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Marcel Chin-A-Lien — Global Petroleum & Energy Advisor – 21 february 2026

Golden Lane Investments Advisory Group

Guyana Gas-to-Shore (GtS)

Domestic-first monetisation in an oil-dominant system — Wales and Berbice cases, with a transparent, source-anchored audit trail

Author: Marcel Chin-A-Lien  |  Affiliation: Petroleum & Energy Advisor  |  Date: 21 February 2026  |  No exports assumed Public sources only

Contents

1. Executive summary

2. Scope, definitions, and what is “verified”

3. Trusted public anchors (Government / Operator / IMF)

4. Method: turning anchored inputs into a domestic GtS model

5. Domestic architectures: Gas-to-Wales vs Gas-to-Berbice

6. Cumulative domestic gas consumption (TCF), 2027–2050

7. Oil recovery & NPV sensitivity to gas diversion

8. Decision gates and “what must be shown”

References

Author CV

1. Executive summary

Guyana’s Gas-to-Shore (GtS) should be evaluated as a domestic demand sink within an oil-dominant, pressure-managed deepwater development system.

ExxonMobil publicly states that gross recoverable resource in the Stabroek Block is estimated at nearly 11 billion oil-equivalent barrels.^[1] Partner communications and reporting indicate rapid ramp to roughly ~1.3 million bpd by 2030, with higher installed capacity potential.^[2] Reuters reporting from the Guyana Energy Conference quotes Exxon’s Guyana President on Uaru and Whiptail scaling output to around ~1.4 million bpd after Whiptail, with each project at ~250 kbpd.^[3]

Bottom line (domestic-first):

Wales-scale gas demand (power-dominant) is typically compatible with an oil-protective reservoir regime.

Berbice is a higher-upside industrial corridor concept, but becomes materially reservoir-sensitive at larger volumes (because domestic offtake competes with pressure maintenance).

The correct metric is not “gross BCFD produced,” but how much net sales gas can be diverted without eroding oil value.

2. Scope, definitions, and what is “verified”

This paper is intentionally conservative: it uses trusted public sources (Government of Guyana, ExxonMobil, partner disclosures, IMF, and Reuters reporting of official statements) and declares where subsurface behaviour is not publicly disclosed.

We do not present a single “true” Stabroek gas number; instead we publish a most probable case and a bandwidth with explicit causes (GOR evolution, reinjection requirement, cycling/recycling, facilities uptime).

Definitions (to avoid common confusion)

1. Fresh associated gas generated = oil rate × GOR (plus any non-associated gas if developed later).
2. Gross produced / handled gas = fresh gas + recycled gas returning after reinjection.
3. Net surface gas = gross gas minus fuel + flare/vent + processing/spec/shrink losses.
4. Domestic sales gas = gas delivered to power/industry, constrained by demand build-out and reinjection priority.

Note: Government reporting provides time-series charts for gas produced/injected/flared/fuel.

These are the correct baseline for auditing “what happened” operationally.^[4][5]

3. Trusted public anchors (Government / Operator / IMF)

3.1 Resource and production scale (Stabroek)

• Operator anchor: ExxonMobil states the Stabroek Block gross recoverable resource is estimated to be nearly 11 billion oil-equivalent barrels.^[1]
• Partner anchor: CNOOC’s “Strategy Preview” (22 Jan 2025) states 8 projects will be in operation by 2030, with total production expected to be 1.3 million bpd and capacity 1.7 million bpd (Stabroek).^[2]
• Public statement reporting: Reuters (18 Feb 2026) reports Exxon expects Uaru then Whiptail to lift output to ~1.15 mmbpd and then ~1.4 mmbpd once Whiptail is online (each ~250 kbpd).^[3]
• Government reinforcement: the Petroleum Management Programme “Discoveries” archive references additions to “almost 11 billion barrels of oil equivalent” in public announcements.^[6]

3.2 Official operational reporting for gas disposition

The Government of Guyana’s Petroleum Management Programme publishes charting and data pages covering gas produced and how gas is dispositioned (injected, flared, used as fuel). This reporting provides the proper audit baseline for any claims about “available gas” versus reinjection requirement.^[4][5]

3.3 Wales Gas-to-Energy (GtE) scope as officially described

The IMF’s 2025 Article IV consultation documentation describes the Gas-to-Energy project as transporting associated gas to shore for power generation, referencing a first phase supporting a 300 MW combined-cycle plant.^[7] The Office of the President (10 Nov 2022) also publicly frames the Wales development as a 300 MW combined-cycle power plant and an NGL plant at Wales under an EPC procurement process.^[8] DPI project updates (Oct 2025) describe accelerated construction (24/7 work schedule) and continued emphasis on power and industrialisation objectives.^[9]

3.4 Berbice pathway as publicly reported

Reuters reporting from Feb 2026 describes Exxon assessing the size of Stabroek gas resources and discussing a potential second gas pipeline concept toward Berbice, explicitly conditioned on industrial demand. The report also notes Longtail (~2030) as the first project expected to produce non-associated gas, potentially supporting such a concept.^[10]

4. Method: turning anchored inputs into a domestic GtS model

Where subsurface behaviour is not publicly disclosed, the model uses explicit bands. The objective is to keep the paper defensible under scrutiny: if a number is not anchored, it is presented as a scenario variable rather than a fact.

4.1 “Most probable” technical bands used

• System-average fresh GOR band: 800–1,500 scf/bbl (most probable ~1,100 scf/bbl). (Not published Stabroek-wide; used as explicit band.)
• Recycling intensity: recycled:fresh ratio 2.0–4.0 (most probable ~3.0). (Reservoir dependent; affects gross handled gas.)
• Surface losses: combined fuel + flare + processing/spec/shrink losses ~8–15% (most probable ~10%).

Why this matters: A high “gas production” peak can reflect recycled gas returning to producers. It does not automatically mean large volumes are available for domestic sales without an oil penalty. Any credible GtS assessment must separate fresh gas, gross handled gas, and net sales gas.

5. Domestic architectures: Gas-to-Wales vs Gas-to-Berbice

5.1 Case A — Gas-to-Wales (power-dominant)

Wales is the flagship domestic pathway, centred on a 300 MW combined-cycle plant and associated infrastructure, as described in IMF documentation and Government statements.^[7][8][9] Demand is primarily power-driven, with potential incremental industrial loads over time.

Wales domestic offtake profile (mmscfd)	Low	Most probable	High
2027–2029	50	60	100
2030–2035	150	200	300
2036–2045	200	225	300
2046–2050	100	150	250

5.2 Case B — Gas-to-Berbice (industrial corridor)

Berbice is treated as a second-stage domestic sink tied to industrial development. Reuters reporting indicates a Berbice pipeline concept is conditional on sufficient industrial demand, with future gas developments (including Longtail) potentially relevant to supply.^[10] This case can create more economic value per unit gas than power-only, but pushes the system closer to reinjection constraints.

Berbice domestic offtake profile (mmscfd)	Low	Most probable	High
2027–2029	0	0	0
2030–2035	100	150	250
2036–2045	250	400	600
2046–2050	150	250	400

6. Cumulative domestic gas consumption (TCF), 2027–2050

Conversion used: 1 mmscfd sustained for 1 year = 0.000365 TCF. Cumulative consumption is the sum across the four time buckets in Section 5.

Scenario (2027–2050)	Low (TCF)	Most probable (TCF)	High (TCF)
Wales-only	1.30	1.60	2.32
Berbice-only	1.41	2.24	3.47
Combined Wales + Berbice	2.70	3.84	5.79

These values are domestic demand pulls under a no-export policy. They are not claims of “proven gas available,” because availability is constrained by reinjection priorities and facility limits.

7. Oil recovery & NPV sensitivity to gas diversion

The key technical uncertainty is the oil penalty function for diverting gas away from reinjection and toward domestic use. Public sources do not disclose field-by-field reinjection minimums, therefore we use screening regimes anchored to a simple metric:

D = Domestic sales gas ÷ Fresh associated gas at plateau
Fresh plateau gas depends on the oil rate and GOR. With a Stabroek system producing ~1.3–1.4 mmbpd by ~2030 (^[2][3]) and plausible GOR bands, plateau fresh gas may lie in the order-of-magnitude range of ~1–2 BCFD. Wales demand typically sits in a low-diversion regime; combined Wales+Berbice at ~600 mmscfd can enter a high-diversion regime.

Regime	Indicative diversion (D)	Indicative EUR oil loss	Indicative NPV10 loss	Typical domestic case
A — Oil-protective	≤ 15–20%	0–1%	0–1%	Wales-only (typical)
B — Balanced	20–35%	1–3%	1–4%	Moderate Berbice; combined ≤500 mmscfd
C — Gas-forward	≥ 35–45%	3–7% (higher in adverse reservoirs)	4–10%	Combined ≥600 mmscfd sustained

Physical causes of variation (why these are bands, not point values)

• Aquifer support vs injection dependence: stronger aquifer reduces marginal value of gas reinjection; weak aquifer increases it.
• Heterogeneity and vertical segregation: gas override can force higher injection for effective sweep and plateau preservation.
• Breakthrough and recycling: high cycling can inflate gross handled gas; diverting gas can either reduce inefficiency or collapse pressure support—reservoir specific.
• Facilities constraints: compression/treating reliability can cap both reinjection and domestic delivery.

8. Decision gates and “what must be shown”

8.1 Wales — the bankable domestic base case

• Policy/plan coherence: aligns with IMF and Government project descriptions (300 MW plant, associated infrastructure).^[7][8][9]
• Reservoir governance: typically within oil-protective diversion levels if ramped responsibly.
• Audit requirement: publish and maintain an operational scorecard from PMP data for gas produced/injected/flared/fuel as the baseline evidence trail.^[4][5]

8.2 Berbice — industrial upside, but conditional by design

• Key condition: Reuters reporting explicitly ties a Berbice pipeline to sufficient industrial demand (i.e., creditworthy offtake).^[10]
• Technical gate: define acceptable oil penalty tolerance and demonstrate reinjection constraints with field-by-field reservoir management evidence.
• Phasing gate: Berbice ramp should match reservoir maturity and any additional gas development timing (e.g., Longtail / later gas projects).^[10]

References

Protocol: Only trusted, published sources consulted (Government, operator, partner, IMF, and Reuters reporting of official statements). Access date: 21 Feb 2026.

1. ExxonMobil (Corporate). Guyana Project Overview. States Stabroek gross recoverable resource is “nearly 11 billion oil equivalent barrels.” Accessed 21 Feb 2026. https://corporate.exxonmobil.com/locations/guyana/operations/guyana-project-overview
2. CNOOC Limited. Strategy Preview, 22 Jan 2025 (PDF). Page 18: “8 projects will be in operation by 2030… total production expected to be 1.3 million barrel/day and capacity 1.7 million barrel/day.” Accessed 21 Feb 2026. https://www.cnoocltd.com/english/investorrelations/resultspresentations/presentations/202501/P020250122591479424099.pdf
3. Reuters. Exxon’s Uaru and Whiptail projects in Guyana are moving ahead of schedule, executive says, 18 Feb 2026. (Reports official statements on production increases to ~1.15 mmbpd with Uaru and ~1.4 mmbpd after Whiptail; each ~250 kbpd.)
4. Government of Guyana — Ministry of Natural Resources, Petroleum Management Programme. Charts (gas injected/flared/used; oil production; etc.). Accessed 21 Feb 2026. https://petroleum.gov.gy/charts/
5. Government of Guyana — Ministry of Natural Resources, Petroleum Management Programme. Gas Injected, Flared and Used (data page / chart). Accessed 21 Feb 2026. https://petroleum.gov.gy/data-chart/gas-injected-flared-and-used/
6. Government of Guyana — Ministry of Natural Resources, Petroleum Management Programme. Discoveries archive (public announcements referencing additions to “almost 11 billion barrels of oil equivalent”). Accessed 21 Feb 2026. https://petroleum.gov.gy/article_category/discoveries/
7. International Monetary Fund (IMF). Guyana: 2025 Article IV Consultation—Press Release; Staff Report; and Statement by the Executive Director (Country Report). Published May 2025. Accessed 21 Feb 2026. Landing page: https://www.imf.org/en/publications/cr/issues/2025/05/07/guyana-2025-article-iv-consultation-press-release-staff-report-and-statement-by-the-566712 PDF: https://www.imf.org/-/media/files/publications/cr/2025/english/1guyea2025001-print-pdf.pdf
8. Office of the President of Guyana. President Ali’s statement on the Government’s issuance of No-Objection to CH4/Lindsayca building the 300 MW Gas Power Plant at Wales, 10 Nov 2022. Accessed 21 Feb 2026. https://op.gov.gy/president-alis-statement-on-the-governments-issuance-of-no-objection-to-ch4-lindsayca-building-the-300-megawatt-gas-power-plant-at-wales/
9. Department of Public Information (DPI), Guyana. 24/7 work schedule now in effect for Wales Gas-to-Energy project, 11 Oct 2025. Accessed 21 Feb 2026. https://dpi.gov.gy/24-7-work-schedule-now-in-effect-for-wales-gas-to-energy-project/
10. Reuters. Exxon working to determine gas resource at Guyana’s Stabroek Block, minister says, 19 Feb 2026. (Reports official statements on assessment of gas resources; Longtail ~2030 as first non-associated gas project; and discussion of a potential new pipeline concept to Berbice conditioned on industrial demand.)

Interpretation safeguard: Where a parameter is not disclosed in the references above (e.g., system-wide GOR evolution, minimum reinjection requirement, recycled gas ratio), it is treated as a scenario variable and expressed as a bandwidth with stated physical causes—rather than asserted as a fact.

Author CV

Marcel Chin-A-Lien is a Global Petroleum & Energy Advisor and the publisher of PetroleumEnergyInsights.com. His work focuses on upstream petroleum systems, basin and play analysis, field development strategy, and energy economics, with a regional emphasis on the Guyana–Suriname Basin and adjacent Atlantic Margin provinces.

Through Golden Lane Investments Advisory Group, he supports governments, operators, investors, and industrial stakeholders with independent technical-commercial analysis, scenario modelling, and decision-grade briefs across exploration, development, fiscal frameworks, and integrated gas-to-power / gas-to-industry strategies.

Core competencies

• Petroleum systems & basin evaluation; play construction and risking
• Deepwater development screening (FPSO/subsea architectures, phasing, gas handling strategy)
• Integrated gas monetisation strategy (power, industry, infrastructure architecture)
• Fiscal/economic benchmarking and transparent, reproducible modelling
• Publication-grade technical communication for mixed audiences

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Prepared by Marcel Chin-A-Lien — Petroleum & Energy Advisor

Golden Lane Investments Advisory Group