InPlay Oil Business Model Canvas

Surface access and mineral leases underpin development, with 2024 industry surveys showing over 70% of onshore projects contingent on negotiated rights. InPlay negotiates leases, surface rights and community agreements to secure pad drilling and infrastructure buildout. Constructive relations with landowners and mineral holders enable phased development and reduce delays. Responsible operations sustain social licence and continuity with local stakeholders.

InPlay leverages specialist drilling/completion contractors (avg lateral 8,000 ft, >20-stage fracs in 2024) and performance-based contracts to align costs with EURs. Midstream partners secure takeaway and processing (US pipeline capacity ~11 million bpd in 2024) via 3–10 year agreements to protect netbacks. Tech, data and finance partners delivered ~10% uptime gain, ~20% F&D cost reduction and hedging/credit to stabilize cash flow.

Completion design tailors stage spacing (typically 50–150 ft), fluid systems and proppant loads (commonly 50,000–250,000 lb per stage) to reservoir targets. Real-time frac diagnostics in 2024 drove SRV optimization and EUR uplifts of roughly 10–30% in operator reported case studies. Supply logistics target >95% on-time sand and water delivery, while post-frac cleanup shortens time-to-first-production by ~20–40%.

Geology, 3D seismic and petrophysics convert horizons into drillable PODs; type curves set IRR hurdles (20–25%) and top-quartile bench targets (>25–30%). Multi-well pads and optimized trajectories cut surface footprint ~50%, cycle time ~25% and lateral cost ~30%. Completions (50k–250k lb proppant/stage), >95% sand delivery, real-time frac and digital surveillance drove EUR +10–30% and uptime +25% (2024 Brent ~84 USD/bbl).

Battery sites, tanks, pipelines and water-handling systems cut lifting costs by lowering fuel and trucking needs—battery electrification has reduced onsite diesel use 30–50% in 2024 pilots; access to gas processing enables NGL recovery worth an estimated 10–20% uplift to gas revenue while cutting methane emissions up to 90%; SCADA and telemetry deliver real-time visibility, reducing downtime ~20%; modular facilities shorten build time ~30% and scale capex efficiently.

InPlay’s core Alberta acreage, skilled technical team and modern completions drive low breakevens and faster cycles; 2024 pilots cut diesel 30–50% and SCADA reduced downtime ~20%. Financials: £25m RCF, £10m cash, hedge ~60% 2024 volumes, net debt/EBITDA target <1.0x. NGL recovery adds 10–20% to gas revenue; US crude ~12.9m b/d (EIA 2024).

Oil, NGLs and gas deliver multiple revenue streams for InPlay, reducing exposure to a single commodity and enabling blended cashflow stability; in 2024 Brent averaged about 86 USD/bbl while Henry Hub averaged roughly 2.9 USD/MMBtu. Liquids uplift—NGLs and crude—complements lower gas realizations, boosting realized liquids pricing versus gas. Flexibility in marketing lets InPlay capture premium outlets and optimize netbacks across the product mix.

Light-crude focus with 2024 WTI ~US$80/bbl drove strong netbacks; pad drilling and multi-well pads lowered F&D and break-evens. Data-driven horizontals (horizontals >90% US shale prod) and multi-stage fracs raised IPs and EURs with ML optimization. Liquids/NGLs plus gas (Brent ~US$86/bbl; Henry Hub ~US$2.9/MMBtu) diversified cashflows.

Coordinated midstream planning aligns facility capacity with growth, helping match supply to the US crude pipeline throughput (~12.8 million b/d in 2024, EIA) and avoid bottlenecks. Transparency through shared data reduces downtime and routine flaring, supporting the World Bank zero routine flaring by 2030 agenda. Joint problem-solving lifts throughput and reliability, while shared KPIs (availability, turnaround time, flaring rates) measurably raise service levels.

Structured offtake and volume commitments secure demand and price realization; 2024 global oil demand ~102 mb/d (IEA). Active spot sales capture upside—WTI avg ~$80/bbl in 2024—while diversification limits counterparty risk. Transparent reporting, ESG disclosures and local partnerships cut permitting delays and maintain social licence.

Term offtake agreements, typically 12–24 month contracts in 2024, capture quality premiums by guaranteeing consistent grades to refiners. Coordinated logistics—scheduling, storage and inland transport—ensure on-time deliveries and lower demurrage exposure. Deep refiner relationships improve netbacks by narrowing basis differentials. Rigorous quality assurance and third-party testing in 2024 strengthened InPlay Oil’s market reputation.

Pipelines carry >90% of Canadian crude, lowering per-barrel cost and emissions; third-party marketing taps parts of 2024 global demand 101.6 mn b/d and US supply 12.9 mn b/d to optimize netbacks; term offtakes (12–24 months) and tankage (SPR cap 714 mn bbl) enable timing optionality; swaps, collars and basis hedges stabilize cash flows and manage differentials.

Energy marketers act as intermediaries matching supply with demand across regions, enabling producers to tap global crude demand of about 101 million barrels per day in 2024 (IEA). They provide logistics and pricing expertise, managing shipping, storage and hedging to optimize netbacks. By offering credit and flexible offtake terms and diversifying sales channels, marketers reduce working-capital pressure and broaden market access for producers.

Refiners/upgraders need consistent light crude; US refinery utilization was 91.5% in 2024. Gas processors/utilities require steady gas/NGLs; Henry Hub averaged 2.95 $/MMBtu in 2024. Marketers enable access to global crude demand ~101 mb/d (IEA 2024). Banks/investors set cost of capital with US policy rate 5.25–5.50% in 2024.

Transportation and processing costs include pipeline tariffs and gas processing and NGL fractionation fees that can materially erode realizations; with 2024 Henry Hub averaging about $2.80/MMBtu, tolls and fees often consume a meaningful share of margin. Blending and storage add logistics cost and working-capital; take-or-pay obligations can force under- or over-utilization of capacity. Optimization targets netback improvement through toll negotiation, plant optimization and third-party contracting.

Drilling & completion (65–75% of well CAPEX in 2024) and pad efficiencies cut per‑well costs ~10–20%. LOE averaged C$9.00/boe in 2024; automation reduced field visits ~35%. Transport/processing tolls, Henry Hub ~$2.80/MMBtu and $80/t CO2 carbon price pressured netbacks. G&A ran ~8–12% with IR/audit $0.5–1.5M.

Natural gas sales deliver proceeds from dry gas marketed at AECO or regional hubs, with AECO averaging about CAD 2.65/GJ in 2024. Seasonal pricing and basis hedges (commonly annual contracts) protect margins across winter peaks. Processing shrinkage, typically accounted in contracts at c.8%, is deducted before revenue allocation. High operational reliability improves nominations and largely eliminates imbalance penalties.

Primary income from light crude sold to WTI/Edmonton with realized premiums via API, pipelines/rail; volumes driven by drilling and declines. NGLs (propane/butane/condensate) often contribute 20–35% of liquids revenue; Mont Belvieu spreads and fractionation boost value. Gas sold at AECO ~CAD 2.65/GJ (2024); hedging covers 50–75% of 12‑month volumes; byproducts add ~1–3%.