South Africa
Technical Assistance Report-Petroleum Sector Fiscal Regime Reform-Additional Analysis for the Davis Tax Committee

This Technical Assistance report lists key issues discussed between the IMF’s Fiscal Affairs Department (FAD) and the Davis Tax Committee regarding recommendations for tax reforms in the oil and gas sector in South Africa. It is suggested that the royalty should have a single flat rate, rather than the current variable rate formula. The 5 percent flat rate proposed in the FAD report is modest by international standards. For corporate tax purposes, the current immediate expensing of capital expenditure and the 100 percent and 50 percent uplifts for exploration and development expenditure are overly generous and will lead to both a revenue loss and a long delay before revenue is collected.

Abstract

This Technical Assistance report lists key issues discussed between the IMF’s Fiscal Affairs Department (FAD) and the Davis Tax Committee regarding recommendations for tax reforms in the oil and gas sector in South Africa. It is suggested that the royalty should have a single flat rate, rather than the current variable rate formula. The 5 percent flat rate proposed in the FAD report is modest by international standards. For corporate tax purposes, the current immediate expensing of capital expenditure and the 100 percent and 50 percent uplifts for exploration and development expenditure are overly generous and will lead to both a revenue loss and a long delay before revenue is collected.

1. This memorandum follows the meetings between the FAD mission and the Davis Tax Committee (DTC) – Sub-Committee on Oil and Gas - in March 2016. The first part of the note lists the main issues discussed with the DTC oil and gas sub-committee regarding their planned recommendation for tax reform in the oil and gas sector. The second part of the note provides additional fiscal analysis prepared at the request of the subcommittee. The basis of the discussion was both the FAD 2015 report1 and the DTC draft oil and gas report which outlined the preliminary recommendations of the sub-committee.

A. Key Issues

2. The mission first sought to understand the committee’s further objectives in reforming the fiscal regime. The DTC’s focus was on defining a robust and stable fiscal regime appropriate to the South African context, with a focus on maintaining a palatable regime for investors. However, the potential instability of the current regime in the event of a large discovery was also recognized by the committee, particularly in the country’s current fiscal context. The importance of revenue generation was also highlighted, given the current urgent revenue needs of the fiscus.

3. Following discussion of individual fiscal regime elements and evaluation of different fiscal regime packages, the subcommittee appears to be moving towards a regime consisting of: (i) a 5 percent royalty, (ii) corporate income tax at the statutory rate with some reform to the current capital depreciation treatment; and (iii) an additional rent capture element in the form of either state participation or a cash flow surcharge.

4. The key issues discussed are outlined in the table below.

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B. Petroleum Fiscal Regime Analysis

5. This analysis builds upon the results of the 2015 Analysis Supplement. First, the modeling of the current fiscal regime is amended, adding the 10 percent state participation interest understood to apply to existing production rights holders. The analysis then goes on to consider variations in fiscal variables as requested by the oil and gas sub-committee, including (i) alternative royalty rates (2 and 5 percent); (ii) alternative capital depreciation treatments, including the accelerated depreciation treatment currently applicable to the manufacturing sector; and (iii) alternative rates for the state participation interest and cashflow surcharge.

Methodology

6. The analysis is based on the medium deepwater offshore oil field example of the 2015 report. To facilitate comparisons with the Analysis Supplement results, the same economic and modeling assumptions are used. Section G later considers the onshore shale gas field example.

7. A key variable underpinning the project economics is the oil price. As a base case assumption, the 2015 analysis assumed the oil price projections of the IMF World Economic Outlook at the time of writing (Figure A45 in the Analysis Supplement) until 2020 beyond which the price projection was kept constant in real terms and inflated at a rate of 2 percent per annum. The petroleum sector has seen a dramatic change in price levels over the past year. To understand the implications of these new market dynamics, the analysis later includes a sensitivity analysis involving lower price assumptions, as well as a consideration of breakeven oil and gas prices under alternative fiscal regimes.

8. The project’s underlying profitability was tested under a range of cost and price assumptions (Figure 1). Under the current cost assumptions, the project would require an oil price of at least $40/Bbl to breakeven on a pre-tax basis, i.e. before any fiscal imposition. This may be moderated by the recent decline in upstream capital and operating costs, although this decrease has not been as significant as the downward price trends.

Figure 1.
Figure 1.

Sensitivity Analysis (Pre-Tax Project IRR)

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

C. Current Regime

9. The inclusion of the 10 percent carried state participation interest increases the government take by 7-8 percent in discounted terms. It is understood that in addition to the terms modeled for the current regime in the 2015 report, companies are also subject to a 10 percent state participation requirement, provided for in their petroleum production rights. Under this arrangement, the development costs are assumed to be carried by the IOC and repaid out of the cash flows attributable to the state under this participating interest. The analysis assumes that the carried costs are repaid with an interest rate of 7 percent (nominal), reflecting a reasonable premium over the LIBOR benchmark interest rate. Figure 2 and Table 2 shows the simulation results and the government revenue profile under this updated regime. If the BEE participation is considered as part of the government take, the AETR is now between 45 and 55 percent, depending on the price assumption used.

Table 1.

Fiscal Terms – Current Regime

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Figure 2.
Figure 2.

Government Revenue Profile – Current Regime

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

Table 2.

Simulation Results – Current Regime

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D. Alternative Capital Depreciation Methods

10. The impact of varying the capital depreciation treatment applicable to the current regime was analyzed. In particular, the option of an accelerated depreciation over 4 years according to a 40-20-20-20 schedule, as currently applicable to the South African manufacturing sector, was analyzed. Figure 3 ilustrates the impact of varying depreciation treatments under the hypothetical scenario where corporate income tax is the only charge on the project. It shows that the accelerated depreciation treatment yields a similar revenue result and time profile when compared to the option of 5-year straight line depreciation and 10 percent allowance for corporate capital (ACC) combination proposed in the 2015 report.

Figure 3.
Figure 3.

CIT Profiles under Alternative Depreciation Regimes

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

11. The impact of varying the rate of ACC uplift was tested. The exact results of the modeling depend on the assumptions assumed for the interest rate and debt-equity ratio in the accelerated depreciation case, and the ACC rate under the IMF proposed scenario. The analysis assumes that 70 percent of development expenditure is debt-financed, and the real interest rate assumed is LIBOR (1 percent) + 3.5 percent, which amounts to a nominal rate of approximately 6.6 percent, assuming an inflation rate of 2 percent. Under these assumptions, the total ACC uplift deductible is larger than the interest payments deductible under the accelerated depreciation regime and outweighs the effect of the acceleration in depreciation, explaining the difference in CIT receipts in the two scenarios. However, assuming a higher rate for the interest payments, or using a lower ACC rate would eliminate this discrepancy. Figure 4 illustrates this using a scenario assuming a 6 percent ACC uplift.

Figure 4.
Figure 4.

CIT Profiles – Varying the ACC rate

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

E. Variation of Royalty and Additional Rent Capture Parameters

12. As per the recent request of the DTC, the impact of varying a range of fiscal parameters is analyzed. Figure 4 demonstrates the impact on government revenue, government take and the investor’s return when various fiscal parameters are adjusted relative to the current regime modeled in Section B. Many of the options analyzed are revenue enhancing. However, it is clear that a move to a 2 percent royalty would leave the government with less revenue. In addition, as currently calibrated, the cashflow surcharge yields slightly less revenue than the state participation due to differences between the uplift mechanism and the interest on carried costs, as well as the fact that exploration costs are not repaid under the state participation arrangement.

Figure 5.
Figure 5.

Impact of Fiscal Parameter Adjustments

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

F. Analyzing the Fiscal Package

13. At the request of the DTC, a series of new scenarios was analyzed. The scenarios of the 2015 report contain a 5 royalty and the cashflow surcharge and state participation mechanisms set at 20 percent levels. The scenarios in this analysis assess the implications of setting or maintaining the cashflow surcharge or state participation at 10 percent, and of lowering the royalty to 2 percent. The accelerated depreciation is assumed under these scenarios as per the DTC request, and not the 5-year straight line and ACC treatment assumed in the 2015 report. However, for the overall fiscal package the differences between the two depreciation options do not result in significant differences in the headline fiscal regime indicators.

Table 3.

Fiscal Regime Terms – Alternative Scenarios1/

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The ACC is applied as an annual uplift on the balance of undepreciated capital assets. The cashflow surcharge applies a one-time uplift to capital as it is incurred. The interest charges on any carried costs under the state participation arrangement are applied annually to the balance of costs not yet repaid.

Table 4.

Simulation Results

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14. The scenarios were evaluated for revenue raising capacity, neutrality and progressivity. In terms of revenue raising capacity, the scenarios yield broadly similar AETRs, between 46 and 51 percent in discounted terms. Scenarios 1 and 3 yield almost identical results, as do Scenarios 2 and 4, reflecting the revenue equivalence of the cashflow surcharge and state participation when set at the same levels. However, all of these scenarios clearly yield a lower government take than the recommended scenarios in the 2015 report due to the presence of either a lower royalty rate or lower rate for the additional rent capture mechanism. The scenarios also yield very similar breakeven prices, and post-tax investor payback periods which range from 6.2 to 6.35 years from production. In terms of progressivity, Scenarios 2 and 4 with their combination of 2 percent royalties and 20 percent additional rent capture mechanisms are marginally more progressive, although again the difference appears to be minimal.

G. Shale Gas

Capital depreciation treatments in shale gas

15. Analysis of varying capital depreciation treatments was carried out on the shale gas example analyzed in the 2015 report. The same project production and cost parameters were used as in the 2015 example, and a gas price of $8.8/MMbtu was assumed which allows the project to generate a pre-tax project return of 18.5 percent in real terms. Figure 6 analyzes the impact of varying depreciation treatments under the hypothetical scenario where corporate income tax is the only charge on the project.

Figure 6.
Figure 6.

Simulation Results

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

16. The current uplift treatment is very costly in the case of shale gas because of the repeated capital drilling expenditure incurred in shale gas production. The current regime of immediate expensing of capital combined with generous uplifts results in a 5 year delay in CIT payments relative to the alternative treatments. Even without the uplifts, immediate expensing compared with the alternatives delays CIT payments by 2 years.

17. As in the offshore example, the accelerated depreciation treatment yields a similar revenue result and time profile to the 5-year straight line depreciation and 10 percent allowance for corporate capital (ACC) combination. Again, the small difference in the CIT receipts and profiles is explained by the modeling assumptions used. The magnitude of the ACC at 10 percent is significantly larger than the interest payments deductible under the accelerated depreciation regime and outweighs the effect of the acceleration in depreciation. However, a lower ACC rate, as explained in Section F, would eliminate this discrepancy (Figure 8).

Figure 7.
Figure 7.

CIT Profiles under Alternative Depreciation Regimes

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

Figure 8.
Figure 8.

CIT Profiles – Varying the ACC rate

Citation: IMF Staff Country Reports 2016, 259; 10.5089/9781475520286.002.A001

H. Carbon Taxes

18. The impact of the South African Draft Carbon Tax Bill was analyzed. The bill proposes a tax of R120/ton2 of emissions or CO2 equivalent. However, a large number of allowances may be applicable, which could relieve to up to 95 percent of emissions in oil and gas production from the tax payable, particularly if as under the current royalty legislation both oil and gas are treated as refined products. The global average for CO2 emissions from petroleum extraction is approximately 130 kg of CO2 per ton of oil equivalent3, although the figure is usually lower for offshore operations. Assuming an emissions rate of 100kg per ton of oil equivalent, Table 5 shows the estimated carbon tax applicable to the 500MMBbl project both with and without the allowances contained in the draft bill.

19. When expressed as an effective royalty, the carbon tax implemented without any allowances would amount to 2.1 percent of the petroleum value under the 2015 WEO price projections. This figure decreases to 0.11 percent when the effect of the allowances is included. Since the carbon tax is defined as a monetary amount per ton of emissions, Table 5 shows that the effective royalty burden will decrease as prices increase. The calculations in Table 5 use only the global average described above; that average, and also the application of tax allowances, may not accurately represent the eventual position for production in South Africa. Thus Table 5 is shown only for illustration purposes.

Table 5.

Fiscal Impact of the Carbon Tax

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1

South Africa – Fiscal Regimes for Mining and Petroleum: Opportunities and Challenges, Philip Daniel, Martin Grote, Peter Harris, and Alpa Shah, IMF Fiscal Affairs Department, April 2015

2

It is assumed in the analysis that this amount would increase annually in line with inflation, remaining constant in real terms.

South Africa: Technical Assistance Report-Petroleum Sector Fiscal Regime Reform-Additional Analysis for the Davis Tax Committee
Author: International Monetary Fund. Fiscal Affairs Dept.