Occidental Petroleum Business Model Canvas

Drilling, completions, seismic and subsurface vendors boost Occidental’s operational performance by delivering faster well cycles and higher subsurface resolution, supporting fields that target EOR uplift of roughly 10–20 percentage points. Advanced EOR chemicals, CO2 handling and monitoring solutions are core to Oxy’s CO2-EOR strategy and can raise recovery while reducing leak risk. Partnerships accelerate deployment of automation and digital oilfield tools that industry studies show can cut operating costs by ~15% and improve safety and innovation through joint vendor programs.

Oxy leverages upstream JVs (Permian ~600,000+ boe/d in 2024), midstream/takeaway and CO2 pipeline partners for EOR/CCUS scale, vendors for ~15% opex cuts via digital/EOR tech, and capture/DAC/storage partners as global CCS reached ~40 MtCO2/yr in 2024 while Oxy targets ~70 MtCO2/yr by 2035.

Negotiate capture and long-term offtake agreements and develop storage sites and CO2 pipelines to link emitters, aligning with Occidental’s strategy to commercialize large-scale storage and transport hubs.

Implement MRV frameworks meeting 45Q and voluntary market standards to ensure permanence and creditability for stored CO2.

Integrate DAC pilots like 1PointFive and phase scale-up toward commercial hubs while structuring multi-decade offtake contracts with industrial emitters.

Identify and appraise prospects then execute multi-pad drilling (2024 programs averaged 4–6 wells per pad) across the Permian, DJ, GOM and select international assets.

Optimize landing zones, spacing and completions using seismic and real-time geosteering to maximize EURs and lower unit costs.

Operate wells, facilities and CO2-EOR programs to sustain ~1.0 million BOE/d production (2024) and extend field life.

Market crude, gas and NGLs, hedge via swaps/collars and develop CO2 transport/storage and DAC hubs linked to long-term offtakes.

Occidental’s central processing facilities, gathering systems and terminals enable scalable throughput across its asset base, supporting roughly 1.2 million boe/d of production in 2024. Integrated power, produced water handling and sand logistics drive unit cost and uptime outcomes, lowering downtime risk. Offshore platforms and subsea tiebacks in the Gulf of Mexico expand low-decline economics and reserve recovery. Onshore and terminal storage plus blending assets enhance marketed crude and product optionality.

Occidental’s key resources: Permian ~1.2M net acres, proved reserves ~2.0B BOE and ~1.2M boe/d production (2024). CO2 infrastructure and targets: 70 Mtpa by 2035, DAC pilot 1 Mt/yr (Carbon Engineering) ~600M USD capex. Liquidity ~10B USD (2024) plus committed facilities, structured finance for CCUS hubs and hedging to stabilize cash flow.

Occidental offers turnkey capture, transport and storage that de-risk emitter transitions by bundling CO2 capture with pipeline and geologic storage services; OXY expanded this capability by acquiring Carbon Engineering via 1PointFive in 2023. Long-dated storage contracts (typically 10–20 years) provide price certainty for buyers. Commercial DAC adds removals for hard-to-abate sectors and OXY’s regulatory familiarity expedites permitting and project deployment.

Occidental combines scale (~1.2MM boe/d in 2024) and low lifting costs (~$6–8/boe) with multi-basin production and active hedging to secure stable feedstock and cashflows. Leading CO2-EOR and CCUS (1PointFive/Carbon Engineering acquisition) link lower-carbon barrels and MRV-backed storage to commercial decarbonization solutions. Turnkey capture-to-storage, long-term contracts (10–20y storage) and marketing optionality raise customer certainty.

Dedicated account management delivers tailored logistics, scheduling, and quality management for key accounts, which for Occidental—producing about 1.0 million BOE/d in 2024—focus on sustaining high-value flows. Single points of contact streamline communication and escalation, while regular contract reviews (quarterly) optimize performance. Rapid issue resolution protocols preserve service levels and contractual KPIs.

Occidental secures volume via multi-year offtake/supply contracts (typ. 3–20 year tenors) with indexed pricing and take-or-pay terms for cash-flow predictability. Co-development of CCUS shares capex/revenue risk with shared MRV and regulatory milestones; 2024 CCUS unit cost range cited $40–$120/tonne. Dedicated account management for ~1.0 million BOE/d production (2024) and quarterly contract reviews sustain reliability.

In-house and third-party commodity marketers at Occidental optimize price realization across ~1.2 million boe/d of upstream sales (2024), using basis, storage and timing strategies to capture differential spreads and seasonal premiums. Traders extend reach to buyers in 40+ countries, enhancing liquidity and hedging options. Structured deals and tolling arrangements balance downside risk with commercial flexibility.

Account teams sell crude, gas, NGLs and CO2 via contracts, spot and tolling, leveraging pipeline/terminal access and hubs to optimize realization; ~1.2M boe/d sales (2024). Digital EDI/ERP and MRV dashboards speed settlements and customer integration. CCUS hubs aggregate emitters, cutting transport/storage unit costs ~25–30%; global CCUS ~50 MtCO2/yr (2024).

Industrial emitters—cement, steel, ammonia and chemical plants—drive roughly 30% of global CO2 emissions and urgently need CCUS solutions; long-lived facilities favor multi-decade (20–30 year) storage contracts for asset-level de-risking. Capture integration demands engineering, retrofit capex and O&M support tied to plant throughput. Carbon credit integrity is paramount after 2023–24 market scrutiny of standards and registries.

Refiners, power/gas, industrial emitters, traders and governments form Occidental’s core customers, each valuing reliability, contract tenor, quality and decarbonization options. Demand drivers: oil ~101 mbpd (2024), US refinery util ~88%, gas ~38% of US power; financial terms hinge on hedging, long-term offtakes and CCUS incentives. Permitting, pore-space and 45Q credits (up to $85/t DAC) shape project economics.

Pipeline and terminal fees materially compress Occidental’s netbacks, with Permian takeaway differentials averaging around 8 USD/bbl in 2024, raising per‑barrel transport burdens; storage and blending add variable costs often running fractions to low single‑digit USD/bbl; basis management and logistics create additional hedging and trucking expenses; export access to Gulf Coast/Asian markets can carry premiums of roughly 1–3 USD/bbl.

Pad drilling, completions and processing are ~60% of project capex; offshore tiebacks/maintenance ~10–15%. Permian takeaway differential ~8 USD/bbl (2024); US federal tax 21%. CCUS hubs need multi‑billion upfront spend; AROs/GOM plugging and R&D/DAC pilots are recurring costs.

Occidental generates fees and margin from supplying and injecting CO2 for EOR while capturing value from incremental barrels produced; CO2-EOR contracts and service rates underpin recurring revenue. CO2-EOR commonly increases recovery by 30–60%, driving incremental barrels that boost cash flow per well. Integration of capture, transport and injection lowers unit CO2 handling costs and, with multi-decade field life, extends predictable cash flows.

Crude oil is primary revenue, 2024 guidance ~1.2 million boe/d with Brent/WTI-linked pricing and growing export volumes. Natural gas and NGLs deliver steady contract and spot sales (Henry Hub ~$2.80/MMBtu in 2024). CO2-EOR provides margin via incremental barrels (30–60% recovery uplift) and service fees. CCUS/storage monetized through per-ton fees plus 45Q-linked credits, creating multi-decade annuity cashflows.