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Competitiveness of Ghana’s Upstream Petroleum Fiscal Regime: Fit for Purpose?


This chapter assesses the attractiveness of Ghana’s upstream petroleum fiscal regime against key features of optimal fiscal policy, namely: efficiency of targeting economic rents, risk sharing, neutrality and progressiveness. We also identify potential fiscal reform options that Ghana can consider in optimising its fiscal regime. Various full lifecycle cash flow models are estimated using three oil field sizes—large (750 mmboe), medium (250 mmboe), small (50 mmboe)—with different cost profiles and four different pre- and post-Jubilee contract terms. Our results show that Ghana’s fiscal regime is investor-friendly with an average effective tax rate (AETR) or government take of 51.38% from royalties, IOC income taxes, and additional oil entitlements (AOE). The inclusion of the State’s Carried and Participating Interest (state take) pushes the AETR into the 65%–75% range, comparable with 65%–85% IMF benchmark values. In the context of Ghana’s low resource base, this balances the trade-offs between investment promotion and securing revenues to the State, especially when compared with other countries in the region and beyond. Also, we find that Ghana’s hybrid fiscal regime is regressive at the lower end of the oil price scale if oil prices are below $60/bbl while being slightly progressive with increasing oil prices above $60/bbl. In terms of the windfall tax structure, simulations using four tax scenarios indicate that the current AOE regime underperforms on the size and timing of revenues generated to the State. The windfall tax regime can be vastly simplified and at the same time accrue more revenues to the State by reducing the current five tiers to one: using a higher top headline rate while also lowering the trigger threshold. Furthermore, Ghana can also consider introducing targeted fiscal packages aimed at maximising economic recovery of over 500 mmboe of stranded reserves. Finally, we note significant institutional challenges regarding the capacity of some State agencies to efficiently and effectively monitor petroleum costs. In the absence of a change to the fiscal regime, the ability of Ghana’s regulatory and commercial institutions to monitor and audit costs will determine the extent to which the nation will generate significant revenues beyond just royalties and State participation.

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    Kpodo, K., 2017. ENI pumps first oil from Ghana’s Sankofa field. Available at: (Accessed: 31 July 2021).

  4. 4.

    See Sections 63–76 titled “Division I: Petroleum operations”.

  5. 5.

    See Sections 85–89 titled “Fiscal Provisions”.

  6. 6.

    See Sections 71–78 titled “Fiscal Provisions”.

  7. 7.

    See Section 71(1) of Petroleum (Exploration and Production) (General) Regulations, 2018 (L.I. 2359).

  8. 8.

    See Nakhle, C., and Acheampong, T., 2017. “Comparative assessment of oil and gas windfall taxation in Ghana”. Ghana Oil and Gas for Inclusive Growth (GOGIG).

  9. 9.

    See Section 17 of Income Tax Act, 2015 (Act 896); and regulation 19 of Income Tax Regulations, 2016 (L.I. 2244).

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    See Myers, K., 2010. Selling oil assets in Uganda and Ghana–A taxing problem. Revenue Watch Institute Release, New York, 16.

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    See Mansour, M. and Nakhle, C. (2016). Fiscal stabilization in oil and gas contracts–evidence and implications. Oxford Institute for Energy Studies. OIES PAPER: SP 37.

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    See Section 66(1)(d) of Income Tax Act, 2015 (Act 896).

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    Stephens, T. K., & Dowuona-Hammond, C., 2019. From total immunization to an economic balancing act: The trajectory of stabilization clauses in Ghana’s petroleum agreements. Oil, Gas & Energy Law Journal (OGEL), 17(2).

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    See Nakhle (2008).

  19. 19.

    Two main variations of the AETR are usually estimated in the literature and in practice. These are the government take and state take. Government take is the sum of the state’s royalty entitlements, special petroleum taxes, profit oil, and corporation taxes as well as bonuses, rentals and other fiscal and quasi-fiscal levies. On the other hand, the state take includes the government take as well as revenues from direct participation by the NOC (GNPC in Ghana’s case). In other words, the state take is the percentage of a project’s gross operating profit, which accrues to a sovereign government by way of royalties and taxes paid by investors, plus the operating profit (cash flow effect) attributable to the state’s direct participation such as carried and participating interest in a project. For our results we report the government take (without state participation) on a discounted and undiscounted basis. See World Bank (2019), van Meurs (2016), Tordo (2007), and Johnston (2007).

  20. 20.

    See also Tables 3 and 4.

  21. 21.

    See pg. 14 of Appendix A “Invitation to Tender document for First Oil & Gas Licensing Round”, published by the Ministry of Energy (21st January 2019).

  22. 22.

    As stated earlier in Sect. 2.2, progressive fiscal regimes collect a higher share of the rents from rising oil prices or lower costs, among others.

  23. 23.

    Note that for Scenarios 1–3, all the trigger point tax rates were set at 5, 10 and 15% in line with the Jubilee field contract to ensure consistency.

  24. 24.

    MTR is the amount of tax paid on an additional dollar of income.

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    See Cameron, P. D., & Stanley, M. C. (2017). Oil, gas, and mining: A sourcebook for understanding the extractive industries. World Bank Publications.

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Appendix: Fiscal Calculations—Cash Flow Methodology

Appendix: Fiscal Calculations—Cash Flow Methodology

The project net cash flow (NCFt) is computed by matching the relationships among the input variables. They are the gross revenues per year (GRt), royalty paid per year ROYt), total recoverable costs per year (COSTSt), income tax paid per year (TAXt) and additional oil entitlement paid per year (AOEt). It is defined as:

$$\text{NCF}_t = \text{GR}_t - \text{ROY}_t -\text{COSTS}_t - \text{TAX}_t - \text{AOE}_t$$

Additionally, we estimate the net present value (NPV) by calculating the discounted revenue for each year using the formula:

$$\text{NPV} = \mathop \sum \limits_{t = P_1 }^T \frac{\text{CF}_t }{{\left( {1 + r} \right)^t }} - \mathop \sum \limits_{t = C_1 }^N \frac{I_t }{{\left( {1 + r} \right)^t }}$$

where, \({\text{CF}}_{\text{t}}\) = the cash flow at given time, r = the discount factor, \({\text{I}}_{\text{t}}\) = investments at time t, \({\text{P}}_1\) = first year of production, \({\text{C}}_1\) = first year investment, \({\text{N}}\) = total investment years, \({\text{T}}\) = total years of cash flow.

The NPV methodology is justifiable by the fact that it properly accounts for all the relevant revenue streams and costs, considering the time value of these cash flows. Other project metrics such as the internal rate of return (IRR), discounted profitability index (DPI), payback period, undiscounted government take and NPV/BOE are also reported.

The respective components that make up the \(\text{NCF}_t\) are elaborated as follows:

Gross Revenues: The Gross Revenues \((\text{GR}_t )\) per year arising out of hydrocarbon sales is the product of the average annual oil price (\((P_t)\)) and the yearly production rate (\(({Q}_t)\)) for all fields. Oil here refers to the cumulative oil, gas and condensate production in barrels of oil equivalent (boe).

$$\text{GR}_t = \mathop \sum \limits_{t = 1}^T P_t Q_t$$

Royalty: The royalty which is taken as a percentage of the gross revenues and are tax-deductible:

$$\text{ROY}_t = \tau \times \text{GR}_t$$

Royalty tax rate falls between \(0 \le \tau \le 12.5\%\) in Ghana’s petroleum agreements. Details are provided in Sect. 2.3.5.

Costs: These are the total costs for each field which comprises of exploration and appraisal costs, development costs, operating costs and decommissioning costs. It is given as:

$$\text{Total Cost} = \sum \left( {\text{EA Costs + Devex + Opex + Aband} } \right)$$

Tax: The income tax base is computed by taking the total revenue ceiling (the investor’s share of the post royalty revenues) and deducting the following: finance costs (loan interest), recoverable costs (depreciated capital costs, depreciated exploration and appraisal costs, operating costs and decommissioning costs) and any prior period losses carried forward.

Additional Oil Entitlement: The State at any time is entitled to a portion of Contractor’s share of crude oil from each separate Development and Production Area. The Additional Oil Entitlement (AOE) is levied on the basis of the after-tax inflation-adjusted rate of return (ROR) which the Contractor has achieved with respect to such Development and Production Area at the time in question. The ROR is calculated on a sliding scale as a resource rent tax in accordance with the following computation:

$$\text{NCF}_t = \text{GR}_t - \text{ROY}_t - \text{COSTS}_t - \text{TAX}_t$$
$$\text{FA}_t = \text{FA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t$$
$$\text{SA}_t = \text{SA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \delta \text{FA}_t$$
$$\text{TA}_t = \text{SA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \gamma \text{SA}_t - \delta \text{FA}_t$$
$$\text{YA}_t = \text{YA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \tau \text{TA}_t - \gamma \text{SA}_t - \delta \text{FA}_t$$
$$\text{ZA}_t = \text{ZA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \beta \text{YA}_t - \tau \text{TA}_t - \gamma \text{SA}_t - \delta \text{FA}_t$$

where \(\text{NCF}_t\) is the net cash flow, \(\text{GR}_t\) gross revenues,\(\text{ROY}_t\) royalty paid, \(\text{COSTS}_t\) total recoverable costs,\(\text{TAX}_t\) income tax paid, \(\text{FA}_t\) first account, \(\text{SA}_t\) second account, \(\text{TA}_t\) third account, \(\text{YA}_t\) fourth account, \(\text{ZA}_t\) fifth account, \(r\) compounded internal rate of return and \(\gamma ,\tau ,\delta ,\beta\) applicable additional oil entitlement charges.

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Acheampong, T., Ali-Nakyea, A. (2022). Competitiveness of Ghana’s Upstream Petroleum Fiscal Regime: Fit for Purpose?. In: Acheampong, T., Kojo Stephens, T. (eds) Petroleum Resource Management in Africa. Palgrave Macmillan, Cham.

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