25 million tonnes per annum and capacity at Tintaya is 124,000 tonnes per annum. The decision for an orderly return to full production at Tintaya was approved in August 2003.

Escondida

We hold a 57.5% interest in Escondida, an open-pit copper mine accessible by road and located in northern Chile’s Atacama Desert, at an altitude of approximately 3,100 metres, 160 kilometres southeast of the port city of Antofagasta. The other owners are affiliates of Rio Tinto plc, which hold a 30% interest, JECO, which holds a 10% interest, (Mitsubishi Corporation, 7%, Mitsubishi Materials Corporation, 1%, Nippon Mining and Metals Company Limited, 2%), and the International Finance Corporation, which holds a 2.5% interest.

Escondida has committed its forecast annual copper concentrate production under long-term sales contracts ranging in duration from 5 to 10 years. Expiration of these contracts varies, with the earliest being at the end of calendar year 2003 and the latest in 2012. Forecast production is fully committed (though not 100% priced) through to the end of calendar year 2004, under long-term contract arrangements. Approximately 70% of annual cathode production is sold under annual contracts to end-users and traders located primarily in Europe, the Far East and Brazil and the remainder of production is sold on a spot basis.

Original construction of the operation was completed in 1990 at a cost of US$836 million and the project has since undergone three phases of expansions at an additional cost of US$1,181 million plus US$451 million for the construction of an oxide plant. The operation has two conventional processing streams, with high quality copper concentrate being extracted from sulphide ore through a flotation extraction process and pure copper cathode obtained in a plant applying leaching and subsequent solvent extraction and electro-winning to oxide ores. An open pit mine services both operations, with a current total movement of approximately 350 million tonnes of material each year, while dedicated pipeline and port facilities as well as a private railway are used to transport output.

In the past, Escondida’s annual production has exceeded 890,000 tonnes of copper contained in concentrate and cathode. Based on a current ore feed grade of 1.55% of contained copper, the existing mine equipment and mill facilities are expected to produce 2.9 million tonnes of concentrate in 2003–2004, containing approximately 1.05 million tonnes of copper. The oxide leach plant, commissioned in December 1998, and debottlenecked in 2001, has an annual capacity of 150,000 tonnes of copper cathode.

As a result of a projected reduction in ore grades, annual copper production in concentrate was expected to decrease to below 600,000 tonnes. In November 2000, the owners of Escondida therefore approved the Phase IV Expansion Project. The project offsets the decrease and increases production capacity of the operation to over 1 million tonnes of copper contained in concentrate. Development works for the project commenced in late 2000. The Phase IV expansion was completed at a total cost of US$944 million during fiscal year 2003.

The Phase IV Expansion Project consists of the following equipment and facilities, some of which have been integrated into the existing operations:

•

a new in-pit ore crusher and conveyor to a new concentrator, which is expanding concentrating capacity by 110,000 tonnes per day to 230,000 tonnes per day;

•

a new concentrate slurry pipeline from the new concentrator to the existing concentrator and refurbishment of an existing pipeline to the port at Coloso;

•

additional concentrate filtration and storage capacity at Coloso;

•

increases to the mining fleet to conduct the mining and related materials movements necessary to supply ore feed to the

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new Phase IV plant;

•

modifications to the Coloso port facilities; and

•

a new tailings disposal site.

The estimated remaining mine life after the completion of the Phase IV Expansion Project is in excess of 20 years.

The owners of Escondida approved the Escondida Norte expansion in June 2003. An investment of US$400 million will be required to bring Escondida Norte mine into production. This will include the cost of pre-mine waste removal, the mining equipment fleet, all required infrastructure and owners’ cost.

Escondida is a large porphyry copper deposit with current mine dimensions of 2.2 kilometres in an east-west direction, 3.2 kilometres in a north-south direction and a depth of 464 metres. The ultimate pit limits are estimated to be 3.5 kilometres by 4.8 kilometres, with a depth of 750 metres.

Escondida has the right of indefinite exploitation (mining) concessions for the mining of the Escondida ore body as well as exploration rights for some territory surrounding the existing operation. Exploitation concessions allow the concession holder to mine the area indefinitely contingent upon the annual payment of corresponding license fees.

Separate transmission circuits provide power for the Escondida mine complex. These transmission lines, which are connected to Chile’s northern power grid, are company-owned and are sufficient to supply Escondida post Phase IV. Electricity is purchased under three contracts with local generating companies, Norgener and Nopel.

On November 8, 2001, Escondida announced its decision to temporarily reduce copper production at Escondida by 80,000 tonnes per annum, effective as of that date. This decision was taken in response to the significant fall in demand for copper, arising from unfavourable global economic conditions. In May 2002, Escondida decided to continue these cuts in production until the end of 2002. In December 2002, it was announced that Escondida will operate at a production level of 1.05 million tonnes of copper during calendar year 2003, approximately 200,000 tonnes below its installed production capacity of 1.25 million tonnes. This is being achieved through the combination of mining lower grade ores and balancing maintenance shutdowns in the older Los Colorados concentrator facility, with a steady ramp up of the Phase IV Expansion facilities, which include mine infrastructure and equipment, tailings and concentrate handling systems, as well as the new Laguna Seca concentrator.

Tintaya

Tintaya is an open-pit copper mine located in the Andes at an altitude of approximately 4,000 metres in southern Peru. We hold a 99.9% interest in Tintaya and the remaining interest is held by Peruvian shareholders. The mine site is accessible by road and is located near a public daylight airstrip that we maintain. The deposit is a copper gold skarn system associated with a low-grade porphyry copper body and is approximately 3 kilometres long by 2.5 kilometres wide. We hold mining rights over 3,600 hectares and surface rights over 4,097 hectares on which the Tintaya mine and operations are located. These rights can be held indefinitely. Mine operations consist of conventional truck and shovel operations from multiple pit locations. Electricity for the Tintaya operations is sourced from the Peruvian power grid and supplied under contract with two Peruvian power companies.

Production commenced in 1984 and currently consists of a conventional flotation extraction process producing copper in concentrate from sulphide ore. Tintaya’s total annual production capacity is 90,000 tonnes of copper contained in concentrate along with gold and silver credits. An acid leach plant for oxide ore commenced commercial operation in June 2002 and is designed to produce 34,000 tonnes of copper cathode per year. This plant will increase production to 40,000 tonnes of copper cathode per year. We expect annual production to remain stable until 2010 and then decrease as sulphide ore mining ceases and low grade stockpiles are processed to the end of the life of the mine, which we estimate will be in 2012-2014. As part of our work to improve mining operation efficiencies, we have moved the majority of the Robinson Mine equipment fleet to Tintaya. This equipment is now assembled at Tintaya replacing the old mining fleet.

In January 2002, we temporarily curtailed all copper concentrate production at Tintaya. This decision was taken in response to the fall in demand for copper, arising from unfavourable global economic conditions. This decision was reviewed in April 2002 and again in July and August 2003. The decision for an orderly return to full production was approved by BHP Billiton management in August 2003 and production will commence during September 2003, but sales of concentrate are not expected to be made for several months. Normal operation of the oxide leach plant is continuing as planned.

All copper cathode production is committed for sale to BHP Billiton Marketing AG (BMAG), a marketing and sales company, which is one of our subsidiaries.

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Cerro Colorado

Cerro Colorado is a wholly owned open-pit copper mine located in the Atacama Desert at an altitude of 2,600 metres, approximately 125 kilometres by road, east of Iquique, Chile. Cerro Colorado holds mineral rights over 16,664 hectares and surface rights over approximately 1,305 hectares on which the plant is located. These rights can be held indefinitely.

At Cerro Colorado, we produce finished cathode copper by crushing, agglomeration and heap leaching followed by a solvent extraction-electrowinning process. The electrowinning process produces copper cathode.

We source water requirements from an underground aquifer at Pampa Lagunillas, the rights to which we hold by grant from the state. Two suppliers under long-term contracts supply power to the facilities through the northern Chile power grid.

Construction of the facilities was completed in 1994 at a total cost of US$287 million and commercial production commenced in June 1994. An expansion of annual production capacity to 60,000 tonnes was completed in 1995 at a cost of US$49 million and in 1998, a second expansion of Cerro Colorado was completed, at a cost of US$214 million increasing the mine’s annual production to a nominal 100,000 tonnes of refined copper.

The Cerro Colorado deposit is approximately 2 kilometres long east-west and 1.5 kilometres wide north-south. Two main zones are present. Mineralisation is from 50 metres to 250 metres thick and is covered with 50 metres to 150 metres of leached cap and post-mineral rocks. The east deposit contains multiple layers of oxide and sulphide mineralisation with complex shapes. The west deposit generally consists of one oxide layer overlying one sulphide layer, but locally exhibits some of the complexities present in the east deposit.

We are implementing plant modifications at Cerro Colorado which include increases in the mine’s crushing capacity, leach pad area and mine fleet in order to maintain annual production capacity at a level of 120,000 tonnes per year for the next five years. With these modifications, we estimate that the remaining mine life will be 13 years.

Under current sales contracts that expire December 31, 2008, we are committed to deliver a total of 60,000 tonnes of cathode copper annually to two customers, one in Japan and the other in Germany. We sell the remaining production under annual and spot contracts to various international purchasers. Prices under all contracts are based on the monthly average London Metal Exchange cash settlement price in or around the month of delivery.

In May 1999, the London Metal Exchange approved the registration of Cerro Colorado cathodes. The London Metal Exchange registration enables Cerro Colorado to obtain full premium on its sales and to deliver copper directly to London Metal Exchange warehouses. The New York Commodity Exchange approved the Cerro Colorado cathodes in 2001.

Alumbrera

On March 26, 2003 we announced the sale of our 25% stake in Minera Alumbrera to Wheaton River Minerals Ltd. for a purchase price of US$180 million. Subsequently, Northern Orion Resources Inc. agreed with Wheaton River to purchase half of the stake essentially under the same previously agreed terms with Wheaton. US$125 million of the purchase price was received on the closing date, June 24, 2003. Payment of US$55 million of the purchase price has been deferred by Wheaton (US$ 25 million) and by Northern Orion (US$ 30 million) up to May 30, 2005. The deferred payments bear interest, and are secured by the interests in Minera Alumbrera acquired by Wheaton and Northern Orion.

Highland Valley Copper

We own a 33.6% interest in Highland Valley Copper, a partnership with Teck Cominco Limited and its subsidiary, which hold a 61.4% interest, and Highmont Mining Company, which holds a 5% interest in the venture. We share management responsibility of the venture equally with Teck Cominco. Although the partnership was formed in 1986, with Highmont joining in 1988, production from the Lornex pit commenced in 1972.

The Highland Valley venture holds and operates large scale, open-pit copper-molybdenum mining and milling operations in the Highland Valley area near Logan Lake, British Colombia, Canada. These mining and milling operations produce copper and molybdenum in concentrates. The operation is accessible by highway and is located approximately 80 kilometres southwest of Kamloops and 200 kilometres northeast of Vancouver. The mine operates throughout the year. B.C. Hydro supplies power to the operations through a 138-kilovolt line. The venture’s property interests consist of mineral claims and leases, government grants and some properties in fee simple. Included in these property interests are 33,128 hectares of mineral rights and 2,698 hectares of surface rights. These rights can be held indefinitely.

Facilities include the Highland mill and the Lornex and Valley open-pit mines, which are adjacent to the concentrator. The Lornex pit is approximately 2.5 kilometres long and 1.5 kilometres wide and contains mainly chalcopyrite ore. The Valley pit is round in shape and approximately 2 kilometres in diametre. It contains mainly bornite ore. Both deposits are porphyry type. The mill

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uses semi-autogenous grinding and conventional flotation and has a nominal milling capacity of 120,000 tonnes per day. The venture transports crushed ore from the Valley mine, which comprises approximately 89% of the mill feed, via two 6,000 tonne per hour inclined conveyor belt systems. Two 60 x 89 gyratory semi-mobile crushers, located in the pit, feed the inclined conveyors. Ore from the Lornex mine is trucked to a third fixed gyratory crusher and conveyor system. The three conveyor systems are integrated to allow blending of ore to three mill stockpiles. The venture expects to remain in production into 2009.

The venture sells more than 75% of its production under long-term contracts. The remaining terms of these contracts range from approximately two to six years. The venture sells the remaining production on a spot basis. Contract prices are based on the monthly average London Metal Exchange cash settlement price, generally three months after delivery.

Ok Tedi Mine

On February 8, 2002, we announced the completion of our withdrawal from the Ok Tedi copper and gold mine in Papua New Guinea and transferred our 52% interest to the PNG Sustainable Development Program Limited, an independent company, which now holds such interest for the benefit of the Western Province and the Independent State of Papua New Guinea. The other equity participants, and their interests, in this project are the Independent State of Papua New Guinea, which holds a 30% interest, and Inmet Mining Corporation, which holds an 18% interest. The interest held by the Independent State of Papua New Guinea is held in defined parcels for each of Papua New Guinea, the Western Province of Papua New Guinea and mine area landowners.

As part of the agreement for our withdrawal from this project, we agreed to provide financial support to PNG Sustainable Development Program, if required, for three years. The facility is for US$100 million in the first year, US$85 million in the second year and US$70 million in the third year. The facility is not cumulative, which means that any amount drawn in one year reduces the amount available in subsequent years, with repayment arrangements if such funds are used. In addition, we have agreed to pre-purchase copper concentrate up to an agreed level if Ok Tedi Mining should so request in a drought situation. The agreement also provides us with protection from legal liability arising from operations after our withdrawal.

Also, as part of the withdrawal process, Mine Continuation Agreements between Ok Tedi Mining and communities affected by the mine’s operations were negotiated and executed.

Spence

In January 1997, we announced the discovery of the Spence copper deposit in northern Chile. We hold 100% of the mineral rights in approximately 26,000 hectares and surface rights in approximately 16,000 hectares.

We conducted a feasibility study to develop a project for an open pit mine with facilities capable of processing approximately 50,000 tonnes per day of ore through a combination of chemical and bio-leaching processes to produce 200,000 tonnes per year of electrowon copper cathode. A feasibility study independent peer review was conducted during August 2002. This review focused on the technical core of the Spence project. Further study work has been commenced to ensure that recent advances that have proven successful in other operations are incorporated in the project. A revised feasibility study will be produced and reviewed by the end financial year 2004, prior to submission to our Board for approval.

North American copper assets

Our North American copper assets, other than Highland Valley Copper described above, the Selbaie mine described below and the San Manuel Mine which is in closure, continue on care and maintenance while producing a minor amount of cathode copper at some locations for a transitional period while various alternatives are evaluated.

In June 1999, we announced the cessation of these North American copper operations would occur in the August quarter of 1999 and recorded a charge to profit of A$1,800 million (no tax effect) for asset writedowns (net of estimated realisation values attributed to the remaining assets) and provisions. The provisions relate mainly to site remediation, which will take place over a significant number of years, together with provisions for other closure costs.

Formal closure plans are being developed and are planned to be submitted in accordance with local regulatory timetables. We expect that the expenditure will be incurred after the closure plans have been approved. Approval is anticipated in the next 2-4 years.

In January 2002, we announced the closure of the San Manuel mining facilities and we are currently in the process of closing such facilities.

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Copper-Zinc

Antamina

The Antamina copper-zinc deposit is owned by Compania Minera Antamina S.A., in which we hold a 33.75% interest. Noranda Inc. holds a 33.75% interest, Teck Cominco Limited holds a 22.5% interest and Mitsubishi Corporation holds the remaining 10% interest. The deposit was previously owned by Empresa Minera del Centro del Peru S.A. and was auctioned by CEPRI-Centromin, an agency of the Peruvian Government. The deposit is located in the Peruvian Andes at an altitude of 4,300 metres, approximately 270 kilometres north of Lima, Peru.

A feasibility study based on conventional open-pit mining, milling and flotation technology was completed in March 1998 on the potential of the Antamina deposit to produce 270,000 tonnes of copper and 160,000 tonnes of zinc annually over a 20-year mine life.

In September 1998, the venture participants elected to proceed with development of the project. The agreement with Centromin required the owners to invest US$2.5 billion in the project by June 6, 2002 or pay 30% of the shortfall to Centromin in lieu of further expenditures. On August 2, 2002, a payment of US$111.5 million was made to Centromin in lieu of the expenditure shortfall making the total development cost, including financing costs, working capital, payments to Centromin and sunk costs US$2,228 million.

In June 1999, the project company signed definitive documentation with a group of lenders for US$1.32 billion of project financing. Substantially all the assets of the project company have been pledged to the lenders as security for the loans. The project achieved commercial production in October 2001. On July 1, 2003 the project met its financial completion requirements with respect to its project financing and the loans are non-recourse.

The property comprising the Antamina mine area consists of mining concessions, mining claims and surface rights covering an area of approximately 14,000 hectares. The project company also owns sufficient surface rights for mining infrastructure, the port facility at Huarmey and an electrical substation located at Huallanca. In addition, the project company holds title to all easements and rights of way required for the concentrate pipeline from the mine to the project company’s port at Huarmey. All of the rights can be held indefinitely.

The Antamina deposit is a large copper skarn with zinc, silver, molybdenum and bismuth mineralisation. It has a southwest to northeast strike length of more than 2,500 metres and a width of up to 1,000 metres. The deposit sits at the bottom of a U-shaped glacial valley surrounded by limestone ridges.

Power to the mine site is being supplied under long-term contracts with individual power producers through a 58-kilometre, 220 kilovolt transmission line constructed by the project company, which is connected to the Peru national energy grid. In late 2002, an additional third party owned transmission line was connected to the projects substation, significantly increasing power supply reliability.

The project company has entered into 19 long-term copper and zinc concentrate sales contracts with 16 smelting companies, which, in aggregate, cover approximately 75% of the project’s expected annual production. All but two of the contracts are for terms extending to 2012 or 2013. The balance of production is expected to be sold on an annual or spot basis.

The Antamina project achieved mechanical completion in May 2001. The principal project facilities include a 115-kilometre access road, a truck-shovel pit operation, a 70,000 tonnes per day concentrator, a 300-kilometre concentrate pipeline with a single stage pumping station to transport concentrates in slurry form from the mine to the de-watering, drying, and port facilities at Huarmey, and housing for operating employees and their families in the City of Huaraz, located approximately 200 kilometres by road from the mine.

Selbaie

The wholly-owned Selbaie open-pit mine is situated 250 kilometres north of Rouyn-Noranda in northwestern Quebec, Canada. Selbaie produces zinc and copper concentrates by means of conventional flotation, with gold and silver as by-products in the copper concentrate. Nominal capacity at Selbaie is 11,000 tonnes per day (or 4 million tonnes per year), and mill throughput is 11,000 tonnes per day (or 4 million tonnes per year). Power is supplied by Hydro-Quebec. The estimated remaining mine life is 7 months and is essentially based on stockpiled ore production. Open pit mining has ceased operation in October 2002. Leases at Selbaie are renewable as and when they expire. The most recent renewal extends to 2012.

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Silver, Lead and Zinc

Cannington

Cannington is a mining and concentrating facility that is 100% owned and operated by us, and is the world’s largest single mine producer of both silver and lead. The Cannington silver, lead and zinc deposit is located in northwest Queensland, Australia, and is accessible by sealed road 300 kilometres southeast of Mount Isa. The Cannington deposit is entirely contained within mining leases granted to us in 1994 and which expire in 2029. The deposit consists of a shallow, low grade northern zone and a deeper, higher grade and more extensive southern zone. The southern zone contains a broadly zoned and faulted sequence of silver-lead-zinc, zinc and silver-lead lodes.

We use transverse, long hole open stoping for the extraction of the main, thicker, hanging wall orebodies of the deposit and we use predominantly new Tamrock underground mining equipment. Production commenced in October 1997. Underground mine production for the year ended June 30, 2003 was 2.39 million tonnes. The annual production reflected the benefits of the mine optimisation, which had been undertaken during the year. Work also continued during the year to improve mill throughput and increase metal recovery, and we are continuing an ongoing program of mill improvement. Nominal capacity was 1.5 million tonnes per annum at the time of commissioning. A total of 531,169 wet metric tonnes of concentrate were shipped from the Townsville port facility or sold within Queensland during the year ended June 30, 2003. A power station, comprising 19 x 1.03MW gas –fired and 4 x 1.4MW diesel-fired engines located at Cannington is operated under contract to supply power solely to Cannington.

The Cannington Growth project was approved in February 2003. This project will allow Cannington to improve recoveries, mine the Northern Zone ore body and sustain production at 2.4 million tonnes per annum.

Approximately 90% of Cannington’s lead and zinc concentrate production for the year ending June 30, 2004, is fully committed under long-term contracts with smelters in Australia, Korea, Japan and Europe with the balance being allocated to the spot market.

The reserve as currently stated along with non-reserve mineralisation is expected to support a remaining mine life of approximately 13 years.

Surface exploration is continuing on a number of geophysical and geochemical anomalies in the mine lease area.

Zinc-Lead

Pering

The wholly-owned Pering mine is a zinc mine producing lead as a by-product. The mine is situated in the Northwest Province of South Africa. The ore minerals are sphalerite and galena, both of which are associated with zinc and lead non-sulphide minerals in varying proportions and are generally fine grained. The operation comprised conventional open-pit, shovel and truck mining. Crushing and ball mill comminution was followed by conventional flotation. After filtering and air drying, the concentrates were transported by rail and road and sold to two smelters in South Africa. Pering had a nominal production capacity of 1.2 million dry metric tonnes per year. Pering owns the mineral rights, and therefore it does not have mineral leases. In June 2002, we announced that we would be closing Pering when the economically mineable reserve was depleted. Mining ceased on November 30, 2002. The mill was stopped in February 2003. The closure plan is being finalised and prepared for approval.

Uranium

In June 2002, we announced the sale of our Smith Ranch uranium mine, subject to approval by various regulatory authorities, to Cameco Corporation of Canada. That sale was completed in July 2002. The operating phase of the remaining parts of Rio Algom Mining (RAM), our wholly-owned subsidiary, namely the Ambrosia Lake and Lisbon facilities, has ceased and RAM is now in the final reclamation and remediation phase of the mine closure program for each facility. Both facilities consisted of mining and processing of uranium to produce uranium oxide for sale to the nuclear electricity generating industry. The Ambrosia Lake facility is located approximately 32 kilometres north of Grants, New Mexico and the Lisbon facility is located approximately 48 kilometres southeast of Moab, Utah.

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Reserves and Production

The table below details our copper, zinc, silver, gold, molybdenum and lead reserves in metric tonnes, and are presented in 100% terms as estimated at June 30, 2003.

Base Metals^{(1)(2)(3)(4)(}⁹⁾		Proved Ore Reserve						Probable Ore Reserve				Total Ore Reserves				BHP Billiton Group Interest%
Deposit	Ore type	Tonnes (millions)	Grade					Tonnes (millions)	Grade			Tonnes (millions)	Grade			BHP Billiton Group Interest%
Copper			% TCu	⁽⁵⁾	% SCu	⁽⁵⁾	g/t Au		% TCu	% SCu	g/t Au		% TCu	% SCu	g/t Au
Escondida	Sulphide	672	1.46		—		—	704	1.04	—	—	1,376	1.25	—	—	57.5
	Low grade float	114	0.62		—		—	240	0.62	—	—	354	0.62	—	—	57.5
	Mixed	—	—		—		—	33	1.36	0.42	—	33	1.36	0.42	—	57.5
	Oxide	137	—		0.78		—	36	—	0.59	—	173	—	0.74	—	57.5
Escondida Norte ⁽⁶⁾	Sulphide	84	1.84		—		—	417	1.35	—	—	502	1.44	—	—	57.5
	Low grade float	—	—		—		—	95	0.61	—	—	95	0.61	—	—	57.5
	Oxide	—	—		—		—	117	—	0.77	—	117	—	0.77	—	57.5
Tintaya⁽⁷⁾	Sulphide	31.9	1.30		—		0.24	31.4	1.45	—	0.18	63.3	1.38	—	0.21	99.9
	Oxide	5.0	1.51		1.29		—	31.6	1.58	1.18	—	36.6	1.57	1.20	—	99.9
Cerro Colorado⁽⁸⁾	Oxide	16	0.57		0.40		—	117	0.74	0.59	—	133	0.74	0.58	—	100
	Sulphide	19	1.02		0.12		—	55	0.84	0.11	—	74	0.88	0.11	—	100
			% TCu		% Mo				%TCu	% Mo			%TCu	% Mo
Highland Valley	Sulphide	224	0.42		0.007		—	50	0.42	0.006	—	274	0.42	0.007	—	33.6
Copper – Zinc			% TCu		% Zn		g/t Ag		%TCu	% Zn	g/t Ag		%TCu	% Zn	g/t Ag
Antamina	Sulphide	278	1.27		1.02		14.2	233	1.16	0.93	13.1	511	1.22	0.98	13.7	33.75
			g/t Au		g/t Ag		% TCu		g/t Au	g/t Ag	% TCu		g/t Au	g/t Ag	% TCu
Selbaie	Sulphide Stockpile	2.1	0.25		22		0.27	—	—	—	—	2.1	0.25	22	0.27	100
Silver Lead Zinc			g/t Ag		% Pb		%Zn		g/t Ag	% Pb	%Zn		g/t Ag	% Pb	%Zn
Cannington	Sulphide	15	492		10.85		4.15	8.2	462	10.87	3.74	23.2	482	10.9	4.0	100

(1)	All reserves quoted are diluted and include mining recovery.

(2)	Metallurgical recoveries for the operations are:

	% Metallurgical Recovery
	TCu	SCu	Zn	Pb	Ag	Au	Mo
Escondida Sulphide	81 - 86		—	—	—	—	—
Escondida low grade float	81
Escondida oxide		88
Escondida mixed	39
Escondida Norte Sulphide	80 – 87
Escondida Norte Oxide		85
Tintaya Sulphide	77 - 90.5		—	—	59.4	66.3	—
Tintaya Oxide		78
Cerro Colorado	82.5	82.5	—	—	—	—	—
Highland Valley	89.0	—	—	—	—	—	50
Antamina	88.5 – 95.1	—	0 – 86.4	—	65 – 90	—	0-70
Selbaie	79.5	—	75.5	—	9.9 - 50.4	62.2	—
Cannington	—	—	Ave. 72	Ave. 89	Ave. 89	—	—

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(3)	Approximate drill hole spacings used to classify the reserves are:

	Proven Ore Reserves	Probable Ore Reserves
Escondida	70 x 70m Sulphide, 65 x 65 LG float, 75 x 75m Mixed, 65 x 65m oxide	105x105m Sulphide, 140x140 LG float, 80 x 80m Mixed, 85 x 85m oxide
Escondida Norte	50 x 50m to 55 x 55m depending on geological domain and ore type	60 x 60m to 820 x 280m depending on geological domain and ore type
Tintaya Sulphide	18m in Chabuca area; 25m elsewhere	37m in Chabuca area; 50m elsewhere
Cerro Colorado	35m grid spacing	75m to 100m grid spacing
Highland Valley	Overall 111.1m spacing	Overall 124.2m spacing
Antamina	3 holes within 55m and closest within 40m	Variable between domains , approximately 2 to 3 holes within 55m to 110m and closest within 25m to 55m
Selbaie	All ore reserves now contained in a stockpile	All ore reserves are now measured
Cannington	12.5m x 15m spacing or less	25m x 25m spacing

(4)	A third party reserve audit was conducted by AMEC in calendar 2003 on the Tintaya Sulphide and Oxide reserves. Third party audits have not been conducted on the other base metal reserves for the purposes of this annual report.

(5)	%TCu means percent total copper and %SCu means percent soluble copper.

(6)

The final feasibility study of Escondida Norte was approved by BHP Billiton and its partners in June 2003 as part of the Escondida strategy to maintain copper production capacity in future years. Development costs are estimated at US$ 400 million, which include pre-mine development, new mining equipment, a primary crusher with an overland conveyor, and maintenance and operating support facilities. Pre-mine activities are programed to start in September 2003 and copper production from the Escondida Norte deposit is scheduled for the fourth quarter of calendar 2005.

(7)	Tintaya sulphide production was temporarily halted in November 2001 as a reaction to oversupply in the global copper market, and the oxide operation was commissioned during the year. Tintaya Sulphide production is being restarted during September 2003.

(8)

Following the completion of approximately 18,000 metres of additional drilling, Cerro Colarado has recently completed an updated mineral resource model which has resulted in an approximate 6% increase in the Proven and Probable Ore Reserves (over those included in the table), which will extend the expected mine life by approximately one year to 13 years.

(9)

Prices for the screen – traded metals used for ore reserves estimation are based on “current economics” defined as an average of the spot price over the last three years, including copper US$0.74 per pound, zinc US$0.41 per pound, lead US$0.21 per pound, silver US$4.63 per troy ounce and gold US$292 per troy ounce.

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The table below sets forth the BHP Billiton Group copper, gold, silver, lead, molybdenum, uranium and zinc production for the three years ended June 30, 2003. Production data shown is the BHP Billiton Group share unless otherwise stated.

	June 30, 2003 BHP Billiton Group interest %	BHP Billiton Group Share of Production⁽¹⁾
		Year ended June 30,
		2003	2002	2001
Copper (‘000 tonnes)
Escondida (Chile)	57.5	497.6	425.6	486.1
Tintaya (Peru)⁽²⁾	99.9	35.4	46.2	84.9
Cerro Colorado (Chile)⁽⁴⁾	100	131.1	130.8	96.7
Alumbrera (Argentina)⁽⁴⁾	0	34.4	48.5	32.6
Highland Valley (Canada)⁽⁴⁾	33.6	56.2	62.1	44.9
Antamina (Peru)⁽⁴⁾	33.75	96.9	81.9	—
Selbaie (Canada)⁽⁴⁾⁽⁵⁾	100	8.3	10.2	12.8
Ok Tedi (Papua New Guinea)⁽⁶⁾	—	—	—	216.1
North American Copper⁽⁷⁾	100	10.6	19.1	26.7

Total		870.5	824.3	1,000.8

Gold (‘000 ounces)
Escondida (Chile)	57.5	64.1	52.3	49.6
Tintaya (Peru)⁽²⁾	99.9	0.0	22.3	24.4
Alumbrera (Argentina)⁽⁴⁾	0	121.3	185.4	106.3
Selbaie (Canada)⁽⁴⁾⁽⁵⁾	100	17.8	22.2	38.6
Highland Valley (Canada)⁽⁴⁾	33.6	4.7	4.8	—
Ok Tedi (Papua New Guinea)⁽⁶⁾	—	—	—	521.1

Total		207.9	287.0	740.0

Silver (‘000 ounces)
Cannington (Australia)⁽⁸⁾	100	34,872	35,963	29,488
Antamina (Peru)⁽⁴⁾	33.75	2,227	1,719	—
Alumbrera (Argentina)⁽⁴⁾	0	200	237	145
Highland Valley (Canada)⁽⁴⁾	33.6	604	709	545
Escondida (Chile)	57.5	1,700	1,257	1,391
Selbaie (Canada)⁽⁴⁾⁽⁵⁾	100	1,525	2,073	1,550

Total		41,128	41,958	33,119

Lead (‘000 tonnes)
Cannington (Australia)⁽⁸⁾	100	237.4	231.8	200.3
Pering (South Africa)	100	2.6	4.3	5.9

Total		240.0	236.1	206.2

Zinc (‘000 tonnes)
Cannington (Australia)⁽⁸⁾	100	63.9	58.9	64.2
Antamina (Peru)⁽⁴⁾	33.75	82.7	48.3	—
Selbaie (Canada)⁽⁴⁾⁽⁵⁾	100	30.2	34.2	36.6
Pering (South Africa)⁽⁴⁾	100	17.1	21.1	20.9

Total		193.9	162.5	121.7

Molybdenum (‘000 tonnes)
Highland Valley (Canada)⁽⁴⁾	33.6	1.0	0.7	0.4

Uranium (‘000 pounds)
Rio Algom Mining⁽³⁾⁽⁴⁾	100	54	974	1,238

Notes to the minerals production tables

(1)	Mine production figures for minerals refer to the total quantity of payable metal produced.

(2)	The decrease in production from 2002 to 2003 was attributable to the temporary suspension of sulphide operations at Tintaya in January 2002.

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(3)	In July 2002, we completed the sale of our Smith Ranch uranium mine, which resulted in the cessation of uranium production.

(4)	These were operations of the BHP Billiton Plc Group prior to the DLC merger with the BHP Billiton Limited Group on June 29, 2001.

(5)	The decrease in production is mainly due to the decrease in head grades as the mine approaches the end of its life.

(6)

(7)

The North American copper assets were placed on care and maintenance in June 1999. These assets, other than the San Manuel, Arizona mining facilities, continue on care and maintenance while producing a minor amount of copper cathode at some locations for a transitional period. In January 2002, we announced the closure of the San Manuel, Arizona mining facilities and we are currently in the process of closing such facilities.

(8)	Cannington commenced concentrate production on October 17, 1997. The decrease in silver production in 2003 compared to 2002 was mainly due to a lower grade of ore milled, while the increases in production of zinc and lead for the same periods was due to higher grades.

Regulatory and Fiscal Terms

Chile

The Mining Code of Chile provides for two kinds of mining concessions, namely the exploration concession and the exploitation concession. A concession is defined as an immovable real right that grants the holder the exclusive authority to explore, or explore and exploit, mineral substances within the concession, and become the owner of any extracted substances, in the case of an exploitation concession. As provided by the Mining Code and the Constitution of Chile, mining concessions are established by court ruling. An exploitation concession is of indefinite duration, provided that yearly license fees are paid. An exploration concession is granted for two years and may be renewed for another two-year period, provided that at least half of the concession area is surrendered. License fees are also applicable. Mining concessions are distinct from surface rights and the legislation provides for the ability to request mining easements in the case where the owner of the mining concession is not the same owner as that of the land surface. Mining easements may be established by mutual consent of the owners or by court ruling.

The Decree Law 600 provides the main legal framework for foreign investment in Chile. This law covers types of capital contributions, taxes, foreign exchange, repatriation of profits and capital and administrative procedures. It is based on economic and legal principles found in the Constitution of Chile, with economic equality between foreign investors and nationals being the most important. It offers all foreign investors on a most favored nation basis the same treatment as nationals and guarantees a stable framework by means of an investment contract between foreign investors and the State of Chile. Such contracts cannot be modified unilaterally and are not affected by the passage of new laws. Investment can be made through convertible currencies, tangible assets, technologies that can be capitalised and loans tied to foreign investment projects. Repatriation of capital and profits is guaranteed through the formal currency market.

Peru

Minerals in Peru are legally owned by the State. The exclusive right to exploit mineral deposits is granted to individuals and private sector companies through mining concessions. Three types of concessions that have been established under the General Mining Law are mining, processing and transportation concessions. Mining concessions give rights to explore and extract minerals, but are distinct from property rights over the land surface. Miners must obtain the necessary rights of way to access mineral deposits from surface rights holders. The processing concession grants the holder the exclusive right to construct and operate the facilities necessary to transform minerals into a marketable product. A transportation concession would, for example, cover the construction and operation of a copper concentrate pipeline. Concessions under the General Mining Law are irrevocable provided that the nominal mining good standing fees are paid.

The General Mining Law provides qualifying mining companies with a stability regime covering taxation, foreign exchange and trade regulations. Companies that invest at least US$20 million in the development of an operation of not less that 5,000 tonnes per day, or expand an existing operation by such amount, can enter into a contract with the State that guarantees the stability of the tax laws for a period of 15 years. Free disposition of foreign currency and repatriation of capital and profits are also guaranteed, as is conversion of foreign exchange at the most favourable rate of exchange available at the time of conversion. We also obtain the benefit of accelerated depreciation for machinery, equipment and all other fixed assets.

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Market Conditions

We produce four primary products, namely copper concentrates, copper cathodes (metal), lead concentrates and zinc concentrates. In addition, since they are contained within these concentrates, we also receive payment credits for silver and gold recovered during the smelting and refining process.

We sell most of our copper, lead and zinc concentrates to third party smelters. The remainder of our production is mostly sold to merchants. We sell most of our copper cathodes to rod and brass mills and casting plants. Our customers are located around the world.

We compete against other mining companies producing copper, lead and zinc concentrates and other producers of copper cathode. Merchants can also provide short-term competition, but will not fundamentally affect supply and demand.

During calendar year 2002 total refined copper supplies reached 15.33 million tonnes down 1.7% compared with 2001. Copper demand reached 15.09 million tonnes, up 1.7% from the previous year.

The refined copper market entered the year 2003 in reasonable shape, with supply restraint from major producers and strong demand from China having brought the market into balance, despite little improvement in demand in much of the rest of the world.

Copper prices experienced an important recovery in January and February 2003. Nevertheless, March saw copper prices slipping from a high at US$0.78 per pound at the beginning of the month to US$0.72 per pound by the end of the month. Market sentiment in March was clearly overshadowed by the lead up to, and the outbreak of, war in Iraq with growing concerns amongst many analysts of the potential impact that prolonged action in Iraq would have on an already weak global economy. Thereafter, copper prices traded sideways in a narrow range of US$0.71-0.74 per pound during April 2003, supported by the conclusion of the Iraq war, but capped by worries over the potential negative effects of Severe Acute Respiratory Syndrome (SARS) virus on economic growth in Asia and particularly in China. Negative economic data from the US, Europe and Japan also helped to keep copper prices under pressure in April 2003. Nevertheless, copper prices rose strongly in May 2003 as a weaker dollar; the moderation of the SARS outbreak and a more positive technical picture prompted renewed buying, despite little fresh evidence of consumer interest in the physical market. Copper prices peaked twice at US$0.78 per pound during June 2003 but finally closed at US$0.75 per pound, thus confirming a slight downwards trend in June 2003. Nevertheless, copper prices experienced an important recovery during July 2003, driven largely by fund buying, hitting a 28-month high of US$0.81 per pound on July 30, 2003. The average copper price during the first half of the calendar year 2003 was US$0.75 per pound.

Combined exchange stocks at LME/Comex/Shanghai have continued to decline during 2003, falling by a significant net 300,000 tonnes to 995,000 tonnes by end-July 2003. With refined copper consumption flat to contracting in the US, Europe and Japan, it is perhaps surprising to see exchange stocks continuing to decline so fast this year. Allowing for the Codelco stockpile (which reached 100,000 tonnes by the end of June 2003) this is reasonable in the current economic environment. Most of the credit for this has to go to Chinese consumers. During the first six months of 2003, Chinese apparent refined copper consumption grew by a very impressive rate of around 26%.

Copper Concentrate Matters

In May 2003, the European Commission (Competition Directorate-General) announced that, in coordination with the US Department of Justice and the Canadian Competition Bureau, it had commenced an investigation to ascertain whether there is evidence of a cartel agreement and related illegal practices concerning pricing, customer allocation and market sharing in the copper concentrate sector. BHP Billiton, which was served with notice to submit to this investigation, is cooperating with regulatory authorities and has produced, and continues to produce, documents. This investigation, which involves a number of industry participants, is in its early stages, and accordingly BHP Billiton cannot predict its outcome.

BHP Billiton PLC is one of nine defendants in National Metals, Inc. v. BHP Billiton PLC et. al., case no. cv 1179L LSp in the United States district court for the Southern District of California. The complaint, which was filed in May 2001, seeks damages and restitution on behalf of indirect purchasers of copper concentrate in California and 25 other states. The complaint alleges a conspiracy to fix prices in violation of the states’ antitrust/consumer protection statutes. The case is in the very early stages and, while BHP Billiton cannot predict the outcome of the case, it believes it has meritorious defenses and plans to defend itself vigorously.

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Carbon Steel Materials

Our Carbon Steel Materials Customer Sector Group is a leading supplier of core raw materials and services to the global steel industry. The key raw materials that we supply for steel making are iron in various forms, metallurgical coal and manganese.

Iron Ore

Mount Newman Joint Venture

We hold an 85% joint venture interest in the Mount Newman project, located in the Pilbara region of Western Australia. We manage the project. Other participants in this venture are Mitsui-Itochu Iron Pty Ltd, which holds a 10% interest, and CI Minerals Australia Pty Ltd, which holds a 5% interest in the joint venture. The joint venture was granted a mineral lease in April 1967 under the Iron Ore (Mount Newman) Agreement Act 1964. This lease expires in 2009 with the right for successive renewals of 21 years.

The venture began production in 1969 at the Mount Whaleback orebody. Today, production continues to be sourced from the major Mount Whaleback orebody and is complemented by production from other ore bodies, namely Orebody 25, 29 and 30. At current price assumptions, blend grades and production rates (based on the current projected sales profile), reserves from Mount Whaleback are expected to contribute to the Mount Newman Joint Venture for at least 23 years. Significant other deposits are present on the lease which will support the Mount Newman blend during the 23 year life of the Mount Whaleback deposit and beyond.

The facilities at Mount Whaleback include primary and secondary crushing plants with a nominal capacity of 35 million tonnes of product per year, a heavy media beneficiation plant with a capacity of eight million tonnes of product per year and a train-loading facility. The mining plant and port facilities were originally built in the late 1960’s and have been maintained and enhanced many times since then. An additional primary and secondary crushing plant is present at Orebody 25 with a nominal capacity of eight million tonnes of product per year.

All of the joint venture’s production is transported 426 kilometres on its own railway to the Nelson Point shipping facility at Port Hedland, Western Australia. Facilities at the port include three car dumpers, crushing and screening plants, stockpile reclaimers and ship loading equipment. We can load vessels of 250,000 deadweight tonnes in the sheltered harbor.

In 1998, an under-harbor tunnel between the Nelson Point and Finucane Island facilities was commissioned by the joint venture. The tunnel allows us to transport ore to our Boodarie Iron plant and to ship ore directly by using the Finucane Island ship loading facilities. The current capacity of the Port Hedland facilities is in excess of 80 million tonnes per annum. This will be increased to 100 million tonnes per annum by 2004.

The venture mainly sells iron ore into Asia with minor sales to Australia and Europe. During 2002-2003, 41% of the project’s total dispatches were to China, with 27% of sales to Japan. Approximately 11% of shipments from Mount Newman were to our hot briquetted iron operations.

Yandi Joint Venture

We hold an 85% joint venture interest in the Yandi project located 92 kilometres north of Newman in the Pilbara region of Western Australia. We manage the Yandi project. The other participants in the joint venture are CI Minerals Australia Pty Ltd, which holds an 8% interest, and Mitsui Iron Ore Corporation Pty Ltd, which holds a 7% interest in the venture.

The Yandi mine was granted a mining lease in September 1991 under the Iron Ore (Marillana Creek) Agreement Act 1991. This lease expires in 2012 with the right to extend for a further 42 years if required.

Development of the orebody began in 1991. This included construction of a rail spur to the existing Newman/Hedland rail line, crushing and screening facilities with a capacity of 10 million tonnes per annum, ore stacker, mine load-out tunnel, and on-site administration infrastructure. The project’s first shipment of iron ore was in March 1992. With minor modifications undertaken in 1994, the capacity of the plant was expanded to 15 million tonnes of product per year.

In October 1995, the joint venture expanded the capacity of the Yandi mine by 10 million tonnes per annum to 25 million tonnes per annum. The expansion involved the construction of a new mine at Central Mesa 1, processing plant, train loading facilities and an additional 10-kilometre railway spur. The joint venture began railing of the first ore from the new mine in September 1996.

The joint venture completed pre-stripping activities at another mine called Central Mesa 5 during 2000–2001 with ore from this deposit now being handled through an existing processing plant and train loading facilities. Again with minor modifications, the total capacity at Yandi was increased to approximately 30 million tonnes of product per year.

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On March 3, 2002, we announced that we would deliver up to four million tonnes per annum of a new lump product which will command a premium price over the existing fines. Additional infrastructure was added to the existing Ore Handling Plant 2 to support the on-site production of fine and lump ores, without affecting the quality of the two distinct products. Commissioning took place in June 2002 and increased overall capacity to 38.5 million tonnes per annum . At current assumptions, it is expected that the reserve and non reserve mineralisation will support production from the Yandi mine for at least 20 years. In July 2003, it was announced the production would be further increased to approximately 42 million tonnes per annum.

During 2002-2003, 57% of the venture’s shipments by volume went to Japan and 22% went to Korea. China accounted for 6% of the venture’s shipments. The Yandi deposits are mined by an independent contract mining company on behalf of the joint venture.

Jimblebar

We own 100% of the Jimblebar lease, which is located approximately 40 kilometres east of Newman and is mined by an independent contract mining company on our behalf. We were granted a mining lease at Jimblebar in October 1988 under the Iron Ore (McCamey’s Monster) Agreement Authorisation Act 1972. Our lease expires in 2009 with the right of renewal for successive 21-year periods. The ore currently being produced at Jimblebar is from the Wheelarra Hill 4 (W4) deposit. This ore is blended with ore produced from Mount Whaleback and satellite orebodies (OB25, 29 and 30) to create the Mount Newman blend. The primary and secondary crushing plant at Jimblebar has a nominal capacity of eight million tonnes of product per year. At current price assumptions, blend grades and production rates, reserves from the W4 deposit will continue to support the Mount Newman blend for approximately 14 years. There are significant other deposits on the Jimblebar lease that will support the Mount Newman blend for the 23 year life of the Mount Whaleback deposit and beyond.

Mount Goldsworthy Joint Venture

We hold an 85% joint venture interest in the Mount Goldsworthy Mining Associates project, located at Yarrie, 210 kilometres east of Port Hedland in the Pilbara region of Western Australia. While we manage the project, mining operations are carried out by an independent contractor on the Joint Venture’s behalf. The other participants in the joint venture are CI Minerals Australia Pty Ltd, which holds an 8% interest, and Mitsui Iron Ore Corporation Pty Ltd, which holds a 7% interest in the project. Mount Goldsworthy was commissioned in 1966. The original Goldsworthy mine was closed in 1982 and mining operations ceased at Shay Gap in 1993. Since then, mining has continued from the adjacent Nimingarra mine and Yarrie, 30 kilometres to the southeast.

The Mount Goldsworthy mines are covered by four separate mineral leases under the Iron Ore (Mount Goldsworthy) Agreement Act 1964 and the Iron Ore (Goldsworthy – Nimingarra) Agreement Act 1972. These leases were granted between 1965 and 1974 and the last one expires in 2014. We have the right of renewal over these leases for successive 21-year periods.

All production from the Mount Goldsworthy mines is transported on a venture-owned railway to Port Hedland. From there, the venture ships the ore through the Finucane Island facility, which has a capacity of approximately 12 million tonnes per annum. During 2002–2003, 38% of the venture’s sales by volume were to Japan, 33% were to BHP Steel Limited’s Port Kembla Steelworks and 21% were to China. At current price assumptions, blend grades and production rates, reserves at the Mount Goldsworthy mines are sufficient to support mining activities until at least mid 2006.

Area C and Products and Capacity Expansion Projects

During April 2002 we announced approval for the development of a new iron ore mine at Area C and an expansion of the Port Hedland port and rail facilities, both in the Pilbara region of north Western Australia.

Area C represents the largest undeveloped Marra Mamba resource in the Pilbara region. The project involves developing mine infrastructure and a rail spur link to the existing Yandi/Newman railway. Capital costs are expected to be US$213 million for development of the new mine (our share is US$181 million). As part of the Area C development we have entered into an arrangement with POSCO to develop the ‘C Deposit’ section of Area C.

Area C, which is located 37 kilometres from our existing Yandi mine, is covered by the Iron Ore (Mount Goldsworthy) Agreement Act 1964. We hold a mineral lease for Area C that expires on August 4, 2007 and is renewable for periods of 21 years.

Under the original construction program, the capacity of Area C was to be incrementally expanded to 15 million tones per annum by 2011, with an estimated mine life of 17 years.

First production cargoes are scheduled for loading in September 2003, with the project to be officially opened on 30 October 2003.

The Products and Capacity Expansion (PACE) Project involves the expansion of rail and port facilities to ensure a system capacity of 100 million tonnes per annum. This capacity was originally planned to be completed by 2011 at a total capital cost of

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US$351 million (our share is US$299 million). The project comes under the Mount Newman and the Mount Goldsworthy Agreement Acts.

In July 2003, we announced the acceleration of the development of these Projects at an additional cost of US$42.5 million (US$50 million 100% basis) for additional rail infrastructure, ore handling capacity at Area C and accelerated pre-stripping at Mt Whaleback. The capacity expansion will now be complete by 2004.

Samarco

We own 50% of Samarco Mineração S.A., a Brazilian company. The remaining 50% interest in Samarco is held by Companhia Vale do Rio Doce (CVRD).

Utilising long-term mining concessions from the Brazilian Government, Samarco operates a complex of open-pit iron ore mines called the Samarco Alegria Complex, in the state of Minas Gerais, a concentrator at a site called Germano and pelletising operations and a port at Ponta Ubu in the state of Espirito Santo, Brazil. Mining concessions were granted to Samarco for so long as it mines the Alegria Complex. Alegria and Germano are both located approximately 100 kilometres by road from Belo Horizonte. Samarco began production at the Germano mine in 1977. The vast majority of sales are under multi-year contracts.

Samarco commenced production at the Alegria Complex in 1992. The Alegria Complex has now replaced the depleted Germano mine. Ore is transported from the Alegria mine to the Germano concentrator plant via a five-kilometre conveyer belt. The concentrator plant has a capacity of 15.5 million tonnes per annum of iron ore concentrates. From Germano, the concentrates are transported to Ponta Ubu through a 396-kilometre slurry pipeline. At Ponta Ubu, Samarco’s two pelletising plants have a production capacity of approximately 13 million tonnes per annum of pellets and up to two million tonnes per annum of concentrate and screens product. At current price assumptions and production rates, reserves at the Alegria mine are sufficient for approximately 20 years.

Other

On December 30, 2002, we announced that Sweet River Investments Limited (Sweet River), a company in which BHP Billiton holds a 66.97% interest, announced its intention to sell its 11.56% interest in Valepar SA to Companhia Siderurgica Nacional. Valepar SA is a major shareholder in Brazil’s Companhia Valo do Rio Doce (CVRD), the largest iron ore producer in the world. Prior to the sale, our interest in Sweet River corresponded to approximately 2.1% of CVRD’s total capital.

Coal

Queensland Coal

Together with Mitsubishi Development Pty. Ltd., we own and manage operations through a jointly owned entity, BM Alliance Coal Operations Pty Ltd (BMA), and jointly market the coal produced. We own six open-pit coal mines, one underground coal mine and a port in the Bowen Basin, Queensland, Australia. These mines are separated into two joint venture structures, in which we own 50%, namely the Central Queensland Coal Associates (CQCA) joint venture and the Gregory joint venture. Mitsubishi Development Pty Ltd owns the remaining 50% in these two joint venture structures. In addition, BMA operates two other Bowen Basin mines for BHP Mitsui Coal Pty Ltd in which we own an 80% interest. The majority of our production is high quality metallurgical coal used for steel making. Some energy coal is also produced from three of these mines.

Most of the coal from the CQCA northern area mines and some coal from the Gregory mine is shipped through the venture’s owned and operated Hay Point coal terminal. The CQCA joint venture participants and the Gregory joint venture participants have entered into a rail transport agreement with Queensland Rail providing for the transportation of coal from their mines until June 30, 2006. Hay Point port, located at Mackay, handles around 33 million tonnes per annum of coal and can accommodate bulk carriers of up to 230,000 deadweight tonnes. The port has two berths with loading capacities of 6,000 and 4,500 tonnes per hour. Most of the coal from the Blackwater mine and Gregory joint venture mines is shipped through the R.G. Tanna Coal Terminal at Gladstone, which is owned by the Gladstone Port Authority. All of the coal from the CQCA and the Gregory joint venture mines is transported to ports on railroads owned and operated by the State of Queensland.

The ventures sell most of their metallurgical coal to the global steel industry. In 2002–2003, approximately 49% of the metallurgical coal sales were to north Asia, 11% to south Asia, 28% to western Europe and approximately 12% elsewhere. Virtually all of the sales are under annually priced term contracts with minimal spot sales.

Central Queensland Coal Associates Joint Venture

Through our 50% interest in the CQCA joint venture, we operate five open-pit mines, namely Blackwater, Goonyella, Peak Downs, Saraji and Norwich Park and the Hay Point coal terminal. The adjacent South Blackwater and Blackwater mines were integrated into a single 14 million tonnes per annum operation in mid-2002. These mines are all located in Queensland, Australia.

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Goonyella mine commenced operations in 1971 and has a capacity to produce eight million tonnes per annum. Goonyella merged operationally with the adjoining Riverside mine in 1989 and is operated as the Goonyella Riverside mine. At current price assumptions and production rates, reserves from the Goonyella mine can support operations for approximately 79 years. Peak Downs mine produced its first coal in 1972 and has a capacity to produce eight million tonnes per annum. At current price assumptions and production rates, reserves from the Peak Downs mine can also support operations for approximately 69 years.

Saraji mine commenced production in 1974 and has a capacity of five million tonnes per annum. At current price assumptions and production rates, reserves from the Saraji mine are expected to be depleted in approximately 73 years. First coal was mined from the Norwich Park mine in 1979 and it has a production capacity of five million tonnes per annum. At current price assumptions and production rates, reserves from the Norwich Park mine are expected to be depleted in approximately 16 years. Blackwater mine commenced production in 1967 and has a production capacity of 14 million tonnes each year. At current price assumptions and production rates, reserves from the Blackwater mine are expected to be depleted in approximately 20 years.

The leases for the CQCA mines expire in 2004, 2008, 2009, 2010, 2011, 2012, 2015, 2017, 2020, 2021, 2023, and 2024 and are renewable for such further periods as the Queensland Governor-in-Council allows in each particular case.

Gregory Joint Venture

Through our 50% interest in the Gregory joint venture, we operate an open-pit mine called Gregory and an underground mine called Crinum.

The Gregory mine became operational in 1979 and has a capacity to produce over two million tonnes per year. At current price assumptions and production rates, reserves from the Gregory mine are expected to be depleted in approximately 2014. Crinum mine, which commenced longwall production in 1997, has a capacity of five million tonnes per year. At current price assumptions and production rates, reserves from the Crinum mine are also expected to be depleted in approximately 2014. All coals are beneficiated, using heavy media processes, to marketable specifications.

The venture’s leases for the Gregory and Crinum mines expire in 2006, 2014, 2018 and 2019 and are renewable for such further periods as the Queensland Governor-in-Council allows in each particular case.

BHP Mitsui Coal

We have an 80% interest in BHP Mitsui Coal Pty Ltd. Mitsui & Co. Ltd Group owns the remaining 20% interest in BHP Mitsui Coal. Until June 28, 2001, we managed BHP Mitsui Coal’s coal mines at Riverside and South Walker Creek, located in central Queensland, Australia. BHP Mitsui Coal’s coal mines are now managed by the BHP Billiton Mitsubishi Alliance (BMA).

The joint venture commissioned Riverside, an open-pit mine producing metallurgical coal, in 1983. Riverside has a production capacity of three million tonnes per year. At current price assumptions and production rates, reserves from Riverside are expected to be depleted in 2005. South Walker Creek became operational in 1998. It is an open-pit mining operation, producing pulverised coal injection fuel and minor quantities of by-product energy coal. South Walker Creek has a production capacity of 4.3 million tonnes per year. At current price assumptions and production rates, the current reserve base for South Walker Creek are expected to be depleted in approximately 2027. Exploration has significantly increased the reserve base in the past year. The venture contracted substantially all of the operations at South Walker Creek to Thiess Contractors for two years from November 30, 2000. This contract has been renewed for three years, commencing July 2003. BHP Mitsui Coal has entered into a rail transport agreement with Queensland Rail providing for the transportation of coal from the Riverside and South Walker Creek mines until June 30, 2006. The principal markets for the coal are Europe, Japan, Korea and Brazil.

BHP Mitsui Coal’s mining leases expire in 2005, 2020 and 2025 and are renewable for such further periods as the Queensland Governor-in-Council allows in each particular case.

BHP Mitsui Coal holds significant undeveloped leases in the Bowen Basin (principally, Wards Well, Poitrel, Kemmis-Walker, Nebo West).

Illawarra Coal

We wholly-own and operate four underground coal mines, namely Appin, Elouera, West Cliff and Dendrobium, in the Illawarra region of New South Wales, Australia. These mines produce coking coal primarily used for steelmaking. We produce coal under leases expiring in 2010, 2011, 2012, 2013, 2016, 2017, 2021 and 2023. These leases have renewal rights under the New South Wales Mining Act 1992 for periods of 21 years. Our current production capacity is 7.9 million tonnes of clean wet coal per year.

Appin commenced productionin 1962 with longwall mining starting in 1969. Appin currently produces approximately three million tonnes of clean wet coal each year and, at current price assumptions and production rates, its reserves are expected to support production for at least another 24 years.

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Elouera officially opened in 1993 with the amalgamation of the Nebo, Kemira and Wongawilli coal mining leases. Elouera currently produces approximately 1.5 million tonnes of clean wet coal per year and, at current price assumptions and production rates, its reserves are expected to be depleted during 2005. West Cliff was commissioned in 1976 and currently produces approximately 2.5 million tonnes of clean wet coal per year. At current price assumptions and production rates, reserves from West Cliff are expected to be depleted in approximately 30 years.

Our Board approved construction of the new Dendrobium mine in the Illawarra in December 2001. This mine will replace the Elouera mine when its reserves are depleted. The Dendrobium mine will be a modern longwall mine producing up to 5.2 million tonnes of raw coal per annum (3.6 million tonnes of clean coal per annum) with a capital expenditure requirement of approximately US$170 million. Reserves at the Dendrobium mine are expected to support production for at least 17 years.

We also own a 16.7% shareholding interest in the lease of the Port Kembla Coal Terminal Limited, which operates a coal loading facility at Port Kembla in New South Wales, Australia. We manage the terminal under contract, on behalf of the shareholding companies.

Over 50% of the metallurgical coal we produce at Illawarra Coal is sent to BHP Steel Limited’s Port Kembla Steelworks in New South Wales under a long term supply contract, and One Steel Limited’s Steelworks at Whyalla, South Australia. We export the remainder of our production and also sell a middlings by-product into the export energy market.

Manganese

Our 60% owned global manganese ore and alloy business comprises operations in South Africa and Australia and is the world’s largest integrated producer of manganese units. Our South African operations are held through Samancor Limited, while the Australian assets are owned through a local subsidiary. Anglo American Corporation holds the remaining 40% in both entities.

Manganese ore is produced by Hotazel Manganese Mines, located in the Kalahari Basin in South Africa, and the Groote Eylandt Mining Company Pty Ltd (GEMCO) in Australia’s Northern Territory. Approximately 60% of the ore production is sold to alloyers across the world, while the remaining 40% is converted into alloys at two plants, namely Metalloys in Meyerton, South Africa and the Tasmanian Electro Metallurgical Co. (TEMCO) in Tasmania, Australia. Through Samancor, we also hold a 50% interest in Advalloy, a refined manganese alloy joint venture, and a 51% interest in the Manganese Metal Company. With a production capacity of 44,000 tonnes per annum through its Nelspruit and Krugersdorp facilities, the Manganese Metal Company is the world’s leading producer of electrolytic manganese metal.

Hotazel Manganese Mines encompasses two mines in South Africa’s Northern Cape Province. Mamatwan, first commissioned in the mid 1960s, is an open-cut, medium grade ore producer, while Wessels, commissioned in the early 1970s, is a high-grade underground mechanised mine. The mines at Hotazel have a combined annual production capacity of 3.54 million tonnes of ore, which includes one million tonnes used for sinter production. All of the mineral leases will be affected by the new South African Mining Charter. Refer to “Business Description – Carbon Steel Materials – Regulatory and Fiscal Terms – South African Mining Charter” for more information.

At GEMCO, a high-grade manganese ore is extracted using open-cut, strip mining methods. The mine was first commissioned in 1965 and has a current production capacity of 3.0 million tonnes per annum. All of the GEMCO mineral leases are situated on Aboriginal land held under the Aboriginal Land Rights (Northern Territory) Act 1976. The current mineral leases, other than MLN 2 and MLN 3, are renewal leases of the original mineral leases granted for a term of 21 years. GEMCO leases are subject to renegotiations in 2006 and 2010. At current price assumptions and production rates, GEMCO’s reserves are expected to be depleted in approximately 23 years.

Our two manganese alloy plants, Metalloys in Gauteng, South Africa and TEMCO in Tasmania, Australia have a combined annual production capacity of some 700,000 tonnes of alloy, which is exported to steelmakers across the globe.

Manganese production for 2002–2003 was 4.1 million tonnes of manganese ore and 737,000 tonnes of manganese alloy. Our products include manganese ore, high and medium carbon ferro manganese, silico manganese and electrolytical manganese metal. In 2002–2003, sales to Asia were 35% for manganese ore and 13% for alloy. Europe accounted for 9% of manganese ore sales and 19% of alloy sales. Approximately 3% of ore sales and 24% of manganese alloy sales were to Northern America.. The remainder of sales were mainly to Australia, the Middle East, South Africa and South America. Prices are determined through periodic client negotiations.

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Hot Briquetted Iron

Boodarie Iron Western Australia

Our wholly-owned Boodarie Iron plant in Western Australia undertakes secondary processing of raw iron ore, purchased from the Mount Newman joint venture. We use Finmet technology to convert iron ore into hot iron briquettes for use in electric-arc furnace and integrated steelmaking operations. The North West Shelf Joint Venture supplies gas to the plant under a take-or-pay contract expiring in October 2013. We mainly export our briquettes to China, South Korea and Taiwan. We also provide briquettes to BHP Steel Limited’s operations at Port Kembla.

Following the commencement of trials on train 1, the remaining three trains (2–4) were brought on stream progressively from April 1999. The plant encountered process difficulties during 1999–2000, its first full year of operation. Technical problems during the processing of iron ore fines caused blockages and limited production. We have written-off the full value of the plant, which is approximately A$2.5 billion before taxes, because of the capital cost overruns during construction and commissioning, the difficulties we faced during production ramp-up and the significant deterioration of market conditions. The final write-down occurred in March 2000.

From April to December 2000, we carried out process development trials, which demonstrated solutions to overcome our major technology problems. In December 2000, we approved the continued operation of the plant, subject to key performance indicators being achieved, and authorised capital expenditure of A$110 million over 18 months. In October 2001, we successfully operated all four trains simultaneously for the first time.

Following the temporary suspension of operations between March and July 2002, due to a tube failure in a gas re-heating furnace, production ramp-up has continued steadily with the Boodarie Iron plant producing 1.7 million tonnes of briquettes in 2002-2003.

HBI Venezuela

In 1997, we entered into a joint venture agreement with International Briquettes Holding (IBH), a subsidiary of Siderurgica Venezolana SACA, pursuant to which we became a 50% shareholder in Orinoco Iron, Operaciones RDI and Brifer.

Orinoco Iron constructed a new hot briquetted iron facility in Peurto Ordaz, Venezuela using Finmet technology at a cost of approximately US$915 million. The plant commenced operations in May 2000 and is continuing its production ramp-up. Production was initially constrained by commissioning difficulties and, in more recent times, a shortage of operating funds to allow multiple train operation.

Operaciones RDI operated a plant in Puerto Ordaz that produced hot briquetted iron using Fior based technology, but the plant ceased operations in March 2001.

Brifer is a Barbados-based technology company that co-owns the Finmet technology jointly with Voest Alpine Industrieanlagenbau GmbH.

In March 2001, we announced we would write-off our equity investment in HBI Venezuela, cease any further investment and raise provisions to support our total financial obligations in relation to the assets following a detailed review of the future economic value of the asset. As a result of the write-off, we took an after tax charge to profit of US$410 million in the quarter ended March 31, 2001.

In March 2001, Orinoco Iron defaulted on an interest payment and in April 2001, the lenders to Orinoco Iron accelerated the maturity of the principal and interest outstanding under the bank credit facility and made demands on the guarantors. As one of Orinoco Iron’s guarantors, we paid 50% of the amounts due. We are working with the bank syndicates, the Venezuelan government and IBH to secure a financial restructuring package to enable the operation to continue. Negotiations are ongoing.

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Reserves and Production

The tables below detail our iron ore, metallurgical coal and manganese reserves in metric tonnes, and are presented in 100% terms as estimated at June 30, 2003.

Iron Ore Reserves⁽⁸⁾

Deposit^{(1)(2)(3)(4)(5)(6)}	Ore Type⁽⁷⁾	Proved Ore Reserve			Probable Ore Reserve			Total Ore Reserve			BHP Billiton Group Interest(%)
		Tonnes	Grade		Tonnes	Grade		Tonnes	Grade
		(millions)	%Fe	%P	(millions)	%Fe	%P	(millions)	%Fe	%P
Western Australia:
Mt. Newman JV	BKM	802	62.9	0.07	148	61.9	0.07	950	62.7	0.07	85
	MM	57	62.1	0.07	18	61.2	0.05	76	61.9	0.07	85
Jimblebar	BKM	175	62.0	0.07	72	61.5	0.08	247	61.8	0.07	100
Mt. Goldsworthy JV
Northern Areas	NIM	17	63.0	0.05	4	60.7	0.04	21	62.6	0.05	85
Area C ⁽⁹⁾	MM	184	62.7	0.06	19	62.8	0.06	204	62.7	0.06	85
Yandi JV	CID	485	58.3	0.04	156	58.1	0.04	641	58.3	0.04	85
Brazil:
Samarco		275	47.2	0.04	179	45.7	0.04	454	46.6	0.04	50

(1)	The reserves presented for each joint venture include a combination of high grade (direct crusher feed) and low grade (usually requiring beneficiation). All tonnages are in wet metric tonnes except for Samarco, which is in dry metric tonnes.

(2)	The reserve grades listed refer to in-situ head grades, iron (Fe) and phosphorus (P). Western Australia Iron ore is marketed as lump (direct blast furnace feed) and fines (sinter plant feed). Samarco is marketed predominantly as direct reduction and blast furnace pellets.

(3)	Mining dilution and mining recovery (in general around 95%) has been taken into account in the estimation of reserves for all Western Australian iron ore operations. For Samarco the mine recovery is 96.5% (not included in the reserve estimate) of the stated diluted reserve.

(4)

Metallurgical recovery is 100% for all of the West Australian iron ores except for the low-grade part of the Mt Newman JV (350 million tonnes) where the beneficiation plant recovery is 65%. For both Mt Newman JV and Jimblebar the recovery of screened low-grade lump is 70% and 55%, respectively. For Samarco the beneficiation plant recovery is 57% to 59%.

(5)	Third party reserve audits have not been conducted on our reserves for purposes of this annual report.

(6)	Drill spacings used to classify Proven and Probable Reserves for the West Australian Iron Ore deposits are between 100m by 50m and 200m by 100m. For Samarco the drill spacings used are 50m by 50m and 150m by 100m for proven and probable reserves, respectively.

(7)	Ore types are BKM – Brockman, MM – Marra Mamba, NIM – Nimingarra and CID – Channel Iron Deposit.

(8)	Prices to establish the economic viability of the iron ore reserves are based on current contract prices.

(9)	Whilst 85% is shown as the ‘BHP Billiton Group Interest’ for Area C, POSCO (a Korean steelmaker) has a 20% legal interest in the C deposit of Area C. In substance, the Group retains virtually all of this interest and this disclosure and the financial statements are prepared on this basis.

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Manganese Reserves

		Proved Ore Reserve			Probable Ore Reserve			Total Ore Reserve			BHP Billiton Group Interest (%)
Deposit^{(1)(2)(3)(4)(5)(6)}	Ore Type	Tonnes (millions)	Grade % Mn	%Fe	Tonnes (millions)	Grade % Mn	%Fe	Tonnes (millions)	Grade % Mn	%Fe	BHP Billiton Group Interest (%)
South Africa
Wessels (UG)		3.1	48.0	—	13.2	48.2	—	16.3	48.2	—	60
Mamatwan (OC)		18.6	37.9	4.6	6.0	38.0	4.7	24.6	37.9	4.6	60

				Yield (%)			Yield (%)			Yield (%)
Australia
GEMCO (OC)	ROM	42.5	48.0	44	46.3	47.6	41	88.7	47.8	42	60

(1)	Tonnages are on a dry basis. Mining dilution and recovery is included in the reserve estimate.

(2)	Mining method: OC = open-cut, UG = underground

(3)	No third party reserve audits have been undertaken in the last three years.

(4)	Metallurgical recovery for Wessels, Mamatwan and GEMCO varies with required market specifications.

(5)

For the South African manganese deposits, underground sampling and drill spacings of +/-230m are used for Proved and Probable Reserves respectively at Wessels,while drill spacings of between 40m and 80m are used to classify Proved and Probable Reserves at Mamatwan. For GEMCO, drill spacings of 60m by 120m and 120m by 120m are used for proven and probable reserves, respectively.

(6)	Prices to establish the economic viability of the manganese ore reserves are based on current contract prices.

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Metallurgical Coal Reserves⁽⁸⁾

				Marketable Reseves⁽²⁾
Assigned Reserves⁽⁷⁾	Deposit^(3)(4)(5)(6)	Mining Method⁽¹⁾	Reserve Tonnes⁽²⁾ (millions)	Tonnes (millions)	Volatile Matter (%)	BHP Billiton Group Interest (%)
Queensland Coal reserves at operating mines:
CQCA JV:
	- Goonyella	OC	801	558	23.6	50
	- Peak Downs	OC	933	501	20.4	50
	- Saraji	OC	585	337	18.4	50
	- Norwich Park	OC	97	68	16.5	50
	- Blackwater	OC	284	235	25.4	50
	- South Blackwater	OC	47	48	26.5	50

	Sub-total		2,747	1,747

Gregory JV:
	- Gregory	OC	17	14	33.7	50
	- Crinum	UG	55	46	31.4	50

	Sub-total		72	60

BHP Mitsui Coal:
	- Riverside	OC	6.7	4.7	23.2	80
	- South Walker Ck	OC	134	96	13.1	80

	Sub-total		141	101

Total Queensland coal reserves at operating mines			2,960	1,908

Illawarra Coal reserves at operating mines⁽¹⁰⁾:
	- Appin	UG	84	78	22.7	100
	- West Cliff	UG	79	72	20.8	100
	- Elouera	UG	5	4	23.9	100
	- Dendrobium	UG	92	63	22.9	100

Total Illawarra Coal reserves at operating mines			260	217

Unassigned Reserves⁽⁷⁾
Queensland Coal undeveloped reserves:
CQCA JV:
	- Daunia ⁽⁹⁾	OC	0	0	—	50
BHP Mitsui Coal:
	- Poitrel/Winchester	OC	79	62		80
	- Nebo West ⁽⁹⁾	OC	0	0		80
	Sub-total		79	62

Total undeveloped reserves			79	62

(1)	Mining method: OC = open-cut, UG = underground.

(2)

Coal Reserve (metric tonnes) is the sum of Proven and Probable coal reserve estimates, which include allowances for diluting materials and for losses that occur when the coal is mined and are at the moisture content when mined. Marketable Coal Reserve (metric tonnes) are the tonnages of coal available, at specified moisture and quality, for sale after beneficiation of the Coal Reserve. Note that where the coal is not beneficiated the Coal Reserve and Marketable Coal Reserve are the same.

(3)	Coal wash plant recovery:

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Queensland Coal:			Illawarra Coal:
Goonyella	70	%	Appin	89	%
Peak Downs	56	%	West Cliff	87	%
Saraji	58	%
Norwich Park	71	%
Blackwater/South Blackwater	83	%	Elouera	74	%
Gregory/Crinum	84	%	Dendrobium	69	%
Riverside	70	%
South Walker	72	%

(4)	Third party reserve audits have not been conducted on our reserves for purposes of this annual report.

(5)	Reserves are quoted on an air-dried qualities, as this is the basis they are sold on the international market. As received moisture bases range from 8% to 10%, depending on mine and product.

(6)	A drill spacing of 1,000m is used to classify Proven reserves and 1,000m to 2,000m to classify Probable reserves

(7)	The unassigned, undeveloped coal reserves are based on feasibility studies.

(8)	Prices to establish the economic viability of the metallurgical coal reserves are based on average of past three years average coal prices.

(9)	Daunia and Nebo West are not fully permitted (ie. do not have Surface Rights) as required by US SEC Industry Guide 7

(10)	Cordeaux and Tower mines were closed in 2002-2003. The remaining Coal Reserves at Tower have been allocated to Appin.

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The table below details our coking coal, iron ore, manganese and hot briquetted iron production for the years ended June 30, 2003, June 30, 2002 and June 30, 2001. Production data shown is our share unless otherwise stated.

		BHP Billiton Group Share of Production			BHP Billiton Group Interest %
	Coal Type⁽¹⁾	Year ended June 30,
	Coal Type⁽¹⁾	2003	2002	2001
		(thousands of tonnes)
Iron Ore⁽²⁾⁽³⁾
Mt. Newman (Australia)		21,958	23,374	20,950	85
Jimblebar (Australia)		5,418	5,201	4,643	100
Mt. Goldsworthy (Australia)		6,712	6,447	6,601	85
Yandi (Australia)		31,788	27,256	26,156	85
Whyalla (Australia)⁽⁴⁾		—	—	909	100
Samarco (Brazil)⁽⁵⁾		7,856	5,629	7,508	50

Total Iron Ore		73,732	67,907	66,767

Queensland coal production CQCA joint venture⁽⁶⁾
Goonyella	Met	3,812	3,776	3,978	50
Peak Downs	Met	3,631	3,828	3,129	50
Saraji	Met	2,321	2,547	2,075	50
Norwich Park	Met	2,161	2,073	1,828	50
Blackwater⁽⁷⁾	Met/Th	6,841	7,037	4,328	50

Total CQCA JV		18,766	19,261	15,338

Total Gregory JV⁽⁶⁾⁽⁸⁾		2,525	2,440	3,626	50

BHP Mitsui Coal⁽⁹⁾
Riverside	Met	2,641	3,402	3,272	80
South Walker Creek	Met/Th	3,927	3,341	3,147	80
Total BHP Mitsui Coal		6,568	6,743	6,419

Total Queensland Coal		27,859	28,444	25,383

Illawarra coal production
Illawarra Collieries	Met/Th	6,763	7,088	6,574	100
Manganese Ore⁽¹⁰⁾
(Australia)		1,853	1,668	1,612	60
(South Africa)		2,249	1,867	2,162	60

Total Manganese Ore		4,102	3,535	3,774

Manganese Alloys⁽¹⁰⁾
(Australia)		234	212	246	60
(South Africa)		503	406	398	60

Total Manganese Alloys		737	618	644

Hot Briquetted Iron
HBI Western Australia⁽¹¹⁾		1,670	1,047	848	100
HBI Venezuela⁽¹²⁾		—	—	198	50

Total HBI		1,670	1,047	1,046

(1)	Coal Type: Met – metallurgical, Th – thermal.

(2)	The figures for the years ended June 30, 2001, 2002 and 2003 for iron ore are reported in wet tonnes as opposed to historical, which is in dry tonnes. The equivalent wet tonnes for the prior years would be approximately 5% higher than the numbers shown above.

(3)	West Australian iron ore production was higher than 2002 due to continued strong demand for all products in Asian markets, particularly China.

(4)	Spun-off as part of OneSteel Limited in October 2000, and therefore production can no longer be attributed to the BHP Billiton Group.

(5)	Production statistics relate to pellet feed and pellets. Samarco production for the year ended June 30, 2003 was 40% higher than the corresponding period in 2002 due to ongoing strong market conditions.

(6)	BHP Billiton interest is 50% from June 28, 2001 (previously CQCA joint venture 52.1% and Gregory joint venture 64.14%).

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(7)	Includes South Blackwater production from January 2002. We acquired our share of South Blackwater in July 2001. South Blackwater is equally owned by BHP Billiton and Mitsubishi Development Pty Ltd.

(8)	We report the production from Gregory and Crinum on a combined basis since the beginning of 2001-2002.

(9)	BHP Mitsui Coal production shown on a 100% basis before 20% outside equity interest.

(10)	Saleable production shown on a 100% basis. BHP Billiton interest in saleable production is 60%. These were operations of the BHP Billiton Plc Group prior to the DLC merger with the BHP Billiton Limited Group on June 29, 2001.

(11)	Boodarie Iron commenced operations in February 1999. Following rectification of initial technical difficulties production has progressively ramped up since late in 2000.

(12)

The production at HBI Venezuela commenced in May 2000. The plant experienced a range of technical, process and operational problems during startup. In March 2001, BHP Billiton Limited announced it was writing off its investment and would cease to fund the operation. The plant has continued to operate notwithstanding a severe shortage of operating funds which has limited the capacity of the plant and constrained the capability to operate multiple trains simultaneously.

Regulatory and Fiscal Terms

Western Australia

In Western Australia, minerals in the ground belong to the Government, and rights to mine are granted by the Government. The Newman, Yandi and Goldsworthy mining, rail and port operations are conducted under agreements with the Government of Western Australia. The agreements have been ratified by Acts of Parliament.

Queensland

In the State of Queensland, the Government owns coal until it is mined. At that point it becomes the property of the holder of the mining lease subject to payment of a royalty to the Government of Queensland. Matters of ownership of the coal and payment of the royalties are regulated under the Queensland Mineral Resources Act 1989 and the regulations made under this Act. The current royalty rate is 7% of the coal’s invoiced selling price adjusted for certain allowable charges as determined by the Minister.

New South Wales

All coal in the State of New South Wales belongs to the Government. This has been the case since the introduction of the Coal Acquisition Act in 1981. Coal can only be mined by the holder of a Mining Lease under the Mining Act of 1992. A royalty of A$1.70 per clean tonne is paid on all coal mined.

Brazil

Exploitation concessions are granted by the Federal Government, through the National Mining Department. A license is valid until the depletion of the reserve, subject to mining operations being performed in accordance with an approved plan. Financial compensation for the Exploitation of Mineral Resources is payable at a rate of 3% of net turnover from the sale proceeds. In addition to financial compensation for the Exploitation of Mineral Resources, Samarco pays royalties for ore extracted from reserves belonging to CVRD. Samarco blends the ore from its own reserves with that from CVRD’s reserves. The amount of royalties due to CVRD has been agreed at 4% of the total amount of dividends declared by Samarco per year.

Generally there are no restrictions on distribution and remittance of profits abroad. Payment of dividends and remittance of dividends are not subject to withholding tax.

South Africa

A specific category of State-owned mineral rights is known as Alienated State land. Here the State has disposed of the surface rights and retained the mineral rights. The owner of the surface rights obtains the exclusive right to explore for any minerals under their land and the exclusive right to apply to the State for a right to mine. Mining companies acquire these exclusive rights by way of Nomination Agreements in perpetuity, granted by the surface owner to the mining company, or by acquiring the ownership of the surface rights. However, the Minerals Act 1991 amended applicable provisions so that a mineral lease with the State had to be entered into in respect of such rights by December 31, 1996, or within such longer period as the Minister of Minerals and Energy may determine. Failing this, the right to prospect and the exclusive right to apply to the State for a mineral lease would lapse. Samancor Manganese received an extension from the Minister of Minerals and Energy pending finalisation of the State mineral leases which have been applied for. Within the BHP Billiton Group, it is only these so-called Section 43 rights held by Samancor that have not yet

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been converted to a State mineral lease and may be affected by the new South African mining legislation, including, among other things, the accompanying charter. Negotiations with the State are continuing.

South African Mining Charter

The Mineral and Petroleum Resources Development Act, 2002, and ancillary legislation, the Empowerment Charter, for the South African mining industry, targets 26% ownership of South African mining assets by historically disadvantaged South Africans within 10 years. The Charter requires that the transfer of ownership must be at fair market value and we have indicated our willingness to enter into negotiations on that basis.

As the Act and Charter are both unclear on what will comprise the 26% (value or tonnage or a combination of both) a scorecard has been developed and was published on February 18, 2003. The scorecard provides guidelines for mining companies operating in South Africa on measurement of their progress in meeting the requirements of the Charter.

The scorecard applies when companies convert from ‘old order rights’ to ‘new order rights’ within the five year period stipulated in the transitional provisions. The requirements for conversion deal not only with ownership, but also with such aspects as management, procurement and social development. The scorecard provides that 15% of ownership should vest in historically disadvantaged South Africans within a period of five years from the new Act taking effect.

The Royalty Bill

The State is considering imposing royalties based on revenues instead of on its share of profit, which is currently payable in respect of State-owned minerals. Introduction of the Bill has been postponed until 2004, and it is not known what form it will contain, or when such royalties will become payable. The chrome and coal mines may be affected, however it is estimated that Samancor manganese will not be required to make higher payments to the State than it does at present.

Our South African mining operations, principally the Ingwe energy coal mines, Samancor manganese and chrome mines and our investment in Richards Bay Minerals, represent approximately 6% of our total net operating assets.

We have noted the Charter’s content and generally support its broad objectives, most of which accord with long established programs that we have underway. The effect of the Charter will ultimately depend on the specifics of the implementation process. We are already a prominent participant in the South African empowerment processes, including the Eyesizwe Mining and Kuyasa Mining transactions, corporate social investment through the BHP Billiton Development Trust and the Samancor Foundation, and in employment and procurement equity across our operations. We have a long history of successful major partnerships in Southern Africa, many involving the Industrial Development Corporation. We believe that our South African operations should not be adversely affected materially by the Mineral and Petroleum Resources Development Act or the accompanying legislation.

Market Conditions

Global crude steel production rose strongly in 2002-2003 to a record level of 918 million tonnes representing an increase of 75 million tonnes or 8.9%. All regions exhibited growth, with the developing world being responsible for most of the increase. Chinese production increased 21.6% compared to 2001-2002. Chinese output has grown at a rate of more than 64 million tonnes over the past two years to stand at 197 million tonnes. High Chinese demand for steel has underpinned strong Japanese steel exports of around 36 million tonnes, very close to the record levels seen in the 1970s, and high Japanese steel production of 110 million tonnes. Exports in calendar year 2002 increased 20% over calendar year 2001, led by China up 43%, Korea 40% and other South East Asian countries, with exports to Europe and North America declining. Japanese production has remained at over 100 million tonnes for the past three years despite subdued domestic demand. As a result the Asian share of global production has increased to approximately 43%.

A number of factors have emerged to drive steel prices up in 2002-2003. Firstly, the US implemented tariffs on imported steel products in early calendar year 2002. The EU responded with its own measures, and many other countries also enacted some form of protection, import monitoring or anti-dumping measures. The strong export situation arising from China has resulted in a very rapid rise in steel prices late in calendar year 2002, before falling sharply in early calendar year 2003. China is now in its second round of quotas and tariffs which began on May 24, 2003. Secondly, production restraint, aligning supply with demand, as has been evident in Europe, Japan and the US, has been generally successful in sustaining prices. Finally, a factor coming into play is metallics prices. Rising scrap and pig iron prices (again China is a driving factor) are pushing up steelmaking costs which flow through into the general steel market, particularly in South East Asia and North America, where electric arc furnace production is strong.

Global pig iron production followed the trends of crude steel production reaching 628 million tonnes in 2002-2003, an increase of approximately 48 million tonnes or 8.3%. This high production drove strong demand for iron ores and metallurgical coals including pulverised coal injection (PCI) coals. Strong domestic demand for coke in China to meet strengthening pig iron production of 182 million tonnes saw Chinese merchant coke redirected to meet internal demand. This led to export prices doubling to over US$140 per tonne and encouraged new capacity and a growth in exports. Strong pig iron production and the restart of some facilities in the United States has further tightened demand for merchant coke and assisted in maintaining a strong coke market.

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High pig iron production in nearly all key Asian economies during 2002-2003, coupled with further substitution of domestic for imported ores in China, resulted in seaborne iron ore shipments of approximately 510 million tonnes. After falling in the early part of calendar year 2002, pellet demand has picked up once again in line with all other iron ore products. The fines market was very strong, driven by higher imports from China on the back of strong pig iron production. The outlook for fines supply remains tight as Chinese demand is forecast to increase significantly in 2003-2004. Strong demand for pig iron has also led to an increase in the demand for lump iron ore.

Metallurgical coal demand has been robust across all segments. Strong demand for coke, on the back of higher pig iron production, together with high prices has resulted in increased use of hard coking coals. Demand for hard coking coal in China appears to have outstripped supply allowing for the recent commencement of imports. Growth in Australian exports has been offset by a decline in Canadian and US supply, and high cost European production. With some new coking coal capacity coming on-stream in the short term and coking coal demand expected to remain steady, the outlook is for a continuation of positive market conditions.

The strengthening steel market and continued disruption of gas supply to DRI producers from Venezuela has seen Asian scrap and metallics import prices rise to US$170 per tonne. In addition, both North American and Asian prices for HBI have risen strongly. Chinese steel growth also resulted in higher HBI demand, with China now representing our main market for Boodarie^™ Iron. The 2003-2004 market outlook is for growth in Chinese demand for scrap and metallics, including HBI. Continued global economic and steel growth should see an increase in scrap and HBI demand.

The stronger steel industry also resulted in an increase in demand for ferroalloys. Production problems during the financial year saw high carbon ferro manganese experience a sustained price recovery with corresponding effects for manganese ore. Strong steel production in China also resulted in a rise in alloy demand and manganese ore imports. Sustained steel production due to the upturn in the global steel industry will likely to lead to increased manganese ore and alloy demand.

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Diamonds and Specialty Products

The Diamonds and Specialty Products group is our newest Customer Sector Group and encompasses the existing businesses of diamonds, titanium minerals, Integris Metals and Minerals Exploration & Technology. Our EKATI Diamond Mine, of which we own 80%, is located in the Canadian Northwest Territories and is expected to produce on an annual basis approximately four million carats of gem-quality rough diamonds. EKATI Diamond Mine’s annual production represents approximately 4% of current world diamond production by weight and 7% by value. Richards Bay Minerals, of which we own 50%, is a heavy mineral sands mine and smelter based in South Africa. Integris Metals is a 50% owned metals distributor with branches throughout the United States and Canada. Minerals Exploration is tasked with growing BHP Billiton’s mineral resources through both greenfield and brownfield discovery. Technology is tasked with ensuring the use of optimal technology across BHP Billiton’s operations, technical marketing of our products as well as generating growth opportunities through the development of new technologies.

EKATI Diamond Mine

The EKATI Diamond Mine is located in the Northwest Territories in Canada. The mine is located approximately 300 kilometres northeast of Yellowknife. Normal access to the site is provided by aircraft. Road access is available for about 10 weeks by ice road from late January to early April. Major facilities at the mine include camp accommodations, a truck maintenance shop with office complex, an equipment-warming shed, the process plant and a powerhouse capable of producing 22 megawatts of electricity.

The mine plan is based on multiple kimberlite pipe development. Initially, open pit or surface mining has been used. Present operating pipes include Panda and Koala, which are adjacent to the main facilities, and Misery, which is located about 30 kilometres southeast of the main camp. Pre-production development of the Fox pipe, which is located 7 kilometres southwest of the main camp, was started in 2002 and will begin producing ore in 2006. Predevelopment activities will also begin in the second half of calendar year 2003 on the Beartooth pipe, located just north of the Panda pit; this pipe should contribute ore beginning 2004. Underground operations commenced ore production from the Koala North pipe in 2002. Future pipes include Sable, which is located 19 kilometres north of the main camp. Mining of the Panda open pit started in early 1997 and will be completed in calendar year 2003. Initial underground operations to access the deeper ore at the Panda pit has commenced. The processing plant began operation in mid-1998. Initial ore production was estimated to be 9,000 tonnes per day in the project’s original feasibility study. Production is currently averaging 12,000 tonnes per day.

We own an 80% interest in the Core Zone joint venture that manages the property on which the mine is located. The other participants in the Core Zone joint venture are Charles E. Fipke and Stewart L. Blusson, each of whom holds a 10% interest. We also hold a 58.8% interest in property managed by the Buffer Zone joint venture. The other participants in the Buffer Zone joint venture are Archon Minerals Limited, which holds a 31.2% interest, and Charles E. Fipke, who holds a 10% interest. Tenure is secured through ownership of 370 mineral claims or mining leases. Mining leases have been granted for reserves until 2017, a period sufficient to cover production from current proved and probable reserves. At June 30, 2003, the joint venture had converted all except three of its claims, totalling 856,453 acres, to lease status. The three outstanding claims are in good standing and may be converted to lease status in the future.

The joint venture has continued surface exploration activities throughout the mine property area. Exploration core drilling of geophysical and geochemical targets during summer 2001 and 2002 confirmed 12 additional kimberlite pipes bringing the total number of known kimberlite occurrences on the property to 150. Further evaluation work and engineering studies are expected to bring some of these pipes into the mine plan.

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Reserves and Production

The table below details our diamond reserves (in dry metric tonnes and 100% terms), estimated at June 30, 2003.

Proved Ore Reserve

Probable Ore Reserve

Total Ore Reserves

BHP
Billiton
Group
Interest

Recoverable
Product⁽¹⁾

Tonnes

Grade

Tonnes

Grade

Tonnes

Grade

(millions)

(Carats/tonne
> 2.0mm size)

(millions)

(Carats/tonne
> 2.0mm size)

(millions)

(Carats/tonne
> 2.0mm size)

(%)

(Carats in
millions)

Diamonds

EKATI ^(2)(3)(4)

1.0

(1)	These figures are expressed in terms of the recoverable quantity of marketable product.

(2)	Search radii of 30m and 60m are used to classify Proven and Probable Reserves, respectively.

(3)	Third party reserve audits have not been conducted on our reserves for purposes of this annual report.

(4)	Diamond prices used for pit optimisations and ore reserves reflect current marketing conditions.

The table below details our share of diamond production for the years ended June 30, 2003, 2002 and 2001. Our interest in EKATI Diamond Mine increased from 51% to 80% effective July 3, 2001, when we acquired a controlling interest in Dia Met Minerals Limited, which corporation was subsequently wholly acquired on October 30, 2001.

Regulatory and Fiscal Terms

In Canada, title to land is divided into (a) surface rights, which can be acquired from the government (or the current owner thereof) and registered in Land Title or Registry offices within each Province or Territory, and (b) mineral rights which are reserved to the Government in most land grants and are granted by license or lease to permitted miners or prospectors for a fixed term, subject to compliance with specified annual rental and performance obligations. The government’s title both to the land and the mineral rights has primacy, subject only to the burden of proven aboriginal title and treaties that may accord subsurface rights to the aboriginal party. Under the Constitution Act, 1867, the title to all mines, minerals and royalties was passed to the Provinces, which regulate the acquisition and development of mineral claims through provincial mining or mineral tenure legislation. The Northwest Territories is one of the few jurisdictions in Canada where, subject to aboriginal Land Claim Agreements, the bulk of government lands remain under federal control, with the acquisition and maintenance of title being governed by the Territorial Lands Act and the Canada Mining Regulations, the administration of which is handled by the federal Department of Indian and Northern Affairs Canada. Development of pipes at the EKATI Diamond Mine is regulated by the Mackenzie Valley Land and Water Board under the auspices of the Mackenzie Valley Resource Management Act of the Northwest Territories.

Market Conditions

Production from the EKATI Diamond Mine represents approximately 7% of the world supply by value. The principal supplier, controlling over 40% of global production, is De Beers, which, combined with global marketing contracts, gives them a market share of nearly 60%. Alrosa, which accounts for 98% of Russian production, produces about 17% of world supply, approximately half of which is sold to De Beers and half within Russia. The other main independent sources are various mines in Angola and Rio Tinto’s Argyle Mine in Australia and Diavik Mine near EKATI.

BHP Billiton Diamonds Inc. has marketed 100% of EKATI’s rough diamond production since January 2003 (previously 35% was sold to De Beers under contract). Approximately 60-70% of sales are made to regular customers, 10 - 20% in smaller allocations by auction or negotiation to a much larger number of “window” customers, up to 7% under contract to three Northwest Territories manufacturers and the remainder sold as both polished diamonds and rough diamonds directly to jewelry retailers or polishers. Rough diamond sales are made in 10 cycles per year, approximately at five-weekly intervals, which is standard industry practice. In November 2002, the EKATI brand of polished diamonds was merged with the Aurias^TM brand and programs are being instituted to

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expand the market for this product globally under the Aurias^TM brand. Newly introduced in May 2003 was CanadaMark^TM, a hallmark program, which identifies the polished stones as being of Canadian origin. Polished diamonds for the branding operations are obtained through contract polishing programs or through buy-back arrangements with customers for rough diamonds.

Titanium minerals

Our interest in titanium minerals consists of our effective 50% interest in Richards Bay Minerals and a 100% interest in the TiGen minerals sands project in Mozambique. Richards Bay Minerals is jointly owned with Rio Tinto and our share was part of the BHP Billiton Plc Group prior to the DLC merger with the BHP Billiton Limited Group on June 29, 2001. Richards Bay Minerals was formed in 1976 to mine and beneficiate the sands in the coastal dunes north of Richards Bay in the province of KwaZulu-Natal, South Africa. These operations involve the mining of heavy mineral sands to produce ilmenite, natural rutile, zircon and pig iron. Richards Bay Minerals processes the ilmenite to produce titanium dioxide slag and high purity iron.

Richards Bay Minerals has rights to over 1 billion tonnes of heavy mineral sands reserves. This should be sufficient to sustain mining for approximately 20 years. In the early 1990’s, a new furnace and mining plant were installed at a total cost of US$300 million. The fifth sand mining plant, Mining Plant E, was completed under budget in November 1999 at a cost of approximately US$189 million. This plant, along with an expansion to Mining Plant A, also completed in 1999, should allow Richards Bay Minerals to maintain an annual titanium slag capacity of around one million tonnes for the foreseeable future. Due to an oversupply in the slag market, Richards Bay has been operating at less than its rated slag capacityduring calendar year 2002.

Richards Bay Minerals has full rights to the mining leases of all its reserves. Richards Bay Minerals’ mining leases are valid for the remainder of the mine life, although this may be affected by legislative changes flowing from the South African mining charter. Refer to “Business Description – Carbon Steel Materials – Regulatory and Fiscal Terms – South African Mining Charter” for further information.

Richards Bay Minerals mines heavy mineral sands from five ponds located in coastal dunes using a dredging process. A large artificial freshwater pond is created in the dunes, on which the dredge and concentrator plant float. Burrowing into the mining face of the dune, the dredge advances at a rate of two metres to three metres per day, depending on the height of the dune. As the sand face is undermined it collapses into the pond, a slurry is formed and is sucked up and pumped to a floating concentrator. In the concentrator, the heavy minerals are separated from the lighter sand particles by using a gravity separation process, and stockpiled as heavy mineral concentrate for transportation to the mineral separation plant. The sand residue is used for dune reshaping and rehabilitation.

The heavy mineral concentrate is transported from the mining plants to the mineral separation plant where the material is passed over a series of magnets that remove the ilmenite which is set aside to be fed into the smelter.

The non-magnetic minerals, including zircon and rutile, remain and are further processed by means of an electrostatic process which takes advantage of the difference in the electrical conductivity of the minerals. Zircon and rutile can be dispatched and sold in their raw form, although some zircon is upgraded to produce a higher quality product by the removal of various impurities.

The ilmenite, containing approximately 50% titanium dioxide, is transferred by conveyor for further beneficiation, which involves smelting. Controlled quantities of calcined ilmenite and charred coal are fed into electric furnaces at the smelter where the mixture is reduced to produce titanium dioxide slag, with a grading of titanium dioxide of approximately 85% and high purity iron. The slag is tapped into moulds and the iron into ladles. The high purity iron undergoes further treatment whereby chemical additives are injected to obtain various grades of low manganese pig iron.

Approximately 90% of the titanium dioxide slag produced by Richards Bay Minerals is suitable for the chloride process of titanium dioxide pigment manufacture and is sold internationally under medium-term contracts. The zircon, rutile and pig iron are sold as end products both internationally and locally.

We have a 100% interest in TiGen, a heavy mineral sands resource located at Moebase in Mozambique, 500 kilometres north of Beira. A preliminary feasibility study was completed in 1996 and concluded that the ilmenite from Moebase could be treated to produce a good quality chlorinatable slag. In 1997, we began a phased feasibility study of TiGen, which has not yet been completed. Test work and analysis relating to this study is also being conducted. Results to date indicate that the resource contains ilmenite, rutile and zircon and is one of the world’s major heavy mineral sands deposits, comparable in size to Richards Bay Minerals.

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Reserves and Production

The table below details our titanium minerals reserves in metric tonnes as estimated at January 1, 2003.

Ore type

Proved

Reserves

Probable
Reserves

Total

Reserves

BHP Billiton
Group
Interest