Edgar Filing: BHP Group Ltd

Form 6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

February 19, 2019


BHP GROUP LIMITED		BHP GROUP PLC
(ABN 49 004 028 077)		(REG. NO. 3196209)
(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)
171 COLLINS STREET, MELBOURNE, VICTORIA 3000 AUSTRALIA		NOVA SOUTH, 160 VICTORIA STREET
		LONDON, SW1E 5LB
		UNITED KINGDOM
(Address of principal executive offices)		(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or

Form 40-F: ☒ Form 20-F ☐ Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934: ☐ Yes ☒ No

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): n/a


Release Time		IMMEDIATE
Date		19 February 2019
Number		05/19

BHP RESULTS FOR THE HALF YEAR ENDED 31 DECEMBER 2018

Safety and sustainability: We will continue our work to improve safety at our operations

•

Tragically we had a fatality at Saraji in December 2018, despite improvements in our safety performance indicators.

Maximise cash flow: Solid free cash flow generation and margin above 50%

•

Attributable profit of US$3.8 billion and Underlying attributable profit⁽ⁱ⁾of US$3.7 billion down 8% from the prior period.

•

Underlying EBITDA⁽ⁱ⁾of US$10.5 billion at a margin⁽ⁱ⁾of 52% from continuing operations.

•

Net operating cash flow of US$6.7 billion and free cash flow⁽ⁱ⁾of US$3.6 billion from continuing operations with volumes and commodity prices broadly in line with the prior period.

•

Productivity⁽ⁱ⁾guidance is now expected to be broadly flat for the 2019 financial year largely reflecting the unplanned production outages at Olympic Dam, Western Australia Iron Ore, Spence and Nickel West.

Capital discipline: Net debt reduced to US$9.9 billion and to remain at the lower end of the target range

•

Net debt⁽ⁱ⁾of US$9.9 billion, reduced by US$1.0 billion from 30 June 2018 (reduced by US$5.5 billion from 31 December 2017), which includes US$7.0 billion⁽ⁱⁱ⁾of proceeds received from the Onshore US sale, partially offset by the completion of a US$5.2 billion off-market BHP Group Limited share buy-back.

•

Capital and exploration expenditure⁽ⁱ⁾of US$3.5 billion. Guidance unchanged at below US$8 billion per annum for the 2019 and 2020 financial years. This includes investments in the high returning West Barracouta (Bass Strait) and Atlantis Phase 3 (US Gulf of Mexico) projects approved in December 2018 and February 2019, respectively.

•

In exploration, we encountered oil at Trion (Mexico), hydrocarbons at Bongo-2 (Trinidad and Tobago) and had early success at our copper exploration program in the Stuart Shelf (South Australia). We also added new optionality with interests acquired in the Orphan Basin (offshore Eastern Canada) and SolGold (Cascabel copper project in Ecuador).

Value and returns: Onshore US sale completed with US$10.4 billion net proceeds returned to shareholders

•

The Onshore US sales process was completed on 31 October 2018, with the net proceeds of US$10.4 billion returned to shareholders through a combination of an off-market buy-back in December 2018 and a special dividend (US$1.02 per share) in January 2019.

•

The Board has determined to pay an interim dividend of 55 US cents per share which includes an additional amount of 18 US cents per share (equivalent to US$0.9 billion) above the 50% minimum payout policy. This brings the total announced returns to shareholders over the last six months to US$13.2 billion.

•

Underlying return on capital employed⁽ⁱ⁾, excluding Onshore US assets, of 15% (after tax).


Half year ended 31 December	2018 US$M		2017 US$M		Change %
Total operations
Attributable profit		3,764		2,015		87	%
Basic earnings per share (cents)		71.0		37.9		87	%
Interim dividend per share (cents)		55.0		55.0		0	%
Net operating cash flow		7,274		7,343		(1	%)
Capital and exploration expenditure		3,501		2,877		22	%
Net debt		9,890		15,411		(36	%)
Underlying attributable profit		3,732		4,053		(8	%)
Underlying basic earnings per share (cents)⁽ⁱ⁾		70.4		76.1		(8	%)

Continuing operations
Profit from operations		7,333		7,165		2	%
Underlying EBITDA		10,539		10,836		(3	%)
Underlying attributable profit⁽ⁱ⁾		4,032		4,399		(8	%)
Net operating cash flow		6,709		6,993		(4	%)

Results for the half year ended 31 December 2018

BHP Chief Executive Officer, Andrew Mackenzie:

“The collapse of the Brumadinho dam in Brazil is a tragedy and we offer our heartfelt sympathy to all those affected. At BHP, we are committed to learn from what happened, and as an industry we must redouble our efforts to make sure events like this cannot happen.

Our focus on portfolio simplification, cash generation and capital discipline delivered higher cash returns to shareholders in the December 2018 half year.

Our strong balance sheet and fully funded capital investment plans allowed us to return the US$10.4 billion net Onshore US proceeds to shareholders in the form of a US$5.2 billion off-market share buy-back completed in December 2018 and a US$5.2 billion special dividend paid in January 2019. The Board has also today determined to pay an interim dividend of 55 cents per share, which equates to a payout ratio of 75 per cent.

Since the beginning of 2016, we have reduced debt by US$16 billion, reinvested US$20 billion in the business and returned more than US$25 billion to shareholders.

A strong second half is expected to partially offset the impacts from operational outages in the first half, with unit costs across our business forecast to improve.

We have a portfolio of attractive development opportunities and have recently approved the West Barracouta and Atlantis Phase 3 projects in petroleum and had early success in our oil and copper exploration programs. We are confident in our plans to increase shareholder value and returns.”

Sustainability is one of our core values

Safety, health and environment

The health and safety of our employees and contractors, and that of the broader communities in which we operate, are central to the success of our organisation. Tragically, one of our colleagues died at Saraji in Queensland in December 2018. Our Total Recordable Injury Frequency (TRIF) was 4.3 per million hours worked⁽ⁱⁱⁱ⁾ for the first half of the 2019 financial year, a two per cent reduction from 30 June 2018. The frequency rate for high potential injuries, which are injury events where there was the potential for a fatality, declined by 25 per cent⁽ⁱⁱⁱ⁾.

We are determined to become safer through the redesign of our work and increased application of technology to eliminate hazards, while improving our awareness through leadership engagement in the field. Proactive hazard reporting from the workforce and in-field safety leadership engagements increased significantly in the December 2018 half year.

Samarco

BHP remains committed to supporting the Renova Foundation with the recovery of communities and ecosystems affected by the Samarco tragedy.

Resettlement of the Bento Rodrigues, Paracatu and Gesteira communities is a priority of the Renova Foundation. Key milestones have been achieved in each of the three relocation programs.

As part of the compensation program, more than 8,200 general damages claims have been resolved in addition to the resolution of approximately 260,000 claims for temporary interruption to water supplies immediately following the dam failure. The river remediation programs continue to deliver improvements in water quality, with turbidity levels in impacted areas returned to historical levels.

The restart of Samarco’s operations will occur only if it is safe, economically viable and has the support of the community. To restart, Samarco requires the necessary licencing approvals and the funding for restart preparation works. A key consideration regarding further shareholder funding is that restart remains economically viable, which includes an appropriate debt restructure.

In the December 2018 half year, BHP reported an exceptional loss of US$210 million (after tax) in relation to the Samarco dam failure. Additional commentary is included on page 42.

Financial performance

Earnings and margins

•

Attributable profit of US$3.8 billion includes an exceptional gain of US$32 million (after tax), compared to an attributable profit of US$2.0 billion, which includes an exceptional loss of US$2.0 billion (after tax), in the prior period. The December 2018 half year exceptional gain is related to the reversal of provisions for global taxation matters which were resolved during the period, partially offset by a loss related to the Samarco dam failure. The December 2017 half year exceptional loss related to the US tax reform and the Samarco dam failure.

•

Underlying attributable profit of US$3.7 billion, compared to US$4.1 billion in the prior period.

•

Profit from operations (continuing operations) of US$7.3 billion, compared to US$7.2 billion in the prior period, has increased as a result of lower depreciation and amortisation charges and the favourable impacts of exchange rate movements, partially offset by higher costs.

•

Underlying EBITDA (continuing operations) of US$10.5 billion, compared to US$10.8 billion in the prior period, with higher costs (including production outages), inflation and other net movements (in total US$1.1 billion) more than offsetting the benefits of higher volumes at WAIO and Queensland Coal and favourable exchange rate movements (in total US$0.8 billion).

•

Underlying EBITDA margin (continuing operations) of 52 per cent, compared to 55 per cent in the prior period.

•

Underlying return on capital employed of 13.0 per cent (after tax), compared with 12.8 per cent in the prior period. Underlying return on capital employed, excluding Onshore US assets, is approximately 15 per cent (after tax), compared with 17 per cent in the prior period.

Productivity and costs

•

A negative movement in productivity of US$460 million was recorded and reflects a negative impact of US$835 million related to unplanned production outages at Olympic Dam (acid plant outage in August 2018), WAIO (train derailment in November 2018), Spence (fire at the electro-winning plant in September 2018) and Nickel West (fire at the Kalgoorlie smelter in September 2018). This impact was partially offset by the build-up of inventory levels during the outages (benefit of approximately US$160 million) as well as record volumes at Jimblebar and South Walker Creek. The inventory build from the outages will be released in the coming periods.

•

We expect a strong second half performance to offset the negative productivity movement in this period, bringing the overall movement to broadly flat for the full year, down from the previous guidance of US$1 billion.

•

We will continue to drive productivity improvements as we unlock value through technology with the ongoing automation of our supply chain, reduce our reliance on labour hire through the continued roll out in Australia of our Operations Services initiative to leverage best practice in production and maintenance, and continue to set records for underground development, equipment utilisation, milling and production across our operations.

•

Unit costs⁽ⁱ⁾at our major assets were above full year guidance (at 2019 financial year guidance exchange rates of AUD/USD 0.75 and USD/CLP 663) as a result of planned maintenance and production outages during the period.

•

Full year unit cost guidance remains unchanged for our major assets (based on exchange rates of AUD/USD 0.75 and USD/CLP 663).

•

Historical costs and guidance are summarised below:


	H1 FY19 at
	Medium-term guidance⁽¹⁾		FY19 guidance⁽¹⁾		guidance exchange rates⁽¹⁾		realised exchange rates⁽²⁾		H1 FY18		H1 FY19⁽²⁾vs H1 FY18
Conventional Petroleum unit cost (US$/boe)		<13		<11		11.36		11.14		10.17		10	%
Escondida unit cost (US$/lb)		<1.15		<1.15		1.18		1.17		1.06		10	%
Western Australia Iron Ore unit cost (US$/t)		<13		<14		15.03		14.51		14.90		(3	%)
Queensland Coal unit cost (US$/t)		~57		68—72		72.72		70.20		71.21		(1	%)

(1)	FY19 unit costs guidance are based on exchange rates of AUD/USD 0.75 and USD/CLP 663.

(2)	Average exchange rates for H1 FY19 of AUD/USD 0.72 and USD/CLP 671.

•

Production and guidance are summarised below:


Production	H1 FY19		H1 FY18 vs H1 FY19			FY18		FY19 guidance
Petroleum Conventional (MMboe)		63		(1	%)		120		113 - 118	FY19 guidance unchanged, with volumes expected to be towards the upper end of range.
Copper (kt)		825		(1	%)		1,753		1,645 - 1,740	FY19 guidance increased.
Escondida (kt)		580		0	%		1,213		1,120 - 1,180	FY19 guidance unchanged, with volumes expected to be towards the lower end of range.
Other copper⁽¹⁾(kt)		245		(2	%)		540		525 - 560	FY19 guidance increased from 500-525 kt and reflects the retention of Cerro Colorado (60-70 kt).
Iron ore⁽²⁾(Mt)		119		2	%		238		241 - 250	FY19 guidance unchanged.
WAIO (100% basis) (Mt)		135		(1	%)		275		273 - 283	FY19 guidance unchanged.
Metallurgical coal (Mt)		21		2	%		43		43 - 46	FY19 guidance unchanged.
Energy coal (Mt)		13		(5	%)		29		28 - 29	FY19 guidance unchanged.

(1)	Other copper comprises Pampa Norte (including Cerro Colorado production for the full 2019 financial year to reflect its retention, previous guidance only included 35 kt of production for the first half of the 2019 financial year), Olympic Dam and Antamina.

(2)	Increase in BHP’s share of volumes reflects the expiry of the Wheelarra Joint Venture sublease in March 2018, with control of the sublease area reverted to the Jimblebar Joint Venture, which is accounted for on a consolidated basis with minority interest adjustments.

•

Group copper equivalent production was broadly unchanged in the December 2018 half year^(iv), with volumes for the full year also expected to be in line with the 2018 financial year^(iv).

Cash flow and balance sheet

•

Net operating cash flows (continuing operations) of US$6.7 billion, with volumes and commodity prices broadly in line with the prior period and higher Australian and Chilean income tax payments in the period.

•

Free cash flow (continuing operations) of US$3.6 billion for the half year. Free cash flow of US$10.6 billion, which includes US$7.0 billion⁽ⁱⁱ⁾of proceeds received from the sale of Onshore US. Remaining consideration of US$3.5 billion to be received during the June 2019 half year.

•

Our balance sheet remains strong with net debt of US$9.9 billion at 31 December 2018 (30 June 2018: US$10.9 billion; 31 December 2017: US$15.4 billion). The reduction of US$1.0 billion in the half year (or US$5.5 billion from 31 December 2017) includes proceeds received from the sale of Onshore US, partially offset by the completion of a US$5.2 billion off-market buy-back.

•

We will maintain a strong balance sheet through the commodity price cycle, with a targeted net debt range of US$10 to US$15 billion^(v). In the near term, we expect net debt to remain at the lower end of the target range.

•

Gearing ratio⁽ⁱ⁾of 15.2 per cent (30 June 2018: 15.3 per cent; 31 December 2017: 19.9 per cent).

Dividends and share buy-back

•

On 17 December 2018, a US$5.2 billion off-market buy-back of BHP Group Limited shares was successfully completed. On 30 January 2019, a special dividend of US$1.02 per share, representing the balance of US$5.2 billion of the net proceeds from the sale of Onshore US, was paid to shareholders.

•

The dividend policy provides for a minimum 50 per cent payout of Underlying attributable profit at every reporting period. The minimum dividend payment for the December 2018 half year period is 37 US cents per share or US$1.9 billion.

•

The Board has determined to pay an additional amount of 18 US cents per share or US$0.9 billion, taking the interim dividend to 55 US cents per share. This is equivalent to a 75 per cent payout ratio.

•

This brings the total announced returns to shareholders over the last six months to US$13.2 billion.

Capital and exploration

•

Capital and exploration expenditure of US$3.5 billion in the December 2018 half year included maintenance expenditure^(vi)of US$0.8 billion, exploration of US$0.4 billion and Onshore US expenditure of US$0.4 billion.

•

Capital and exploration expenditure guidance is unchanged at below US$8 billion per annum for the 2019 and 2020 financial years, subject to exchange rate movements.

•

This guidance includes a US$0.9 billion exploration program being executed for the 2019 financial year, with US$750 million for petroleum exploration and appraisal expenditure.

•

Historical capital and exploration expenditure and guidance are summarised below:


	FY19e US$B		H1 FY19 US$M		H1 FY18 US$M		FY18 US$M
Maintenance⁽¹⁾⁽²⁾		2.1		829		994		1,930
Development
Minerals		4.0		1,545		859		2,494
Conventional Petroleum⁽²⁾		0.6		287		225		555

Capital expenditure (purchases of property, plant and equipment)		6.7		2,661		2,078		4,979

Add: exploration expenditure		0.9		397		464		874

Capital and exploration expenditure – continuing operations		7.6		3,058		2,542		5,853

Capital and exploration expenditure – discontinued operations		0.4		443		335		900

Capital and exploration expenditure – total operations		<8.0		3,501		2,877		6,753

(1)	Includes capitalised deferred stripping of US$1.0 billion for the FY19e and US$508 million for the H1 FY19 (H1 FY18: US$433 million; FY18: $880 million).

(2)	Conventional Petroleum capital expenditure for FY19e includes US$0.6 billion of development and US$0.1 billion of maintenance.

•

Average annual sustaining capital expenditure guidance over the medium term is unchanged and forecast to be approximately:

•

US$4 per tonne for WAIO, including the capital cost for South Flank;

•

US$8 per tonne for Queensland Coal; and

•

US$5 per tonne for New South Wales Energy Coal (NSWEC).

•

At the end of the December 2018 half year, BHP had five major projects under development (in petroleum, copper, iron ore and potash) with a combined budget of US$10.6 billion over the life of the projects.

Major projects

•

On 13 February 2019, the BHP Board approved an investment of US$0.7 billion (BHP share) for the development of the Atlantis Phase 3 project in the deepwater Gulf of Mexico.

•

Major projects are summarised below:

Commodity

Project and ownership

Project scope / capacity⁽¹⁾

Capital
expenditure⁽¹⁾US$M

Date of
initial
production

Progress / comments

Budget

Target

Projects in execution at 31 December 2018

Iron Ore

South Flank
(Australia)
85%

Sustaining iron ore mine to replace production from the 80 Mtpa Yandi mine.

3,061

CY21

21% complete
On schedule and
budget

Copper

Spence Growth Option
(Chile)
100%

New 95 ktpd concentrator is expected to increase Spence’s payable copper in concentrate production by approximately 185 ktpa in the first 10 years of operation and extend the mining operations by more than 50 years.

2,460

FY21

34% complete
On schedule and
budget

Petroleum

North West Shelf Greater
Western Flank-B
(Australia)
16.67%
(non-operator)

To maintain LNG plant throughput from the North West Shelf operations.

216

CY19

98% complete
First production
achieved in October
2018, ahead of
schedule and below
budget.

Petroleum

Mad Dog Phase 2
(US Gulf of Mexico)

23.9% (non-operator)

New floating production facility with the capacity to produce up to 140,000 gross barrels of crude oil per day.

2,154

CY22

37% complete
On schedule and
budget

Other projects in progress at 31 December 2018

Potash⁽²⁾

Jansen Potash (Canada)
100%

Investment to finish the excavation and lining of the production and service shafts, and to continue the installation of essential surface infrastructure and utilities.

2,700

82% complete
Within the approved
budget

(1)	Unless noted otherwise, references to capacity are on a 100 per cent basis, references to capital expenditure from subsidiaries are reported on a 100 per cent basis and references to capital expenditure from joint operations reflect BHP’s share.

(2)	Potash capital expenditure of approximately US$240 million is expected for the 2019 financial year.

Capital Allocation Framework

Adherence to our Capital Allocation Framework aims to balance value creation, cash returns to shareholders and balance sheet strength in a transparent and consistent manner.


	H1 FY19 US$B			H1 FY18 US$B			FY18 US$B
Net operating cash flow – total operations		7.3			7.3			18.5

Our priorities for capital
Maintenance capital		0.8			1.0			1.9
Strong balance sheet		✓			✓			✓
Minimum 50% payout ratio dividend		2.5			1.8			3.8

Excess cash⁽¹⁾		3.6			3.8			11.8

Balance sheet		1.8			1.5			5.6
Additional dividends		0.9			0.5			1.4
Buy-back		5.2			–			–
Organic development		2.7			1.9			4.9
Acquisitions/(Divestments)		(7.0	)		(0.1	)		(0.1	)

(1)

Includes dividends paid to non-controlling interests of US$0.6 billion for H1 FY19 (H1 FY18: US$0.9 billion); excludes exploration expenses of US$0.2 billion (H1 FY18: US$0.2 billion) which is classified as organic development in accordance with the Capital Allocation Framework; net cash outflow of US$0.4 billion (H1 FY18: US$0.7 billion).

Outlook

Economic outlook

The global economy grew around 3³⁄₄ per cent in the 2018 calendar year, with a notable pick up in the US economy and resilient growth in China. We expect world growth to sit in the range of 3¹⁄₄ per cent to 3³⁄₄ per cent for the 2019 calendar year. Further escalation in trade protection is a downside risk.

We expect China’s economic growth to slow modestly in the 2019 calendar year. The negative impact of weaker exports will be partially offset by easier monetary and fiscal policy. In our view, China’s policymakers will continue to seek a balance between the pursuit of reform and maintenance of macroeconomic and financial stability. Over the longer term, we expect China’s economic growth rate to decelerate as the working age population falls and the capital stock matures.

The US performed strongly in the 2018 calendar year but near-term prospects are less certain. The expansionary impact of tax cuts will progressively fade and trade policies remain unpredictable. In Europe and Japan, we believe business confidence and manufacturing momentum peaked in the 2018 calendar year. In India, growth prospects are solid. The general election, timed for the first half of the 2019 calendar year, is a key milestone for the country’s reform trajectory.

Commodities outlook

Crude oil prices were volatile in the second half of the 2018 calendar year. Brent Crude hit a four year high ahead of US sanctions on Iran taking effect. Prices then fell sharply towards the end of the 2018 calendar year on mounting oversupply concerns, despite OPEC “Plus” announcing further production cuts in December 2018. The fundamental outlook remains positive, underpinned by rising demand from the developing world and natural field decline in supply.

The Japan-Korea Marker price for LNG was higher on average compared to the previous calendar year, reflecting strong demand and slower than expected ramp-ups. A material amount of new supply is expected to come online in 2019. Longer term, the demand outlook for gas remains positive. Depleting domestic gas supplies in some major consuming markets will help LNG to grow faster than overall gas demand.

Copper prices have maintained a relatively tight range for much of the December 2018 half year. This period of stability followed a sharp drop associated with the trade tensions that escalated in the June quarter of 2018. Against this backdrop, we believe underlying fundamentals remain sound. Copper demand should grow steadily. Grade decline, rising input costs, water constraints and a scarcity of high-quality future development opportunities continue to constrain the industry’s ability to cheaply meet this growing demand and provide support for our positive outlook.

Global steel production has maintained healthy growth in the 2018 calendar year. Growth is expected to slow in the 2019 calendar year, along with the global economy. Margins have begun to normalise from the extremes seen in the initial stages of steel Supply Side Reform in China. That is an anticipated development. We expect quality differentiation to remain a durable element in price formation for steel-making raw materials.

The Platts 62% Fe Iron Ore Fines index performed solidly in the December 2018 half year, driven by firm pig iron production and unanticipated supply disruptions. The lump premium has been strong. In the short term, the supply picture is uncertain following the tragedy in Brazil. Total demand in the 2019 calendar year is expected to be similar to last year.

The Platts premium low-volatility metallurgical coal price index finished the 2018 calendar year strongly, with healthy demand conditions, especially in India, set against a modest recovery in seaborne supply. China’s import policies remain a source of uncertainty. Over the longer term, India is expected to sustain strong demand growth, while high quality metallurgical coals are expected to continue to offer steelmakers value-in-use benefits in mature markets.

Potash prices have performed strongly over the last year, despite several major capacity additions coming online. Demand lifted again in the 2018 calendar year, following a record in 2017 calendar year. We expect annual demand growth of between two and three per cent over the next decade, resulting in demand exceeding available supply from existing and forthcoming capacity by the mid-to-late 2020s.

Further information on BHP’s economic and commodity outlook can be found at: bhp.com/prospects

Underlying EBITDA

The following table and commentary describe the impact of the principal factors(i) that affected Underlying EBITDA for the December 2018 half year compared with the December 2017 half year:


	US$M
Half year ended 31 December 2017		10,836
Net price impact:
Change in sales prices		32		Higher average realised prices for petroleum and metallurgical coal, offset by lower average realised prices for thermal coal, copper and iron ore.
Price-linked costs		(173	)	Increased royalties reflect higher realised prices related to petroleum and metallurgical coal.
		(141	)
Change in volumes:
Productivity		50		Increased volumes at WAIO (record production at Jimblebar, expiry of the Wheelarra Joint Venture, partially offset by the impact from a train derailment) and our Australian coal operations (record production at South Walker Creek, higher wash-plant throughput at Poitrel and improved ultra-class truck productivity) offset by lower volumes at Spence (fire at the electro-winning plant).
Growth		(95	)	Lower petroleum volumes due to planned dry-dock maintenance at Pyrenees and expected natural field decline.
		(45	)
Change in controllable cash costs:
Operating cash costs		(606	)	Higher costs reflect: increased planned maintenance activity; costs related to unplanned production outages at Olympic Dam, WAIO, Spence and Nickel West; increased contractor stripping activity and rates at Queensland Coal; and lower concentrator head grade at Escondida, partially offset by favourable inventory movements across a number of assets.
Exploration and business development		(1	)	Higher petroleum exploration expenses (expensing of two wells and seismic acquisition cost) offset by lower study costs (following development approval of the Escondida Water Supply Extension project in March 2018).
		(607	)
Change in other costs:
Exchange rates		674		Impact of the weakening Australian dollar and Chilean peso against the US dollar.
Inflation		(206	)	Impact of inflation on the Group’s cost base.
Fuel and energy		(158	)	Predominantly higher diesel prices at minerals assets.
Non-Cash		124		Higher capitalisation of deferred stripping and lower depletion at Escondida.
One-off items		–
		434
Asset sales		20
Ceased and sold operations		45		Sale of Bruce and Keith oil and gas fields in the United Kingdom.
Other items		(3	)	Lower average realised prices received by our equity accounted investments largely offset by higher sales volumes from Antamina and a favourable impact from the revaluation of the embedded derivative in the Trinidad and Tobago gas contract.

Half year ended 31 December 2018		10,539

The following table reconciles relevant factors with changes in the Group’s productivity:


Half year ended 31 December 2018	US$M
Change in controllable cash costs		(607	)
Change in volumes attributed to productivity		50

Change in productivity in Underlying EBITDA		(557	)
Change in capitalised exploration		97

Change attributable to productivity measures		(460	)

Prices and exchange rates

The average realised prices achieved for our major commodities are summarised in the following table and are presented on a total operations basis:


Average realised prices⁽¹⁾	H1 FY19		H1 FY18		H2 FY18		FY18		H1 FY19 vs H1 FY18			H1 FY19 vs H2 FY18			H1 FY19 vs FY18
Oil (crude and condensate) (US$/bbl)		69.41		53.76		67.07		60.12		29	%		3	%		15	%
Natural gas (US$/Mscf)⁽²⁾		3.98		3.54		3.71		3.62		12	%		7	%		10	%
US natural gas (US$/Mscf)		2.88		2.84		2.77		2.80		1	%		4	%		3	%
LNG (US$/Mscf)		10.19		7.48		8.65		8.07		36	%		18	%		26	%
Copper (US$/lb)⁽⁵⁾		2.54		3.08		2.93		3.00		(18	%)		(13	%)		(15	%)
Iron ore (US$/wmt, FOB)		55.62		56.54		56.86		56.71		(2	%)		(2	%)		(2	%)
Metallurgical coal (US$/t)		179.82		164.22		189.66		177.22		9	%		(5	%)		1	%
Hard coking coal (HCC) (US$/t)⁽³⁾		197.86		182.29		205.80		194.59		9	%		(4	%)		2	%
Weak coking coal (WCC) (US$/t)⁽³⁾		134.12		120.99		143.40		131.70		11	%		(6	%)		2	%
Thermal coal (US$/t)⁽⁴⁾		84.15		87.49		86.47		86.94		(4	%)		(3	%)		(3	%)
Nickel metal (US$/t)		12,480		11,083		13,974		12,591		13	%		(11	%)		(1	%)

(1)

Based on provisional, unaudited estimates. Prices exclude sales from equity accounted investments, third party product and internal sales, and represent the weighted average of various sales terms (for example: FOB, CIF and CFR), unless otherwise noted. Includes the impact of provisional pricing and finalisation adjustments.

(2)	Includes internal sales.

(3)

Hard coking coal (HCC) refers generally to those metallurgical coals with a Coke Strength after Reaction (CSR) of 35 and above, which includes coals across the spectrum from Premium Coking to Semi Hard Coking coals, while weak coking coal (WCC) refers generally to those metallurgical coals with a CSR below 35.

(4)	Export sales only; excludes Cerrejón. Includes thermal coal sales from metallurgical coal mines.

(5)	Comparative financial information has been restated for the new accounting standard, IFRS 15 Revenue from Contracts with Customers, which became effective from 1 July 2018.

In Copper, the provisional pricing and finalisation adjustments will decrease Underlying EBITDA by US$272 million in the 2019 financial year.

The following exchange rates relative to the US dollar have been applied in the financial information:


	Average Half year ended 31 December 2018		Average Half year ended 31 December 2017		As at 31 December 2018		As at 31 December 2017		As at 30 June 2018
Australian dollar⁽¹⁾		0.72		0.78		0.71		0.78		0.74
Chilean peso		671		638		696		615		648

(1)	Displayed as US$ to A$1 based on common convention.

Depreciation, amortisation and impairments

Depreciation, amortisation and impairments decreased by US$449 million to US$3.1 billion, reflecting lower depreciation and amortisation at Petroleum due to lower volumes at Shenzi and an increase in estimated remaining reserves at Atlantis, lower depreciation at Escondida due to an increase in asset life of the Escondida Water Supply project, and lower impairment charges compared to the previous period which predominantly related to conveyors at Escondida.

Net finance costs

Net finance costs decreased by US$125 million to US$533 million due to higher interest earned on increased cash and term deposit holdings along with higher interest.

Taxation expense

2018

2017

Half year ended 31 December

Profit before
taxation
US$M

Income tax
expense
US$M

Profit before
taxation
US$M

Income tax
expense
US$M

Statutory effective tax rate

6,800

(2,358

)

34.7

6,507

(4,101

)

63.0

Adjusted for:

Exchange rate movements

–

(98

)

Exceptional items⁽¹⁾

210

(242

)

210

2,320

Adjusted effective tax rate⁽ⁱ⁾

7,010

(2,532

)

36.1

6,717

(1,879

)

28.0

(1)	Refer exceptional items below for further details.

The Group’s adjusted effective tax rate, which excludes the influence of exchange rate movements and exceptional items, was 36.1 per cent (31 December 2017: 28.0 per cent). The higher adjusted effective tax rate reflects a reduction in US tax credits related to Chilean taxes. The adjusted effective tax rate is expected to be in the range of 33 to 38 per cent for the 2019 financial year.

Other royalty and excise arrangements which are not profit based are recognised as operating costs within Profit before taxation. These amounted to US$1.2 billion during the period (31 December 2017: US$986 million).

Exceptional items

The following table sets out the exceptional items for the December 2018 half year. Additional commentary is included on page 36.


Half year ended 31 December 2018	Gross US$M			Tax US$M		Net US$M
Exceptional items by category
Samarco dam failure⁽¹⁾		(210	)		–		(210	)
Global taxation matters⁽²⁾		–			242		242

Total		(210	)		242		32

Attributable to non-controlling interests		–			–		–
Attributable to BHP shareholders		(210	)		242		32

(1)	Refer to note 4 Exceptional items and note 12 Significant events – Samarco dam failure of the Financial Report for further information.

(2)	Financial impact of US$242 million relates to the reversal of provisions for global taxation matters which were resolved during the period. Refer to note 4 Exceptional items of the Financial Report for further information.

Debt management and liquidity

During the December 2018 half year, the Group continued to focus on debt reduction, with no new debt issued and a €1.25 billion bond repaid at maturity. The repayment of maturing debt and fair value adjustments contributed to a US$1.3 billion overall decrease in the Group’s gross debt, from US$26.8 billion at 30 June 2018 to US$25.5 billion at 31 December 2018.

At the subsidiary level, Escondida refinanced US$0.2 billion of maturing long term debt.

The Group has a US$6.0 billion commercial paper program backed by a US$6.0 billion revolving credit facility which expires in May 2021. As at 31 December 2018, the Group had no outstanding US commercial paper, no drawn amount under the revolving credit facility and US$15.6 billion in cash and cash equivalents.

Dividend

The BHP Board today determined to pay an interim dividend of 55 US cents per share (US$2.8 billion). The interim dividend to be paid by BHP Group Limited will be fully franked for Australian taxation purposes.

BHP’s Dividend Reinvestment Plan (DRP) will operate in respect of the interim dividend. Full terms and conditions of the DRP and details about how to participate can be found at bhp.com.


Events in respect of the interim dividend	Date
Currency conversion into rand		1 March 2019
Last day to trade cum dividend on Johannesburg Stock Exchange Limited (JSE)		5 March 2019
Ex-dividend Date JSE		6 March 2019
Ex-dividend Date Australian Securities Exchange (ASX), London Stock Exchange (LSE) and New York Stock Exchange (NYSE)		7 March 2019
Record Date		8 March 2019
Dividend Reinvestment Election date (including currency conversion and currency election dates for ASX and LSE)		11 March 2019
Payment Date		26 March 2019
DRP Allocation Date (ASX and LSE) within 10 business days after the payment date		9 April 2019
DRP Allocation Date (JSE), subject to the purchase of shares by the Transfer Secretaries in the open market Central Securities Depository Participant (CSDP) accounts credited/updated on or about		9 April 2019

BHP Group Plc shareholders registered on the South African section of the register will not be able to dematerialise or rematerialise their shareholdings between the dates of 6 March and 8 March 2019 (inclusive), nor will transfers between the UK register and the South African register be permitted between the dates of 1 March and 8 March 2019 (inclusive). American Depositary Shares (ADSs) each represent two fully paid ordinary shares and receive dividends accordingly. Details of the currency exchange rates applicable for the dividend will be announced to the relevant stock exchanges following conversion, and will appear on the Group’s website.

Any eligible shareholder who wishes to participate in the DRP, or to vary a participation election, should do so in accordance with the timetable set out above or, in the case of shareholdings on the South African branch register of BHP Group Plc, in accordance with the instructions of their Central Securities Depository Participant (CSDP) or broker. The DRP allocation price will be calculated in each jurisdiction as an average of the price paid for each share purchased to satisfy DRP elections. The allocation price applicable to each exchange will made available at bhp.com/DRP.

On 17 December 2018, BHP determined to pay a special dividend of US$1.02 per share (US$5.2 billion), which was paid on 30 January 2019 related to the disbursement of proceeds from the disposal of Onshore US.

Corporate governance

During the December 2018 half year, we announced that Wayne Murdy had decided not to stand for re-election at the 2018 Annual General Meetings of BHP, and retired from the Board as a Non-executive Director effective 2 November 2018.

The current members of the Board’s committees are:


Risk and Audit Committee	Nomination and Governance Committee	Remuneration Committee	Sustainability Committee
Lindsay Maxsted (Chairman)	Ken MacKenzie (Chairman)	Carolyn Hewson (Chairman)	Malcolm Broomhead (Chairman)
Terry Bowen	Malcolm Broomhead	Anita Frew	Ken MacKenzie
Anita Frew	Carolyn Hewson	Shriti Vadera	John Mogford
	Shriti Vadera

Segment summary⁽¹⁾

A summary of performance for the December 2018 and December 2017 half years is presented below. It excludes Onshore US.


Half year ended 31 December 2018 US$M	Revenue⁽²⁾			Underlying EBITDA⁽³⁾			Underlying EBIT⁽³⁾			Exceptional items⁽⁴⁾			Net operating assets⁽³⁾		Capital expenditure		Exploration gross⁽⁵⁾		Exploration to profit⁽⁶⁾
Petroleum		3,203			2,258			1,440			–			7,828		339		316		167
Copper		5,069			1,924			895			–			23,796		1,014		20		20
Iron Ore		7,418			4,341			3,526			(130	)		18,264		732		46		21
Coal		4,512			2,025			1,696			–			9,801		305		10		10
Group and unallocated items⁽⁷⁾		582			(9	)		(74	)		(20	)		3,517		271		5		5
Inter-segment adjustment⁽⁸⁾		(42	)		–			–			–			–		–		–		–

Total Group		20,742			10,539			7,483			(150	)		63,206		2,661		397		223


Half year ended 31 December 2017 (Restated) US$M	Revenue⁽²⁾⁽⁹⁾			Underlying EBITDA⁽³⁾			Underlying EBIT⁽³⁾			Exceptional items			Net operating assets⁽³⁾		Capital expenditure		Exploration gross⁽⁵⁾		Exploration to profit⁽⁶⁾
Petroleum		2,581			1,633			617			–			8,589		277		378		208
Copper		6,132			3,195			2,052			–			23,983		993		19		19
Iron Ore		7,221			4,307			3,430			(153	)		19,135		470		41		10
Coal		4,047			1,790			1,436			–			9,904		185		7		7
Group and unallocated items⁽⁷⁾		589			(89	)		(204	)		(13	)		2,492		153		19		19
Inter-segment adjustment⁽⁸⁾		(44	)		–			–			–			–		–		–		–

Total Group		20,526			10,836			7,331			(166	)		64,103		2,078		464		263

(1)

Group and segment level information is reported on a statutory basis which, in relation to Underlying EBITDA, includes depreciation, amortisation and impairments, net finance costs and taxation expense of US$291 million (2017: US$318 million) related to equity accounted investments. It excludes exceptional items of US$117 million (2017: US$137 million) related to share of loss from equity accounted investments.

Group profit before taxation comprised Underlying EBITDA, exceptional items, depreciation, amortisation and impairments of US$3,206 million (2017: US$3,671 million) and net finance costs of US$533 million (2017: US$658 million).

(2)	Revenue is based on Group realised prices and includes third party products. Sale of third party products by the Group contributed revenue of US$633 million and Underlying EBITDA of US$26 million (2017: US$725 million and US$29 million).

(3)	For more information on the reconciliation of certain alternative performance measures to our statutory measures, reasons for usefulness and calculation methodology, please refer to alternative performance measures set out on pages 57 to 66.

(4)	Exceptional items of US$(150) million excludes net finance costs of US$(60) million included in the total US$(210) million related to the Samarco dam failure.

(5)	Includes US$175 million capitalised exploration (2017: US$272 million).

(6)	Includes US$1 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2017: US$71 million).

(7)

Group and unallocated items includes Functions, other unallocated operations including Potash, Nickel West and consolidation adjustments. Revenue not attributable to reportable segments comprises the sale of freight and fuel to third parties. Exploration and technology activities are recognised within the relevant segments.


Half year ended 31 December 2018 US$M	Revenue		Underlying EBITDA⁽³⁾			D&A		Underlying EBIT⁽³⁾			Net operating assets⁽³⁾			Capital expenditure		Exploration gross		Exploration to profit
Potash		–		(56	)		2		(58	)		3,585			86		–		–
Nickel West		563		43			1		42			(180	)		128		5		5

Half year ended 31 December 2017 US$M	Revenue		Underlying EBITDA⁽³⁾			D&A		Underlying EBIT⁽³⁾			Net operating assets⁽³⁾			Capital expenditure		Exploration gross		Exploration to profit
Potash		–		(76	)		2		(78	)		3,258			117		–		–
Nickel West		575		71			39		32			(296	)		27		19		19

(8)	Comprises revenue of US$37 million generated by Petroleum (2017: US$38 million) and US$5 million generated by Iron Ore (2017: US$6 million).

(9)	Comparative financial information has been restated for the new accounting standard, IFRS15 Revenue from Contracts with Customers, which became effective from 1 July 2018.

Petroleum

Underlying EBITDA for Petroleum, excluding Onshore US, increased by US$625 million to US$2.3 billion in the December 2018 half year.


	US$M
Underlying EBITDA for the half year ended 31 December 2017		1,633
Net price impact		692		Higher average realised prices: Crude and condensate oil US$69.91/bbl (2017: US$54.27/bbl); Natural gas US$4.67/Mscf (2017: US$4.13/Mscf); LNG US$10.19/Mscf (2017: US$7.48/Mscf).
Change in volumes: growth		(95	)	Higher uptime in the US Gulf of Mexico and Australia and increased tax barrels in Trinidad & Tobago were more than offset by planned Pyrenees dry-dock maintenance and natural field decline across the portfolio.
Change in controllable cash costs		(97	)	Additional maintenance at our Australian assets (US$60 million) and higher exploration expenses (US$37 million) due to Ocean Bottom Node survey acquisition in Gulf of Mexico and expensing the Bongos-1 (mechanical failure) and Concepcion-1 wells.
Ceased and sold operations		42		Sale of our interests in the Bruce and Keith oil and gas fields.
Other		83		Other includes exchange rate, inflation and other items. Other items includes the impact from revaluation of embedded derivatives in Trinidad and Tobago gas contract of US$11 million loss (2017: US$97 million loss).
Underlying EBITDA for the half year ended 31 December 2018		2,258

Conventional Petroleum unit costs increased by 10 per cent to US$11.14 per barrel of oil equivalent due to the impact of planned maintenance and lower volumes. Unit cost guidance for the 2019 financial year remains unchanged at less than US$11 per barrel (based on an exchange rate of AUD/USD 0.75). In the medium term, we expect an increase in unit costs to less than US$13 per barrel as a result of natural field decline.


Conventional Petroleum unit costs⁽¹⁾(US$M)	H1 FY19			H2 FY18		H1 FY18		FY18
Revenue		3,203			2,827		2,581		5,408

Underlying EBITDA		2,259			1,749		1,644		3,393

Gross costs		944			1,078		937		2,015

Less: exploration expense⁽²⁾		166			379		137		516
Less: freight		64			84		68		152
Less: development and evaluation		20			21		13		34
Less: other⁽³⁾		(8	)		38		68		106

Net costs		702			556		651		1,207

Production (MMboe, equity share)		63			56		64		120

Cost per boe (US$)⁽⁴⁾⁽⁵⁾		11.14			9.93		10.17		10.06

(1)	Conventional Petroleum assets exclude divisional activities reported in Other and closed mining and smelting operations in Canada and the United States.

(2)	Exploration expense represents conventional Petroleum’s share of total exploration expense.

(3)	Other includes non-cash profit on sales of assets, inventory movements, foreign exchange, provision for onerous lease costs and the impact from revaluation of embedded derivatives in the Trinidad and Tobago gas contract.

(4)	H1 FY18 and H2 FY18 restated to exclude costs related to the Onshore US sale process

(5)	H1 FY19 based on an exchange rate of AUD/USD 0.72.

On 13 February 2019, the BHP Board approved the development of the Atlantis Phase 3 project in the US Gulf of Mexico. The project includes a subsea tie back with the potential to increase production by an estimated 38,000 barrels of oil per day (100 per cent basis) at its peak from eight new production wells. This decision follows sanction by BP (the operator).

Petroleum exploration

Petroleum exploration expenditure for the December 2018 half year was US$316 million, of which US$166 million was expensed. Activity for the period was largely focused in the US Gulf of Mexico, Trinidad & Tobago and Mexico. A US$750 million exploration and appraisal program is being executed for the 2019 financial year.

In the US Gulf of Mexico, Samurai-2 and Samurai-2 ST01 drilling has delineated the accumulation of oil. Further appraisal and development planning at Samurai is in progress. In the southern portion of the Wildling sub-basin, we continue to assess the potential resource, with further appraisal drilling now expected in the 2020 financial year. In the Western US Gulf of Mexico, the Ocean Bottom Node^(vii⁾ seismic acquisition was completed in early January 2019 and processed data is expected to be delivered during the March 2020 quarter.

Following the success in Trinidad and Tobago of the Bongos-2 Exploration well in the first half of the 2019 financial year, phase 3 of our deepwater exploration drilling campaign has been accelerated and will start in the second half of the 2019 financial year. Phase 3 will test three wells on three prospects in the northern licence area.

In Mexico, we spud the Trion-2DEL appraisal well in November 2018 and encountered oil in line with expectations. This was followed by a planned down dip geologic sidetrack which encountered oil and water, as predicted, further appraising the field and delineating the resource. Following the recent encouraging results in the Trion block, an additional appraisal well (3DEL) to further delineate the scale and characterisation of the resource is expected to be drilled in the second half of the 2019 calendar year.

Having been the successful bidder in October 2018 for licences in the Orphan Basin, offshore Eastern Canada, we have begun working with the Canada-Newfoundland and Labrador Offshore Petroleum Board to meet all regulatory requirements for the exploration phase. The licences became effective 15 January 2019.

Financial information for Petroleum for the December 2018 and December 2017 half years is presented below.


Half year ended 31 December 2018 US$M	Revenue⁽¹⁾			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets			Capital expenditure		Exploration gross⁽²⁾		Exploration to profit⁽³⁾
Australia Production Unit⁽⁴⁾		201			124			90			34			650			8
Bass Strait		768			580			241			339			2,300			16
North West Shelf		906			691			148			543			1,527			61
Atlantis		505			414			136			278			1,150			8
Shenzi		294			241			77			164			739			28
Mad Dog		160			124			29			95			1,070			180
Trinidad/Tobago		145			82			29			53			259			15
Algeria		143			119			13			106			46			3
Exploration		–			(166	)		20			(186	)		974			–
Other⁽⁵⁾		89			52			37			15			(32	)		20

Total Petroleum from Group production		3,211			2,261			820			1,441			8,683			339		316		167

Closed mines⁽⁶⁾		–			(1	)		–			(1	)		(855	)		–		–		–
Third party products		–			–			–			–			–			–		–		–

Total Petroleum		3,211			2,260			820			1,440			7,828			339		316		167

Adjustment for equity accounted investments⁽⁷⁾		(8	)		(2	)		(2	)		–			–			–		–		–

Total Petroleum statutory result		3,203			2,258			818			1,440			7,828			339		316		167


Half year ended 31 December 2017 (Restated) US$M	Revenue⁽¹⁾			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets			Capital expenditure		Exploration gross⁽²⁾		Exploration to profit⁽³⁾
Australia Production Unit⁽⁴⁾		291			206			135			71			828			2
Bass Strait		666			512			288			224			2,701			19
North West Shelf		663			497			116			381			1,573			80
Atlantis		355			245			198			47			1,361			71
Shenzi		264			212			94			118			845			5
Mad Dog		118			84			28			56			787			47
Trinidad/Tobago		64			(60	)		19			(79	)		290			6
Algeria		101			78			14			64			18			3
Exploration		–			(136	)		98			(234	)		1,174			–
Other⁽⁵⁾		57			9			28			(19	)		(143	)		44

Total Petroleum from Group production		2,579			1,647			1,018			629			9,434			277		378		208

Closed mines⁽⁶⁾		–			(11	)		–			(11	)		(845	)		–		–		–
Third party products		10			(1	)		–			(1	)		–			–		–		–

Total Petroleum		2,589			1,635			1,018			617			8,589			277		378		208

Adjustment for equity accounted investments⁽⁷⁾		(8	)		(2	)		(2	)		–			–			–		–		–

Total Petroleum statutory result		2,581			1,633			1,016			617			8,589			277		378		208

(1)

Total Petroleum statutory result revenue includes: crude oil US$1,667 million (2017: US$1,403 million), natural gas US$676 million (2017: US$581 million), LNG US$665 million (2017: US$423 million), NGL US$175 million (2017: US$141 million) and other US$20 million (2017: US$33 million which includes third party products).

(2)	Includes US$150 million of capitalised exploration (2017: US$241 million).

(3)	Includes US$1 million of exploration expenditure previously capitalised, written off as impaired (included in depreciation and amortisation) (2017: US$71 million).

(4)	Australia Production Unit includes Macedon, Pyrenees and Minerva.

(5)

Predominantly divisional activities, business development, UK (divested in November 2018), Neptune and Genesis. Also includes the Caesar oil pipeline and the Cleopatra gas pipeline, which are equity accounted investments. The financial information for the Caesar oil pipeline and the Cleopatra gas pipeline presented above, with the exception of net operating assets, reflects BHP’s share.

(6)	Comprises closed mining and smelting operations in Canada and the United States. Petroleum manages the closed mine sites due to their geographic location.

(7)

Total Petroleum statutory result Revenue excludes US$8 million (2017: US$8 million) revenue related to the Caesar oil pipeline and the Cleopatra gas pipeline. Total Petroleum statutory result Underlying EBITDA includes US$2 million (2017: US$2 million) D&A related to the Caesar oil pipeline and the Cleopatra gas pipeline.

Copper

Underlying EBITDA for the December 2018 half year decreased by US$1.3 billion to US$1.9 billion.


	US$M
Underlying EBITDA for the half year ended 31 December 2017		3,195

Net price impact		(940	)	Lower average realised price:
				Copper US$2.54/lb (2017: US$3.08/lb).
Change in volumes: productivity		(114	)	Lower concentrator head grade at Escondida; decreased sales volumes at Spence predominantly as a result of a fire at the electro-winning plant and lower stacked materials at the end of June 2018 reflecting planned maintenance, partially offset by higher cathode sales at Cerro Colorado.
Change in controllable cash costs		(301	)	Lower concentrator head grade at Escondida; planned drawdown of mined ore inventory following the Los Colorados Extension commissioning; end-of-negotiation bonus payments at Escondida and Cerro Colorado and costs related to production outages at Olympic Dam and Spence. This was partially offset by favourable inventory movements at Cerro Colorado, inventory build-up at Olympic Dam and Spence during outages and prior period unfavourable fixed cost dilution impact as a result of the smelter maintenance campaign at Olympic Dam.
Change in other costs:
Exchange rates		208
Inflation		(73	)
Non-cash		84		Increased waste movement and decreased deferred stripping depletion at Escondida.
Other		(135	)	Other includes fuel and energy of US$(56) million and other items (including lower profit from equity accounted investments).

Underlying EBITDA for the half year ended 31 December 2018		1,924

Escondida unit costs increased by 10 per cent to US$1.17 per pound, mainly due to lower concentrator head grade (11 per cent decrease) and labour settlement costs. Unit cost guidance for the 2019 financial year remains unchanged at less than US$1.15 per pound (based on an exchange rate of USD/CLP 663), as improved labour productivity and maintenance optimisation strategies are expected to partially offset a decrease in average concentrator head grade of approximately 15 per cent, consistent with the mine plan, and an increase in the usage of higher cost desalinated water. Unit costs are expected to remain at less than US$1.15 per pound over the medium term.


Escondida unit costs (US$M)	H1 FY19		H2 FY18		H1 FY18		FY18
Revenue		3,339		4,234		4,112		8,346

Underlying EBITDA		1,570		2,403		2,518		4,921

Gross costs		1,769		1,831		1,594		3,425

Less: by-product credits		224		251		196		447
Less: freight		76		73		50		123

Net costs		1,469		1,507		1,348		2,855

Sales (kt, equity share)		571		631		578		1,209

Sales (Mlb, equity share)		1,259		1,391		1,273		2,664

Cost per pound (US$)⁽¹⁾		1.17		1.08		1.06		1.07

(1)	H1 FY19 based on exchange rates of AUD/USD 0.72 and USD/CLP 671.

Consistent with our exploration focus on copper, in September 2018, BHP acquired an initial 6.1 per cent interest in SolGold Plc (SolGold), the majority owner and operator of the Cascabel porphyry copper-gold project in Ecuador. On 15 October 2018, BHP entered into an agreement to acquire an additional 100 million shares in SolGold, for an investment of US$59 million, with our total interest now approximately 11.2 per cent.

In November 2018, BHP confirmed identification of a potential new iron oxide, copper, gold mineralised system, located 65 kilometres to the south east of BHP’s operations at Olympic Dam in South Australia. Laboratory assay results show downhole mineralisation intercepts ranging from 0.5 per cent to six per cent copper with associated gold, uranium and silver metals. This exploration project is at an early stage and there is currently insufficient geological information to assess the size, quality and continuity of the mineralised intersections. BHP is evaluating and interpreting the results reported, and planning a further drilling program to commence in early in the 2019 calendar year.

Financial information for Copper for the December 2018 and December 2017 half years is presented below.


Half year ended 31 December 2018 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets			Capital expenditure			Exploration gross		Exploration to profit
Escondida⁽¹⁾		3,339			1,570			611			959			13,223			475
Pampa Norte⁽²⁾		613			284			207			77			2,254			291
Antamina⁽³⁾		562			374			55			319			1,310			119
Olympic Dam		523			(38	)		207			(245	)		7,123			247
Other⁽³⁾⁽⁴⁾		–			(103	)		5			(108	)		(114	)		1

Total Copper from Group production		5,037			2,087			1,085			1,002			23,796			1,133

Third party products		594			13			–			13			–			–

Total Copper		5,631			2,100			1,085			1,015			23,796			1,133			20		20

Adjustment for equity accounted investments⁽⁵⁾		(562	)		(176	)		(56	)		(120	)		–			(119	)		–		–

Total Copper statutory result		5,069			1,924			1,029			895			23,796			1,014			20		20


Half year ended 31 December 2017 US$M	Revenue⁽⁶⁾			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets			Capital expenditure			Exploration gross		Exploration to profit
Escondida⁽¹⁾		4,112			2,518			900			1,618			14,580			466
Pampa Norte⁽²⁾		860			428			143			285			1,686			191
Antamina⁽³⁾		677			495			57			438			1,254			103
Olympic Dam		479			27			97			(70	)		6,657			334
Other⁽³⁾⁽⁴⁾		–			(83	)		4			(87	)		(194	)		2

Total Copper from Group production		6,128			3,385			1,201			2,184			23,983			1,096

Third party products		681			23			–			23			–			–

Total Copper		6,809			3,408			1,201			2,207			23,983			1,096			19		19

Adjustment for equity accounted investments⁽⁵⁾		(677	)		(213	)		(58	)		(155	)		–			(103	)		–		–

Total Copper statutory result		6,132			3,195			1,143			2,052			23,983			993			19		19

(1)	Escondida is consolidated under IFRS 10 and reported on a 100 per cent basis.

(2)	Includes Spence and Cerro Colorado.

(3)	Antamina, SolGold and Resolution are equity accounted investments and their financial information presented above with the exception of net operating assets reflects BHP Group’s share.

(4)	Predominantly comprises divisional activities, greenfield exploration and business development. Includes Resolution and SolGold (acquired in October 2018).

(5)

Total Copper statutory result Revenue excludes US$562 million (2017: US$746 million) revenue related to Antamina. Total Copper statutory result Underlying EBITDA includes US$56 million (2017: US$58 million) D&A and US$120 million (2017: US$155 million) net finance costs and taxation expense related to Antamina, Resolution and SolGold that are also included in Underlying EBIT. Total Copper Capital expenditure excludes US$119 million (2017: US$103 million) related to Antamina.

(6)	Comparative financial information has been restated for the new accounting standard, IFRS15 Revenue from Contracts with Customers, which became effective from 1 July 2018.

Iron Ore

Underlying EBITDA for the December 2018 half year increased by US$34 million to US$4.3 billion.


	US$M
Underlying EBITDA for the half year ended 31 December 2017		4,307

Net price impact		(166	)	Lower average realised price:
				Iron ore US$55.62/wmt, FOB (2017: US$56.54/wmt, FOB).
Change in volumes: productivity		123		Increased sales volumes supported by record production at Jimblebar, higher volumes
				reflecting the expiry of the Wheelarra Joint Venture⁽¹⁾and the prior period impact from
				the Mt Whaleback fire. This increase was partially offset by the impact from a train
				derailment on 5 November 2018 which resulted in the suspension of rail operations for
				five days.
Change in controllable cash costs		28		Favourable inventory movements, partially offset by derailment remediation costs and
				higher maintenance activity.
Change in other costs:
Exchange rates		169
Inflation		(53	)
Other		(67	)	Other includes fuel and energy of US$(44) million, non-cash and other items.

Underlying EBITDA for the half year ended 31 December 2018		4,341

(1)	Increased volumes reflecting the expiry of the Wheelarra Joint Venture sublease in March 2018, with control of the sublease areas reverting to the Jimblebar Joint Venture, which is accounted for on a consolidated basis with minority interest adjustments.

WAIO unit costs decreased by three per cent to US$14.51 per tonne (or US$13.85 per tonne on a C1 basis excluding third party royalties(2)), reflecting favourable exchange movements which offset impacts from maintenance and unplanned outages during the period. Unit cost guidance for the 2019 financial year remains unchanged at less than US$14 per tonne (based on an exchange rate of AUD/USD 0.75). In the medium term, we expect to lower our unit costs to less than US$13 per tonne.


WAIO unit costs (US$M)	H1 FY19		H2 FY18		H1 FY18		FY18
Revenue		7,317		7,479		7,117		14,596

Underlying EBITDA		4,300		4,604		4,265		8,869

Gross costs		3,017		2,875		2,852		5,727

Less: freight		741		650		626		1,276
Less: royalties		540		571		504		1,075

Net costs		1,736		1,654		1,722		3,376

Sales (kt, equity share)		119,620		121,228		115,543		236,771

Cost per tonne (US$)⁽¹⁾		14.51		13.64		14.90		14.26

Cost per tonne on a C1 basis excluding third party royalties (US$)⁽²⁾		13.85		12.41		13.68		13.03

(1)	H1 FY19 based on an average exchange rate of AUD/USD 0.72.

(2)	Excludes third party royalties of US$0.84 per tonne (December 2017: US$0.73 per tonne), exploration expenses, depletion of production stripping, demurrage, exchange rate gains/losses, net inventory movements and other income.

Financial information for Iron Ore for the December 2018 and December 2017 financial years is presented below.


Half year ended 31 December 2018 US$M	Revenue		Underlying EBITDA		D&A		Underlying EBIT		Net operating assets			Capital expenditure		Exploration gross⁽¹⁾		Exploration to profit
Western Australia Iron Ore		7,317		4,300		798		3,502		19,318			723
Samarco⁽²⁾		–		–		–		–		(1,240	)		–
Other⁽³⁾		79		28		17		11		186			9

Total Iron Ore from Group production		7,396		4,328		815		3,513		18,264			732

Third party products⁽⁴⁾		22		13		–		13		–			–

Total Iron Ore		7,418		4,341		815		3,526		18,264			732		46		21

Adjustment for equity accounted investments		–		–		–		–		–			–		–		–

Total Iron Ore statutory result		7,418		4,341		815		3,526		18,264			732		46		21


Half year ended 31 December 2017 US$M	Revenue		Underlying EBITDA		D&A		Underlying EBIT		Net operating assets			Capital expenditure		Exploration gross⁽¹⁾		Exploration to profit
Western Australia Iron Ore		7,117		4,265		873		3,392		19,959			446
Samarco⁽²⁾		–		–		–		–		(1,025	)		–
Other⁽³⁾		76		36		4		32		201			24

Total Iron Ore from Group production		7,193		4,301		877		3,424		19,135			470

Third party products⁽⁴⁾		28		6		–		6		–			–

Total Iron Ore		7,221		4,307		877		3,430		19,135			470		41		10

Adjustment for equity accounted investments		–		–		–		–		–			–		–		–

Total Iron Ore statutory result		7,221		4,307		877		3,430		19,135			470		41		10

(1)	Includes US$25 million of capitalised exploration (2017: US$31 million).

(2)	Samarco is an equity accounted investment and its financial information presented above, with the exception of net operating assets, reflects BHP Billiton Brasil Ltda’s share. All financial impacts following the Samarco dam failure have been reported as exceptional items in both reporting periods.

(3)	Predominantly comprises divisional activities, towage services, business development and ceased operations.

(4)	Includes inter-segment and external sales of contracted gas purchases.

Coal

Underlying EBITDA for the December 2018 half year increased by US$235 million to US$2.0 billion.


	US$M
Underlying EBITDA for the half year ended 31 December 2017		1,790

Net price impact		238		Higher average realised metallurgical coal prices partially offset by lower thermal coal
				price:
				Hard coking coal US$197.86/t (2017: US$182.29/t);
				Weak coking coal US$134.12/t (2017: US$120.99/t);
				Thermal coal US$84.15/t (2017: US$87.49/t).
Change in volumes: productivity		53		Increased sales volumes supported by record production at South Walker Creek,
				higher wash-plant throughput at Poitrel (from Red Mountain processing facility),
				improved ultra-class truck productivity and prior period impacts from lower volumes at
				Broadmeadow (roof conditions) and Blackwater (geotechnical issues). This increase
				was partially offset by the scheduled longwall move at Broadmeadow during the
				period.
Change in controllable cash costs		(145	)	Increased contractor stripping activity and rates coupled with higher planned
				maintenance activity at Queensland Coal (US$65 million) and unfavourable inventory
				movements and increased contractor mining and stripping activity at NSWEC
				(US$80 million).
Change in other costs:
Exchange rates		193
Inflation		(47	)
Other		(57	)	Other includes: fuel and energy of US$(56) million and other items.

Underlying EBITDA for the half year ended 31 December 2018		2,025

Queensland Coal unit costs decreased by one per cent to US$70 per tonne, reflecting higher sales volumes and favourable exchange rate movements, partially offset by the impacts from planned maintenance during the period. Unit cost guidance for the 2019 financial year remains unchanged and is expected to be between US$68 and US$72 per tonne (based on an exchange rate of AUD/USD 0.75). In the medium term, we expect to lower our unit costs to approximately US$57 per tonne.


Queensland Coal unit costs (US$M)	H1 FY19		H2 FY18		H1 FY18		FY18
Revenue		3,767		4,038		3,350		7,388

Underlying EBITDA		1,811		2,143		1,504		3,647

Gross costs		1,956		1,895		1,846		3,741

Less: freight		85		86		64		150
Less: royalties		394		419		321		740

Net costs		1,477		1,390		1,461		2,851

Sales (kt, equity share)		21,039		21,383		20,516		41,899

Cost per tonne (US$)⁽¹⁾		70.20		65.00		71.21		68.04

(1)	H1 FY19 based on an average exchange rate of AUD/USD 0.72.

NSWEC unit costs increased by 14 per cent to US$54 per tonne as a result of unfavourable inventory movements and increased strip ratio and contractor stripping activity. This was partially offset by increased sales volumes and the impacts from favourable exchange rate movements. Unit cost guidance for the 2019 financial year remains unchanged at between US$43 and US$48 per tonne (based on an exchange rate of AUD/USD 0.75), with costs expected to be towards the upper end of the guidance range. In the medium term, geological constraints are expected to continue as the mine plan works through the monocline, with unit costs forecast to remain at approximately US$45 per tonne during this period.


New South Wales Energy Coal unit costs (US$M)	H1 FY19		H2 FY18		H1 FY18		FY18
Revenue		745		804		697		1,501

Underlying EBITDA		191		328		241		569

Gross costs		554		476		456		932

Less: royalties		60		60		51		111

Net costs		494		416		405		821

Sales (kt, equity share)		9,083		9,536		8,486		18,022

Cost per tonne (US$)⁽¹⁾		54.39		43.62		47.73		45.56

(1)	H1 FY19 based on an average exchange rate of AUD/USD 0.72.

Financial information for Coal for the December 2018 and December 2017 half years is presented below.


Half year ended 31 December 2018 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets			Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		3,767			1,811			269			1,542			8,328			256
New South Wales Energy Coal⁽¹⁾		799			229			75			154			968			47
Colombia⁽¹⁾		423			199			52			147			892			65
Other⁽²⁾		–			(63	)		1			(64	)		(387	)		3

Total Coal from Group production		4,989			2,176			397			1,779			9,801			371

Third party products		–			–			–			–			–			–

Total Coal		4,989			2,176			397			1,779			9,801			371			10		10

Adjustment for equity accounted investments⁽³⁾⁽⁴⁾		(477	)		(151	)		(68	)		(83	)		–			(66	)		–		–

Total Coal statutory result		4,512			2,025			329			1,696			9,801			305			10		10


Half year ended 31 December 2017 US$M	Revenue			Underlying EBITDA			D&A			Underlying EBIT			Net operating assets⁽⁵⁾			Capital expenditure			Exploration gross		Exploration to profit
Queensland Coal		3,350			1,504			294			1,210			8,384			176
New South Wales Energy Coal⁽¹⁾		750			304			92			212			1,035			10
Colombia⁽¹⁾		403			201			47			154			905			39
Other⁽²⁾		–			(53	)		2			(55	)		(420	)		(1	)

Total Coal from Group production		4,503			1,956			435			1,521			9,904			224

Third party products		–			–			–			–			–			–

Total Coal		4,503			1,956			435			1,521			9,904			224			7		7

Adjustment for equity accounted investments⁽³⁾⁽⁴⁾		(456	)		(166	)		(81	)		(85	)		–			(39	)		–		–

Total Coal statutory result		4,047			1,790			354			1,436			9,904			185			7		7

(1)	Newcastle Coal Infrastructure Group and Cerrejón are equity accounted investments and their financial information presented above with the exception of net operating assets reflects BHP Group’s share.

(2)	Predominantly comprises divisional activities.

(3)

Total Coal statutory result Revenue excludes US$423 million (2017: US$403 million) revenue related to Cerrejón. Total Coal statutory result Underlying EBITDA includes US$52 million (2017: US$47 million) D&A and US$61 million (2017: US$56 million) net finance costs and taxation expense related to Cerrejón, that are also included in Underlying EBIT. Total Coal statutory result Capital expenditure excludes US$65 million (2017: US$39 million) related to Cerrejón.

(4)

Total Coal statutory result Revenue excludes US$54 million (2017: US$53 million) revenue related to Newcastle Coal Infrastructure Group. Total Coal statutory result excludes US$38 million (2017: US$63 million) Underlying EBITDA, US$16 million (2017: US$34 million) D&A and US$22 million (2017: US$29 million) Underlying EBIT related to Newcastle Coal Infrastructure Group until future profits exceed accumulated losses. Total Coal Capital expenditure excludes US$1 million (2017: US$ nil) related to Newcastle Coal Infrastructure Group.

(5)	Queensland Coal net operating assets have been restated to reflect ceased operations in Other on a consistent basis with the December 2018 half year. There is no change to the overall net operating assets position.

Group and unallocated items

Underlying EBITDA loss for Group and unallocated items decreased by US$80 million to US$9 million in the December 2018 half year, as a favourable exchange rate impact on the off-market buy-back of BHP Group Limited shares more than offset the decrease in EBITDA at Nickel West.

Nickel West’s Underlying EBITDA decreased from US$71 million to US$43 million for the December 2018 half year predominantly due to the drawdown of ore inventories as the business transitions to new ore bodies and the impact from a fire at the Kalgoorlie smelter in September 2018, partially offset by higher prices and favourable exchange rate movements.

The Financial Report set out on pages 25 to 49 for the half year ended 31 December 2018 has been prepared on the basis of accounting policies and methods of computation consistent with those applied in the 30 June 2018 Financial Report with the exception of new accounting standards and interpretations which became effective from 1 July 2018. This news release including the financial information is unaudited. Variance analysis relates to the relative financial and/or production performance of BHP and/or its operations during the December 2018 half year compared with the December 2017 half year, unless otherwise noted. Operations includes operated and non-operated assets, unless otherwise noted. Numbers presented may not add up precisely to the totals provided due to rounding.

The following abbreviations may have been used throughout this report: barrels (bbl); billion cubic feet (bcf); barrels of oil equivalent (boe); billion tonnes (Bt); cost and freight (CFR); cost, insurance and freight (CIF), dry metric tonne unit (dmtu); free on board (FOB); grams per tonne (g/t); kilograms per tonne (kg/t); kilometre (km); metre (m); million barrels of oil equivalent (MMboe); million barrels of oil equivalent per day (MMboe/d); thousand cubic feet equivalent (Mcfe); million cubic feet per day (MMcf/d); million ounces per annum (Mozpa); million pounds (Mlb); million tonnes (Mt); million tonnes per annum (Mtpa); ounces (oz); pounds (lb); thousand barrels of oil equivalent (Mboe); thousand ounces (koz); thousand ounces per annum (kozpa); thousand standard cubic feet (Mscf); thousand tonnes (kt); thousand tonnes per annum (ktpa); thousand tonnes per day (ktpd); tonnes (t); and wet metric tonnes (wmt).

The following footnotes apply to this Results Announcement:

(i)

We use various alternative performance measures to reflect our underlying performance. For further information on the reconciliations of certain alternative performance measures to our statutory measures, reasons for usefulness and calculation methodology, please refer to alternative performance measures set out on pages 57 to 66.

(ii)

Net proceeds received from the sale of Onshore US at 31 December 2018 comprises of US$0.3 billion from the sale of Fayetteville and US$6.7 billion from the sale of Eagle Ford, Haynesville and Permian. Payment of the deferred consideration is not subject to any conditions and has been recognised as a US$3.5 billion receivable at 31 December 2018.

(iii)

Reported for total operations (including Onshore US).

(iv)	Copper equivalent production based on 2018 financial year average realised prices. Excludes production from Onshore US.

(v)	Adoption of IFRS 16 Leases is effective for the Group from 1 July 2019 and the potential impact is currently under review.

(vi)	Maintenance capital includes non-discretionary spend for the following purposes: deferred development and production stripping; risk reduction, compliance and asset integrity.

(vii)

WGOM OBN 2018 Seismic Permit is OCS Permit T18-010.

Forward-looking statements

This release contains forward-looking statements, including statements regarding: trends in commodity prices and currency exchange rates; demand for commodities; plans, strategies and objectives of management; closure or divestment of certain operations or facilities (including associated costs); anticipated production or construction commencement dates; capital costs and scheduling; operating costs and shortages of materials and skilled employees; anticipated productive lives of projects, mines and facilities; provisions and contingent liabilities; tax and regulatory developments.

Forward-looking statements can be identified by the use of terminology, including, but not limited to, ‘intend’, ‘aim’, ‘project’, ‘anticipate’, ‘estimate’, ‘plan’, ‘believe’, ‘expect’, ‘may’, ‘should’, ‘will’, ‘continue’, ‘annualised’ or similar words. These statements discuss future expectations concerning the results of operations or financial condition, or provide other forward-looking statements.

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 release. Readers are cautioned not to put undue reliance on forward-looking statements.

For example, our future revenues from our operations, projects or mines described in this release 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 or the feasibility of the development of a particular project, the expansion of certain facilities or mines, or the continuation of existing operations.

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 some 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; labour unrest; and other factors identified in the risk factors discussed in BHP’s filings with the U.S. Securities and Exchange Commission (the ‘SEC’) (including in Annual Reports on Form 20-F) which are available on the SEC’s website at www.sec.gov.

Except as required by applicable regulations or by law, the Group does not undertake any obligation to publicly update or review any forward-looking statements, whether as a result of new information or future events.

Past performance cannot be relied on as a guide to future performance.

No offer of securities

Nothing in this release should be construed as either an offer, or a solicitation of an offer, to buy or sell BHP securities in any jurisdiction, or be treated or relied upon as a recommendation or advice by BHP.

Reliance on third party information

The views expressed in this release contain information that has been derived from publicly available sources that have not been independently verified. No representation or warranty is made as to the accuracy, completeness or reliability of the information. This release should not be relied upon as a recommendation or forecast by BHP.

No financial or investment advice – South Africa

BHP does not provide any financial or investment ‘advice’ as that term is defined in the South African Financial Advisory and Intermediary Services Act, 37 of 2002, and we strongly recommend that you seek professional advice.

BHP and its subsidiaries

In this release, the terms ‘BHP’, ‘Group’, ‘BHP Group’, ‘we’, ‘us’, ‘our’ and ‘ourselves’ are used to refer to BHP Group Limited, BHP Group Plc and, except where the context otherwise requires, their respective subsidiaries as identified in note 27 ‘Subsidiaries’ in section 5.1 of BHP’s 30 June 2018 Annual Report on Form 20-F. Notwithstanding that this release may include production, financial and other information from non-operated assets, non-operated assets are not included in the BHP Group and, as a result, statements regarding our operations, assets and values apply only to our operated assets unless otherwise stated.

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LOGO

BHP

Financial Report

Half year ended

31 December 2018

Contents

Half Year Financial Statements


	Page
Consolidated Income Statement for the half year ended 31 December 2018		27

Consolidated Statement of Comprehensive Income for the half year ended 31 December 2018		27

Consolidated Balance Sheet as at 31 December 2018		28

Consolidated Cash Flow Statement for the half year ended 31 December 2018		29

Consolidated Statement of Changes in Equity for the half year ended 31 December 2018		30

Notes to the Financial Information		31

1. Basis of preparation		31

2. Impact of new accounting standards		33

3. Revenue		35

4. Exceptional items		36

5. Interests in associates and joint venture entities		37

6. Net finance costs		37

7. Income tax expense		38

8. Earnings per share		39

9. Dividends		39

10. Share capital		40

11. Financial risk management – Fair values		40

12. Significant events – Samarco dam failure		42

13. Discontinued operations		47

14. Subsequent events		49

Directors’ Report		50

Directors’ Declaration of Responsibility		52

Lead Auditor’s Independence Declaration under Section 307C of the Australian Corporations Act 2001		53

Independent Review Report		54

Consolidated Income Statement for the half year ended 31 December 2018


	Notes	Half year ended 31 Dec 2018 US$M			Half year ended 31 Dec 2017 US$M Restated			Year ended 30 June 2018 US$M Restated
*Continuing operations*
Revenue	3		20,742			20,526			43,129
Other income			170			123			247
Expenses excluding net finance costs			(13,695	)		(13,697	)		(27,527	)
Profit from equity accounted investments, related impairments and expenses	5		116			213			147

Profit from operations			7,333			7,165			15,996

Financial expenses			(772	)		(737	)		(1,567	)
Financial income			239			79			322

Net finance costs	6		(533	)		(658	)		(1,245	)

Profit before taxation			6,800			6,507			14,751

Income tax expense			(2,224	)		(4,057	)		(6,879	)
Royalty-related taxation (net of income tax benefit)			(134	)		(44	)		(128	)

Total taxation expense	7		(2,358	)		(4,101	)		(7,007	)

Profit after taxation from Continuing operations			4,442			2,406			7,744

*Discontinued operations*
(Loss)/profit after taxation from Discontinued operations	13		(293	)		168			(2,921	)

Profit after taxation from Continuing and Discontinued operations			4,149			2,574			4,823

Attributable to non-controlling interests			385			559			1,118
Attributable to BHP shareholders			3,764			2,015			3,705

Basic earnings per ordinary share (cents)	8		71.0			37.9			69.6
Diluted earnings per ordinary share (cents)	8		70.8			37.7			69.4
Basic earnings from Continuing operations per ordinary share (cents)	8		76.6			35.1			125.0
Diluted earnings from Continuing operations per ordinary share (cents)	8		76.4			35.0			124.6

The accompanying notes form part of this financial information.

Consolidated Statement of Comprehensive Income for the half year ended 31 December 2018


	Half year ended 31 Dec 2018 US$M			Half year ended 31 Dec 2017 US$M			Year ended 30 June 2018 US$M
Profit after taxation from Continuing and Discontinued operations		4,149			2,574			4,823
Other comprehensive income
Items that may be reclassified subsequently to the income statement:
Net valuation gains on investments taken to equity		–			10			11
Hedges:
(Losses)/gains taken to equity		(344	)		666			82
Losses/(gains) transferred to the income statement		267			(623	)		(215	)
Exchange fluctuations on translation of foreign operations taken to equity		2			(1	)		2
Exchange fluctuations on translation of foreign operations transferred to income statement		(6	)		–			–
Tax recognised within other comprehensive income		23			(15	)		36

Total items that may be reclassified subsequently to the income statement		(58	)		37			(84	)

Items that will not be reclassified to the income statement:
Remeasurement gains on pension and medical schemes		8			2			1
Tax recognised within other comprehensive income		3			(3	)		(14	)

Total items that will not be reclassified to the income statement		11			(1	)		(13	)

Total other comprehensive (loss)/income		(47	)		36			(97	)

Total comprehensive income		4,102			2,610			4,726

Attributable to non-controlling interests		389			561			1,118
Attributable to BHP shareholders		3,713			2,049			3,608

The accompanying notes form part of this financial information.

Consolidated Balance Sheet as at 31 December 2018


	31 Dec 2018 US$M			30 June 2018 US$M
ASSETS
Current assets
Cash and cash equivalents		15,575			15,871
Trade and other receivables		6,395			3,096
Other financial assets		237			200
Inventories		3,972			3,764
Assets held for sale		–			11,939
Current tax assets		92			106
Other		136			154

Total current assets		26,407			35,130

Non-current assets
Trade and other receivables		196			180
Other financial assets		885			999
Inventories		1,041			1,141
Property, plant and equipment		66,673			67,182
Intangible assets		718			778
Investments accounted for using the equity method		2,582			2,473
Deferred tax assets		3,849			4,041
Other		63			69

Total non-current assets		76,007			76,863

Total assets		102,414			111,993

LIABILITIES
Current liabilities
Trade and other payables		5,616			5,977
Interest bearing liabilities		1,527			2,736
Liabilities held for sale		–			1,222
Other financial liabilities		19			138
Current tax payable		1,101			1,773
Provisions		1,977			2,025
Deferred income		128			118

Total current liabilities		10,368			13,989

Non-current liabilities
Trade and other payables		4			3
Interest bearing liabilities		23,938			24,069
Other financial liabilities		1,256			1,093
Non-current tax payable		136			137
Deferred tax liabilities		3,381			3,472
Provisions		7,700			8,223
Deferred income		315			337

Total non-current liabilities		36,730			37,334

Total liabilities		47,098			51,323

Net assets		55,316			60,670

EQUITY
Share capital – BHP Group Limited		1,111			1,186
Share capital – BHP Group Plc		1,057			1,057
Treasury shares		(16	)		(5	)
Reserves		2,233			2,290
Retained earnings		46,262			51,064

Total equity attributable to BHP shareholders		50,647			55,592
Non-controlling interests		4,669			5,078

Total equity		55,316			60,670

The accompanying notes form part of this financial information.

Consolidated Cash Flow Statement for the half year ended 31 December 2018


	Notes		Half year ended 31 Dec 2018 US$M			Half year ended 31 Dec 2017 US$M Restated			Year ended 30 June 2018 US$M
Operating activities
Profit before taxation				6,800			6,507			14,751
Adjustments for:
Depreciation and amortisation expense				2,888			3,206			6,288
Impairments of property, plant and equipment, financial assets and intangibles				168			299			333
Net finance costs				533			658			1,245
Profit from equity accounted investments, related impairments and expenses				(116	)		(213	)		(147	)
Other				84			321			597
Changes in assets and liabilities:
Trade and other receivables				298			(672	)		(662	)
Inventories				(108	)		(279	)		(182	)
Trade and other payables				(297	)		331			719
Provisions and other assets and liabilities				(232	)		(123	)		7

Cash generated from operations				10,018			10,035			22,949
Dividends received				281			370			709
Interest received				240			79			290
Interest paid				(676	)		(557	)		(1,177	)
Settlement of cash management related instruments				167			(275	)		(292	)
Net income tax and royalty-related taxation refunded				3			39			17
Net income tax and royalty-related taxation paid				(3,324	)		(2,698	)		(4,935	)

Net operating cash flows from Continuing operations				6,709			6,993			17,561

Net operating cash flows from Discontinued operations				565			350			900

Net operating cash flows				7,274			7,343			18,461

Investing activities
Purchases of property, plant and equipment				(2,661	)		(2,078	)		(4,979	)
Exploration expenditure				(397	)		(464	)		(874	)
Exploration expenditure expensed and included in operating cash flows				222			192			641
Net investment and funding of equity accounted investments				(356	)		271			204
Proceeds from sale of assets				102			72			89
Other investing				(61	)		(138	)		(141	)

Net investing cash flows from Continuing operations				(3,151	)		(2,145	)		(5,060	)

Net investing cash flows from Discontinued operations				(443	)		(301	)		(861	)

Proceeds from divestment of Onshore US, net of its cash		13		6,924			–			–

Net investing cash flows				3,330			(2,446	)		(5,921	)

Financing activities
Proceeds from interest bearing liabilities				150			500			528
Settlements of debt related instruments				(160	)		(227	)		(218	)
Repayment of interest bearing liabilities				(1,739	)		(4,008	)		(4,188	)
Purchase of shares by Employee Share Ownership Plan (ESOP) Trusts				(82	)		(96	)		(171	)
Share buy-back – BHP Group Limited				(5,220	)		–			–
Dividends paid				(3,411	)		(2,276	)		(5,220	)
Dividends paid to non-controlling interests				(623	)		(925	)		(1,582	)

Net financing cash flows from Continuing operations				(11,085	)		(7,032	)		(10,851	)

Net financing cash flows from Discontinued operations				(13	)		(27	)		(40	)

Net financing cash flows				(11,098	)		(7,059	)		(10,891	)

Net (decrease)/increase in cash and cash equivalents from Continuing operations				(7,527	)		(2,184	)		1,650
Net increase/(decrease) in cash and cash equivalents from Discontinued operations				109			22			(1	)
Proceeds from divestment of Onshore US, net of its cash				6,924			–			–
Cash and cash equivalents, net of overdrafts, at the beginning of the period				15,813			14,108			14,108
Foreign currency exchange rate changes on cash and cash equivalents				(220	)		331			56

Cash and cash equivalents, net of overdrafts, at the end of the period				15,099			12,277			15,813

The accompanying notes form part of this financial information.

Consolidated Statement of Changes in Equity for the half year ended 31 December 2018

Attributable to BHP shareholders

Non-
controlling
interests

Total
equity

Share capital

Treasury shares

Reserves

Retained
earnings

Total equity
attributable to
BHP
shareholders

US$M

BHP
Group
Limited

BHP
Group
Plc

BHP
Group
Limited

BHP
Group
Plc

Balance as at 1 July 2018

1,186

1,057

)

–

2,290

51,064

55,592

5,078

60,670

Impact of adopting IFRS 9

–

)

–

)

Balance as at 1 July 2018

1,186

1,057

)

–

2,290

51,057

55,585

5,078

60,663

Total comprehensive income

–

(58

)

3,771

3,713

389

4,102

Transactions with owners:

Purchase of shares by ESOP Trusts

–

(79

)

–

(82

)

–

(82

)

Employee share awards exercised net of employee contributions

–

(48

)

(23

)

–

Employee share awards forfeited

–

(12

)

–

Accrued employee entitlement for unexercised awards

–

Dividends

–

(3,356

)

(3,356

)

(630

)

(3,986

)

BHP Group Limited shares bought back and cancelled

(75

)

–

(5,199

)

(5,274

)

–

(5,274

)

Divestment of subsidiaries, operations and joint operations

–

(168

)

(168

)

Balance as at 31 December 2018

1,111

1,057

(16

)

–

2,233

46,262

50,647

4,669

55,316

Balance as at 1 July 2017

1,186

1,057

)

2,400

52,618

57,258

5,468

62,726

Total comprehensive income

–

2,014

2,049

561

2,610

Transactions with owners:

Purchase of shares by ESOP Trusts

–

(87

)

–

(96

)

–

(96

)

Employee share awards exercised net of employee contributions

–

(100

)

–

Employee share awards forfeited

–

)

–

Accrued employee entitlement for unexercised awards

–

Distribution to non-controlling interests

–

)

Dividends

–

(2,291

)

(2,291

)

(839

)

(3,130

)

Balance as at 31 December 2017

1,186

1,057

)

–

2,391

52,351

56,977

5,184

62,161

The accompanying notes form part of this financial information.

Notes to the Financial Information

1.	Basis of preparation

This general purpose financial report for the half year ended 31 December 2018 is unaudited and has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’ as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU), AASB 134 ‘Interim Financial Reporting’ as issued by the Australian Accounting Standards Board (AASB) and the Disclosure and Transparency Rules of the Financial Conduct Authority in the United Kingdom and the Australian Corporations Act 2001 as applicable to interim financial reporting.

The half year financial statements represent a ‘condensed set of financial statements’ as referred to in the UK Disclosure and Transparency Rules issued by the Financial Conduct Authority. Accordingly, they do not include all of the information required for a full annual report and are to be read in conjunction with the most recent annual financial report. The comparative figures for the financial year ended 30 June 2018 are not the statutory accounts of the Group for that financial year. Those accounts, which were prepared under IFRS, have been reported on by the Company’s auditor and delivered to the registrar of companies. The auditor has reported on those accounts; the report was unqualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report and did not contain statements under Section 498 (2) or (3) of the UK Companies Act 2006.

The directors have made an assessment of the Group’s ability to continue as a going concern and consider it appropriate to adopt the going concern basis of accounting in preparing the half year financial statements.

The half year financial statements have been prepared on a basis of accounting policies and methods of computation consistent with those applied in the 30 June 2018 annual financial statements contained within the Annual Report of the Group, with the exception of the following new accounting standards and interpretations which became effective from 1 July 2018:

•

IFRS 9/AASB 9 ‘Financial Instruments’ which replaces IAS 39/AASB 139 ‘Financial Instruments: Recognition and Measurement’;

•

IFRS 15/AASB 15 ‘Revenue from Contracts with Customers’ which replaces previous revenue requirements, including IAS 18/AASB 118 ‘Revenue’; and

•

IFRIC 22 ‘Foreign Currency Transactions and Advance Consideration’.

Note 2 describes the impact of new accounting standards and interpretations. In addition to restatements arising from the application of the new accounting standards, the 31 December 2017 financial information has been restated for the effects of applying IFRS 5/AASB 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ to the Petroleum business’s Onshore US operations comprising of Eagle Ford, Permian, Haynesville and Fayetteville assets.

While not applied in the current reporting period, IFRS 16/AASB 16 ‘Leases’ is effective from 1 January 2019 and is applicable for the Group from 1 July 2019.


Title of standard		Summary of impact on the financial statements
IFRS 16/AASB 16 ‘Leases’		The Group continues to progress its IFRS 16 implementation project, focusing on the review of new contractual arrangements, aggregation of data to support the measurement of leases on transition and implementation of changes to systems and processes.

		The Group is actively monitoring developments in the generally accepted application of IFRS 16. Practice continues to develop in the identification of leases, particularly in mining services and logistics arrangements, and in their measurement, including the allocation of payments between lease and non-lease components. Work is ongoing to finalise the Group’s accounting policies and interpretations in these areas and the outcomes may impact the quantification of any transition adjustments recognised by the Group.

		The Group expects to use the modified retrospective approach and the available practical expedients in measuring leases on transition, including not recognising low value or short term leases on balance sheet. The Group continues to assess the use of the grandfathering provisions to retain its existing lease classifications. Under the modified retrospective approach, the comparative periods will not be restated on transition.

		There are a number of measurement differences between the existing leases standard and IFRS 16 that will impact the initial recognition of lease liabilities and right of use assets and their subsequent measurement. These differences include that:

		• payments under contracts will be allocated between lease and non-lease components; • the minimum lease payments, applying indexing levels at the reporting date, will be discounted over the expected lease term rather than the minimum term; • the lease liability will be re-measured periodically for changes in the expected term and indexation.

		The transition impact of adopting IFRS 16 will reflect the final accounting policy determinations, the lease population at transition and variables such as interest and foreign exchange rates and any index levels which adjust the lease payments.

		The Group is progressing the design and build of a lease accounting system, and initial training on the impacts of IFRS 16 has been developed and is being delivered to relevant teams, including accounting, reporting and supply.

		The Group will disclose the impact on adoption in its 2019 Annual Report.

A number of other accounting standards and interpretations, along with revisions to the Conceptual Framework for Financial Reporting have been issued, and will be applicable in future periods. While these remain subject to ongoing assessment, no significant impacts have been identified to date. These standards have not been applied in the preparation of these half year financial statements.

All amounts are expressed in US dollars unless otherwise stated. The Group’s presentation currency and the functional currency of the majority of its operations is US dollars as this is the principal currency of the economic environment in which it operates. Amounts in this financial information have, unless otherwise indicated, been rounded to the nearest million dollars.

2.	Impact of new accounting standards

This note explains the impact of adopting IFRS 9/AASB 9 ‘Financial Instruments’ (IFRS 9) and IFRS 15/AASB 15 ‘Revenue from Contracts with Customers’ (IFRS 15) on the Group’s financial statements from 1 July 2018. The adoption of other changes to IFRS applicable from 1 July 2018, including IFRIC 22 ‘Foreign Currency Transactions and Advance Consideration’, did not have a significant impact on the Group’s financial statements.

IFRS 9 Financial Instruments

This standard revises the classification and measurement of financial assets and financial liabilities, introduces a forward looking ‘expected credit loss’ impairment model and modifies the approach to hedge accounting. Upon adoption of the new standard on 1 July 2018, the Group has adjusted the opening balance sheet, with no restatement of comparatives required. Adoption impacts include:

•

At 1 July 2018, the Group reassessed the classification and measurement of financial assets and liabilities based on the business model by which they are managed and their cash flow characteristics.

Financial assets previously classified as loans and receivables of US$17.7 billion were recategorised as amortised cost. The Group’s available for sale (AFS) shares of US$33 million were designated as fair value through other comprehensive income (FVOCI), while investments in shares after 1 July 2018 will be designated at fair value through profit or loss (FVTPL) or FVOCI on an investment by investment basis.

Other AFS investments of US$47 million were classified as held at FVTPL because they are not investments in shares and their cash flows do not consist solely of payments of principal and interest. The adoption of IFRS 9 has not resulted in any changes to the classification of financial assets held at FVTPL or to the classification or measurement of financial liabilities.

•

Financial assets carried at amortised cost are tested for impairment based on expected losses, whereas the previous policy required that impairments were recognised only when there was objective evidence that a credit loss was present. Upon adoption of IFRS 9, an expected credit loss provision of US$7 million against cash and cash equivalents and trade receivables was recognised in retained earnings.

•

From 1 July 2018, the Group has applied the amended rules on hedge accounting which enable closer alignment between the Group’s risk management strategy and the accounting outcomes. IFRS 9 broadens the scope of arrangements that may qualify for hedge accounting and allows for simplification of hedge designations. Other changes under the standard mean that hedge effectiveness is only considered on a prospective basis with no set quantitative thresholds and voluntary de-designation of hedges is prohibited.

Certain of the Group’s existing derivatives hedging foreign currency notes and debentures, were in qualifying fair value and cash flow hedge relationships and have been treated as continuing hedges. The opportunity to apply simplified hedge designations under IFRS 9 will continue to be assessed for future hedge relationships. Risks present in the derivative only, such as counterparty credit risk, are not part of the hedge designation and will continue to be recognised through the income statement.

Foreign currency basis has been separately measured as a cost of hedging and movements continue to be recognised in reserves, with US$176 million being reclassified into the cost of hedging reserve on transition. The hedging reserves at transition will continue to be transferred to the income statement over the life of the underlying notes and debentures.

The impact of adopting IFRS 9 on Total equity as at 1 July 2018 is as follows:


	US$M
Total equity as at 30 June 2018		60,670
Impairment provision resulting from application of the Expected Credit Loss model		(7	)

Total equity as at 1 July 2018		60,663

The table below summarises the change in classification and measurement of financial assets and liabilities upon adoption of IFRS 9 on 1 July 2018.


	Measurement category under IAS 39	Measurement category under IFRS 9
Financial assets
Derivative contracts	FVTPL	FVTPL
Investment in shares	AFS	FVOCI
Other investments	AFS or FVTPL	FVTPL

Cash and cash equivalents	Loans and receivables	Amortised cost
Trade and other receivables	Loans and receivables	Amortised cost
Provisionally priced trade receivables	FVTPL	FVTPL
Loans to equity accounted investments	Loans and receivables	Amortised cost

Financial liabilities
Other financial liabilities	FVTPL	FVTPL
Trade and other payables	Amortised cost	Amortised cost
Provisionally priced trade payables	FVTPL	FVTPL
Bank overdrafts and short-term borrowings	Amortised cost	Amortised cost
Bank loans	Amortised cost	Amortised cost
Notes and debentures	Amortised cost	Amortised cost
Finance leases	Amortised cost	Amortised cost
Other	Amortised cost	Amortised cost

IFRS 15 Revenue from Contracts with Customers

This standard modifies the determination of when to recognise revenue and how much revenue to recognise. Revenue is recognised when control of the promised goods or services passes to the customer. The amount of revenue recognised should reflect the consideration to which the entity expects to be entitled in exchange for those goods or services.

The Group has applied the full retrospective transition approach, resulting in the restatement of comparative information. Comparative information in the consolidated income statement has been restated to reflect changes in the presentation of treatment costs and refining charges included in concentrate sales contracts.

Concentrate sales contracts require the Group to physically deliver concentrate with the contractual sales amount reflecting the final refined metal content delivered, reduced by treatment costs and refining charges. Revenue was previously recognised at the gross value of the final refined metal content delivered with contractually agreed treatment costs and refining charges recorded as an expense. Under IFRS 15 treatment costs and refining charges will instead be recognised as a reduction to revenue, reflecting the consideration that the Group expects to receive from the customer. This will have no net income statement impact as applying this change would have reduced revenue and expenses by US$251 million for the half year ended 31 December 2017 and US$509 million for the year ended 30 June 2018, with no impact on profit after tax. This change has no impact on the basic and diluted earnings per ordinary share.

Revenue includes both revenue from contracts with customers, which is recognised under IFRS 15 and provisional pricing adjustments, which are recognised under IFRS 9. Following adoption of IFRS 15 provisional pricing adjustments will be separately disclosed in the notes to the financial statements as other revenue. The impact of all other measurement differences identified between IAS 18 and IFRS 15 was immaterial at 1 July 2018.

3.	Revenue

Revenue by segment


Half year ended 31 December 2018 US$M	Petroleum		Copper			Iron Ore		Coal		Group and unallocated items/ eliminations			Group total
Revenue from contracts with customers		3,071		5,328			7,401		4,509		549			20,858
Other revenue		132		(259	)		17		3		(9	)		(116	)

Total revenue		3,203		5,069			7,418		4,512		540			20,742


Half year ended 31 December 2017 US$M	Petroleum		Copper			Iron Ore		Coal		Group and unallocated items/ eliminations			Group total
Revenue from contracts with customers		2,525		5,790			7,196		4,044		533			20,088
Other revenue		56		342			25		3		12			438

Total revenue		2,581		6,132			7,221		4,047		545			20,526


Year ended 30 June 2018 US$M	Petroleum		Copper			Iron Ore		Coal		Group and unallocated items/ eliminations			Group total
Revenue from contracts with customers		5,194		12,660			14,782		8,887		1,225			42,748
Other revenue		214		121			28		2		16			381

Total revenue		5,408		12,781			14,810		8,889		1,241			43,129

Revenue by geographical location


	Revenue by location of customer
	Half Year ended 31 Dec 2018 US$M		Half year ended 31 Dec 2017 US$M		Year ended 30 June 2018 US$M
Australia		1,247		1,110		2,304
Europe		983		818		1,886
China		11,176		10,511		22,660
Japan		2,081		2,015		4,628
India		1,141		1,285		2,439
South Korea		1,067		1,374		2,588
Rest of Asia		1,355		1,454		2,620
North America		1,176		1,234		2,715
South America		362		566		1,054
Rest of world		154		159		235

		20,742		20,526		43,129

Recognition and measurement (following adoption of IFRS 15)

The Group generates revenue from the production and sale of commodities. Revenue is recognised when or as control of the promised goods or services passes to the customer. In most instances, control passes when the goods are delivered to a destination specified by the customer, typically on board the customer’s appointed vessel. The amount of revenue recognised reflects the consideration to which the Group expects to be entitled in exchange for the goods or services.

Where the Group’s sales are provisionally priced, the final price depends on future index prices. The amount of revenue initially recognised is based on the relevant forward market price. Adjustments between the provisional and final price are accounted for under IFRS 9 and recognised in revenue. Provisional pricing adjustments are separately disclosed as other revenue. The period between provisional pricing and final invoicing is typically between 60 and 120 days.

Revenue from concentrate is net of treatment costs and refining charges.

Revenue from the sale of significant by-products is included within revenue. Where a by-product is not significant, revenue is credited against costs.

4.	Exceptional items

Exceptional items are those gains or losses where their nature, including the expected frequency of the events giving rise to them, and amount is considered material to the financial statements. Such items included within the Group’s profit for the half year are detailed below. Exceptional items attributable to Discontinued operations are detailed in note 13 Discontinued operations:

Half year ended 31 December 2018

Gross
US$M

Tax
US$M

Net
US$M

Exceptional items by category

Samarco dam failure

(210

)

–

(210

)

Global taxation matters

–

242

Total

(210

)

242

Attributable to non-controlling interests

–

Attributable to BHP shareholders

(210

)

242

Samarco Mineração SA (Samarco) dam failure

The exceptional loss of US$210 million related to the Samarco dam failure in November 2015 comprises the following:


Half year ended 31 December 2018	US$M
Expenses excluding net finance costs:
Costs incurred directly by BHP Billiton Brasil Ltda and other BHP entities in relation to the Samarco dam failure		(33	)
Loss from equity accounted investments, related impairments and expenses:
Share of loss relating to the Samarco dam failure		(47	)
Samarco dam failure provision		(70	)
Net finance costs		(60	)

Total⁽¹⁾		(210	)

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