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Net debt ~$400M, Net Debt/EBITDA ~1.5x; 20% rate rise adds ~$8M annual interest cost, manageable given ~$200M operating cash flow

Floating-rate exposure on ~$300M revolving credit; 20% rate increase (~100-120bps) raises annual interest burden by ~$6-8M, ~3-4% EBITDA impact

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

Strait of Magellan/Andean border crossings for Chile-Argentina logistics; Caribbean shipping lanes for Colombian crude export routes

High exposure: Colombian peso (primary revenue ~60%), Chilean peso, and Argentine peso—all subject to devaluation; ARS risk most acute given inflation >100%

Operations in Colombia (~60% revenue), Chile, Brazil, Argentina, Ecuador; COP and ARS devaluation represent largest sovereign currency translation risks

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.

Oilfield services concentrated in Schlumberger/Halliburton/Baker Hughes; no single vendor likely >30% but switching costs moderate in frontier basins

Upstream E&P—physically asset-intensive; cloud dependency minimal, operations run on proprietary seismic/reservoir software with on-premise or local hosting

Midstream infrastructure (pipelines, processing) in Colombia; physical asset model, not cloud-dependent; 30-day cloud termination causes data disruption, not operational halt

Low API coupling risk; uses industry-standard reservoir simulation software (Petrel, Eclipse); no proprietary third-party API lock-in identified

Very low Howey Test risk; revenue from hydrocarbon extraction and sale—commodity transaction, not an investment contract or securities offering

High

Minimal GDPR/CCPA exposure; B2B commodity producer with limited consumer personal data processing; primary compliance risk is local Colombian and Chilean data regulations

Low antitrust risk; sub-5% market share in all operating countries; operates in competitive fragmented upstream sectors alongside majors and NOCs

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

~100% transactional—spot and term crude oil/gas sales; no subscription or retainer revenue; multi-year offtake agreements provide partial volume visibility

Hydrocarbon production and sale at market-linked prices; revenue directly tied to production volumes and Brent/WTI-indexed crude pricing

Price-taker model tied to Brent benchmark minus quality/transport differentials; no pricing power; hedging program covers ~30-40% of production providing partial floor

Very low—commodity price-taker; differentiation via low-cost production (operating cost ~$8-10/boe) rather than pricing power

Gross margin ~55-65% at $70-80/bbl Brent; highly sensitive to oil price; breakeven ~$30-35/bbl all-in

No free-rider leakage; physical commodity with clear title transfer; offtake buyers are contracted refiners and traders with no free consumption pathway

Revenue growth is sublinear to headcount; doubling production via existing fields requires minimal incremental staff; drilling contractors are variable external cost

Incremental production growth via infill drilling ~$8-12/boe finding cost; marginal cost of growth is capital-intensive but not headcount-intensive

Not applicable—not a franchise model; however, PSC/joint-venture compliance with ANH (Colombia) and ENAP (Chile) presents analogous regulatory drift risk

At 10x scale, customer acquisition cost remains near zero; crude buyers are abundant globally; bottleneck is production capacity and pipeline access, not sales

No network effects present; upstream E&P is a linear production model; value does not increase with additional users or participants

AI displacement risk low for core extraction; AI/ML applicable to seismic interpretation and reservoir modeling—could reduce exploration cost 10-15% over 5 years

Tier 3 recession resistance; oil demand partially inelastic but price collapse in recessions (2020: Brent -50%) severely compresses margins and cash flow

National oil companies and international trading houses (Trafigura, Vitol, Ecopetrol) purchasing crude offtake under term and spot contracts

Regional refineries in Latin America and Caribbean; concentration risk moderate—Ecopetrol and state refiners may represent 30-40% of Colombian offtake

["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)

~$250-300M annual capex; majority allocated to development drilling in existing fields (Llanos Basin); limited reallocation toward energy transition or future-state infrastructure