REG - Woodside Energy Grp. - Second Quarter 2023 Report
19/07/2023 07:00
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RNS Number : 4543G Woodside Energy Group Ltd 19 July 2023
Woodside Energy Group Ltd
ACN 004 898 962
Mia Yellagonga
11 Mount Street
Perth WA 6000
Australia
T +61 8 9348 4000
www.woodside.com
ASX: WDS
NYSE: WDS
LSE: WDS
Announcement
Wednesday, 19 July 2023
SECOND QUARTER REPORT FOR PERIOD ENDED 30 JUNE 2023
Delivering reliable production
· Delivered quarterly production of 44.5 MMboe (489 Mboe/day), down
5% from Q1 2023 due to planned turnaround and maintenance activities.
Full-year production guidance remains unchanged at 180-190 MMboe.
· Delivered sales volume of 48.4 MMboe, down 4% from Q1 2023,
primarily due to lower production.
· Delivered revenue of $3,084 million, down 29% from Q1 2023, due
to lower realised prices and lower production.
· Achieved a portfolio average realised price of $63/boe.
· Sold 31% of produced LNG at prices linked to gas hub indices.
Executing major projects
· Mad Dog Phase 2 successfully achieved first production at the
Argos platform in April 2023, increasing production in the US Gulf of Mexico.
· The Scarborough development was 38% complete at the end of the
period, with manufacturing of the export trunkline complete and Pluto Train 2
module fabrication ramping up.
· The Sangomar project was 88% complete at the end of the period,
with 12 of 23 wells drilled and completed. The floating production storage and
offloading (FPSO) topsides integration and pre-commissioning works continued
in Singapore.
· The Sangomar project is now targeting first oil in mid-2024 and
the total cost of the project is expected to be US$4.9-5.2 billion, an
increase of 7-13% from the previous cost estimate of US$4.6 billion.
Investing in growth
· Approved a final investment decision to develop the Trion
resource in Mexico, with the development remaining subject to regulatory
approval of the field development plan (FDP).
· Made a final investment decision on the Julimar-Brunello Phase 3
project.
· Progressed contracting activities for the plant construction
scope and schedule-critical packages for H2OK.
Woodside CEO Meg O'Neill said:
"It was an extremely difficult period for everyone at Woodside, given the
tragic death in early June of a contractor employee at the North Rankin
Complex.
"Western Australian Police and the National Offshore Petroleum Safety and
Environmental Management Authority (NOPSEMA) are investigating the incident
and Woodside is conducting an internal investigation.
"Strong underlying operational performance in the second quarter was impacted
by planned turnaround and maintenance activities particularly at the onshore
Pluto LNG facility and associated offshore facilities in Western Australia.
"The team delivered a successful turnaround, completing the planned activities
at Pluto on schedule.
"Whilst production and sales were lower compared with the first quarter of
2023, they were higher than the corresponding period last year, reflecting
Woodside's expanded operations portfolio.
"In the US Gulf of Mexico, we commenced production from the Argos offshore
facility. This was a significant milestone for the Mad Dog Phase 2 project and
production is expected to ramp up through the year.
"The Scarborough and Pluto Train 2 project continued to make good progress and
is now 38% complete. Fabrication of both the topsides and hull of the floating
production unit has ramped up. The accommodation village in Karratha, which
will service the Pluto Train 2 construction workforce, is now complete. Pluto
Train 2 module fabrication and foundation site works is progressing well.
"We conducted a cost and schedule review at Sangomar following the
identification of remedial work required on the FPSO. We have taken the
prudent decision to conduct the remedial work while the FPSO remains at the
shipyard in Singapore.
"This minimises the impact to the project schedule as it is safer, more
efficient and more cost effective than undertaking the work offshore Senegal.
First oil is now targeted for mid-2024.
"We also achieved an important step towards value-accretive investment in
future growth, taking a final investment decision to develop the Trion oil
field offshore Mexico, subject to the regulator's approval of the field
development plan which is expected in the fourth quarter of this year. Trion
is expected to deliver shareholder returns which exceed Woodside's capital
allocation framework targets following its forecast start up in 2028.
"A final investment decision was also taken for the Julimar-Brunello Phase 3
project, which will provide a new supply of gas to the non-operated Wheatstone
LNG facility in Western Australia.
"We are progressing contracting activities for the plant construction scope
and other schedule-critical packages for H2OK and aiming to be ready for a
final investment decision in 2023."
Comparative performance at a glance
Q2 2023 Q1 2023 Change % Q2 2022 1 Change %
Production 2 MMboe 44.5 46.8 (5%) 33.8 32%
489
371
Mboe/day 520
Sales MMboe 48.4 50.4 (4%) 35.8 35%
Revenue $ million 3,084 4,330 (29%) 3,438 (10%)
Operational overview
Production
· Production decreased compared to the previous quarter to 44.5
MMboe, primarily due to the planned major turnarounds on Pluto LNG and
Ngujima-Yin FPSO. This was partly offset by seasonal demand from Bass Strait
and higher production from Mad Dog following first production from the Argos
facility in April 2023.
Australian LNG
· Completed significant planned turnaround and maintenance
activities on the onshore and offshore facilities at Pluto LNG on schedule,
with production recommencing in June 2023.
Julimar-Brunello
· Made a final investment decision on Julimar-Brunello Phase 3 in
April 2023. The project involves the drilling of up to four development wells
in the Julimar field and the installation of subsea infrastructure to connect
to the existing Julimar field production system.
Bass Strait
· Commenced the commercial tender process for decommissioning a
number of facilities within the Gippsland Basin and continued plug and
abandonment (P&A) of wells that are no longer producing.
· Progressed front-end engineering design (FEED) work on Phase 1 of
the South East Australia carbon capture and storage (SEA CCS) project. Phase 1
of the SEA CCS project aims to use existing infrastructure to store CO(2) in
the depleted Bream field off the coast of Gippsland, Victoria.
Gulf of Mexico
· A successful appraisal well, SWX4, was drilled in the southwest
part of the Mad Dog field. An extension of the current development through a
multi-well tie-back to Argos is being evaluated.
· The second of two wells was completed on the Shenzi North
project. Subsea work is ongoing with the first of three subsea installation
campaigns completed, installing manifolds and high integrity
pressure-protection system packages. The project was 82% complete at the end
of the period.
Australia Oil
· The Ngujima-Yin FPSO successfully completed a planned five-yearly
maintenance turnaround in a Singapore drydock with production expected to
recommence in July 2023.
· The Enfield P&A campaign continued with four wells
permanently plugged and three xmas trees removed. The plugging of 13 of 18
Enfield wells and removal of 16 of 18 xmas trees has been completed.
Project and development activities
Mad Dog Phase 2
· First production was successfully achieved at the Argos platform
in April 2023. Production is expected to continue to ramp-up through 2023.
Scarborough
· Scarborough upstream pipeline manufacturing is now complete, with
pipeline coating ongoing. Ramp up of the floating production unit (FPU)
fabrication for both the topsides and hull continued.
· Pluto Train 2 module fabrication and foundation site works
progressed. The construction accommodation village was completed.
· Pluto Train 1 design activities and market engagement for
long-lead items continued.
· The relevant Western Australian regulator accepted the
Scarborough Trunkline Installation (State Waters) Environment Plan. Engagement
with NOPSEMA continued regarding Commonwealth Environment Plans.
· The project was 38% complete at the end of the period and first
LNG cargo is targeted for 2026.
Sangomar Field Development Phase 1
· A cost and schedule review was conducted following the
identification of remedial work required on the FPSO facility.
· First oil is now expected in mid-2024 and the total development
cost is expected to be US$4.9-5.2 billion, representing a 7-13% increase from
the previous cost estimate of US$4.6 billion.
· FPSO topsides integration and pre-commissioning works continued
in Singapore.
· The development drilling program continued with 12 of 23 wells
completed.
· The subsea installation campaign was 76% complete, with the
overall subsea work scope 95% complete at the end of the period.
· The project was 88% complete at the end of the period.
Trion
· In June 2023, Woodside made a final investment decision to
develop the Trion resource in Mexico. The development is expected to deliver
shareholder returns which exceed Woodside's capital allocation framework
targets. 3
· Following Woodside's approval, the joint venture approved the
FDP. The FDP was submitted to the regulator and approval is expected in Q4
2023.
· Long-lead orders were placed for the FPU topsides rotating
equipment.
· The FPU engineering, procurement and construction contract was
executed with Hyundai Heavy Industries.
New energy
H2OK
· Contracting activities for the plant construction scope and other
schedule critical packages progressed.
· Woodside purchased 94 acres of land in the Westport Industrial
Park in Ardmore, Oklahoma, for the proposed H2OK facility.
· Woodside is targeting final investment decision readiness for
H2OK in 2023.
Hydrogen Refueller @H2Perth
· Awarded the contract for the engineering and fabrication of the
hydrogen production equipment and submitted Western Australian environmental
approval application documents. The Commonwealth environmental approval
application documents were submitted subsequent to the quarter.
Woodside Solar:
· Completed the solar electrical tie-in scope at the Pluto LNG
facility during the 2023 Pluto shutdown.
· Woodside Solar is targeting final investment decision readiness
in 2023.
Marketing
Australian domestic gas
· The long-term gas sale and purchase agreement (GSPA) with
Perdaman Chemicals and Fertiliser Pty Ltd (Perdaman) became unconditional
following a final investment decision being made by Perdaman on its
2.3 million tonne per annum urea plant, near Karratha, Western Australia.
Supply under the GSPA is for approximately 130 terajoules per day of gas over
a term of 20 years, commencing upon commissioning of the plant expected in
2026 or 2027.
· Woodside executed several natural gas sales agreements for the
combined supply of approximately 80 petajoules of pipeline gas to
Western Australian domestic customers including retailers, commercial and
industrial users. Delivery is expected to take place from Q4 2023 to the end
of 2025.
· Following an expression of interest (EOI) process, Woodside
executed several natural gas sales agreements for the supply of approximately
40 petajoules of gas to domestic customers including retailers, commercial and
industrial users in the eastern Australian gas market from 2024 to 2026.
Corporate activities
Hedging
· Woodside has placed oil price hedges for approximately 21.8 Mmboe
of 2023 production at an average price of approximately $74.5 per barrel, of
which approximately 11.2 MMboe has been delivered. As at the end of the
period, Woodside hedged approximately 6.2 MMboe of 2024 production at an
average price of approximately $75.2 per barrel.
· Subsequent to the period, Woodside placed oil price hedges on a
further 19.8 MMboe of production and has now hedged approximately 26.0 MMboe
of 2024 production at an average price of approximately $75.36 per barrel.
· Woodside also has a hedging program for Corpus Christi LNG
volumes designed to protect against downside pricing risk. These hedges are
Henry Hub and Title Transfer Facility (TTF) commodity swaps. Approximately 81%
of Corpus Christi volumes for the remainder of 2023 and approximately 29% of
2024 volumes have reduced pricing risk as a result of hedging activities.
· The year-to-date pre-tax expense related to hedged positions is
approximately $229 million, with $103 million pre-tax expense related to oil
price hedges, $99 million pre-tax expense related to Corpus Christi hedges
and $27 million pre-tax expense related to other hedge positions. Hedging
losses will be included in "other expenses" in the half-year financial
statements.
2023 half year results and teleconference
· Woodside's Half-Year Report 2023 and associated investor briefing
will be released to the market on Tuesday, 22 August 2023. It will also be
available on Woodside's website at www.woodside.com (http://www.woodside.com)
.
· A teleconference providing an overview of the 2023 half-year
results and a question-and-answer (Q&A) session will be hosted by CEO and
Managing Director, Meg O'Neill, and Chief Financial Officer, Graham Tiver, on
Tuesday, 22 August at 08:00 AWST / 10:00 AEST / 19:00 CDT (Monday 21 August).
· We recommend participants pre-register 5 to 10 minutes prior to
the event with one of the following links:
o https://webcast.openbriefing.com/wds-hyr-2023/
(https://webcast.openbriefing.com/wds-hyr-2023/) to view the presentation and
listen to a live stream of the Q&A session
o https://s1.c-conf.com/diamondpass/10031114-ldyp34.html
(https://s1.c-conf.com/diamondpass/10031114-ldyp34.html) to participate in the
Q&A session. Following pre-registration, participants will receive the
teleconference details and a unique access passcode.
2023 full-year guidance
Prior Current
Production MMboe 180 - 190 No change
Capital expenditure $ billion 6.0 - 6.5 No change
Gas hub exposure % of produced LNG 20 - 25 No change
Half-year 2023 line-item guidance
Financial reporting guidance
· Woodside's net profit after tax for the first half of 2023 is
expected to include the recognition of a Pluto petroleum resource rent tax
(PRRT) deferred tax asset (DTA) expense of approximately $630 million due to
lower realised pricing in the first half of 2023 and lower forecast short-term
pricing. The reduction of the DTA is recognised as an expense in the PRRT tax
line item in the consolidated income statement in the financial statements and
is included in the half-year 2023 line-item guidance below. The post-tax
impact of the Pluto PRRT DTA expense is approximately $430 million.
· Woodside also expects to recognise a DTA of approximately $320
million for Trion, following the final investment decision in June 2023. The
recognition of the deferred tax asset represents the expected future tax
benefit due to the expenditure incurred on the Trion project.
· The Pluto PRRT DTA expense and the Trion DTA recognition are
expected to be excluded from the underlying NPAT for the purposes of
calculating the 2023 half-year dividend, consistent with prior practice.
Comments
Taxes
PRRT expense $ million 750 - 1,000 Includes Pluto PRRT DTA expense of ~$630m.
Income tax expense $ million 150 - 400
Includes Trion DTA recognition on final investment decision of ~$320m benefit;
and the effect of the Pluto PRRT DTA expense of ~$200m.
Contacts:
INVESTORS MEDIA
Matthew Turnbull (Group) Christine Forster
M: +61 410 471 079 M: +61 484 112 469
E: christine.forster@woodside.com
Sarah Peyman (Australia)
M: +61 457 513 249
Rohan Goudge (US)
M: +1 (713) 679-1550
E: investor@woodside.com (mailto:investor@woodside.com)
This announcement was approved and authorised for release by Woodside's
Disclosure Committee.
Production summary
Three months ended Year to date
June 2023 Mar June 2022 4 June 2023 June 2022(4)
2023
AUSTRALIA
LNG
North West Shelf Mboe 8,746 9,673 5,826 18,419 10,438
Pluto 5 Mboe 8,765 12,154 12,328 20,919 21,654
Wheatstone Mboe 2,588 2,456 1,645 5,044 4,053
Total Mboe 20,099 24,283 19,799 44,382 36,145
Pipeline gas
Bass Strait Mboe 4,170 3,133 2,353 7,303 2,353
Other 6 Mboe 3,080 3,037 1,692 6,117 2,445
Total Mboe 7,250 6,170 4,045 13,420 4,798
Crude oil and condensate
North West Shelf Mbbl 1,546 1,684 1,104 3,230 1,910
Pluto(5) Mbbl 699 961 967 1,660 1,712
Wheatstone Mbbl 425 408 277 833 698
Bass Strait Mbbl 904 777 441 1,681 441
Macedon & Pyrenees Mbbl 759 631 223 1,390 223
Ngujima-Yin Mbbl - 869 2,275 869 3,673
Okha Mbbl 421 431 444 852 869
Total Mboe 4,754 5,761 5,731 10,515 9,526
NGL2
North West Shelf Mbbl 339 292 228 631 409
Pluto(5) Mbbl 45 50 60 95 66
Bass Strait Mbbl 1,191 723 503 1,914 503
Total Mboe 1,575 1,065 791 2,640 978
Total Australia 7 Mboe 33,678 37,279 30,366 70,957 51,447
Three months ended Year to date
June 2023 Mar June 2022 8 June 2023 June 2022(8)
2023
INTERNATIONAL
Pipeline gas
Gulf of Mexico Mboe 349 330 122 679 122
Trinidad & Tobago Mboe 2,723 2,236 829 4,959 829
Other(9) Mboe - 30 - 30 -
Total Mboe 3,072 2,596 951 5,668 951
Crude oil and condensate
Atlantis Mbbl 2,792 2,696 987 5,488 987
Mad Dog Mbbl 1,627 939 411 2,566 411
Shenzi Mbbl 2,599 2,596 765 5,195 765
Trinidad & Tobago Mbbl 294 297 150 591 150
Other3F 9 Mbbl 81 39 27 120 27
Total Mboe 7,393 6,567 2,340 13,960 2,340
NGL4
Gulf of Mexico Mbbl 350 331 119 681 119
Other(9) Mbbl - 17 - 17 -
Total Mboe 350 348 119 698 119
Total International Mboe 10,815 9,511 3,410 20,326 3,410
Total production Mboe 44,493 46,790 33,776 91,283 54,857
Product sales
Three months ended Year to date
June 2023 Mar June 2022 10 June 2023 June 2022(10)
2023
AUSTRALIA
LNG
North West Shelf Mboe 9,003 10,564 5,616 19,567 10,628
Pluto5 Mboe 9,592 11,310 11,094 20,902 20,527
Wheatstone 11 Mboe 2,312 2,350 1,464 4,662 3,985
Total Mboe 20,907 24,224 18,174 45,131 35,140
Pipeline gas
Bass Strait Mboe 4,113 3,082 2,194 7,195 2,194
Other Mboe 3,040 2,939 1,629 5,979 2,377
Total Mboe 7,153 6,021 3,823 13,174 4,571
Crude oil and condensate
North West Shelf Mbbl 1,855 1,089 1,018 2,944 1,636
Pluto Mbbl 614 614 1,828 1,228 2,300
Wheatstone Mbbl 309 350 354 659 643
Bass Strait Mbbl 1,035 82 333 1,117 333
Ngujima-Yin Mbbl - 1,141 2,436 1,141 3,772
Okha Mbbl - 653 619 653 619
Macedon & Pyrenees Mbbl 1,032 518 - 1,550 -
Total Mboe 4,845 4,447 6,588 9,292 9,303
NGL7
North West Shelf Mbbl 255 170 - 425 -
Pluto Mbbl 73 182 - 255 -
Bass Strait Mbbl 903 1,109 213 2,012 213
Total Mboe 1,231 1,461 213 2,692 213
Total Australia Mboe 34,136 36,153 28,798 70,289 49,227
Three months ended Year to date
June 2023 Mar June 2022 12 June 2023 June 2022(12)
2023
INTERNATIONAL
Pipeline gas
Gulf of Mexico Mboe 341 343 127 684 127
Trinidad & Tobago Mboe 2,700 2,295 836 4,995 836
Other8 13 Mboe 6 7 3 13 3
Total Mboe 3,047 2,645 966 5,692 966
Crude oil and condensate
Atlantis Mbbl 2,710 2,668 883 5,378 883
Mad Dog Mbbl 1,628 941 379 2,569 379
Shenzi Mbbl 2,652 2,673 718 5,325 718
Trinidad & Tobago Mbbl 248 413 204 661 204
Other(13) Mbbl 65 63 28 128 28
Total Mboe 7,303 6,758 2,212 14,061 2,212
NGL9
Gulf of Mexico Mbbl 363 342 124 705 124
Other(13) Mbbl 3 4 2 7 2
Total Mboe 366 346 126 712 126
Total International Mboe 10,716 9,749 3,304 20,465 3,304
MARKETING
LNG1 14 Mboe 3,532 4,483 3,741 8,015 7,079
Total Mboe 3,532 4,483 3,741 8,015 7,079
Total Marketing Mboe 3,532 4,483 3,741 8,015 7,079
Total sales Mboe 48,384 50,385 35,843 98,769 59,610
Revenue (US$ million)
Three months ended Year to date
June 2023 Mar June 2022 15 June 2023 June 2022(15)
2023
AUSTRALIA
North West Shelf 667 1,270 523 1,937 1,159
Pluto11 724 1,131 1,286 1,855 2,115
Wheatstone12 16 204 324 160 528 427
Bass Strait 328 211 232 539 232
Macedon 53 51 16 104 16
Ngujima-Yin - 100 288 100 436
Okha - 56 67 56 67
Pyrenees 89 50 1 139 1
INTERNATIONAL
Atlantis 203 199 109 402 109
Mad Dog 116 68 44 184 44
Shenzi 200 199 83 399 83
Trinidad & Tobago 112 136 66 248 66
Other13 17 4 5 3 9 3
Marketing revenue14 18 344 479 511 823 990
Total sales revenue 19 3,044 4,279 3,389 7,323 5,748
Processing revenue 38 47 42 85 77
Shipping and other revenue 2 4 7 6 8
Total revenue 3,084 4,330 3,438 7,414 5,833
Realised prices
Three months ended Three months ended
Units June 2023 Mar June 2022(15) Units June 2023 Mar June 2022(15)
2023 2023
LNG produced15 20 $/MMBtu 10.9 16.7 13.8 $/boe 69 105 87
LNG traded16 21 $/MMBtu 11.0 16.7 21.5 $/boe 70 105 137
Pipeline gas $/boe 37 38 57
Oil and condensate $/bbl 75 76 115 $/boe 75 76 115
NGL $/bbl 41 51 48 $/boe 41 51 48
Average realised price $/boe 63 85 95
Dated Brent $/bbl 78 81 114
JCC (lagged three months) $/bbl 87 100 86
WTI $/bbl 73.8 76.1 108.4
JKM $/MMBtu 12.6 26.0 31.3
TTF $/MMBtu 12.6 24.7 31.6
· Average realised price was A$6.1/GJ in Western Australia,
A$12.6/GJ in east coast Australia and $6.7/Mcf for International in Q2 2023.
Expenditure (US$ million)
Three months ended Year to date
June 2023 Mar June 2022 22 June 2023 June 2022(22)
2023
Exploration and evaluation expense
Exploration and evaluation expensed1F 81 52 27 133 34
Permit amortisation 2 2 2 4 3
Total 83 54 29 137 37
Capital expenditure
Exploration and evaluation capitalised18F 23 (,)19F 24 92 37 5 129 10
Oil and gas properties 1,229 1,279 748 2,508 1,505
Total 1,321 1,316 753 2,637 1,515
Trading costs 237 385 442 622 793
Key project expenditure (US$ million)
Three months ended Year to date
June 2023 Mar June 2022 June 2023 June 2022
2023
Capital expenditure
Scarborough 25 578 626 353 1,204 800
Sangomar 272 279 207 551 449
Exploration
· In the US Gulf of Mexico, Woodside acquired a 44% working
interest in two leases in Green Canyon and spudded the Spinel well with
co-owner and operator BP in early June 2023.
· Woodside has acquired five of the leases for which it was the
highest bidder in lease sale 259 - four operated and one non-operated.
· Seismic acquisition was completed over Petroleum Exploration
Licence 87, in the Orange Basin offshore Namibia. A decision on exercising the
option to enter will follow evaluation of seismic data.
Exploration or appraisal wells drilled
Region Permit area Well Target Interest (%) Spud date Water depth (m) Planned well depth (m)20 26 Remarks
Gulf of Mexico GC 868 Mad Dog Oil 23.9% 12 March 2023 1,331 7,437 Drilling complete
Non-operator
SWX4
Gulf of Mexico GC 436 Spinel Oil 44% 7 June 1,258 7,042 Drilling ongoing
Non-operator 2023
Permits and licences
Key changes to permit and licence holding during the quarter ended 30 June
2023 are noted below.
Region Permits or licence areas Change in interest (%) Current interest (%) Remarks
Myanmar A-6 (40) 0 Operated
Korea Blocks 8 & 6-1N (50) 0 Operated
Trinidad & Tobago TTDA-5 (65) 0 Operated
Gulf of Mexico GC436, GC480 44 44 27 Non-operated
Gulf of Mexico GC210, GC211, 100 100 Operated
AC125, AC126
Gulf of Mexico GC598 40 40 Non-operated
Seismic and geophysical survey activity
Region Field Permits or licence areas Remarks
Namibia PEL 87 - Orange Basin Deep Water PEL 87 Licence Acquisition of 6,593 km(2) of 3D seismic completed
Production rates
Average daily production rates (100% project) for the quarter ended 30 June
2023:
Woodside Production rate Remarks
share23F 28
(100% project, Mboe/d)
June 2023 Mar
2023
AUSTRALIA
NWS Project
LNG 29.91% 321 340
Crude oil and condensate 29.98% 57 59
NGL 33.27% 11 10
Pluto LNG
LNG 90.00% 83 117 Production was lower due to planned facilities turnaround.
Crude oil and condensate 90.00% 8 11
Pluto-KGP Interconnector
LNG 100.00% 22 30 Production was lower due to planned facilities turnaround.
Crude oil and condensate 100.00% 1 1
NGL 100.00% 0 1
Wheatstone 29
LNG 11.86% 240 229
Crude oil and condensate 14.90% 31 30
Bass Strait
Pipeline gas 43.75% 105 82 Production was higher due to seasonal demand and reduced onshore and offshore
maintenance activities.
Crude oil and condensate 45.96% 22 18
NGL 45.83% 29 19
Australia Oil
Ngujima-Yin 60.00% 0 16 Production was lower due to planned maintenance turnaround.
Okha 50.00% 9 10
Pyrenees 64.97% 13 11
Other
Pipeline gas25F 30 34 34
Woodside Production rate Remarks
share26 31
(100% project, Mboe/d)
June 2023 Mar
2023
INTERNATIONAL
Atlantis
Crude oil and condensate 38.50% 80 78
NGL 38.50% 5 5
Pipeline Gas 38.50% 7 6
Mad Dog
Crude oil and condensate 20.86% 86 50 Mad Dog Phase 2 started up in April.
NGL 20.86% 2 2
Pipeline Gas 20.86% 2 1
Shenzi
Crude oil and condensate 64.39% 44 45
NGL 64.39% 2 2
Pipeline Gas 64.39% 1 1
Trinidad & Tobago
Crude oil and condensate 61.07% 32 5 6
Pipeline gas 52.58%(32) 57 56
Forward looking statements and other conversion factors
Disclaimer and important notice
This announcement contains forward-looking statements with respect to
Woodside's business and operations, market conditions, results of operations
and financial condition. All forward-looking statements contained in this
announcement reflect Woodside's views held as at the date of this
announcement. All statements, other than statements of historical or present
facts, are forward-looking statements and generally may be identified by the
use of forward-looking words such as 'guidance', 'foresee', 'likely',
'potential', 'anticipate', 'believe', 'aim', 'estimate', 'expect', 'intend',
'may', 'target', 'plan', 'forecast', 'project', 'schedule', 'will', 'should',
'seek' and other similar words or expressions. Similarly, statements that
describe the objectives, plans, goals or expectations of Woodside or other
statements about Woodside's future plans for projects and the timing thereof,
the implementation of Woodside's strategy and Woodside's expectations and
guidance with respect to production and certain financial and operating
results, are or may be forward-looking statements. The information and
statements in this announcement about Woodside's future strategy and other
forward-looking statements are not guidance, forecasts, guarantees or
predictions of future events or performance, but are in the nature of
aspirational targets that Woodside has set for itself and its management of
the business. Those statements and any assumptions on which they are based are
only opinions and are subject to change without notice and are subject to
inherent known and unknown risks, uncertainties, assumptions and other
factors, many of which are beyond the control of Woodside, its related bodies
corporate and their respective officers, directors, employees, advisers or
representatives. Important factors that could cause actual results to differ
materially from those in the forward-looking statements include, but are not
limited to, fluctuations in commodity prices; actual demand; currency
fluctuations; geotechnical factors; drilling and production results; gas
commercialisation; development progress; operating results; engineering
estimates; reserve estimates; loss of market; industry competition;
environmental risks; climate related risks; physical risks; legislative,
fiscal and regulatory developments; changes in accounting standards; economic
and financial markets conditions in various countries and regions; political
risks; project delay or advancement; regulatory approvals; the impact of armed
conflict and political instability (such as the ongoing conflict in Ukraine)
on economic activity and oil and gas supply and demand; cost estimates; the
effect of future regulatory or legislative actions on Woodside or the
industries in which it operates, including potential changes to tax laws; as
well as general economic conditions, inflationary conditions, prevailing
exchange rates and interest rates and conditions in financial markets. Details
of the key risks relating to Woodside and its business can be found in the
"Risk" section of Woodside's most recent Annual Report released to the
Australian Securities Exchange and London Stock Exchange, and in Woodside's
most recent Annual Report on Form 20-F filed with the U.S. Securities and
Exchange Commission and available on the Woodside website at
https://www.woodside.com/investors/reports-investor-briefings. You should
review and have regard to these risks when considering the information
contained in this announcement.
If any of the assumptions on which a forward-looking statement is based were
to change or be found to be incorrect, this would likely cause outcomes to
differ from the statements made in this announcement.
Investors are strongly cautioned not to place undue reliance on any
forward-looking statements. Actual results or performance may vary materially
from those expressed in, or implied by, any forward-looking statements. Except
as required by law or regulation, Woodside does not undertake to update or
revise any forward-looking statements contained in this announcement, whether
as a result of new information, future events, or otherwise.
All figures are Woodside share for the quarter ending 30 June 2023, unless
otherwise stated.
All references to dollars, cents or $ in this presentation are to US currency,
unless otherwise stated.
References to "Woodside" may be references to Woodside Energy Group Ltd or its
applicable subsidiaries.
Product Unit Conversion factor bbl barrel
bcf billion cubic feet of gas
boe barrel of oil equivalent
Mbbl thousand barrels
Mboe thousand barrels of oil equivalent
Mcf thousand cubic feet of gas
MMboe million barrels of oil equivalent
MMBtu million British thermal units
MMscf million standard cubic feet of gas
scf standard cubic feet of gas
Natural gas 5,700 scf 1 boe
Condensate 1 bbl 1 boe
Oil 1 bbl 1 boe
Natural gas liquids (NGL) 1 bbl 1 boe
Facility Unit LNG conversion factor
Karratha Gas Plant 1 tonne 8.08 boe
Pluto Gas Plant 1 tonne 8.34 boe
Wheatstone 1 tonne 8.27 boe
The LNG conversion factor from tonne to boe is specific to volumes produced
at each facility and is based on gas composition which may change over time.
1 Q2 2022 reflects the performance of the interests acquired as part of the
merger with BHP's Petroleum business from 1 June 2022.
2 Q2 2023 includes 0.23 MMboe, Q1 2023 includes 0.31 MMboe and Q2 2022
includes 0.30 MMboe primarily from feed gas purchased from Pluto non-operating
participants processed through the Pluto-KGP Interconnector.
3 Forecast IRR and payback period assume Woodside equity of 60% in Trion;
includes capital carry of approximately US$460m of capital expenditure for
PEMEX (at Woodside's final investment decision). IRR and the payback period
are a look forward from June 2023 and assume US$70/bbl (real terms 2022) Brent
oil price. Payback period is calculated from undiscounted cash flows, RFSU +
approximately 4 years.
4 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
5 Q2 2023 includes 1.96 MMboe of LNG, 0.08 MMboe of condensate and 0.04
MMboe of NGL, Q1 2023 includes 2.70 MMboe of LNG, 0.11 MMboe of condensate and
0.05 MMboe of NGL and Q2 2022 includes 2.51 MMboe of LNG and 0.10 MMboe of
condensate and 0.06 MMboe of NGL processed at the Karratha Gas Plant (KGP)
through the Pluto-KGP Interconnector.
6 Includes the aggregate Woodside equity domestic gas production from all
Western Australian projects.
7 Q2 2023 includes 0.23 MMboe, Q1 2023 includes 0.31 MMboe and Q2 2022
includes 0.30 MMboe primarily from feed gas purchased from Pluto non-operating
participants processed through the Pluto-KGP Interconnector.
8 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
9 Overriding royalty interests held in the Gulf of Mexico (GoM) for several
producing wells.
10 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
11 Includes periodic adjustments reflecting the arrangements governing
Wheatstone LNG sales of 0.15 MMboe in Q2 2023, 0.06 MMboe in Q1 2023 and 0.06
MMboe in Q2 2022.
12 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
13 Overriding royalty interests held in the GoM for several producing wells.
14 Purchased LNG volumes sourced from third parties.
15 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
16 Q2 2023 includes $11 million, Q1 2023 includes $3 million and Q2 2022
includes $5 million recognised in relation to periodic adjustments reflecting
the arrangements governing Wheatstone LNG sales. These amounts will be
included within other income/(expenses) in the financial statements rather
than operating revenue.
17 Overriding royalty interests held in the GoM for several producing wells.
18 Values include revenue generated from purchased LNG volumes, as well as
the marketing margin on the sale of Woodside's produced liquids portfolio.
Hedging impacts are excluded.
19 Total sales revenue excludes all hedging impacts.
20 Realised prices include the impact of periodic adjustments reflecting the
arrangements governing Wheatstone LNG sales.
21 Excludes any additional benefit attributed to produced LNG through
third-party trading activities.
22 June 2022 reflects the performance of the interests acquired as part of
the merger with BHP's Petroleum business from 1 June 2022.
23 Exploration capitalised represents expenditure on successful and pending
wells, plus permit acquisition costs during the period and is net of well
costs reclassified to expense on finalisation of well results.
24 Project final investment decisions result in amounts of previously
capitalised exploration and evaluation expense (from current and prior years)
being transferred to oil and gas properties. This table does not reflect the
impact of such transfers.
25 Scarborough key project expenditure includes Scarborough offshore, Pluto
Train 2, Pluto Train 1 modification and Train 2 tie-in spend. Prior period
comparatives have been restated to include Pluto Train 1 modification and
Train 2 tie-in spend of $21 million in Q2 2022 and
$34 million in YTD Q2 2022.
26 Well depths are referenced to the rig rotary table.
27 Pending regulatory approval.
28 Woodside share reflects the net realised interest for the period.
29 The Wheatstone asset processes gas from several offshore gas fields,
including the Julimar and Brunello fields, for which Woodside has 65%
participating interest and is the operator.
30 Includes the aggregate Woodside equity domestic gas production from all
Western Australian projects.
31 Woodside share reflects the net realised interest for the period.
32 Operations governed by production sharing contracts, Woodside share
changes monthly.
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