1. Strategic Snapshot

Colombian upstream enters 2026 operationally intact but competitively stratified. The sector’s weighted benchmark — 811,796 boepd, representing over 95% of national hydrocarbon output — generated USD 24.15/boe in adjusted EBITDA against a 3Q2025 Brent averaging USD 68.17/bbl, sustaining a cash floor of approximately USD 37/bbl at the country level. Those aggregate figures, however, obscure the dynamic that matters most to capital allocation: a USD 14/boe spread in EBITDA between the sector’s most efficient and least efficient private operators, driven not by reservoir quality but by logistics infrastructure access.

The table below places the sector’s core metrics in a single frame. What it cannot show is that those metrics aggregate operators with fundamentally different structural positions. SierraCol, evacuating through the OBC pipeline at USD 0.20/boe transport cost, operates at a cash floor near USD 35/bbl and generated USD 39.38/boe in adjusted EBITDA last quarter. Gran Tierra’s Colombian operations, carrying USD 24.91/boe in lifting and USD 1.61/boe in transport on maturing Putumayo fields, reached their cash breakeven at around USD 49/bbl. The Independents Benchmark — the five private operators excluding Ecopetrol — carries a weighted TOC of USD 33.10/boe and a cash floor near USD 40/bbl, which is where the capital allocation conversation actually begins.

Three events converging in the January–June 2026 window create a temporary information asymmetry worth tracking: the Catatumbo tax expiry (scheduled 31 December 2025, with USD 0.60–0.76/boe of cost relief for the affected operators), the Frontera infrastructure spin-off targeting close in 1H2026, and the Parex Capachos-LLA-74 production ramp that was already at approximately 49,300 boe/d in October 2025. Operators with early visibility into the post-spin-off pipeline access conditions in the northwest basin will be positioned to evaluate assets before that information is uniformly priced into the market.

The efficiency map positions each operator by two coordinates — lifting cost on the horizontal axis, adjusted EBITDA on the vertical — with bubble size encoding SBR production. Ecopetrol’s dominant bubble anchors the center of the chart without anchoring its top: its EBITDA sits below the benchmark line it statistically sets. SierraCol, by contrast, occupies the upper-left quadrant — low lifting, high EBITDA — a position that reflects pipeline infrastructure advantage as much as field efficiency. The chart below maps the events that could shift those positions over the next twelve months.

2. Executive Overview

3Q2025 performance in Colombian upstream does not reflect an abrupt operational deterioration — it reflects the visible manifestation of a mature structure facing a less accommodating price environment. The year-on-year Brent contraction exposed internal asymmetries that had remained partially obscured under higher-price cycles.

The defining characteristic of the quarter is the structural divergence between scale, logistics, and corporate cost load. Colombia operates on a largely amortized historical infrastructure, but with logistical bottlenecks that produce material gaps between operators with privileged pipeline access and those dependent on road transport. This difference is not cyclical — it is structural and recurring. The USD 11.52/boe gap between OBC pipeline access (SierraCol, USD 0.20/boe) and truck-dependent evacuation (Frontera, USD 11.72/boe) exceeds every other operational variable in the benchmark, including the entire range of lifting cost variation across the six operators.

Ecopetrol’s 78.5% statistical weight anchors the sector average, but not through margin leadership. Its competitive lifting cost — USD 12.18/boe — is absorbed into corporate overhead, and its adjusted EBITDA of USD 22.54/boe sits below the private-sector simple average. The Colombia Country benchmark, while useful for systemic context, is dominated by one company’s scale. The Independents Benchmark — five private operators, USD 33.10/boe weighted TOC, cash floor near USD 40/bbl — gives the cleaner read for capital allocation.

The sector’s royalty structure, when correctly restated on a gross production (SBR) basis, adds USD 8.75/boe of weighted state take. This figure is invisible under a superficial reading of most operator P&Ls — GeoPark delivered 4,612 barrels per day in kind to the ANH last quarter, a cost that never appeared as a cash line. Frontera’s PAP mechanism routes most of its royalty burden through in-kind volume deductions rather than income statement charges. This benchmark restores that visibility uniformly across all six operators, which is the precondition for any credible cross-operator cost comparison.

Against Guyana (EBITDA/boe near USD 45) and the Permian (approximately USD 35), Colombia’s weighted benchmark at USD 24.15/boe occupies a middle tier — competitive for operators with infrastructure access, structurally challenged for those without it. SierraCol at USD 39.38/boe and Parex at USD 29.96/boe are the exceptions that approach regional competitiveness. The question for a capital allocator is not whether Colombia is viable, but which Colombian assets carry the cost structure to compete in that range at current Brent — and which are sustained by a price environment that, if it moved to USD 60/bbl, would put two of the six operators below their cash breakeven.

This report covers the upstream Colombia operations of six selected operators for the quarter ended 30 September 2025. It excludes offshore, downstream, Ecuador and Canada operations, and mid-small operators. It does not constitute reservoir analysis, asset valuation, or investment advice.

3. Operational & Market Landscape

3.1 Production & Benchmark Composition

The benchmark is built on gross SBR production reported for 3Q2025, weighting adjusted EBITDA and unit costs by each operator’s relative share. The methodology avoids simple averages and captures the true architecture of Colombian upstream, where productive concentration introduces scale effects and explicit methodological asymmetries. The result is not a ranking — it is a structural map of the competitive system.

Colombia Upstream Benchmark · 3Q2025
Six operators · 3Q2025 · Gross SBR production basis
Operadora SBR (boepd) Lifting ($/boe) Transport ($/boe) Adj. EBITDA ($/boe) Benchmark Weight Primary Source
Ecopetrol (E&P Col) 637,500 $12.18/boe $3.36/boe $22.54/boe 78.5% 3T2025 Report — Tables 3, 7, 8, 10
SierraCol Energy 42,500 $19.20/boe $0.20/boe $39.38/boe 5.2% MDA 3Q2025 — Performance Overview pp. 3 & 7
Parex Resources 43,953 $15.36/boe $4.73/boe $29.96/boe 5.4% MDA+FS Q3 2025 — Operating Netback p.30
Frontera Energy 38,934 $14.02/boe $11.72/boe $27.52/boe 4.8% MDA Q3 2025 — Operating Netback Continuing Ops pp. 2 & 9
GeoPark (Colombia) 26,208 $12.50/boe $2.72/boe $29.42/boe 3.2% Results Supplement 3Q2025 p.4 + FS note 2 pp. 10-11
Gran Tierra (Colombia) 22,701 $24.91/boe $1.61/boe $17.57/boe 2.9% Form 10-Q SEC 3Q2025 — pp. 38 & 43
Lifting: Cash production costs excluding transport and G&A. | Ecopetrol transport: USD 3.36/boe from Table 10 of 3T2025 Report (Cenit pipeline tariff — best available proxy; not the direct E&P fee). | GeoPark transport: Selling expenses Colombia (USD 6.6M) ÷ gross production (26,208 bopd × 92 days) = USD 2.72/boe. Report publishes USD 3.30/boe on sold volume (post-RIK); corrected to gross basis for comparability. | Frontera: Lifting = production costs excl. energy (USD 8.46) + energy costs (USD 5.56) = USD 14.02/boe. | Parex: Production expense includes non-recurring USD 1.95/boe true-up on non-operated costs; normalized lifting ≈ USD 13.41/boe. | Gran Tierra: EBITDA on consolidated WI basis (Colombia + Ecuador + Canada) — explicit methodological asymmetry. | Source: Primary 3Q2025 filings · RAPIDS/EN/COL-UP/3Q25/001.

The table above reflects a benchmark structured around Ecopetrol’s gravitational pull: 78.5% of production weight, with transport, lifting, and EBITDA figures that anchor all aggregates. Removing Ecopetrol and reading the five private operators reveals a more diverse competitive landscape — one where logistics access, royalty burden, and asset lifecycle stage produce an EBITDA range of nearly USD 22/boe between the top and bottom of the group.

3.2 Cost Structure Decomposition

The chart below reads each operator’s realized price as a full bar, then breaks it into its constituent claims: royalties, lifting, transport, G&A, and the operating netback that remains. This is the cost structure as it actually operates — starting from what the barrel sells for, not from an abstract cost base. Reading it from left to right across the bars, the different economic architectures become immediately visible: SierraCol arrives at its netback through low costs across every component; Frontera consumes a disproportionate share in transport; GeoPark concedes the largest royalty slice in the group despite its efficient lifting.

The decomposition confirms that Parex’s relatively moderate netback — despite competitive lifting — reflects a higher transport burden and a royalty structure that, combined, consume nearly USD 20/boe before G&A. GeoPark’s position is the starkest case: USD 12.50/boe in lifting is the lowest field-level cost in the private peer group, yet an 18.8% royalty rate on gross production erases that advantage and leaves a netback comparable to operators with materially higher field costs.

The transport segment in the chart above also makes visible what the aggregate often obscures: the USD 11.52/boe gap between SierraCol’s OBC pipeline access (USD 0.20/boe) and Frontera’s truck-dependent evacuation (USD 11.72/boe) is not a contracting or operational variable — it is a physical infrastructure constraint. It does not compress when Brent moves. In a downside price scenario, that structural premium compounds: take-or-pay obligations remain fixed while realized prices decline, widening the effective cost gap in cash-margin terms precisely when it matters most.

3.3 Comparability Adjustments

Direct cost comparisons across six operators are not straightforward from primary filings. Each of the operators analyzed here reports under a different accounting architecture — some reflecting royalties as volume deductions, others as cash expense lines, others embedded in the realized price — and each has made legitimate commercial choices that affect which costs appear where on the income statement. The table below documents each structural difference and the normalization applied. Its purpose is not to criticize any individual reporting convention but to establish, explicitly and verifiably, the basis on which this benchmark treats cost figures as comparable.

Cost Comparability Matrix · Colombia Upstream 3Q2025
Reporting convention differences normalized across six operators · 3Q2025
Dimension Operator Reported Convention Benchmark Impact
Lifting Definition Frontera Energy Reports lifting as two lines: (1) Production costs excl. energy, net FX hedge = USD 8.46/boe; (2) Energy costs, net FX hedge = USD 5.56/boe. FX hedge (USD/COP contracts) is netted into each line separately. Benchmark lifting = USD 14.02/boe (sum of both lines). The energy split enables tracking field electricity exposure but does not alter the comparable total.
Transport — Data Source Ecopetrol (E&P Col) E&P-to-Cenit transport is an intragroup transfer eliminated in consolidation. Table 7 reports Lifting (USD 12.18) and Diluent (USD 4.76) separately. For comparability, diluent is deducted from realized price (Table 3: 64.30 → 59.54). Transport used is Table 10 'Cost per Barrel Transported' from Cenit segment: USD 3.36/boe. Table 10 USD 3.36 is the Cenit pipeline network unit cost, not the E&P direct fee. Best available public proxy. Included with explicit sourcing flag.
Royalties In-Kind (RIK) GeoPark (Colombia) Delivers ~4,612 bopd in kind directly to the ANH. 'Royalties paid in cash' is only USD 1.4M (residual). RIK volume is deducted from gross production before revenues are recognized. Lifting of USD 12.5/boe is computed per produced boe (gross basis), not on net volumes. This report restates all royalties — RIK + cash — on SBR basis for full comparability.
Royalties In-Kind (RIK) Frontera Energy PAP (high-price clause) payments delivered in kind in most blocks. Cash royalty line in the netback table is minimal — most state take is invisible in P&L. RIK restated here: 3,257 boed × USD 64.40 + cash 2,454k = USD 6.07/boe SBR. Without this restatement, Frontera's apparent cost structure understates state burden by ~USD 5.4/boe.
Wellhead Sales Parex Resources Explicitly reports 'Parex wellhead sales discount' = USD 3.91/bbl in 3Q25 as a negative line in its realized price table. The wellhead discount reduces visible realized price but eliminates the corresponding transport cost. The netback is economically equivalent — difference is presentation, not barrel economics.
Wellhead Sales GeoPark (Colombia) Sells ~24% of volume at wellhead. No explicit 'discount' line — reports lower gross revenue instead. Selling expenses Colombia = ~USD 6.6M. Report publishes USD 3.30/boe on sold volume (21,610 bopd, post-RIK); corrected to gross production basis: USD 6.6M ÷ (26,208 × 92 days) = USD 2.72/boe. Gross-basis correction is necessary: all other operators compute transport on pre-royalty production. Using USD 3.30 (post-RIK) would overstate GeoPark's relative transport cost by USD 0.58/boe. BP/CPO-5 deal (Aug-25) raised selling expenses from USD 3.5M (3Q24) to USD 7.2M (3Q25) as sales shifted from wellhead to export.
EBITDA Basis Gran Tierra (Colombia) US GAAP does not disaggregate Adj. EBITDA by country. USD 17.57/boe is consolidated WI EBITDA (Colombia + Ecuador + Canada) ÷ total WI production (42,685 boed). May over- or under-state Colombia-specific EBITDA depending on segment mix. This is the best metric available under US GAAP but is not strictly comparable with the IFRS Colombia-only figures of the other five operators.
Source: RAPIDS™ analysis on primary 3Q2025 MDA and FS. | RIK = Royalties In-Kind (physical barrels delivered to ANH). | PAP = High-price clause (Cláusula de Participación a Precios Altos — Frontera). | Wellhead = sale at wellhead with no transport charge to operator.

All four asymmetries share one characteristic: when correctly sourced from primary filings, the operating netback and EBITDA/boe already absorb their effects. The distortion lives in superficial reads of individual cost lines out of context. Frontera’s lifting is fully comparable once both energy and production cost components are summed. GeoPark’s USD 12.50/boe is the lowest field-level lifting in the benchmark — but computed on gross production before royalty deductions; the royalty restatement in §3.4 captures the full state burden separately. Parex’s wellhead discount is the accounting mirror of a transport cost that other operators show as a separate line: the economics are identical, the presentation differs.

3.4 Cost Structure & Capital Survival Thresholds

Two thresholds matter to a capital allocator in a Brent USD 68 environment. The first is the Total Operating Cost (TOC) — the cash cost per barrel including lifting, transport, royalties, and G&A. This is the survival floor: if realized price falls below TOC, the operator burns cash today. The second is the Total Production Cost (TPC) — TOC plus DD&A — the accounting breakeven below which equity is being eroded even if cash is positive. Royalties are restated on a gross production (SBR) basis across all operators, regardless of whether they were paid in kind, in cash, or embedded in price, ensuring the state’s take is fully reflected in the cost structure.

Cost Structure & Capital Survival Thresholds · Colombia Upstream 3Q2025
USD/boe · Six operators plus weighted benchmarks · 3Q2025
Operator Realized
Cash Costs → TOC
 Op. Netback
Non-Cash → TPC
Brent Floor
Lifting Transport Royalties G&A TOC DD&A TPC Cash Floor Acct. Floor
Colombia Country (6 operators)
Ecopetrol (E&P Col) 59.5 12.2 3.4 8.9 3.5 28.0 44.0 10.3ᵈ 38.2ᵈ ~37 ~47
SierraCol Energy 64.2 19.2 0.2 9.1 3.0 31.5 44.2 8.5ᵈ 40.0ᵈ ~35 ~44
Parex Resources 62.4 15.4 4.7 6.7 3.9 30.7 34.7 15.1ᵈ 45.8ᵈ ~36 ~52
Frontera Energy 59.7 14.0 11.7 6.1 4.7 36.5 34.0 20.0ᵈ 56.5ᵈ ~45 ~65
GeoPark (Colombia) 60.6 12.5 2.7 11.4 4.5 31.1 33.0 11.1ᵈ 42.2ᵈ ~39 ~50
Gran Tierra (Colombia) 56.7 24.9 1.6 8.7 2.0 37.3 30.2 26.1 63.4 ~49 ~75
Weighted Benchmarks
Colombia Benchmark 59.9 13.2 3.6 8.8 3.5 29.1 42.3 11.4 40.4 ~37 ~49
Independents Benchmark 61.2 16.8 4.5 8.1 3.7 33.1 36.0 15.4 48.5 ~40 ~55
ᵈ DD&A derived from EBITDA/FFO differential or geographic segment allocation — not published as a unitized line. Ecopetrol: realized price adjusted for diluent cost (64.30 − 4.76 = 59.54). Royalties at ANH regulatory rate ~15%. Op. Netback reconstructed from Tables 3, 7, 10. GeoPark: all per-boe figures corrected from sold-volume (21,610 bopd) to gross-production basis (26,208 bopd). Frontera: DD&A not disaggregated by geography; heavy-oil field proxy applied. Royalties restated on SBR basis: RIK volumes valued at each operator’s realized price; cash royalties scaled to SBR denominator. Source: Primary 3Q2025 filings · RAPIDS/EN/COL-UP/3Q25/001.

The table above is the reference document for this section. The chart below maps each operator’s operating netback against its TOC (cash floor), making the margin gap immediately visible. Operators to the left of the sector average realized price line are selling below the sector mean; those whose TOC approaches their netback carry the thinnest cash buffer against a price correction.

The chart shows three operators — SierraCol, Ecopetrol, and Parex — with netbacks materially above their TOC; their cash margin bands are wide and visibly separated from the survival floor. Frontera and Gran Tierra Colombia operate with netbacks that sit close to their TOC, leaving limited buffer. At a realized price of USD 49/boe rather than USD 59.90, Gran Tierra’s Colombian netback would be negative — a scenario that is not remote at Brent USD 55–60 given the typical Colombia discount to Brent.

The Colombia Country benchmark carries a weighted TOC of USD 29.07/boe — a figure shaped by Ecopetrol’s efficient lifting at 78.5% of production weight. The Independents Benchmark, at USD 33.10/boe weighted TOC, reflects the structural costs faced by private operators without that scale advantage. The dispersion in individual cash floors — from approximately USD 35/bbl for SierraCol to USD 49/bbl for Gran Tierra Colombia — is not a function of operator quality but of asset lifecycle stage, logistics access, and the royalty burden, which ranges from 8% to nearly 19% of SBR-equivalent production across the group. Those three variables are visible in the decomposition chart above; they are the structural reality that scenario analysis must price.

4. Market Actor Intelligence

Colombian upstream concentrates control among a small number of actors whose strategic positions are structurally distinct. Ecopetrol anchors the sector by scale and regulates the infrastructure backbone through Cenit. The private operators — SierraCol, Parex, Frontera, GeoPark, and Gran Tierra — hold differentiated positions across the Llanos, VMM, and Putumayo basins, each navigating a different combination of logistics access, contractual structure, and asset lifecycle. Two regulatory actors, the ANH and Ecopetrol’s infrastructure segment, shape the conditions under which all private operators compete for evacuation capacity and block access.

Market Actor Intelligence · Upstream Colombia 3Q2025
Active operators · Key basins · Strategic position 3Q2025
Operadora Type Key Basins 3Q25 Distinguishing Position
Ecopetrol (E y P) State NOC Llanos, VMM, Foothills, Coast 78.5% of SBR benchmark. Authorized Coveñas FSRU for LNG.
SierraCol Energy Private – PE Caño Limón, La Cira Infantas Efficiency frontier. OGMP 2.0 Level 5. 2028 bond tender offer.
Parex Resources Private – TSX LLA-34, LLA-74, Llanos Sur, VMM Capachos + LLA-74 ramp. Net Debt/Adj. EBITDA: 0.46x.
Frontera Energy Private – TSX Llanos (Quifa, CPE-6), Magdalena Infrastructure spin-off target 1H2026. Terminated P-135 Take-or-Pay.
GeoPark (Colombia) Private – NYSE LLA-34 (JV Parex), Putumayo 17% YoY production decline. New BP CPO-5 contract Aug-25.
Gran Tierra (Colombia) Private – NYSE/TSX Midas (Acordionero), Chaza, Suroriente Colombia prod. –23% YoY. Canada expansion (i3). Highest lifting in benchmark.
ANH Regulatory Nacional Concession authority. Active committed work programs.
Ecopetrol (Infraestr.) State NOC Colombia Pipeline (ODC), OBC Controls strategic pipeline evacuation infrastructure.
Note: This section is descriptive. Actor identification does not imply relationship recommendation. | Source: Public 3Q2025 reports and corporate announcements.

The positioning data in the table above reveals two patterns that are not obvious from production figures alone. The first is the divergence between volume and strategic agency: Ecopetrol produces 78.5% of the benchmark’s SBR but holds a different kind of influence than the private operators — one exercised through infrastructure control and regulatory access rather than through operational nimbleness. The second is the concentration of reconfiguration activity among mid-sized private operators: three of the five private operators have active strategic events — a spin-off, a production ramp, and a portfolio exit — that will alter their competitive position materially by the end of 2026.

5. Signal Intelligence & Pattern Recognition

The signals identified below are qualified by observable evidence from primary filings, not by opinion. They are categorized by type and direction — whether they represent structural features that will persist, emerging dynamics that could change the competitive map, or regulatory events with defined timelines. None should be read as investment recommendations; they are the raw material for scenario construction.

Signal Intelligence and Pattern Recognition · Colombia Upstream 3Q2025
Qualified signals by type, evidence, and direction · Colombia Upstream 3Q2025
Signal Type Signal Source / Evidence Intensity Direction
Emerging Un-arbitraged pipeline vs. truck logistics gap SierraCol USD 0.20 vs. Frontera USD 11.72 (reportes primarios 3Q25) High ↑ Growing asymmetry
Structural Ecopetrol as statistical anchor of benchmark 78.5% of SBR production; EBITDA below private-sector average High → Persistent
Emerging Frontera Infrastructure Spin-off (1H2026) MDA 3Q25: target close 1H2026; transaction in progress Medium ↑ Potential catalyst
Regulatory Catatumbo Tax Expiry (31-Dec-2025) SierraCol USD 0.60/boe; Frontera USD 2.4M; Temporary Law 2361/2024 Medium ↓ Relief expected 2026
Watch Gran Tierra Colombia Production Decline WI Colombia –23% YoY (22,701 vs. 29,328 boepd) Medium ↓ Accelerating decline
Emerging GeoPark: contractual and portfolio reconfiguration New BP CPO-5 contract Aug-25; LLA-32/Platanillo divestiture Low → Evolving
Structural 2025 Rainy Season: operational transport impact Reported by GeoPark, Frontera; Ecopetrol 2.15 MMbbl deferred Medium → Q3 impact absorbed
Emerging Parex Post-Drilling Ramp (Capachos + LLA-74) Oct-25: production ~49,300 boe/d vs. 43,953 in 3Q25 High ↑ 4Q25/2026 momentum
Source: RAPIDS™ validation against primary 3Q2025 filings. Intensity: High/Medium/Low based on observable evidence.

Of the signals catalogued above, the most consequential is the temporal coincidence of three reconfiguration events in the first half of 2026. The Catatumbo tax expiry scheduled for 31 December 2025 will release USD 0.60–0.76/boe of cost burden from SierraCol and Frontera simultaneously. The Frontera infrastructure spin-off — targeting close in 1H2026 — could alter pipeline capacity access conditions in the northwest Llanos basin in ways that are difficult to price before the transaction structure is public. And Parex’s Capachos-LLA-74 ramp, already at approximately 49,300 boe/d in October 2025, adds a volume-driven unit cost dilution effect entering 4Q25. The overlap of these three dynamics creates a window in which asset and capacity evaluations conducted before mid-2026 will reflect structurally different cost assumptions than evaluations conducted after.

6. Scenario Architecture

These are scenario constructs, not forecasts. Cost structures are held at 3Q2025 levels; the only variable modelled is Brent price sensitivity at approximately USD 0.65 EBITDA/boe per USD 1/bbl of Brent movement. The chart below plots the resulting benchmark EBITDA across six price environments.

At base case Brent of USD 68–72, the sector operates as observed in 3Q2025: the weighted benchmark in the USD 23–25/boe EBITDA range, pipeline-advantaged operators sustaining above-average margins, and the OBC-to-truck cost gap producing no observable narrowing. The Catatumbo tax, expiring on 31 December 2025, has already begun its transition out of the cost structure for SierraCol and Frontera — a regulatory tailwind that does not require a Brent move to materialize.

The upside case at USD 75–85 pushes the weighted EBITDA above USD 29/boe and introduces compounding effects: the post-Capachos production ramp dilutes Parex’s unit costs further, and the Frontera infrastructure spin-off, if completed in 1H2026, would restructure pipeline access economics in the northwest Llanos basin with consequences that are difficult to model before the transaction terms are public.

The downside case is where operator differentiation becomes most consequential. At Brent of USD 55–60, the weighted benchmark falls to USD 14–18/boe and Gran Tierra Colombia’s Colombian operations move into cash-negative territory. Frontera’s position is shaped less by lifting efficiency than by its take-or-pay contractual obligations on transport: those costs do not compress with price, which means netback compression at Frontera in a downside scenario is amplified relative to operators with more flexible logistics. Operators selling at the wellhead, or holding optionality over evacuation mode, carry a structural advantage under those conditions.

A material price resurgence beyond USD 95 would narrow the gap between Colombia and Guyana in EBITDA terms. It would not close it. The structural cost difference reflects asset position, contract architecture, and infrastructure access — none of which are price-cycle variables. At that Brent level, the relevant question shifts from sector survival to comparative capital deployment efficiency: which Colombian assets justify incremental investment against alternatives available at equivalent price assumptions.

7. Strategic Implications

7.1 For Service Companies

Ecopetrol’s 78.5% SBR concentration defines a services market with one dominant customer operating under capex and prioritization parameters that do not always reflect private-sector efficiency dynamics. The most active drilling in 3Q25 was concentrated in the independents: SierraCol (26 wells + 25 workovers in Caño Limón and La Cira Infantas), Parex (Capachos-LLA-74 ramp, development wells), and Frontera (Quifa-CPE-6 optimization). Margin compression under Brent USD 68 introduces visible pressure on contracting cycles and day rates in development drilling, where competition for rig windows intensifies when prices justify activity but don’t allow slack in service costs.

7.2 For Financial Institutions

The EBITDA/boe dispersion between SierraCol (USD 39.38) and Gran Tierra (USD 17.57) — a USD 21.81/boe differential between operators of comparable volume — signals that logistics infrastructure access is today a primary determinant of Colombian upstream asset valuation. Leverage structure diverges materially: SierraCol (1.1x Net Debt/EBITDA) with an active tender offer on its 2028 bonds; Parex (0.46x Total Funded Debt/Adj. EBITDA, USD 240M revolving credit); and Gran Tierra (total debt USD 762M, 9.50% Senior Notes 2029, with 25% of principal subject to mandatory call in October 2026). Gran Tierra’s 2026 partial maturity is the nearest observable refinancing pressure in the analyzed universe.

7.3 For Strategic Corporates

3Q25 presents a simultaneous evaluation window across three asset reconfiguration dynamics: the Frontera spin-off process (Colombia infrastructure, target close 1H2026), GeoPark’s Ecuador exit (Perico and Espejo blocks acquired by Gran Tierra, expected close 4Q25), and Gran Tierra’s Colombia position reduction. None of these movements constitutes an entry opportunity per se — they are portfolio repositioning signals that could alter the control map of infrastructure assets and exploration blocks over the 2026–2027 horizon, with secondary effects on pipeline capacity access conditions in specific basins.

7.4 International Competitive Position

Colombia’s position in the global capital competition for upstream investment is best understood not as a country bet but as an operator-selection exercise. The chart below places each Colombian operator’s adjusted EBITDA/boe alongside Guyana and the Permian Basin as reference benchmarks. The distribution it reveals is not uniform — SierraCol competes at Permian-equivalent returns, while Gran Tierra Colombia operates at a level that invites questions about capital deployment priorities when alternatives are priced at USD 35–45/boe.

Colombia competes for upstream capital on a risk-return profile that is neither straightforwardly attractive nor clearly uncompetitive — it occupies the middle of a distribution where the tails are held by Guyana and the challenged frontier markets. The USD 20.85/boe gap between the Colombia Country benchmark and Guyana is real, but it aggregates SierraCol’s USD 39.38/boe — above the Permian reference — with Gran Tierra Colombia’s USD 17.57/boe, which represents a materially different investment proposition. The gap that matters is not between Colombia and Guyana; it is between the two ends of the Colombian operator spectrum.

The structural underperformance of the country benchmark concentrates in two places: Ecopetrol’s statistical weight, which anchors the average downward while operating below the private-sector mean, and the logistics premium carried by operators without preferential pipeline access. Neither of these factors is likely to change meaningfully in the near term. The next competitive moves in Colombian upstream will come not from reserve discoveries or production growth, but from infrastructure reordering — the Frontera spin-off, pipeline access negotiations, and the fiscal review of upstream terms — and from continued corporate portfolio rationalization among operators who find their Colombian cost structure difficult to justify against alternatives. The economic architecture of the sector is well-mapped. What changes over the next eighteen months is who holds access to its most efficient channels.

8. Intelligence Gaps & Limitations

Four categories of limitation affect the precision of this analysis and should be understood before using the figures for specific decisions.

The most material constraint is the Gran Tierra EBITDA figure. US GAAP does not disaggregate adjusted EBITDA by country, so the USD 17.57/boe figure used in the Colombia Country benchmark is a consolidated WI EBITDA across Colombia, Ecuador, and Canada. The Colombia-only Operating Netback of USD 30.17/boe, derived directly from Form 10-Q pages 38 and 43, offers a closer approximation to the Colombia-specific reality, but it is not strictly comparable with the IFRS segment figures of the other five operators.

The second category concerns DD&A quality. The TPC column in §3.5 required deriving or estimating depreciation, depletion, and amortization for four of six operators, since unitized DD&A by country is not a standard disclosure. Gran Tierra Colombia and GeoPark have direct primary source data. Parex DD&A is derived from the EBITDA-to-FFO differential. SierraCol’s is a cross-reference estimate. Ecopetrol’s is derived from Table 8 of its results report weighted by a Colombia production fraction. Frontera’s is a heavy-oil field proxy. All four carry the quality flag ᵈ in the table. The TPC figures should be read as directional, not as precise accounting figures.

Two Parex items warrant specific disclosure: the 3Q2025 lifting figure of USD 15.36/boe includes a non-recurring USD 1.95/boe true-up on non-operated costs from prior periods, which means the normalized recurring figure is closer to USD 13.41/boe; and the February 2026 Investor Presentation production figure of approximately 48,606 boe/d reflects the post-Capachos ramp through 4Q2025, not the 3Q2025 production of 43,953 boe/d used in this benchmark.

The international reference figures — USD 45/boe for Guyana and USD 35/boe for the Permian — are secondary-source estimates used for directional framing only. They have not been validated against primary filings and should not be treated as audited data points. The analysis universe excludes mid-small operators and the Pacific and Caribbean Continental basins; the benchmark is highly representative by volume but partial by operator diversity. Finally, the 2025 rainy season impact on lifting costs was not uniformly disaggregated across all operators, introducing noise in period-on-period lifting comparisons that is not fully controllable from publicly available data.

9. References

Primary Sources

RAPIDS™ Framework Documents

Secondary and Contextual Sources

RAPIDS™ Governance Note · , Reference ID: RAPIDS/SCOUT-COL-UP-3Q25 · , Version: v1.0.8 · , Classification: Internal · , Date: 24 February 2026 · , Author: JR Engineering Company,

This Scouting Report is produced under the RAPIDS™ intelligence framework (Annex F). It is a non-prescriptive strategic intelligence exposure product. It does not constitute investment advice, technical recommendation, or due diligence. Scenarios are exploratory constructs and SHALL NOT be interpreted as forecasts.Reproduction or redistribution without prior written authorization is prohibited.

File Name (Canonical): RAPIDS_SCOUT_COL_UP_3Q25_v1_0_8_final.Rmd

Version History

Version History · RAPIDS/SCOUT-COL-UP-3Q25
Modification log and current status by version.
Version Date Author Status Description
v1.0.0 18 Feb 2026 JR Engineering Co. Archived Initial release. Six-operator upstream Colombia benchmark. Sections §1–9 complete. Ecopetrol and GeoPark transport marked NA in master data pending primary source resolution.
v1.0.1 19 Feb 2026 JR Engineering Co. Archived Transport cost resolution: Ecopetrol USD 3.36/boe from Table 10 (Cenit network unit cost); GeoPark USD 2.72/boe restated to gross production basis. Gran Tierra Colombia operating netback added to §3.5. Caption alignment standardized (left-aligned). USD notation applied consistently throughout.
v1.0.2 20 Feb 2026 JR Engineering Co. Archived §3.5 expanded: operating netback and full cycle breakeven for all six operators and weighted Colombia aggregate. Three new charts: comparative table, netback-vs-breakeven lollipop, minimum sustainable Brent. DD&A derived or estimated for Ecopetrol (Table 8, E&P allocation), SierraCol (proxy), Parex (EBITDA–FFO differential), Frontera (heavy-oil field proxy); GeoPark from FS Note 2. Quality flags ᵈ/ᵉ added to master table. §8 updated with DD&A flag disclosure.
v1.0.3 20 Feb 2026 JR Engineering Co. Archived Ecopetrol correction: Operating Netback restated to USD 44.00/boe via cash reconstruction from Tables 3, 7, and 10. TOC Ecopetrol revised to USD 34.07/boe. Methodology note added to §3.5 and §8.
v1.0.4 20 Feb 2026 JR Engineering Co. Archived Architectural consolidation: master tibble `dm` centralizes all operator indicators in Setup chunk; duplicate `netback_data` tibble removed from §3.5. Terminology standardized: Full Cycle Breakeven renamed Total Operating Cost (TOC) throughout, with explicit note that TOC excludes G&G, development capex, and debt service. All charts and tables reference `dm` directly.
v1.0.5 23 Feb 2026 JR Engineering Co. Archived Royalties unified on SBR basis across all six operators regardless of payment method (RIK, cash, or price-embedded). TOC/TPC architecture formalized: TOC = cash costs only; TPC = TOC + DD&A. Two weighted benchmarks added: Colombia Country (6 operators) and Independents (5 operators, ex-Ecopetrol). Diluent treatment consolidated into Ecopetrol realized price. Document translated to English throughout.
v1.0.6 24 Feb 2026 JR Engineering Co. Archived Complementary narrative integrated: §1 Strategic Snapshot expanded with capital allocation signal and structural ranking; §2 Executive Overview rewritten as continuous prose argument; §3.1–3.3 introductory paragraphs added; §7.4 regional framing strengthened. Chart subtitles cleaned to descriptive only; methodology moved to footers. DD&A column added to master cost table. Tab spanners restructured: Cash Costs → TOC / Non-Cash → TPC / Brent Floor. Chart heights increased across all visuals.
v1.0.7 24 Feb 2026 JR Engineering Co. Archived Full editorial revision to professional long-form standard. Bold eliminated from narrative body (zero instances pre-§9). Bullet lists converted to continuous prose throughout. Orphan subsections eliminated: §4.1 merged into §4; §5.1 header removed; §7.4 given introductory and closing text. Bridge paragraphs added between all consecutive visuals. §6 scenario blockquote replaced with integrated prose. §8 limitations converted from ten flagged bullets to four thematic paragraphs. USD notation standardized.
v1.0.8 24 Feb 2026 JR Engineering Co. Current Visual rationalization: (1) `costos-componente` redesigned as full revenue decomposition waterfall — each bar anchored to realized price, segmented by Royalties / Lifting / Transport / G&A / Op. Netback; (2) `brecha-logistica` removed — logistics argument absorbed into §3.2 post-chart text; (3) `netback-comparativo` simplified to two-point range chart (TOC open circle vs. netback solid circle), TPC removed (retained in master table), tier-color legend replaced with inline annotation; (4) `brent_minimo` removed — redundant with master table Cash Floor column and netback chart. Net: 2 charts removed, 89 lines reduced. Subsections renumbered §3.3→§3.2, §3.4→§3.3, §3.5→§3.4. References updated to APA 7th edition, full English. Version history updated to full English, v1.0.0–v1.0.8.
RAPIDS™ versioning policy: MAJOR.MINOR.PATCH. Data or section changes = MINOR increment. Typographic or aesthetic corrections = PATCH. | Parent document: RAPIDS/EN/COL-UP/3Q25/001 R1.0.