July 30, 2024

Woodside Energy Group Ltd

 

VIA EDGAR		ACN 004 898 962
United States Securities and Exchange Commission		Mia Yellagonga
Division of Corporate Finance		11 Mount Street
Office of Energy & Transportation 100 F Street, N.E.		Perth WA 6000
Washington, D.C. 20549		Australia
United States of America		T: +61 8 9348 4000 www.woodside.com

Attention: Sandra Wall and John Hodgin

 

Re:

Woodside Energy Group Ltd

Form 20-F for the Fiscal Year Ended December 31, 2023

Filed February 27, 2024

File No. 001-41404

Dear Ms. Wall and Mr. Hodgin:

I refer to your letter, dated June 17, 2024, setting out comments of the Staff of the Securities and Exchange Commission (the “Staff” and the “Commission”) relating to the annual report on Form 20-F for the year ended December 31, 2023 (the “2023 Form 20-F”) of Woodside Energy Group Ltd (the “Company”, “Woodside”, “we” or “our”).

Woodside’s response to the Staff’s comments are set out below. To assist in the Staff’s review, we have preceded our response with the text (in italics and bold type) of the comments as stated in your letter.

Form 20-F for the Fiscal Year Ended December 31, 2023

 

1.

We note disclosure under the heading “International,” here and throughout your filing, which appears to combine information for various individual countries. Please refer to the requirements for separate disclosure by geographic area in: Item 1201(d) of Regulation S- K relating to the disclosures required in Items 1202 through 1208 and in FASB ASC 932- 235-50-6 through 6B relating to the disclosures required in FASB ASC 932-235-50-4 through 50-36, and revise your disclosures accordingly or tell us why a revision is not needed.

This comment applies to the following disclosures:

 

•

Proved developed, proved undeveloped, and total proved reserves in Tables 1 and 2 on pages 48, 49, and 50

 

•

Proved Undeveloped Reserves Reconciliation in Table 3 on page 51

 

•

Capitalized costs on page A-1

 

•

Costs incurred on page A-2

 

•

Results of operations on page A-3

 

•

Standardized measure on page A-4 and Changes therein on page A-5

 

•

Volumes, Realized Prices and Operating Revenues By Product on pages A-9

 

•

Drilling and Other Exploratory and Development Activities and Present Development Activities on page A-15

 

•

Oil and Gas Properties, Wells, Operations and Acreage and Delivery Commitments on page A-16

 

•

Production, Average sales price, and Total average production cost on page A-17

 

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The Company respectfully advises the Staff that, as of December 31, 2023, the reserves of the assets represented under the ‘International’ heading are approximately 25 percent of the Company’s total reserves expressed on an oil-equivalent-barrel basis, and no single country or asset represented under the ‘International’ heading accounts for 15 percent or more of the Company’s total proved reserves.

As described on page 52 of the 2023 Form 20-F, the ‘International’ heading consists of assets in Trinidad and Tobago, Senegal, Mexico and the United States Gulf of Mexico. Our United States Gulf of Mexico assets account for 291.6 MMboe (12 percent) of our total proved reserves. Trinidad and Tobago, Senegal, Mexico collectively account for 313.4 MMboe (13 percent) of our total proved reserves, with no single country accounting for more than eight percent of our total proved reserves. Taking into account the Staff’s comment, the Company proposes to include additional detail similar to the following in the “Notes to the Reserves Statement” on the composition of the reserves set out under the “International” heading, in its future filings, beginning with its annual report on Form 20-F for the year ending December 31, 2024 (the “2024 Form 20-F”) (new language underlined and in bold):

16. ‘International’ consists of Trinidad and Tobago, Senegal, Mexico, and the United States Gulf of Mexico. The United States Gulf of Mexico accounted for 291.6 MMboe, or 12 percent, of the Company’s total proved developed undeveloped reserves as at 31 December 2023 (net Woodside share).

The Company respectfully submits that disclosing the relevant information under a single heading of ‘International’ is “appropriate for meaningful disclosure” given the Company’s current asset portfolio and remaining reserves. The Company will continue to monitor the reserves and production activities of assets under the ‘International’ heading to determine if separate disclosure is required under Subpart 1200 of Regulation S-K or the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, Extractive Activities-Oil and Gas (Topic 932).

 

2.

We note you do not provide an explanation for the significant change in total proved reserves for the year ended December 31, 2021 relating to extensions and discoveries. Please expand your disclosure to explain the reasons for significant changes in the net quantities of total proved reserves for each line in the reserves reconciliation, other than production, for each period presented. Refer to FASB ASC 932-235-50-5 and Instruction 1 to Item 302(b) of Regulation S-K.

The Company respectfully acknowledges the Staff’s comment and advises the Staff that the change in the Company’s total proved reserves for the year ended December 31, 2021, relating to extensions and discoveries was primarily attributable to the first time booking of the Scarborough project (901.9 MMboe, Australia) and the Sangomar project (81.2 MMboe, International).

The Company also acknowledges the Staff’s comment to expand the disclosure to explain reasons for changes in each line of the reserves reconciliation. For the year ended December 31, 2021, revisions increased proved reserves by 39.5 MMboe primarily due to improved production performance in Pluto (+46.6 MMboe) that was offset by poorer than expected production performance in the North West Shelf (-7.4 MMboe).

The Company also respectfully notes that the 2023 Form 20-F includes explanations for significant changes in proved reserves across all categories (including Extensions and Discoveries) for the years ended December 31, 2022 and 2023. In future filings, the Company will continue to include explanations in disclosure for significant changes in the net quantities of total proved reserves for each line in the reserves reconciliation, other than production, for each period presented.

 

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3.	Please disclose if all proved undeveloped reserves (other than PUDs associated with Julimar-Brunello) are scheduled to be fully developed within five years of initial booking.

The Company respectfully acknowledges the Staff’s comment and notes that it has disclosed on page 50 of the 2023 Form 20-F the reasons why certain proved undeveloped reserves have remained undeveloped for five years or more after initial disclosure in accordance with the disclosure requirements in Item 1203(d) of Regulation S-K.

Taking into account the Staff’s comment, however, the Company proposes to include disclosure similar to the following, in its future filings, beginning with its 2024 Form 20-F (new language underlined and in bold):

Only undeveloped reserves in Julimar Brunello have remained undeveloped for longer than five years from the dates they were initially reported and are expected to be developed in a phased manner to meet long-term contractual commitments. The project is included in the company business plan, demonstrating the intent to proceed with the development.

As of December 31, 2023, approximately 89 percent of the Company’s proved undeveloped reserves are scheduled to be developed within five years of initial disclosure. The remaining proved undeveloped reserves (approximately 11 percent) are associated with large and complex capital investment projects, which are scheduled to be developed beyond five years from initial disclosure primarily due to facility ullage constraints and scheduled offshore drilling campaigns. The Company is committed to these projects and continues to actively progress the development of these volumes.

During 2023, Woodside spent $5.3 billion on development activities worldwide. Of this amount, $4.7 billion was spent progressing the conversion of proved undeveloped reserves for projects where development status was achieved in 2023 or is expected to be achieved when development is completed in the future.

 

4.	You disclose your reserves evaluation used the unweighted average first-day-of-the-month market prices for the previous 12-months as prescribed by the SEC. Please consider expanding your disclosure to provide the actual SEC benchmark prices.

The Company respectfully acknowledges the Staff’s comment and submits that the market prices used to determine the Company’s reserves evaluation are consistent with the requirements under Subpart 1200 to Regulation S-K and the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, Extractive Activities-Oil and Gas (Topic 932).

 

5.	Please expand your disclosure on page A-9 to explain the differences between “Production volumes” and “Sales volumes,” and to explain any differences with the disclosures of “Production volumes” and “Average sales prices” on page A-17.

The Company respectfully acknowledges the Staff’s comment. In future filings, beginning with the 2024 Form 20-F, the Company will expand the disclosure to include additional commentary on the differences between sales and production volumes.

Sales volumes disclosed on page A-9 of the 2023 Form 20-F include purchased volumes sourced from third parties. Sales figures excluding third party purchased volumes differ from production volumes primarily due to the timing of liftings.

Production volumes disclosed on page A-9 of the 2023 Form 20-F include production from feed gas purchased from Pluto non-operating participants and processed through the Pluto to Karratha Gas Plant (i.e. Pluto-KGP) interconnector. These volumes are excluded from the production volumes disclosed by geographic area on page A-17 of the 2023 Form 20-F. Average realized prices disclosed on page A-9 of the 2023 Form 20-F vary from those on page A-17 as a result of the inclusion of third-party purchased volumes on page A-9.

 

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Set forth below for the Staff’s reference is a presentation of the expanded disclosure by reference to the 2023 Form 20-F (new language underlined and in bold):

VOLUMES, REALISED PRICES AND OPERATING REVENUES BY PRODUCT

The following describes movements in Woodside’s operating revenues including a discussion of production volumes, sales volumes and realised prices for the years ended 31 December 2023, 2022 and 2021.

 

		Units		2023				2022				2021
Production volumes1
LNG		Bcf			505.0				485.1				403.6
Pipeline gas		Bcf			226.3				163.0				14.3
Crude oil and condensate		MMbbl			51.8				38.7				17.3
NGLs		MMbbl			7.1				5.3				0.5
Total production volumes2		MMboe			187.2				157.7				91.1
Sales volumes3 4
LNG		Bcf			595.7				550.6				519.8
Pipeline gas		Bcf			225.7				161.9				14.3
Crude oil and condensate		MMbbl			50.3				39.3				17.2
NGLs		MMbbl			7.1				4.6				0.7
Total sales volumes2		MMboe			201.5				168.9				111.6
		Units		2023				2022				2021
Average realised prices4
LNG		$/Mcf			13.7				20.5				10.3
Pipeline gas		$/Mcf			6.1				8.4				3.0
Crude oil and condensate		$/bbl			79.0				95.8				76.4
NGLs		$/bbl			39.5				44.4				82.4
Volume - weighted average		$/boe			68.6				98.4				60.7
Operating revenue3 4
LNG		$m			8,165				11,289				5,359
Pipeline gas		$m			1,374				1,362				43
Crude oil and condensate		$m			3,981				3,758				1,316
NGLs		$m			281				206				60
Other revenue		$m			193				202				184
Operating revenue		$m			13,994				16,817				6,962

 

1	Production volumes for 2023, 2022 and 2021 include 1.1 MMboe, 0.9 MMboe and 0.0 MMboe, respectively, of production from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

2	LNG and Pipeline gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 billion cubic feet (Bcf) of gas per 1 million barrel of oil equivalent (MMboe). Volumes of NGLs, oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio.

3

Sales volumes for 2023, 2022 and 2021 include 15.6 MMboe, 14.7 MMboe and 21.8 MMboe, respectively, of purchased volumes sourced from third parties. These third-party volumes are primarily LNG cargoes purchased from Corpus Christi LNG through a long-term offtake agreement and from the spot market. Sales volumes also include feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

4	Sales volumes differ from production volumes primarily due to the timing of liftings and the exclusion of third-party purchased volumes. Average realised prices and operating revenue include third-party purchased volumes.

 

6.	Please expand your disclosure to identify if there are any proved undeveloped reserves associated with the near-term expiring acreage.

The Company respectfully acknowledges the Staff’s comment and confirms that no proved undeveloped reserves are associated with the near-term expiring acreage. In future filings, beginning with our 2024 Form 20-F, the Company will expand the disclosure to identify if there are any proved undeveloped reserves associated with the expiring acreage. Set forth below for the Staff’s reference is a presentation of the expanded disclosure by reference to the 2023 Form 20-F (new language underlined and in bold):

 

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Woodside has initiated exits from our Myanmar, Peru and Ireland positions, totalling approximately 8,426 thousand acres gross (3,670 thousand acres net). Approximately 248 thousand acres gross (200 thousand acres net), 1,333 thousand acres gross (615 thousand acres net) and 784 thousand acres gross (452 thousand acres net) of undeveloped acreage will expire in the years ending 31 December 2024, 2025 and 2026 respectively if Woodside does not establish production or take any other action to extend the terms of the licences and concessions. There are no proved undeveloped reserves associated with the near-term expiring acreage.

 

7.

Please expand your presentation to additionally disclose production, by final product sold, for each field or operational area that contains 15% or more of your total proved reserves for each period presented. Refer to the disclosure requirements in Item 1204(a) of Regulation S-K and the definition of a field in Rule 4-10(a)(15) of Regulation S-X.

The Company respectfully acknowledges the Staff’s comment and advises the Staff that only one field (Scarborough) contained 15 percent or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis for fiscal years ended December 31, 2021, 2022 and 2023. Scarborough is currently under development and has not started production. The Company will separately include the production (by final product sold, of oil, gas, and other products) of each country and field that contains 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis unless prohibited by the country in which the reserves are located.

 

8.	Please expand or modify your disclosure of LNG and Pipeline gas to provide the production volumes and average sales prices in terms of MMcf per unit of gas produced. Refer to the disclosure requirements in Items 1204(a) and (b)(1) of Regulation S-K.

The Company respectfully acknowledges the Staff’s comment. In future filings, beginning with the 2024 Form 20-F, the Company will expand the disclosure to provide the gas production volumes in terms of billion cubic feet (Bcf) and average gas sales prices in terms of US dollar per thousand cubic feet (US$ per Mcf). Set forth below for the Staff’s reference is an expanded disclosure by reference to the 2023 Form 20-F that will be adopted for future filings (new language underlined and in bold):

PRODUCTION

The following table details production by product and geographic location for each of the three years ended 31 December 2023, 2022 and 2021. The volumes are marketable production after deduction of applicable royalties, fuel and flare. Average production costs per unit of production and average sales prices per unit of production has also been included for each of these periods.

 

		20231				20221				20212
Production volumes
LNG (Bcf)
Australia			499.3				481.1				403.6
International			—				—				—
Total LNG			499.3				481.1				403.6
Pipeline gas (Bcf)
Australia			159.6				130.5				14.3
International			65.6				31.9				—
Total pipeline gas			225.2				162.5				14.3
Crude oil and condensate (MMbbl)
Australia			22.7				24.0				17.3
International			29.1				14.7				—
Total crude oil and condensate			51.8				38.7				17.3
Natural gas liquids (NGLs) (MMbbl)
Australia			5.7				4.4				0.5

 

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		20231				20221				20212
International			1.4				0.8				—
Total NGLs			7.1				5.2				0.5
Total petroleum products (MMboe)4
Australia			144.0				135.7				91.1
International			42.1				21.1				—
Total production			186.1				156.8				91.1
Average sales price per produced unit
LNG (US$/Mcf)
Australia			13.4				18.2				9.7
International			—				—				—
Total LNG			13.4				18.2				9.7
Pipeline gas (US$/Mcf)
Australia			6.8				8.3				3.2
International			4.4				8.6				—
Total pipeline gas			6.1				8.4				3.2
Crude oil and condensate (US$/bbl)
Australia			70.8				103.3				75.8
International			77.0				86.7				—
Total crude oil and condensate			74.3				97.0				75.8
Natural gas liquids (NGLs) (US$/bbl)
Australia			38.3				40.6				121.2
International			22.9				34.5				—
Total NGLs			35.2				39.7				121.2
Total average production cost per produced boe (US$/boe)
Australia			(11.2	)			10.4				7.9
International			(8.5	)			16.9				—
Total average production cost per produced boe3			(10.6	)			11.2				7.9

 

1	2023 and 2022 exclude 1.1 MMboe and 0.9 MMboe of production from feed gas purchased from Pluto non-operating participants processed through the Pluto-KGP Interconnector.

2	Production volumes for 2021 has been restated to present marketable production after deduction of applicable royalties, fuel and flare.

3.

Average production costs per produced boe includes direct and indirect costs relating to production of total hydrocarbons and the foreign exchange effect of translating local currency denominated costs into US dollars but excludes cost to transport produced hydrocarbons to the point of sale, ad valorem and severance taxes.

4	LNG and Pipeline gas volumes are converted to oil equivalent volumes via a constant conversion factor, which for Woodside is 5.7 billion cubic feet (Bcf) of gas per 1 million barrel of oil equivalent (MMboe). Volumes of NGLs, oil and condensate are converted from MMbbl to MMboe on a 1:1 ratio.

*  *   *

We are available to discuss any of the foregoing with you and the Staff at your convenience.

Very truly yours,

/s/ Graham Tiver      

Graham Tiver

Chief Financial Officer

 

cc:	Rebecca McNicol

Lucy Bowman

(Woodside Energy Group Ltd)

Waldo D. Jones, Jr.

Benjamin I. Fleming

(Sullivan & Cromwell)

 

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