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Net debt ~$7.5B, Net debt/EBITDA ~1.2x; a 200bps rate rise adds ~$150M annual interest cost, manageable given ~$6B operating cash flow

~70% of debt is fixed-rate; floating rate exposure ~$2B, so 200bps rise increases annual interest ~$40M, low sensitivity

High intensity; OPEC+ supply decisions and Russia-Ukraine conflict drive price volatility.

Strait of Hormuz (LNG tanker routing) and Lombok/Malacca Strait (Asia-Pacific LNG delivery to key buyers Japan, China, Korea)

Revenue in USD-denominated LNG contracts; minimal direct FX devaluation risk; Korean Won, Japanese Yen, Chinese RMB buyer exposure hedged contractually

Operations in Australia, Timor-Leste, Senegal, Trinidad; USD-invoiced LNG limits sovereign currency devaluation exposure to local opex (~15% of costs)

High intensity; commodities: Crude Oil, Natural Gas, Coal, Refined Petroleum Products, Uranium, Steel (equipment); geopolitical: OPEC+ supply decisions and Russia-Ukraine conflict drive price volatility.

No single vendor exceeds 30% of operational input; FEED/EPC contractors (Bechtel, TechnipFMC) are substitutable; moderate lock-in on LNG plant technology

Physical energy commodity producer; no material cloud infrastructure dependency; cloud disruption would affect back-office only, not core operations

Integrated LNG producer and seller; cloud termination impacts trading/analytics systems but not upstream production or offtake contract execution

No significant API coupling risk; Woodside is an industrial producer with proprietary plant operations, not a software/platform business

Not applicable; Woodside sells physical LNG and oil commodities under long-term offtake contracts, not investment contracts; Howey Test risk is negligible

High

Low GDPR/CCPA exposure; primary customers are industrial energy buyers, not consumers; employee data compliance standard but not a material financial risk

Low-moderate; LNG market is globally competitive; Woodside holds ~5% global LNG market share; no dominant market position triggering serious antitrust scrutiny

High burden; regimes: EPA, FERC, DOE, CFTC, OSHA, SEC; Accelerating emissions mandates and methane rules threaten capex economics.

~75-80% recurring via long-term LNG offtake contracts (10-20 year terms); ~20-25% spot/transactional sales; highly recurring revenue base

Long-term contracted LNG and oil sales ($/MMBtu and $/bbl); spot market trading secondary; no subscription or SaaS monetization

Oil-indexed and Henry Hub-linked LNG contracts; oil price floor risk at ~$45/bbl Brent; below ~$50/bbl, margins compress significantly on newer projects

Moderate-high; long-term contracts provide price certainty; spot exposure subject to commodity cycles; limited ability to unilaterally reprice existing contracts

Gross margin ~55-65% at Brent $80+/bbl; EBITDA margin ~45-55%; capital-intensive but strong unit economics at current commodity prices

No free-rider problem; LNG is a rival, excludable commodity; customers are contracted utilities/industrials with high switching costs and long-term dependencies

Revenue growth is sublinear to headcount; production capacity expansions (Scarborough, Pluto T2) add output without proportional headcount increases; capital-intensive not labor-intensive

Marginal cost of growth is capital-driven (plant/infrastructure), not headcount-driven; incremental LNG volume has low marginal labor cost once facility is built

Not applicable; Woodside does not operate a franchise network

At 10x scale, CAC remains low (direct B2B offtake negotiation); unit economics improve with volume; constraint is production capacity, not customer acquisition cost

No meaningful network effects; LNG commodity market has no demand-side economies of scale; value is in resource access and production efficiency

AI displacement risk is low for core operations; AI may optimize maintenance scheduling and reservoir modeling but cannot replace physical LNG production assets

Moderate resilience; long-term contracted volumes provide stability, but spot prices and new project FIDs are vulnerable in deep recessions; Tier 2 recession resistance

Large Asian utility and energy companies (JERA, KOGAS, CNOOC, Sinopec) under long-term LNG offtake contracts; top 5 customers ~50%+ of revenue

European energy traders and utilities (post-2022 energy crisis diversification); US Gulf Coast and spot market buyers; growing but smaller revenue share

["11-0000 Management Occupations", "13-0000 Business and Financial Operations Occupations", "15-0000 Computer and Mathematical Occupations", "17-0000 Architecture and Engineering Occupations", "19-0000 Life, Physical, and Social Science Occupations", "23-0000 Legal Occupations", "41-0000 Sales and Related Occupations", "43-0000 Office and Administrative Support Occupations", "47-0000 Construction and Extraction Occupations", "49-0000 Installation, Maintenance, and Repair Occupations", "53-0000 Transportation and Material Moving Occupations"]

0.33 (HIL — ~33% of characteristic roles agent-automatable)

Capital actively reallocating to future-state: Scarborough/Pluto T2 ($12B+) and Louisiana LNG; legacy North West Shelf sustaining capex declining; net growth-oriented capex profile

0000844551

WDS