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

Abstract

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.

Appendix: Fiscal Calculations—Cash Flow Methodology

The project net cash flow (NCF_t) is computed by matching the relationships among the input variables. They are the gross revenues per year (GR_t), royalty paid per year ROY_t), total recoverable costs per year (COSTS_t), income tax paid per year (TAX_t) and additional oil entitlement paid per year (AOE_t). It is defined as:

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

(1)

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

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

(2)

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).

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

(3)

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

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

(4)

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:

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

(5)

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:

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

(6)

$$\text{FA}_t = \text{FA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t$$

(7)

$$\text{SA}_t = \text{SA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \delta \text{FA}_t$$

(8)

$$\text{TA}_t = \text{SA}_{t - 1} \left( {1 + r} \right) + \text{NCF}_t - \gamma \text{SA}_t - \delta \text{FA}_t$$

(9)

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

(10)

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

(11)

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.