Upstream Oil and Gas Economics Training Course

Participants can convert production and reserves assumptions into model-ready forecast inputs.

• PRMS reserves classes linked to development maturity and economic status
• Production plateaux, ramp-up periods and decline rates structured for forecasts
• Arps decline-curve parameters interpreted for conventional producing fields
• Well count, drilling sequence and facility constraints reflected in profiles
• Recoverable volumes reconciled with annual production and remaining reserves
• Production forecast assumptions documented with source, owner and confidence level

Participants can construct price assumptions suitable for upstream economic evaluation.

• Brent, WTI and regional marker prices selected for crude valuation
• Differentials, quality adjustments and transport deductions applied to realised prices
• Gas pricing mechanisms compared across domestic, LNG and pipeline markets
• Price decks structured using nominal, real and escalated assumptions
• Inflation indices separated from commodity-price escalation within economic models
• Forward curves and long-term planning prices assessed for decision use

Participants can structure capital expenditure estimates and timing for upstream development cases.

• Class 5 through Class 1 estimates interpreted using AACE guidance
• Exploration, appraisal and development expenditures separated by decision stage
• Well costs built from drilling, completion, testing and tie-in components
• Facilities capital grouped into subsea, processing, export and utilities packages
• Contingency allowances linked to estimate maturity, scope definition and risk
• Capital phasing aligned with engineering, procurement, construction and commissioning schedules

Participants can model operating expenditure, transport charges and end-of-life obligations.

• Fixed and variable operating costs separated for production-volume forecasting
• Unit operating costs benchmarked using lifting-cost and throughput measures
• Processing, pipeline and export tariffs incorporated into netback calculations
• Workover, integrity and late-life interventions scheduled within operating forecasts
• Decommissioning scope costed for wells, facilities, pipelines and site restoration
• Abandonment funding assumptions tested against production cessation and cash availability

Participants can build a transparent upstream discounted cash flow model structure.

• Model tabs organised for inputs, calculations, outputs and audit checks
• Monthly and annual time steps selected according to decision purpose
• Gross production converted into entitlement volumes and sales revenue
• Cash flow waterfalls structured from revenue through taxes and free cash flow
• Real and nominal cash flows matched with appropriate discount rates
• Formula checks identify broken links, timing errors and sign conventions

Participants can calculate and interpret standard valuation measures for upstream projects.

• Net present value calculated from discounted after-tax project cash flows
• Internal rate of return tested against reinvestment and multiple-root limitations
• Payout period measured using cumulative undiscounted and discounted cash flows
• Unit technical cost expressed per barrel of oil equivalent
• Finding and development costs calculated from capital spending and reserves additions
• NPV per barrel compared across assets with different production scales

Participants can model royalties, taxes and government take under concessionary systems.

• Royalty calculations applied to gross revenue, volume or value bases
• Cost deductions assessed for depreciation, uplift and tax-loss carryforward
• Corporate income tax modelled using taxable income and fiscal timing
• Ring-fencing rules tested between licences, fields and project phases
• Government take calculated from royalty, tax and state participation proceeds
• Fiscal stability clauses assessed for their economic and contractual implications

Participants can evaluate contractor economics under production-sharing and service-contract terms.

• Cost oil ceilings modelled against eligible cost-recovery balances
• Profit oil split calculated using fixed and sliding-scale formulas
• R-factor mechanisms linked to cumulative revenues, costs and production
• First tranche petroleum and domestic market obligations included accurately
• Recoverable-cost categories tested against contract provisions and audit exposure
• Service-fee remuneration compared with equity-style contractor cash flow

Participants can assess partner positions, funding obligations and alignment issues in joint ventures.

• Equity interests translated into funding shares, revenue shares and reserves
• Carried-interest arrangements modelled through carry limits and recovery mechanisms
• Cash-call timing linked to approved work programmes and budgets
• Joint operating agreement provisions examined for sole-risk and default consequences
• Partner value compared after dilution, taxes and financing constraints
• Alignment issues identified between operator objectives and non-operator priorities

Participants can evaluate exploration and appraisal decisions using risked economic measures.

• Chance of success decomposed into reservoir, trap, charge and retention elements
• Expected monetary value calculated from success, failure and appraisal outcomes
• Exploration well costs weighted against prospective resource and discovery value
• Appraisal programmes assessed using information value and decision-tree logic
• Farm-in terms evaluated through promote, carry and back-in provisions
• Exploration portfolios screened using risked NPV and capital exposure

Participants can compare development concepts using technical, commercial and economic criteria.

• Subsea tieback, platform and floating production concepts compared economically
• Facility capacity matched with plateau production and expansion potential
• Phased development scenarios tested against capital constraints and reservoir uncertainty
• Concept-selection criteria weighted using value, risk, schedule and operability
• Value of flexibility assessed for staged drilling and modular facilities
• Development options ranked using NPV, capital efficiency and execution risk

Participants can select and apply discounting and financing assumptions for investment decisions.

• Weighted average cost of capital constructed from debt and equity inputs
• Country risk, project risk and currency risk treated consistently
• Nominal discount rates matched with nominal inflation and cash flows
• Project-finance debt sizing linked to debt-service coverage ratios
• Loan repayment profiles reflected in equity cash flow calculations
• Corporate hurdle rates distinguished from project-specific discount rates

Participants can identify the assumptions that most affect project value and decision viability.

• One-way sensitivities ranked using tornado-chart value movements
• Two-way tables test combined oil-price and capital-cost exposure
• Base, upside and downside scenarios structured with internally consistent assumptions
• Breakeven oil prices calculated for NPV, payout and fiscal thresholds
• Breakeven production volumes tested against facility capacity and reserve uncertainty
• Schedule delay effects quantified through deferred revenue and extended capital exposure

Participants can incorporate uncertain inputs into probabilistic economic assessments.

• Probability distributions selected for reserves, costs, prices and schedule duration
• Monte Carlo simulation produces probability distributions of project NPV
• P10, P50 and P90 outcomes interpreted for value and downside exposure
• Correlation assumptions defined between production, capital cost and timing variables
• Decision trees compare contingent choices, information value and staged commitments
• Risk registers connect technical uncertainties with economic model assumptions

Participants can connect economic assumptions with reserves status and field-life decisions.

• PRMS commerciality criteria assessed against development maturity and economic viability
• SEC reserves reporting concepts contrasted with PRMS classification principles
• Economic limit defined from operating cash flow and abandonment timing
• Reserve revisions traced to price, cost, performance and development changes
• Remaining value assessed at producing-field decline and late-life stages
• Asset retirement timing tested against tax relief and abandonment liabilities

Participants can rank opportunities and allocate constrained capital across upstream portfolios.

• Risked NPV, capital efficiency and strategic fit used for ranking
• Capital rationing tested through mutually exclusive and divisible investment choices
• Portfolio diversification assessed across basins, fiscal systems and commodity exposure
• Production targets reconciled with capital availability and project maturity
• Marginal value of capital calculated for competing development opportunities
• Portfolio dashboards present value, risk, spend and schedule indicators

Participants can prepare economic evidence for project gates and investment assurance reviews.

• Stage-gate decisions linked to concept select, define and execute maturity
• Decision Quality framing clarifies alternatives, criteria, uncertainties and commitments
• Value assurance reviews test model logic, assumptions and option completeness
• Independent economic review identifies optimism bias and unsupported inputs
• Approval papers distinguish recommendation, evidence, risks and decision required
• Post-investment reviews compare sanctioned assumptions with actual performance

Participants can communicate economic conclusions clearly to technical, commercial and executive stakeholders.

• Investment narratives connect reservoir performance, development scope and economic value
• Waterfall charts explain movements between base case and revised valuation
• Tornado charts communicate dominant uncertainties and management response options
• Assumption registers show source, date, owner, rationale and approval status
• Executive summaries state recommendation, value, downside and required decisions
• Partner presentations distinguish common assumptions from equity-specific economic outcomes

Participants can build, review and present a complete upstream asset investment case with valuation, fiscal analysis, risk assessment and recommendation.

• Production, price, cost and fiscal inputs assembled into one auditable model
• Base-case cash flows calculated through development, production and abandonment
• Alternative development concepts compared using value, risk and capital efficiency
• Sensitivity and Monte Carlo results translated into decision-relevant risk conclusions
• Investment recommendation prepared with assumptions, value drivers and approval conditions
• Peer review challenges model logic, fiscal treatment and presentation evidence