Petroleum Economics Fundamentals is a comprehensive 3-day course that decodes the financial logic underpinning the global oil and gas industry. Oil and gas projects are among the most capital-intensive and economically complex undertakings in the world — and understanding how they are valued, financed, taxed, and traded is essential for anyone seeking to engage meaningfully in the energy sector.

This course bridges the gap between technical industry operations and the economic and financial frameworks that determine whether projects get built, whether governments capture fair value from their resources, and whether investors generate returns. With a particular focus on the African market, participants will develop the economic literacy needed to participate confidently in investment decisions, policy design, contract negotiations, and strategic conversations about the continent’s energy future.

Format	Live virtual sessions via Zoom or Google Meet
Duration	3 Days — 1 hour per session
Frequency	Hosted once a month
Certificate	Certificate of Completion awarded upon finishing all sessions
Open To	Students, non-technical professionals, investors, regulators, energy enthusiasts
Contact	+1 365-654-9225  |  info@pentoragroup.com  |  pentoragroup.com

 

Learning Objectives

By the end of this course, participants will be able to:

• Explain the core economic principles that govern oil and gas exploration, development, and production decisions — including cost structures, production profiles, and field economics.
• Understand global oil and gas pricing mechanisms: how Brent and WTI benchmarks are set, what drives price volatility, and how prices affect government revenues and project viability.
• Interpret the key fiscal instruments used to govern petroleum revenues — royalties, production sharing contracts, concession agreements, and taxes — and evaluate their implications for investors and host governments.
• Apply foundational project evaluation tools: Net Present Value (NPV), Internal Rate of Return (IRR), Payback Period, and Break-even analysis — without needing an engineering or finance background.
• Analyse how petroleum projects are financed, from equity and debt to reserve-based lending and development finance institutions, with specific focus on the African context.
• Understand the economics of petroleum contracts, including Production Sharing Contracts (PSCs), Joint Venture Agreements, and Service Contracts commonly used across Africa.
• Assess the economic dimensions of the energy transition: stranded asset risk, carbon pricing, declining investment in upstream oil and gas, and what this means for African resource-rich nations.
• Apply these tools and frameworks to real-world African petroleum investment and policy scenarios, equipping participants to engage meaningfully in the conversations and decisions that will shape the continent’s energy future.

 

Day 1 — The Economics of Oil & Gas: Costs, Prices & Value Creation

Session Overview

This foundational session establishes the economic logic of the oil and gas industry from the ground up. Participants learn how petroleum projects generate — or fail to generate — economic value, how global oil prices are determined, what drives cost structures across the industry value chain, and why price volatility is the defining risk factor for every actor in the sector. A strong African market lens is applied throughout, grounding concepts in the realities that African producers, governments, and investors face.

 

Topics Covered

1.1  Introduction to Petroleum Economics

• What is petroleum economics? Defining the discipline and its relevance to non-economists
• The economic life cycle of an oil and gas field: exploration, appraisal, development, production, and decommissioning
• Why petroleum economics is different from other industries: long lead times, capital intensity, geological uncertainty, and political risk
• The concept of economic rent in petroleum: why oil and gas generate surplus value and why governments and companies compete to capture it
• Key economic actors: International Oil Companies (IOCs), National Oil Companies (NOCs), independent producers, traders, and host governments
• Africa in the global petroleum economy: production volumes, export revenues, and fiscal dependence across major producing nations

1.2  The Cost Structure of Oil & Gas Projects

• Capital expenditure (CAPEX): exploration costs, appraisal drilling, development drilling, and surface facilities
• Operating expenditure (OPEX): lifting costs, maintenance, personnel, and logistics
• Decommissioning and abandonment costs: an increasingly significant liability, especially for ageing African fields
• Finding and development costs (F&D costs): measuring the cost of adding new reserves
• Lifting cost per barrel: the single most important cost metric for producers and investors
• How costs vary by geography and geology: deepwater vs. onshore, large fields vs. marginal fields, frontier vs. mature basins
• Africa cost benchmarks: why deepwater West Africa, North African desert operations, and East African frontier exploration have very different cost profiles

1.3  Oil & Gas Pricing: How Prices Are Set

• The global benchmark system: Brent Crude, West Texas Intermediate (WTI), and Dubai/Oman — what they are and how they differ
• How crude oil is priced: spot markets, forward markets, and the role of the futures curve
• African crude price differentials: why Nigerian Bonny Light, Angolan Cabinda, and Algerian Saharan Blend trade at premiums or discounts to Brent
• Natural gas pricing: why gas markets are more regional, the role of LNG in globalising gas pricing, and Henry Hub as a US benchmark
• The OPEC+ production quota system: how coordinated supply management influences global prices
• Price volatility: the historical record, its economic consequences for producers and consumers, and strategies for managing it

1.4  Supply, Demand & the Macro-Economics of Oil

• The price elasticity of oil supply and demand: why short-term demand is inelastic and what this means for price swings
• The commodity supercycle: understanding the boom-bust cycles that define the petroleum industry
• Key demand drivers: GDP growth, industrialisation, transport, petrochemicals, and the emerging markets pivot
• The supply side: OPEC vs. non-OPEC, US shale revolution, and the geopolitics of production
• Oil price scenarios and their economic impact on African producer states: the $40, $70, and $100 per barrel worlds
• Currency risk: why oil is priced in USD and what dollar strength means for African governments earning oil revenues

 

Africa’s Fiscal Exposure to Oil Price Volatility ▶  Nigeria’s federal budget requires a minimum of $70–$75/bbl to remain solvent without significant borrowing. ▶  Angola’s oil sector contributes over 90% of export revenues and 60% of government income. ▶  A $10/bbl drop in the oil price costs the average African petro-state between $2–$5 billion per year in lost revenue. ▶  Ghana, Senegal, and Uganda are developing fiscal frameworks that aim to reduce boom-bust dependence from first oil. ▶  Understanding price risk is therefore not an abstract exercise — it is central to African fiscal sovereignty.

 

Day 2 — Project Valuation, Fiscal Regimes & Petroleum Contracts

Session Overview

Day 2 is the analytical heart of the course. Participants learn how oil and gas projects are evaluated financially, how governments structure fiscal systems to capture a fair share of petroleum revenues, and how the most common petroleum contract types — used extensively across Africa — work in practice. No prior finance training is assumed; every concept is introduced from first principles and illustrated with African examples.

 

Topics Covered

2.1  Fundamentals of Project Economics & Valuation

• The time value of money: why a dollar today is worth more than a dollar tomorrow, and why this matters enormously for long-lived oil projects
• Discounted Cash Flow (DCF) analysis: the framework at the heart of all petroleum project valuation
• Net Present Value (NPV): what it is, how to interpret it, and what a positive vs. negative NPV tells an investor
• Internal Rate of Return (IRR): the yield metric every investor and government official needs to understand
• Payback Period: how quickly does an investment recover its costs, and why this matters in high-risk environments?
• Break-even oil price: the price at which a project covers all its costs — one of the most important indicators for African projects
• Sensitivity analysis: testing how NPV and IRR change when oil prices, costs, or production volumes shift
• Real-world application: walking through a simplified African upstream project valuation step by step

2.2  Reserves, Resources & Their Economic Significance

• The petroleum reserves classification system: Proved (1P), Probable (2P), and Possible (3P) reserves
• Why reserves classifications matter: for investors, lenders, governments, and stock market valuations
• Resources vs. reserves: the journey from geological potential to bankable, producible volumes
• Reserves-to-production (R/P) ratio: measuring the longevity of a country or company’s resource base
• How reserves are independently audited: the role of competent persons reports (CPRs) and international standards (SPE-PRMS)
• Africa’s reserves landscape: which countries hold the most proved reserves and what this means for economic planning

2.3  Petroleum Fiscal Regimes: How Governments Capture Value

• What is a fiscal regime? The system of taxes, royalties, and profit-sharing mechanisms that determines how petroleum revenues are divided between the state and investors
• Concession agreements (licence-and-royalty): the oldest fiscal model, used in North Africa and parts of West Africa
• Production Sharing Contracts (PSCs): how cost oil, profit oil, and government take work — the dominant model across sub-Saharan Africa
• Service contracts and technical service agreements: used in mature basins where NOCs retain ownership
• Royalties: fixed vs. sliding-scale royalties and their impact on project economics at different price levels
• Corporate income tax, petroleum profit tax, and windfall profit taxes: the tax layer above fiscal contract terms
• Government take vs. investor take: measuring the fiscal balance and understanding what makes a regime ‘investor-friendly’ vs. ‘resource-nationalist’
• Comparing African fiscal regimes: Nigeria’s Deep Offshore PSC, Angola’s Sonangol-led model, Kenya’s Production Sharing Agreement, and Mozambique’s LNG fiscal framework

2.4  Petroleum Contracts in Practice: Negotiation & Governance

• The anatomy of a Production Sharing Contract: key clauses every non-lawyer needs to understand
• Cost recovery caps: why governments limit how much cost oil companies can recover and the economic implications
• Profit oil splits: how tiered profit oil arrangements align government and investor interests over a field’s life
• Stabilisation clauses: protecting investor economics against adverse changes in law or tax policy
• Local content requirements: equity participation, local employment, and domestic procurement obligations in African PSCs
• Ring-fencing provisions: preventing companies from offsetting losses on one block against profits on another
• Contract renegotiation: when and why governments seek to revise contract terms, and the investor relations and legal implications
• Transparency and accountability: the Extractive Industries Transparency Initiative (EITI) and its role in African petroleum governance

 

Understanding Government Take: A Simplified Illustration ▶  Imagine a field producing 100,000 barrels/day at $80/bbl — generating $8 million/day in gross revenue. ▶  Under a typical African PSC, 30–40% is first allocated as ‘cost oil’ to recover the investor’s capital expenditure. ▶  The remaining ‘profit oil’ is then split — typically 60–70% to government, 30–40% to the investor. ▶  Add royalties (5–12.5%) and corporate income tax (30–50%), and the government’s total take is typically 65–85%. ▶  The investor’s post-tax return on a $2 billion development could range from 8% to 22% IRR depending on the fiscal terms negotiated.

 

Day 3 — Financing, Trade, Transition Risk & Africa’s Petroleum Future

Session Overview

The final session explores how petroleum projects are financed, how oil and gas are traded globally, and how the economics of the energy transition are reshaping investment decisions and government strategies across Africa. Participants leave with a complete economic picture of the petroleum sector and the analytical tools to apply this knowledge in professional, investment, and policy contexts.

 

Topics Covered

3.1  Financing Petroleum Projects in Africa

• The capital structure of an oil and gas project: equity, debt, and quasi-equity instruments
• Project finance vs. corporate finance: why large-scale African petroleum projects use ring-fenced project finance structures
• Reserve-Based Lending (RBL): how banks lend against proved reserves and why this is the dominant debt instrument for African upstream projects
• Development Finance Institutions (DFIs) in African petroleum: the African Development Bank, IFC, DBSA, and Afreximbank
• Export Credit Agencies (ECAs): how China’s Sinosure, the US DFC, and European ECAs de-risk large African energy investments
• The role of National Oil Companies as financiers: NNPC’s joint ventures, Sonangol’s financing model, and NOCG in Equatorial Guinea
• Commodity-backed loans: the ‘oil-for-infrastructure’ model prevalent in Angola, Republic of Congo, and Chad — economics, risks, and legacy
• Sovereign wealth funds and petroleum stabilisation funds: how Norway’s GPF model compares to African equivalents (GNPC, Botswana Pula Fund, Angola’s Fundo Soberano)

3.2  Oil & Gas Trading: How Petroleum Moves Economically

• The physical oil market: spot cargoes, term contracts, and how crude is bought and sold between producers and refiners
• Oil futures and derivatives: hedging price risk using WTI and Brent futures contracts on the NYMEX and ICE exchanges
• How African NOCs trade their equity crude: direct sales to refiners, marketing companies, and commodity trading houses
• The role of commodity trading houses in African oil: Vitol, Glencore, Trafigura, and Gunvor and their dominance in African crude flows
• LNG trade economics: tolling agreements, FOB vs. DES pricing, and how Africa’s LNG exporters (Nigeria, Mozambique, Tanzania) monetise gas
• Oil price risk management for African governments: hedging sovereign revenues — lessons from Mexico’s PEMEX hedging programme
• Downstream retail economics: petrol station margins, subsidies, and the fiscal cost of fuel price controls across Africa

3.3  The Economics of African Petroleum Governance

• Resource curse theory: why resource-rich nations sometimes grow more slowly than resource-poor ones — the empirical evidence
• Dutch Disease: how a booming petroleum sector can hollow out the rest of the economy and what governments can do about it
• Local content economics: the trade-off between maximising local participation and minimising project costs
• Revenue management frameworks: budget rules, fiscal stabilisation funds, and intergenerational equity
• Corruption and rent-seeking in petroleum: the economic cost of weak governance and the EITI’s role in combating it
• Country case studies: Botswana’s diamond model applied to petroleum; Ghana’s Jubilee Fund governance; Nigeria’s NNPC reform under the Petroleum Industry Act (PIA 2021)
• First oil economics: why the gap between discovery and first production is a critical economic variable for governments managing expectations

3.4  Energy Transition Economics & the Future of African Petroleum

• Stranded asset risk: the economic concept, the IEA’s net-zero scenario, and what it means for unmonetised African reserves
• Carbon pricing and its economic implications: the EU Carbon Border Adjustment Mechanism (CBAM) and its potential impact on African hydrocarbon exports
• The divestment movement: how ESG pressure is changing the capital flows available to African petroleum projects
• The investment cliff: declining upstream spending by major IOCs and its economic consequences for African producer states
• Economic diversification: why resource-rich African nations must use petroleum revenues to build non-oil economies — and the economic framework for doing so
• Gas as a transition asset: the economics of African LNG in a decarbonising world — window of opportunity or stranded infrastructure?
• New investment opportunities at the intersection of petroleum and transition: carbon capture on gas fields, hydrogen from gas reforming, and methane emission reduction economics

3.5  Practical Application & Synthesis

• Case study: Full economic assessment of a real-world African upstream project — from reserves to cash flow to government take
• Role-play scenario: Negotiating PSC terms between an investor and a host government finance ministry
• Economic stress test: how does the project economics change at $50/bbl, $70/bbl, and $100/bbl oil price?
• Group discussion: Which African country is best positioned to maximise economic value from its petroleum resources in the energy transition era?
• Q&A with facilitator
• Course wrap-up, key takeaways, and certificate issuance

 

The Economic Stakes for Africa ▶  Africa holds an estimated 125 billion barrels of proved oil reserves and 620 trillion cubic feet of natural gas. ▶  At current production rates, Africa earns approximately $200–$300 billion per year in petroleum revenues. ▶  Yet the African Development Bank estimates that only 30–40 cents of every oil dollar is retained within African economies. ▶  The Petroleum Industry Act (Nigeria, 2021) is the continent’s most significant fiscal reform in decades — designed to attract $100bn+ in new investment. ▶  Participants who understand petroleum economics can help close the gap between Africa’s resource wealth and its development outcomes.

 

Key Economic Concepts at a Glance

Concept	Plain-Language Definition
NPV (Net Present Value)	The total value of a project’s future cash flows, adjusted for the time value of money. A positive NPV means the project is economically worthwhile.
IRR (Internal Rate of Return)	The annualised return rate a project generates on the capital invested. A project is viable if its IRR exceeds the investor’s cost of capital.
Break-even Price	The oil price at which a project covers all its costs (capital + operating) and generates zero profit. Projects with low break-evens are more resilient to price downturns.
Lifting Cost	The cost of extracting one barrel of oil from a producing well. Africa’s lifting costs range from $5/bbl (North Africa onshore) to $30+/bbl (deepwater).
Production Sharing Contract	A fiscal agreement where the government allows a company to recover its costs from oil production, then shares the remaining profit oil according to a pre-agreed formula.
Government Take	The total share of petroleum revenues captured by the host government through royalties, taxes, and profit oil. Typically 65–85% in African producing nations.
Reserve-Based Lending	A loan structure where the borrowing capacity is determined by the value of the borrower’s proved oil and gas reserves, rather than balance sheet assets.
Cost Oil / Profit Oil	Under a PSC, cost oil is the share of production allocated to recovering the investor’s costs. Profit oil is the remainder, split between the investor and government.
Stranded Assets	Petroleum reserves or infrastructure that lose economic value before the end of their expected life, due to falling demand, lower prices, or carbon regulation.
EITI	Extractive Industries Transparency Initiative: a global standard requiring governments and companies to publish revenue and payment data, improving petroleum governance accountability.

 

Assessment & Certification

Participants are evaluated on attendance and engagement across all three sessions. A Certificate of Completion is awarded to participants who attend all three sessions and actively participate. The certificate is issued by Pentora Group and recognises foundational competence in petroleum economics, fiscal regimes, project valuation, and the strategic energy landscape of Africa.