## 1. Fiscal Terms – Current Regime

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---

### Key issues discussed with the Davis Tax Committee (DTC) – Sub‑Committee on Oil and Gas
- DTC objectives: define a robust and stable fiscal regime appropriate to the South African context while keeping it palatable for investors; recognize potential instability of the current regime in the event of a large discovery; emphasize revenue generation given urgent fiscal needs.
- Subcommittee movement toward a package consisting of:
  - a 5 percent royalty,
  - corporate income tax at the statutory rate with reform to capital depreciation treatment,
  - an additional rent capture element via state participation or a cash flow surcharge.
- Requested further analysis on:
  - alternative depreciation treatments (including 40:20:20:20 accelerated depreciation used in manufacturing),
  - 10 percent and 20 percent cashflow surcharge instruments,
  - 10 percent and 20 percent state participation interests,
  - impact of the proposed carbon tax on petroleum projects.
- Other policy notes:
  - Royalty: recommend a single flat rate (5 percent proposed in FAD report); base needs clear definition (presently gross sales at first saleable point).
  - Corporate tax depreciation: current immediate expensing plus 100 percent and 50 percent uplifts for exploration/development are overly generous; IMF mission recommended 5‑year straight line depreciation plus allowance for corporate capital (ACC) on undepreciated balance.
  - Ring‑fencing: remove current 10 percent offset of petroleum losses against non‑petroleum income to maintain a clear petroleum ring‑fence.
  - Fiscal stability: propose stability assurance under revised Schedule 10 and under royalty legislation; state participation stability likely needs contractual assurance.
  - Carbon tax: DTC concerned it would act like an additional royalty; requested project impact analysis.

### Methodology and baseline assumptions
- Modeling base: medium deepwater offshore oil field example from the 2015 report; same economic and modeling assumptions used to facilitate comparison.
- Oil price projection base case: IMF WEO projections used until 2020, then price kept constant in real terms and inflated at 2 percent per annum.
- Sensitivity: analysis includes lower price assumptions and breakeven oil/gas price calculations.
- Key project profitability threshold: project requires an oil price of at least $40/Bbl to breakeven on a pre‑tax basis (before fiscal imposition).
- Project example label: Offshore_South Africa_500MMBbl (Pre tax IRR indicator).

### Current fiscal regime specification (as modeled)
- Royalty: Variable royalty formula (current regime) — 0.5 + [earnings before interest and taxes/(gross sales in respect of refined mineral resources x 12.5)]. Max rate 5%.
- Income Tax Rate: 28%
- Depreciation:
  - Investment Allowance/Accelerated Depreciation: 100% immediate expensing
  - Uplift on Exploration Costs: 100%
  - Uplift on Post-Exploration Costs: 50%
- Loss Carry Forward: Unlimited
- Withholding Taxes:
  - Dividends: 0%
  - Interest: 0%
- Participation Requirements:
  - State Participation: 10% State Participation: Carry through to production with repayment of development costs from participation cashflows with interest
  - Local Participation: 10% HDSA Ownership

### Fiscal impact of adding a carried 10 percent state participation (modeled)
- Inclusion of the 10 percent carried state participation interest increases government take by 7-8 percent in discounted terms.
- Assumed repayment of carried costs with interest at 7 percent (nominal).
- If BEE participation considered part of government take, AETR is between 45 and 55 percent depending on price assumptions.

### Simulation results (selected project metrics under modeled regimes)
- Oil Price Assumptions and selected outcomes (Project Fiscal Results in US$ million real or %):
  - Price cases: $50/bbl (2015 Real Terms) / WEO Price Projections / $80/Bbl (2015 Real Terms)
  - Pre‑tax project IRR: 19.7% / 26.4% / 31.0%
  - Post‑tax IRR on total funds: 15.7% / 21.5% / 25.7%
  - Post‑tax IRR on equity: 18.6% / 25.6% / 30.2%
  - IOC IRR: 18.2% / 25.0% / 29.6%
  - BEE Entity IRR: 23.7% / 32.7% / 39.5%
  - Pre‑tax NCF undiscounted: 12,824 / 20,721 / 27,824
  - Post‑tax investor NCF undiscounted: 7,753 / 12,640 / 17,029
    - of which IOC: 6,793 / 11,138 / 15,040
    - of which BEE Entity: 960 / 1,502 / 1,990
  - Investor Payback Period (years from production): 5.26 / 4.46 / 4
  - Government revenue undiscounted: 4,190 / 7,200 / 9,914
  - AETR undiscounted: 32.7% / 34.7% / 35.6%
  - AETR (including BEE): 40.2% / 42.0% / 42.8%
  - Pre‑tax NCF 10% discount: 2,367 / 4,707 / 6,811
  - Post‑tax investor NCF 10% discount: 1,347 / 2,862 / 4,201
    - of which IOC: 1,154 / 2,504 / 3,696
    - of which BEE Entity: 194 / 358 / 504
  - Investor Payback Period (years from production) NPV 12.5%: 7.76 / 5.79 / 5
  - Government revenue 10% discount: 1,064 / 1,889 / 2,654
  - AETR 10% discount: 45.0% / 40.1% / 39.0%
  - AETR 10% discount (including BEE): 53.1% / 47.7% / 46.4%

### Alternative capital depreciation methods — simulation insights
- Options analyzed included:
  - Immediate expensing with uplift (current),
  - Accelerated depreciation (40-20-20-20) as per manufacturing sector,
  - ACC + 5 years straight line (SL) depreciation.
- Finding: Accelerated depreciation (40-20-20-20) yields a similar revenue result and time profile to the combination of 5‑year straight line depreciation plus 10 percent ACC allowance proposed in the 2015 report (when corporate income tax is the only charge).
- Sensitivity to financing assumptions: model assumes 70 percent of development expenditure is debt financed and real interest rate assumed LIBOR (1 percent) + 3.5 percent = nominal approximately 6.6 percent (assuming inflation 2 percent).
- Under these financing assumptions, total ACC uplift deductible is larger than interest payments deductible under the accelerated depreciation regime, producing differences in CIT receipts; a higher interest payment rate or lower ACC rate would eliminate this discrepancy.

### Varying the ACC uplift rate
- Scenario illustrations include ACC at 10% and ACC at 6% combined with 5‑year SL depreciation.
- Figure comparisons show CIT profiles shift when ACC rate is changed; lower ACC reduces the deductible uplift and can increase CIT receipts relative to higher ACC settings.

### Variation of royalty and additional rent capture parameters — quantified effects
- Policy adjustments simulated relative to the current modeled regime include:
  - Move to 2% royalty
  - Move to 5% royalty
  - Change to ACC + 5 year SL uplift
  - Change to 40/20/20/20 depreciation
  - Add 10% cashflow surcharge
  - Add 10% state participation
  - Add 20% cashflow surcharge
- Key quantified impacts (WEO 2015 Prices / $80/Bbl; results expressed as changes in Government Revenue (NPV 10), AETR (NPV 10), and Post‑Tax IRR (Total Funds)):
  - Government Revenue (NPV 10) impacts (example values from chart):
    - Move to 2% Royalty: -187 and -228
    - Move to a 5% royalty: 8 and 10
    - Change to ACC + 5 year SL Uplift: 215 and 249
    - Change to 40/20/20/20 Depreciation: 315 and 349
    - Add 10% Cashflow Surcharge: -33 and -35
    - Add 10% State Participation: 375 and 518
    - Add 20% Cashflow Surcharge: 307 and 448
  - Results on AETR (NPV 10) — percentage point changes:
    - Move to 2% Royalty: -4.0%
    - Move to a 5% royalty: 0.2%
    - Change to ACC + 5 year SL Uplift: 4.6%
    - Change to 40/20/20/20 Depreciation: 6.7%
    - Add 10% Cashflow Surcharge: -0.7%
    - Add 10% State Participation: 8.0%
    - Add 20% Cashflow Surcharge: 6.5%
  - Post‑Tax IRR (Total Funds) — percentage point changes:
    - Move to 2% Royalty: 0.61%
    - Move to a 5% royalty: -0.04%
    - Change to ACC + 5 year SL Uplift: -0.78%
    - Change to 40/20/20/20 Depreciation: -1.12%
    - Add 10% Cashflow Surcharge: 0.11%
    - Add 10% State Participation: -1.13%
    - Add 20% Cashflow Surcharge: -0.89%
- Interpretation:
  - Many options are revenue enhancing relative to the current regime modeled.
  - A move to a 2 percent royalty would reduce government revenue.
  - As currently calibrated, the cashflow surcharge yields slightly less revenue than state participation due to differences in uplift mechanisms, interest on carried costs, and the non‑repayment of exploration costs under state participation.

### Carbon tax
- DTC concern: proposed carbon tax would add further tax burden on oil and gas companies and would, as drafted, have the effect of a royalty instrument on petroleum rights holders.
- The DTC requested analysis on the carbon tax impact on a petroleum project (analysis requested but not detailed in the provided excerpt).

---

### 13. At the request of the DTC, a series of new scenarios was analyzed

### Alternative fiscal scenarios analyzed
- Scenarios modify: royalty, cashflow surcharge, and state participation levels relative to the 2015 report.
- Royalty options assessed: "5% Flat Rate" and "2% Flat Rate".
- Cashflow surcharge and state participation assessed at 10 percent or 20 percent.
- Accelerated Depreciation (40-20-20-20) is assumed under these scenarios (per DTC request) rather than the 5-year straight line and ACC treatment assumed in the 2015 report.
- Note: "for the overall fiscal package the differences between the two depreciation options do not result in significant differences in the headline fiscal regime indicators."

### Fiscal provisions compared (as presented)
- Royalty: "0.5 + [earnings before interest and taxes/(gross sales in respect of refined mineral resources x 12.5)] x 100. Max 5%" (Current Regime) versus 5% Flat Rate or 2% Flat Rate in scenarios.
- Income tax: "28%" (Current Regime and all scenarios).
- Depreciation: Current Regime — "Immediate Expensing of all Capital Expenditure"; Scenarios — "Accelerated Depreciation (40-20-20-20)".
- Uplift/Allowance for Corporate Capital: Current Regime — "100% uplift on exploration expenditure; 50% uplift on development expenditure".
- Loss carry-forward: "Unlimited" (Current Regime and all scenarios).
- Additional Tax: Current Regime — "Cashflow Surcharge of 10% wth uplift on capital expenditure at 10%"; Scenario variants include "Cashflow Surcharge of 20% wth uplift on capital expenditure at 10%".
- State Participation: Current Regime — "10% State Participation. Carry through to production with repayment of development costs from participation cashflows at interest rate of 7%"; Scenario variants include "20% State Participation. Carry through to production with repayment of development costs from participation cashflows at interest rate of 7%".
- HDSA Requirements: "10% Local Ownership" (Current Regime and all scenarios).

### Simulation results — project fiscal outcomes (selected figures)
- Pre-tax project IRR: "26.4%" (Current Regime and all scenarios).
- Post-tax IRR on total funds:
  - Current Regime: "21.5%"
  - Scenario 1: "20.3%"
  - Scenario 2: "19.7%"
  - Scenario 3: "20.4%"
  - Scenario 4: "20.0%"
- Post-tax IRR on equity:
  - Current Regime: "25.6%"
  - Scenario 1: "24.1%"
  - Scenario 2: "23.6%"
  - Scenario 3: "24.3%"
  - Scenario 4: "23.9%"
- IOC IRR:
  - Current Regime: "25.0%"
  - Scenario 1: "23.6%"
  - Scenario 2: "22.9%"
  - Scenario 3: "23.9%"
  - Scenario 4: "23.5%"
- BEE Entity IRR:
  - Current Regime: "32.7%"
  - Scenario 1: "30.9%"
  - Scenario 2: "31.9%"
  - Scenario 3: "29.6%"
  - Scenario 4: "29.1%"
- Pre-tax NCF undiscounted: "20,721" (US$ million real) for Current Regime and all scenarios.
- Post-tax investor NCF undiscounted:
  - Current Regime: "12,640"
  - Scenario 1: "11,661"
  - Scenario 2: "10,844"
  - Scenario 3: "11,765"
  - Scenario 4: "11,055"
- o/w IOC post-tax NCF undiscounted:
  - Current Regime: "11,138"
  - Scenario 1: "10,235"
  - Scenario 2: "9,347"
  - Scenario 3: "10,468"
  - Scenario 4: "9,829"
- o/w BEE Entity post-tax NCF undiscounted:
  - Current Regime: "1,502"
  - Scenario 1: "1,426"
  - Scenario 2: "1,497"
  - Scenario 3: "1,298"
  - Scenario 4: "1,226"
- Investor Post Tax Payback Period (years from production):
  - Current Regime: "4.46"
  - Scenario 1: "4.56"
  - Scenario 2: "4.52"
  - Scenario 3: "4.56"
  - Scenario 4: "4.51"
- Government revenue undiscounted:
  - Current Regime: "7,200"
  - Scenario 1: "8,179"
  - Scenario 2: "8,996"
  - Scenario 3: "8,074"
  - Scenario 4: "8,785"
- AETR undiscounted:
  - Current Regime: "34.7%"
  - Scenario 1: "39.5%"
  - Scenario 2: "43.4%"
  - Scenario 3: "39.0%"
  - Scenario 4: "42.4%"
- AETR (including BEE) undiscounted:
  - Current Regime: "42.0%"
  - Scenario 1: "46.4%"
  - Scenario 2: "50.6%"
  - Scenario 3: "45.2%"
  - Scenario 4: "48.3%"
- Pre-tax NCF 10% discount: "4,707" (Current Regime and all scenarios).
- Post-tax investor NCF 10% discount:
  - Current Regime: "2,862"
  - Scenario 1: "2,528"
  - Scenario 2: "2,330"
  - Scenario 3: "2,560"
  - Scenario 4: "2,396"
- o/w IOC post-tax NCF 10% discount:
  - Current Regime: "2,504"
  - Scenario 1: "2,199"
  - Scenario 2: "1,980"
  - Scenario 3: "2,265"
  - Scenario 4: "2,117"
- o/w BEE Entity post-tax NCF 10% discount:
  - Current Regime: "358"
  - Scenario 1: "329"
  - Scenario 2: "350"
  - Scenario 3: "295"
  - Scenario 4: "279"
- Investor Payback Period NPV 12.5% (years from production):
  - Current Regime: "5.79"
  - Scenario 1: "6.26"
  - Scenario 2: "6.33"
  - Scenario 3: "6.22"
  - Scenario 4: "6.25"
- Government revenue 10% discount:
  - Current Regime: "1,889"
  - Scenario 1: "2,223"
  - Scenario 2: "2,421"
  - Scenario 3: "2,190"
  - Scenario 4: "2,355"
- AETR 10% discount:
  - Current Regime: "40.1%"
  - Scenario 1: "47.2%"
  - Scenario 2: "51.4%"
  - Scenario 3: "46.5%"
  - Scenario 4: "50.0%"
- AETR 10% discount (including BEE):
  - Current Regime: "47.7%"
  - Scenario 1: "54.2%"
  - Scenario 2: "58.9%"
  - Scenario 3: "52.8%"
  - Scenario 4: "55.9%"

### Interpretation of scenario results
- In revenue raising capacity terms the scenarios yield broadly similar AETRs, "between 46 and 51 percent in discounted terms."
- Scenarios 1 and 3 yield almost identical results; Scenarios 2 and 4 yield almost identical results — reflecting "the revenue equivalence of the cashflow surcharge and state participation when set at the same levels."
- All scenarios yield a lower government take than the recommended scenarios in the 2015 report due to either a lower royalty rate or lower rate for the additional rent capture mechanism.
- Breakeven prices and post-tax investor payback periods are very similar across scenarios, with payback periods "which range from 6.2 to 6.35 years from production."
- 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."

### Shale gas — capital depreciation treatments
- Analysis used the shale gas example from the 2015 report with the same project production and cost parameters and a gas price of "$8.8/MMbtu", generating a pre-tax project return of "18.5 percent" in real terms.
- The current uplift treatment (immediate expensing + generous uplifts) is very costly for shale gas because of repeated capital drilling expenditure.
- Current regime of immediate expensing with uplifts results in a "5 year delay in CIT payments relative to the alternative treatments."
- Even without uplifts, immediate expensing delays CIT payments by "2 years" compared with alternatives.
- Accelerated depreciation yields similar revenue results and time profile to the 5-year straight line depreciation combined with a "10 percent allowance for corporate capital (ACC)".
- 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 acceleration; a lower ACC rate would eliminate this discrepancy.

### Carbon tax analysis (South African Draft Carbon Tax Bill)
- Draft bill proposes a tax of "R120/ton" of emissions or CO2 equivalent.
- Large number of allowances could relieve "up to 95 percent of emissions in oil and gas production from the tax payable", particularly if oil and gas are treated as refined products.
- Global average CO2 emissions from petroleum extraction cited as "approximately 130 kg of CO2 per ton of oil equivalent", but figure usually lower for offshore operations.
- Analysis assumes emissions rate of "100kg per ton of oil equivalent".
- Table 5: Estimated carbon tax for the 500MMBbl project:
  - Total Oil Production MMBoE: "500"
  - Oil Production million tons: "68"
  - CO2 emissions million tons: "6.8"
  - Carbon Tax (without allowances) $mm real: "811"
  - Carbon Tax (with allowances) $mm real: "41"
- Fiscal impact examples:
  - Oil Price = "$50/bbl":
    - Value of Petroleum $mm real: "29,291"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "2.77%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.14%"
  - Oil Price at 2015 WEO prices:
    - Value of Petroleum $mm real: "38,544"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "2.10%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.11%"
  - Oil Price = "$80/bbl":
    - Value of Petroleum $mm real: "46,866"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "1.73%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.09%"
- Assumptions used in carbon tax calculations:
  - Tons per barrel of oil equivalent: "7.4"
  - CO2 emissions rate (kg per ton of oil equivalent): "100"
  - Carbon Tax (Rand/kg of CO2): "120"
  - Allowances (% of total carbon tax payable): "95%"
- Key observation: "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."  
- The effective royalty burden from the carbon tax will decrease as prices increase because the tax is a monetary amount per ton of emissions.

*Source: _cr16259 - 1. Fiscal Terms – Current Regime; _cr16259 - 13. At the request of the DTC, a series of new scenarios was analyzed.*

### 1. Fiscal Terms – Current Regime .......................................................................................

### 1. Fiscal Terms – Current Regime

### Key issues discussed with the Davis Tax Committee (DTC) – Sub‑Committee on Oil and Gas
- DTC objectives: define a robust and stable fiscal regime appropriate to the South African context while keeping it palatable for investors; recognize potential instability of the current regime in the event of a large discovery; emphasize revenue generation given urgent fiscal needs.
- Subcommittee movement toward a package consisting of:
  - a 5 percent royalty,
  - corporate income tax at the statutory rate with reform to capital depreciation treatment,
  - an additional rent capture element via state participation or a cash flow surcharge.
- Requested further analysis on:
  - alternative depreciation treatments (including 40:20:20:20 accelerated depreciation used in manufacturing),
  - 10 percent and 20 percent cashflow surcharge instruments,
  - 10 percent and 20 percent state participation interests,
  - impact of the proposed carbon tax on petroleum projects.
- Other policy notes:
  - Royalty: recommend a single flat rate (5 percent proposed in FAD report); base needs clear definition (presently gross sales at first saleable point).
  - Corporate tax depreciation: current immediate expensing plus 100 percent and 50 percent uplifts for exploration/development are overly generous; IMF mission recommended 5‑year straight line depreciation plus allowance for corporate capital (ACC) on undepreciated balance.
  - Ring‑fencing: remove current 10 percent offset of petroleum losses against non‑petroleum income to maintain a clear petroleum ring‑fence.
  - Fiscal stability: propose stability assurance under revised Schedule 10 and under royalty legislation; state participation stability likely needs contractual assurance.
  - Carbon tax: DTC concerned it would act like an additional royalty; requested project impact analysis.

### Methodology and baseline assumptions
- Modeling base: medium deepwater offshore oil field example from the 2015 report; same economic and modeling assumptions used to facilitate comparison.
- Oil price projection base case: IMF WEO projections used until 2020, then price kept constant in real terms and inflated at 2 percent per annum.
- Sensitivity: analysis includes lower price assumptions and breakeven oil/gas price calculations.
- Key project profitability threshold: project requires an oil price of at least $40/Bbl to breakeven on a pre‑tax basis (before fiscal imposition).
- Project example label: Offshore_South Africa_500MMBbl (Pre tax IRR indicator).

### Current fiscal regime specification (as modeled)
- Royalty: Variable royalty formula (current regime) — 0.5 + [earnings before interest and taxes/(gross sales in respect of refined mineral resources x 12.5)]. Max rate 5%.
- Income Tax Rate: 28%
- Depreciation:
  - Investment Allowance/Accelerated Depreciation: 100% immediate expensing
  - Uplift on Exploration Costs: 100%
  - Uplift on Post-Exploration Costs: 50%
- Loss Carry Forward: Unlimited
- Withholding Taxes:
  - Dividends: 0%
  - Interest: 0%
- Participation Requirements:
  - State Participation: 10% State Participation: Carry through to production with repayment of development costs from participation cashflows with interest
  - Local Participation: 10% HDSA Ownership

### Fiscal impact of adding a carried 10 percent state participation (modeled)
- Inclusion of the 10 percent carried state participation interest increases government take by 7-8 percent in discounted terms.
- Assumed repayment of carried costs with interest at 7 percent (nominal).
- If BEE participation considered part of government take, AETR is between 45 and 55 percent depending on price assumptions.

### Simulation results (selected project metrics under modeled regimes)
- Oil Price Assumptions and selected outcomes (Project Fiscal Results in US$ million real or %):
  - $50/bbl (2015 Real Terms) / WEO Price Projections / $80/Bbl (2015 Real Terms)
  - Pre‑tax project IRR: 19.7% / 26.4% / 31.0%
  - Post‑tax IRR on total funds: 15.7% / 21.5% / 25.7%
  - Post‑tax IRR on equity: 18.6% / 25.6% / 30.2%
  - IOC IRR: 18.2% / 25.0% / 29.6%
  - BEE Entity IRR: 23.7% / 32.7% / 39.5%
  - Pre‑tax NCF undiscounted: 12,824 / 20,721 / 27,824
  - Post‑tax investor NCF undiscounted: 7,753 / 12,640 / 17,029
    - of which IOC: 6,793 / 11,138 / 15,040
    - of which BEE Entity: 960 / 1,502 / 1,990
  - Investor Payback Period (years from production): 5.26 / 4.46 / 4
  - Government revenue undiscounted: 4,190 / 7,200 / 9,914
  - AETR undiscounted: 32.7% / 34.7% / 35.6%
  - AETR (including BEE): 40.2% / 42.0% / 42.8%
  - Pre‑tax NCF 10% discount: 2,367 / 4,707 / 6,811
  - Post‑tax investor NCF 10% discount: 1,347 / 2,862 / 4,201
    - of which IOC: 1,154 / 2,504 / 3,696
    - of which BEE Entity: 194 / 358 / 504
  - Investor Payback Period (years from production) NPV 12.5%: 7.76 / 5.79 / 5
  - Government revenue 10% discount: 1,064 / 1,889 / 2,654
  - AETR 10% discount: 45.0% / 40.1% / 39.0%
  - AETR 10% discount (including BEE): 53.1% / 47.7% / 46.4%

### Alternative capital depreciation methods — simulation insights
- Options analyzed included:
  - Immediate expensing with uplift (current),
  - Accelerated depreciation (40-20-20-20) as per manufacturing sector,
  - ACC + 5 years straight line (SL) depreciation.
- Finding: Accelerated depreciation (40-20-20-20) yields a similar revenue result and time profile to the combination of 5‑year straight line depreciation plus 10 percent ACC allowance proposed in the 2015 report (when corporate income tax is the only charge).
- Sensitivity to financing assumptions: model assumes 70 percent of development expenditure is debt financed and real interest rate assumed LIBOR (1 percent) + 3.5 percent = nominal approximately 6.6 percent (assuming inflation 2 percent).
- Under these financing assumptions, total ACC uplift deductible is larger than interest payments deductible under the accelerated depreciation regime, producing differences in CIT receipts; a higher interest payment rate or lower ACC rate would eliminate this discrepancy.

### Varying the ACC uplift rate
- Scenario illustrations include ACC at 10% and ACC at 6% combined with 5‑year SL depreciation.
- Figure comparisons show CIT profiles shift when ACC rate is changed; lower ACC reduces the deductible uplift and can increase CIT receipts relative to higher ACC settings.

### Variation of royalty and additional rent capture parameters — quantified effects
- Policy adjustments simulated relative to the current modeled regime include:
  - Move to 2% royalty
  - Move to 5% royalty
  - Change to ACC + 5 year SL uplift
  - Change to 40/20/20/20 depreciation
  - Add 10% cashflow surcharge
  - Add 10% state participation
  - Add 20% cashflow surcharge
- Key quantified impacts (WEO 2015 Prices / $80/Bbl; results expressed as changes in Government Revenue (NPV 10), AETR (NPV 10), and Post‑Tax IRR (Total Funds)):
  - Government Revenue (NPV 10) impacts (example values from chart):
    - Move to 2% Royalty: -187 and -228 (two rows shown)
    - Move to a 5% royalty: 8 and 10
    - Change to ACC + 5 year SL Uplift: 215 and 249
    - Change to 40/20/20/20 Depreciation: 315 and 349
    - Add 10% Cashflow Surcharge: -33 and -35
    - Add 10% State Participation: 375 and 518
    - Add 20% Cashflow Surcharge: 307 and 448
  - Results on AETR (NPV 10) — percentage point changes:
    - Move to 2% Royalty: -4.0%
    - Move to a 5% royalty: 0.2%
    - Change to ACC + 5 year SL Uplift: 4.6%
    - Change to 40/20/20/20 Depreciation: 6.7%
    - Add 10% Cashflow Surcharge: -0.7%
    - Add 10% State Participation: 8.0%
    - Add 20% Cashflow Surcharge: 6.5%
  - Post‑Tax IRR (Total Funds) — percentage point changes:
    - Move to 2% Royalty: 0.61%
    - Move to a 5% royalty: -0.04%
    - Change to ACC + 5 year SL Uplift: -0.78%
    - Change to 40/20/20/20 Depreciation: -1.12%
    - Add 10% Cashflow Surcharge: 0.11%
    - Add 10% State Participation: -1.13%
    - Add 20% Cashflow Surcharge: -0.89%
- Interpretation:
  - Many options are revenue enhancing relative to the current regime modeled.
  - A move to a 2 percent royalty would reduce government revenue.
  - As currently calibrated, the cashflow surcharge yields slightly less revenue than state participation due to differences in uplift mechanisms, interest on carried costs, and the non‑repayment of exploration costs under state participation.

### Carbon tax
- DTC concern: proposed carbon tax would add further tax burden on oil and gas companies and would, as drafted, have the effect of a royalty instrument on petroleum rights holders.
- The DTC requested analysis on the carbon tax impact on a petroleum project (analysis requested but not detailed in the provided excerpt).

*Source: _cr16259 - 1. Fiscal Terms – Current Regime.*

### 13.      At the request of the DTC, a series of new scenarios was analyzed. The scenarios

### _cr16259 - 13.      At the request of the DTC, a series of new scenarios was analyzed. The scenarios

### Alternative fiscal scenarios analyzed
- Scenarios modify: royalty, cashflow surcharge, and state participation levels relative to the 2015 report.
- Royalty options assessed: "5% Flat Rate" and "2% Flat Rate".
- Cashflow surcharge and state participation assessed at 10 percent or 20 percent.
- Accelerated Depreciation (40-20-20-20) is assumed under these scenarios (per DTC request) rather than the 5-year straight line and ACC treatment assumed in the 2015 report.
- Note: "for the overall fiscal package the differences between the two depreciation options do not result in significant differences in the headline fiscal regime indicators."

### Fiscal provisions compared (as presented)
- Royalty: "0.5 + [earnings before interest and taxes/(gross sales in respect of refined mineral resources x 12.5)] x 100. Max 5%" (Current Regime) versus 5% Flat Rate or 2% Flat Rate in scenarios.
- Income tax: "28%" (Current Regime and all scenarios).
- Depreciation: Current Regime — "Immediate Expensing of all Capital Expenditure"; Scenarios — "Accelerated Depreciation (40-20-20-20)".
- Uplift/Allowance for Corporate Capital: Current Regime — "100% uplift on exploration expenditure; 50% uplift on development expenditure".
- Loss carry-forward: "Unlimited" (Current Regime and all scenarios).
- Additional Tax: Current Regime — "Cashflow Surcharge of 10% wth uplift on capital expenditure at 10%"; Scenario variants include "Cashflow Surcharge of 20% wth uplift on capital expenditure at 10%".
- State Participation: Current Regime — "10% State Participation. Carry through to production with repayment of development costs from participation cashflows at interest rate of 7%"; Scenario variants include "20% State Participation. Carry through to production with repayment of development costs from participation cashflows at interest rate of 7%".
- HDSA Requirements: "10% Local Ownership" (Current Regime and all scenarios).

### Simulation results — project fiscal outcomes (selected figures)
- Pre-tax project IRR: "26.4%" (Current Regime and all scenarios).
- Post-tax IRR on total funds:
  - Current Regime: "21.5%"
  - Scenario 1: "20.3%"
  - Scenario 2: "19.7%"
  - Scenario 3: "20.4%"
  - Scenario 4: "20.0%"
- Post-tax IRR on equity:
  - Current Regime: "25.6%"
  - Scenario 1: "24.1%"
  - Scenario 2: "23.6%"
  - Scenario 3: "24.3%"
  - Scenario 4: "23.9%"
- IOC IRR:
  - Current Regime: "25.0%"
  - Scenario 1: "23.6%"
  - Scenario 2: "22.9%"
  - Scenario 3: "23.9%"
  - Scenario 4: "23.5%"
- BEE Entity IRR:
  - Current Regime: "32.7%"
  - Scenario 1: "30.9%"
  - Scenario 2: "31.9%"
  - Scenario 3: "29.6%"
  - Scenario 4: "29.1%"
- Pre-tax NCF undiscounted: "20,721" (US$ million real) for Current Regime and all scenarios.
- Post-tax investor NCF undiscounted:
  - Current Regime: "12,640"
  - Scenario 1: "11,661"
  - Scenario 2: "10,844"
  - Scenario 3: "11,765"
  - Scenario 4: "11,055"
- o/w IOC post-tax NCF undiscounted:
  - Current Regime: "11,138"
  - Scenario 1: "10,235"
  - Scenario 2: "9,347"
  - Scenario 3: "10,468"
  - Scenario 4: "9,829"
- o/w BEE Entity post-tax NCF undiscounted:
  - Current Regime: "1,502"
  - Scenario 1: "1,426"
  - Scenario 2: "1,497"
  - Scenario 3: "1,298"
  - Scenario 4: "1,226"
- Investor Post Tax Payback Period (years from production):
  - Current Regime: "4.46"
  - Scenario 1: "4.56"
  - Scenario 2: "4.52"
  - Scenario 3: "4.56"
  - Scenario 4: "4.51"
- Government revenue undiscounted:
  - Current Regime: "7,200"
  - Scenario 1: "8,179"
  - Scenario 2: "8,996"
  - Scenario 3: "8,074"
  - Scenario 4: "8,785"
- AETR undiscounted:
  - Current Regime: "34.7%"
  - Scenario 1: "39.5%"
  - Scenario 2: "43.4%"
  - Scenario 3: "39.0%"
  - Scenario 4: "42.4%"
- AETR (including BEE) undiscounted:
  - Current Regime: "42.0%"
  - Scenario 1: "46.4%"
  - Scenario 2: "50.6%"
  - Scenario 3: "45.2%"
  - Scenario 4: "48.3%"
- Pre-tax NCF 10% discount: "4,707" (Current Regime and all scenarios).
- Post-tax investor NCF 10% discount:
  - Current Regime: "2,862"
  - Scenario 1: "2,528"
  - Scenario 2: "2,330"
  - Scenario 3: "2,560"
  - Scenario 4: "2,396"
- o/w IOC post-tax NCF 10% discount:
  - Current Regime: "2,504"
  - Scenario 1: "2,199"
  - Scenario 2: "1,980"
  - Scenario 3: "2,265"
  - Scenario 4: "2,117"
- o/w BEE Entity post-tax NCF 10% discount:
  - Current Regime: "358"
  - Scenario 1: "329"
  - Scenario 2: "350"
  - Scenario 3: "295"
  - Scenario 4: "279"
- Investor Payback Period NPV 12.5% (years from production):
  - Current Regime: "5.79"
  - Scenario 1: "6.26"
  - Scenario 2: "6.33"
  - Scenario 3: "6.22"
  - Scenario 4: "6.25"
- Government revenue 10% discount:
  - Current Regime: "1,889"
  - Scenario 1: "2,223"
  - Scenario 2: "2,421"
  - Scenario 3: "2,190"
  - Scenario 4: "2,355"
- AETR 10% discount:
  - Current Regime: "40.1%"
  - Scenario 1: "47.2%"
  - Scenario 2: "51.4%"
  - Scenario 3: "46.5%"
  - Scenario 4: "50.0%"
- AETR 10% discount (including BEE):
  - Current Regime: "47.7%"
  - Scenario 1: "54.2%"
  - Scenario 2: "58.9%"
  - Scenario 3: "52.8%"
  - Scenario 4: "55.9%"

### Interpretation of scenario results (paragraph summary points)
- In revenue raising capacity terms the scenarios yield broadly similar AETRs, "between 46 and 51 percent in discounted terms."
- Scenarios 1 and 3 yield almost identical results; Scenarios 2 and 4 yield almost identical results — reflecting "the revenue equivalence of the cashflow surcharge and state participation when set at the same levels."
- All scenarios yield a lower government take than the recommended scenarios in the 2015 report due to either a lower royalty rate or lower rate for the additional rent capture mechanism.
- Breakeven prices and post-tax investor payback periods are very similar across scenarios, with payback periods "which range from 6.2 to 6.35 years from production."
- 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."

### Shale gas — capital depreciation treatments
- Analysis used the shale gas example from the 2015 report with the same project production and cost parameters and a gas price of "$8.8/MMbtu", generating a pre-tax project return of "18.5 percent" in real terms.
- The current uplift treatment (immediate expensing + generous uplifts) is very costly for shale gas because of repeated capital drilling expenditure.
- Current regime of immediate expensing with uplifts results in a "5 year delay in CIT payments relative to the alternative treatments."
- Even without uplifts, immediate expensing delays CIT payments by "2 years" compared with alternatives.
- Accelerated depreciation yields similar revenue results and time profile to the 5-year straight line depreciation combined with a "10 percent allowance for corporate capital (ACC)".
- 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 acceleration; a lower ACC rate would eliminate this discrepancy.

### Carbon tax analysis (South African Draft Carbon Tax Bill)
- Draft bill proposes a tax of "R120/ton" of emissions or CO2 equivalent.
- Large number of allowances could relieve "up to 95 percent of emissions in oil and gas production from the tax payable", particularly if oil and gas are treated as refined products.
- Global average CO2 emissions from petroleum extraction cited as "approximately 130 kg of CO2 per ton of oil equivalent", but figure usually lower for offshore operations.
- Analysis assumes emissions rate of "100kg per ton of oil equivalent".
- Table 5: Estimated carbon tax for the 500MMBbl project:
  - Total Oil Production MMBoE: "500"
  - Oil Production million tons: "68"
  - CO2 emissions million tons: "6.8"
  - Carbon Tax (without allowances) $mm real: "811"
  - Carbon Tax (with allowances) $mm real: "41"
- Fiscal impact examples:
  - Oil Price = "$50/bbl":
    - Value of Petroleum $mm real: "29,291"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "2.77%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.14%"
  - Oil Price at 2015 WEO prices:
    - Value of Petroleum $mm real: "38,544"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "2.10%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.11%"
  - Oil Price = "$80/bbl":
    - Value of Petroleum $mm real: "46,866"
    - Carbon Tax $mm real: "811"
    - Effective Royalty%: "1.73%"
    - Carbon Tax (with allowances) $mm real: "41"
    - Effective Royalty%: "0.09%"
- Assumptions used in carbon tax calculations:
  - Tons per barrel of oil equivalent: "7.4"
  - CO2 emissions rate (kg per ton of oil equivalent): "100"
  - Carbon Tax (Rand/kg of CO2): "120"
  - Allowances (% of total carbon tax payable): "95%"
- Key observation: "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."  
- The effective royalty burden from the carbon tax will decrease as prices increase because the tax is a monetary amount per ton of emissions.

*Source: _cr16259 - 13.      At the request of the DTC, a series of new scenarios was analyzed. The scenarios*

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_Source: https://www.imf.org/-/media/websites/imf/imported-full-text-pdf/external/pubs/ft/scr/2016/_cr16259.pdf_