#Jack St Malo Field Economics Report

Development: Jack St Malo (subsea15) · Lease: 6 leases (G17015, G17016, G18745, G18753, G20394, G21245) · First oil: 2014-12-01 · Discount rate: 10% annual

Data window: 2000-09 -> 2026-04

#Summary

On public BSEE production + cost data, Jack St Malo is NPV-negative at 10% life-to-date: terminal cumulative NPV $-804.5 M.

• 438.7 MMbbl oil produced from 22 producing wells (73 total wellbores), generating $27,891 M gross revenue.
• A high-capex, deepwater signature: $12,850 M of one-time D&C + facilities capital is the dominant driver of the NPV.
• The cumulative-NPV path bottomed at $-3,154.7 M in 2014 and has since recovered $+2,350.2 M as production paid back capital.

Generated from public BSEE OGOR-A production and drilling/WAR records run through a monthly cashflow + trimmed-discount model (build_field_npv_timeline), covering field life through the latest available BSEE OGOR-A month. The NPV timeline below is an additive presentation layer over that model; it does not alter the computed final NPV.

#NPV Timeline

Cumulative discounted NPV evolution over field life, with critical well operations annotated. Terminal cumulative NPV = $-804.5 M.

Cumulative NPV path (by year): █▇▇▇▇▇▇▇▆▆▆▆▆▅▁▁▁▁▂▃▃▄▄▅▅▆▆ start $-75M → trough $-3,155M (2014) → latest $-804M

#Critical Operations Detail

Operations are derived deterministically from BSEE Well Activity Reports (bin/war/) and OGOR-A first-production dates (BSEE OGOR-A pickled .bin DataFrames (zip archives absent in checkout)). Activity codes: DRL=drilling, COM=completion, WO=workover, REC=recompletion, ST=sidetrack; re-entries detected via API completion-suffix changes on a shared wellbore. Markers are annotations only and do not feed the cashflow model.

#Well-Level NPV Stackup

Field terminal NPV decomposed into per-well contributions that sum exactly to the field total. Field NPV = $-804.5 M; sum of per-well net NPV = $-804.5 M (residual $-0.0000).

Reading the ranking. Under production-pro-rata allocation, the largest producer absorbs the most shared capital — so the highest-output well can show the *most negative* net NPV. The Gross well NPV column reflects standalone operating performance; the Net well NPV column reflects each well's share of the fully-loaded field (which is NPV-negative overall, so every well's net is negative). Bottom line: a negative *net* NPV here is an allocation outcome on an NPV-negative field, not a verdict on the well's own performance — read the Gross well NPV column for standalone results.

Per-well net NPV (signed bars; █ = value-additive, ▓ = drag):

PS003       -89.1 M  ▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓
PS005       -80.3 M  ▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓▓
PS001       -50.4 M  ▓▓▓▓▓▓▓▓▓▓▓▓▓▓
PS007       -43.8 M  ▓▓▓▓▓▓▓▓▓▓▓▓
PS004       -43.5 M  ▓▓▓▓▓▓▓▓▓▓▓▓
PN001       -43.1 M  ▓▓▓▓▓▓▓▓▓▓▓▓
PS004       -41.9 M  ▓▓▓▓▓▓▓▓▓▓▓
PN002       -37.9 M  ▓▓▓▓▓▓▓▓▓▓
PS006       -37.0 M  ▓▓▓▓▓▓▓▓▓▓
PS005       -36.9 M  ▓▓▓▓▓▓▓▓▓▓
PS002       -36.0 M  ▓▓▓▓▓▓▓▓▓▓
PS007       -34.4 M  ▓▓▓▓▓▓▓▓▓
PS003       -30.2 M  ▓▓▓▓▓▓▓▓
PN007       -28.1 M  ▓▓▓▓▓▓▓▓
PN005       -26.9 M  ▓▓▓▓▓▓▓
PS008       -26.6 M  ▓▓▓▓▓▓▓
PS002       -22.0 M  ▓▓▓▓▓▓
PS008       -19.7 M  ▓▓▓▓▓
PS009       -19.7 M  ▓▓▓▓▓
PS011       -18.8 M  ▓▓▓▓▓
PS006       -16.8 M  ▓▓▓▓▓
PS001       -16.4 M  ▓▓▓▓
PS012        -4.1 M  ▓
PS014        -0.9 M  ▓

Interactive NPV waterfalls → — two views: an over-time NPV bridge (each year's change in cumulative NPV, with the biggest swings annotated by the events that drove them) and this per-well stackup (each well's net NPV stepping to the field total). Hover any bar for detail. Rebuild with uv run --with plotly python scripts/lower_tertiary/build_npv_stackup_chart.py --dev "Jack St Malo".

By block (OGOR AREA_CODE_BLOCK_NUM):

Block scope: 6 OGOR blocks present; per-block oil shares shown. Per-block NPV would require a block-level cost split (gap: shared facilities/D&C are field-level, not block-tagged).

The stackup covers the 22 producing wells. The field's 73 total wellbores also include appraisal and sidetrack/re-drill bores; their drilling & completion capital is part of the shared cost allocated pro-rata (it is not attributed to a single producer).

Allocation assumption. Shared field costs (facilities, fixed opex, host) and the drilling/completion cost of non-producing bores (appraisal/sidetrack wells with no production to stand against) are pooled and allocated to the producing wells pro-rata by each well's share of total field oil production. Each producing well's own revenue, royalty, variable opex, and directly-resolvable D&C are attributed to it. Per-well NPVs sum to the field NPV.

#Well Geometry (3D)

Interactive 3D well-path views — minimum-curvature trajectories from BSEE directional surveys, rendered with Plotly and Three.js — are in development for this field. When verified they will live at:

• reports/bsee/jack_st_malo_well_path_plotly.html
• reports/bsee/jack_st_malo_well_path_threejs.html

They are intentionally not linked yet: the geometry render must first be confirmed to cover the same lease-resolved producers shown in the NPV stackup above (same APIs, same field), so the economics and the well paths never describe different wells.

#Financial Summary

Life-to-date field economics on public BSEE data (2000-09 -> 2026-04). D&C and facilities are one-time capital already incurred; revenue, royalty and opex accrue with production.

Return metric: MIRR is the return measure used for these developments, not IRR. Deepwater Lower-Tertiary cashflows are heavily front-loaded (large D&C + facilities outflows, then a long production tail), so the net-cashflow sign changes more than once and the IRR polynomial can have multiple — or no — real roots; MIRR (single reinvestment/finance rate at the 10% discount rate) is well-defined and unambiguous. NPV @ 10% remains the primary value metric.

Source-of-record: public BSEE OGOR-A production, drilling and WAR records, run through the field cashflow model.

#Price Sensitivity

NPV is linear in the oil price deck: each +$1/bbl on the realized oil price moves field NPV by $+52.3 M. Life-to-date NPV reaches zero at a flat-equivalent realized WTI of $79/bbl, versus the actual volume-weighted realized $64/bbl over the window.

Exact, not sampled: NPV is affine in a uniform price multiplier (revenue and royalty scale with price; variable/fixed opex, D&C, facilities and discounting do not), so one base run plus one scaled run define the entire line. 'Flat-equivalent realized WTI' is the volume-weighted average price; the underlying deck is the historical monthly WTI path.

#Next Steps

• Get a tailored analysis. Want this for your own assets — a different field, a custom price deck, sensitivities, or a partner-level working-interest view? AceEngineer builds traceable field economics from public data. Contact vamsee.achanta@aceengineer.com to scope an engagement.
• Explore the full play. Jack St Malo is one of 10 Lower Tertiary (Wilcox) fields covered by this model. Regenerate any field with --dev <Field>, or ask for the portfolio economics report for the whole-play NPV view (Jack/St. Malo, Stones, Big Foot, Anchor, Cascade/Chinook, and more).
• See the methodology. Every number here traces to public BSEE OGOR-A production + drilling/WAR records run through a transparent cashflow model — no black box. The pipeline (BSEE public data → parsed .bin → NPV) is reproducible end-to-end.
• Run it yourself. Refresh the data and regenerate this report:

  # 1. refresh the latest BSEE OGOR-A production (2025 + current year)
  uv run python scripts/refresh_bsee_ogor_recent.py
  # 2. regenerate this report (latest window is the default;
  #    leases are auto-derived for the field)
  uv run python scripts/lower_tertiary/generate_field_economics_report.py --dev "Jack St Malo"