Vitesse Energy Business Model Canvas

Source, underwrite and close WI/ORRI packages across core Bakken benches, focusing on benches with inventory depth >200 locations and top-decile operators such as Continental, Chevron and ConocoPhillips.

Target a PDP/PUD mix ~60/40 to balance cash flow and upside, pursue deal IRR >20% and use collars, hedges and contingent payments to protect downside.

Structure step-ups and optioned acreage to preserve optionality and integrate assets via API-driven marketing and reporting, covering ~90% of volumes and targeting a 5–8% lift in realized pricing.

We prioritize capital allocation by selecting wells targeting IRRs above 30% and timing AFE participation to keep the reinvestment rate near 60–70%, optimizing portfolio returns. AFEs are continuously triaged using type curves, per-well costs and spacing to enforce payout thresholds (typically 12–18 months) and hard capital limits. Post-drill actuals are tracked versus pre-drill forecasts with KPI variance targets for EUR and cost under 10%.

WI exposure across Bakken and Three Forks extends inventory life and geological resilience, leveraging North Dakota production that averaged about 1.14 million b/d in 2024 (EIA). The portfolio balance of PDP, DUCs and PUDs supports near- and mid-term cash flows through immediate lift and staged development. Operator diversity reduces single-counterparty and execution risk. Established DSUs provide clearer development timing and capital planning visibility.

Reservoir, land, finance and risk professionals at Vitesse drive underwriting quality, aligning geologic upside with cost control; cross-disciplinary reviews ensure balanced portfolios. Vendor and operator networks provide proprietary insights from field operators and service providers. Agile processes cut decision cycles to under 30 days, supporting faster capital deployment amid 2024 Brent ~83 USD/bbl market conditions.

Non-operated model avoids rig ownership and field overhead, cutting fixed capital and operating burdens while preserving exposure to upstream cash generation. Investors gain oily beta with a lean cost structure, supported by WTI averaging about $80/bbl in 2024. Vitesse targets returns measured by FCF per share rather than volume growth for its own sake. Upside is retained through disciplined AFE selection and strict project economics.

Diversification across multiple operators and DSUs reduces single-well risk by spreading exposure across varied operational practices and lease areas. Different benches and vintages smooth decline curves and performance variance, mirroring the Williston Basin's mixed-production profile (North Dakota averaged ~1.1 million b/d in 2023, EIA). The portfolio functions as a risk-managed index of Williston development, enhancing stability and supporting predictable distributions.

Long-term offtake contracts, commonly 3–10 years in hydrocarbons markets, secure reliable buyers for oil, gas and NGLs and supported many producers during Brent's 2024 average of about $86/bbl. Clear quality specifications and scheduling reduce quality/nomination penalties and demurrage events. Consistent volumes from firm offtake commitments improve pricing outcomes via tighter differentials. A demonstrated performance history typically strengthens counterparty terms and credit lines.

Responsive AFE decisions (targeting 72 hours) and clear communications foster operator trust and faster approvals; industry-standard payment terms of 30–60 days in 2024 help keep crews mobilized. Routine data sharing and post-well reviews drive iterative improvements in drilling efficiency. Close alignment on development plans reduces surprises and rework, while timely payments prevent downtime and preserve vendor relationships.

Direct sales to purchasers, refiners, and traders capture value from a US export market that averaged ~4.5 million b/d in 2024, enabling price capture across hubs. A blended term/spot strategy (mix tailored per cycle) optimizes netbacks versus purely spot exposure. Rigorous quality control and logistics scheduling routinely shave 0.5–1.0 USD/bbl off deductions. Credit-vetted counterparties and LC requirements limit counterparty risk.

Gas gathering and processing agreements connect wells to plants enabling residue gas and NGL recovery, supporting NGL yields that accounted for roughly 8–10% of US gas output in 2024; fees are structured to balance shrink and uplift against plant recovery economics. Takeaway commitments and firm capacity clauses ensure flow assurance; basis hedges and fixed-differential contracts complement physical offtake to lock margins and mitigate basis volatility.

Buyers seeking reliable Williston-sourced barrels prioritize supply proven by EIA 2024 Bakken output near 1.1 million b/d; Vitesse serves both pipeline and truck-delivered volumes to match offtake logistics. Customers value consistent API/sulfur quality and predictable scheduling to minimize refinery downtime. Pricing is tied to WTI benchmarks and regional differentials, with WTI averaging about $80/bbl in 2024.

Counterparties monetize residue gas and NGL streams—U.S. natural gas plant liquids output totaled about 6.0 million barrels per day in 2024 (EIA), creating substantial optionality for processors and marketers. Contracts reward uptime and volume stability through throughput incentives and make-whole provisions. Optionality is amplified via plant connections and interruptible flows. Exposure is managed through basis arrangements and hedges to stabilize netbacks.

Working interest capex (AFE participation) is the primary cash outlay for drilling and completions, typically $5–10M per lateral in US onshore basins in 2024. Timing is tied to operator development cadence—quarterly to biannual spend. Focused on breakevens (~$35–$55/bbl) and payout windows of 12–36 months. Pad-level efficiencies can lower unit D&C costs ~15–25%.

Under JIBs, lease operating expenses (lifting, water handling, workovers) typically account for roughly 30–45% of JV operating spend, driving margins directly by operator cost control. Active monitoring of per-well variances and monthly JIB reconciliations curbs overruns and can cut unexpected LOE by 10–20%. Scaling across pads reduces unit LOE — field studies in 2024 show pad-level synergies lowering LOE per BOE by ~15% on average.

Primary crude oil revenue tracks production volumes and benchmark realizations, with 2024 average WTI near USD 80/bbl and Bakken differentials typically trimming realizations by roughly USD 5–8/bbl.

Combination of term contracts and spot sales diversifies exposure, letting Vitesse lock margins on a portion of output while capturing upside in spot markets.

Quality, pipeline takeaway constraints and marketing costs drive netbacks, and targeted basis hedges are used to stabilize realizations against WTI/Bakken basis swings.

Vitesse captures residue gas and NGL uplift to enhance BOE economics, with 2024 US Henry Hub average near $2.86/MMBtu and Mont Belvieu composite NGL values supporting significant uplift to wellhead realizations.

Processing recoveries and fee structures—including percent-of-liquids recoveries and keep-whole arrangements—directly drive realized value per BOE and margin capture.

Revenue is exposed to regional basis differentials and plant uptime; pipeline constraints or plant outages can materially shift netbacks.

Long-term contracts and hedge programs are used to manage volatility, typically locking in price floors and basis protection for a material portion of production.