Titan Energy Business Model Canvas

Identify, evaluate, and acquire mineral leases and producing properties across the Appalachian Basin, which accounted for roughly 34% of U.S. dry natural gas production in 2023 (EIA). Negotiate lease terms, ROFRs, and JVs to consolidate core blocks while executing disciplined divestitures of non-core assets to optimize capital allocation. Maintain a dynamic inventory of drillable locations tied to cash-flow and reinvestment metrics.

Geology, geophysics, and petrophysics are used to high‑grade targets and optimize well design, reducing drilling variance and improving success rates in plays contributing to US oil output of ~12.5 million bpd in 2024. 3D models and reservoir simulations produce EUR estimates and type curves that underpin spacing and completion decisions. Integrating logs, core, and production data enables continuous model updates and aligns technical plans with capital allocation.

Contiguous leasehold in prospective Appalachian plays anchors development and taps a basin producing over 30 Bcf/d in 2024, improving pipeline access and scale economics. Clear title and favorable lease terms shorten permitting and raise NPV and schedule certainty versus fragmented holdings. Unitization and spacing rights boost EUR recovery per well, while surface use agreements enable efficient multi-well pad design and cost reductions.

Proved, probable and possible reserves form the collateral for borrowing base calculations and drive enterprise valuation, with lenders typically using PDP and PDNP schedules to set credit lines in 2024 market practice.

A robust drilling inventory supporting 5+ years of development underpins multi-year production growth and capital allocation flexibility.

Type curve EURs and well-level type curves inform investment pacing and sanction timing, with sensitivity to oil price and IRR thresholds.

Steep first-year declines (commonly 30–70%) followed by flatter tail PDP profiles stabilize near-term cash flows and reserve monetization planning.

Consistent oil, gas and NGL deliveries are backed by firm takeaway commitments, enabling buyers to secure volumes against market volatility. Redundant midstream paths cut curtailment risk, supporting proven operating uptime. With US production at ~12.5 million b/d crude, ~101 Bcf/d gas and ~5.0 million b/d NGLs in 2024 (EIA), buyers gain predictable volumes for planning.

Lean operations and optimized completions drive breakevens down to roughly $30–45/bbl (industry 2024 range), while pad drilling and scale purchasing cut per‑unit development costs by 15–25%. Low LOE near $6–9/boe in 2024 sustains margins across cycles, enabling customers to access competitive pricing structures and volume discounts.

Named commercial leads manage 150+ refiner, utility, and marketer accounts, providing rapid responses (median 90 minutes) to scheduling and quality queries, conducting quarterly reviews that cut delivery variance ~12% and optimize contract KPIs, and supporting a 2024 renewal rate of ~82% with upsell-driven revenue growth of ~18% year-over-year.

MSAs and term contracts align volume, quality and delivery by locking specifications and forecasts; in 2024 industry practice MSAs typically cover the majority of dispatched capacity. Take-or-pay or minimum volume commitments (commonly ~80% MVC) stabilize cashflows and both parties’ planning. Clear remedies and KPI thresholds (eg 99.5% on-time delivery) reduce disputes, while co-terminus renewals simplify portfolio management and rollover risk.

Negotiate bilateral crude and gas contracts indexed to Brent (2024 average ~$85/bbl) with volume flex clauses; target long-term deals (3–7 years) covering 60–80% of plant output. Align delivery points to plant-gate or major hubs to minimize trucking/terminal fees and demurrage. Maintain 24/7 scheduling desks for nominations and imbalance management. Build strategic ties with anchor buyers among refiners/utilities leveraging US refinery capacity ~18.9 mb/d to secure offtake.

Leverage third-party marketers and aggregators to reach diversified end markets (utilities, industry, retail) while tapping a global 3PL market that exceeded $1.2 trillion in 2023.

Balance smaller volumes and variable qualities via pooled lots and quality-tier pricing; pooled marketing in commodity chains has produced ~3–5% uplift in realizations in recent years.

Outsource logistics in peak periods (adoption rose toward 60% of firms in 2023) to flex capacity and smooth working capital needs.

Regional and national refineries buying Appalachian crude and condensate prioritize stable quality and on-time delivery to protect margins and meet product specs. In 2024 U.S. refinery utilization averaged about 92.4% (EIA), driving demand for term supply with flexibility to balance throughput and feedstock swings. Refineries seek reliable partners to ensure steady barrels and help meet throughput plans and product slate commitments.

Local distribution companies and gas-fired plants require firm gas delivery; EIA data show natural gas supplied about 40% of U.S. power generation in 2024. LDCs operate at distribution pressures of roughly 0.25–60 psi, while plants need higher pipeline pressures (up to ~600 psi) and target >99.99% reliability. Contracts commonly use index-linked pricing (Henry Hub/ NBP) with MVCs and value transparent scheduling support.

Drilling and completion capex centers on major outlays for rigs (US onshore dayrates broadly $20k–60k in 2024), frac crews and materials with full-cycle completion costs commonly $3–8M per lateral well; pad economics hinge on design efficiency and lateral ft cost typically $300–900/ft. Supply chain terms and lead times materially shift cashflow and unit cost, and continuous-improvement programs target 10–20% lower $/ft.

Daily LOE covers well running costs—compression, produced water handling, and chemicals—totaling roughly $9/BOE industry-wide in 2024; tight LOE control directly protects EBITDA margins. Automation and remote monitoring cut emergency callouts and equipment failures by up to 35% (McKinsey, 2024), while targeted preventive maintenance lowers downtime 20–30%, boosting uptime and reducing per‑BOE operating spend.

Revenue from crude and condensate sales to refineries/marketers is benchmarked to Brent/WTI indices with differentials; Brent averaged about 86 USD/bbl in 2024, shaping topline realization. Quality adjustments for API gravity and sulfur commonly alter netbacks by roughly 1–5 USD/bbl. A 40–70% term versus spot sales mix is used to balance cashflow stability and upside from spot price rallies.

Titan sells natural gas at regional hubs and plant gates to utilities and generators, capturing volumes into a market where U.S. dry gas production averaged about 100 Bcf/d in 2024 and Henry Hub averaged roughly $3.00/MMBtu; contracts are index-linked and show clear seasonal winter peaks. Basis and transport optimization typically lift realizations, while a mix of firm contracts provides predictable cash flow.