Economic Impact of Fiscal Incentives on Chemical Enhanced Oil Recovery (CEOR) Project: A Case Study of the Berani Oil and Gas Field

This research evaluates the financial performance of the Chemical Enhanced Oil Recovery (CEOR) project in the Berani Field, managed by Pertama Energy, with a focus on the influence of government incentives on its economic feasibility. The study examines critical financial metrics, including Net Present Value (NPV), Internal Rate of Return (IRR), Payback Period, and Profitability Index (PI), under scenarios both with and without government incentives. By comparing these metrics, the research aims to quantify the economic advantages provided by government support and their role in enhancing project viability. Based on the findings, strategic recommendations are proposed to optimize project economics, including cost management, operational efficiencies, and policy alignment with stakeholder needs. This research contributes valuable insights for industry stakeholders, policymakers, and decision-makers, offering practical guidance on leveraging government incentives to maximize economic returns and promoting investment strategies tailored to the oil and gas sector’s dynamic landscape. This study also emphasizes the potential of innovative recovery technologies in driving sustainable growth in the upstream oil and gas industry.

Introduction

The Indonesian government has set a target to achieve oil production of one million barrels per day and gas production of 12 BSCFD by 2030. Efforts to meet this target include accelerating the implementation of Enhanced Oil Recovery (EOR) technology in promising fields.

One of the most widely used and effective Enhanced Oil Recovery (EOR) techniques is Chemical Enhanced Oil Recovery (CEOR). This method involves the strategic use of specialized chemicals to extract oil from reservoirs that would otherwise remain unrecoverable using conventional methods.

Based on an internal assessment, the Berani Field has been identified as highly suitable for the application of CEOR. Implementing this technology in the field is expected to significantly enhance the recovery factor, enabling more efficient extraction of oil from the reservoir while maximizing its potential. This makes CEOR a promising approach for unlocking additional value from the Berani Field’s hydrocarbon resources.

Literature Study

Pertama Energy manages the Makaram Block as an Operator under a Production Sharing Contract (PSC) with SKK Migas for a 20-year term. The Berani Field which is part of the Makaram Block, is the primary focus of this project investment analysis. The Production Sharing Contract (PSC) is the cornerstone of Indonesia’s upstream oil and gas fiscal regime. Fig. 1 provides a comprehensive overview of how revenues are allocated under Indonesia’s PSC framework. For CEOR projects as in Berani field, a well-designed PSC model preferably with cost recovery or enhanced contractor shares is essential to attract investments while ensuring national energy security.

Fig. 1. PSC scheme illustration.

Government incentives play a crucial role in stimulating investments in the oil and gas sector, particularly for high-risk ventures like Enhanced Oil Recovery (EOR) and marginal field development. These incentives can include tax reliefs, production-sharing adjustments, royalty reductions, and direct subsidies. According to Johnston (1994), fiscal regimes are often tailored to mitigate the capital intensity and technological uncertainty associated with upstream projects. For example, Norway’s tax refund scheme for exploration costs has been a cornerstone in attracting investments in its offshore resources (Thurberet al., 2011).

Methodology

By integrating mathematical modelling and comparative financial analysis, sensitivity analysis, and probabilistic analysis, the CEOR project valuation achieves both depth and breadth. Mathematical modeling establishes baseline metrics, sensitivity analysis identifies critical drivers, and probabilistic analysis quantifies uncertainties, creating a robust framework for evaluating the project’s economic viability.

These methods collectively ensure informed and data-driven decision making. Mathematical modelling involves creating representations of financial processes using equations and quantitative data. It is used to calculate key financial metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), and Payback Period (PP), which form the foundation for project valuation.

The combination of primary data from the company and secondary data from literature and publications ensures a comprehensive evaluation of the CEOR project. Table I summarizes the data collection method used in this research.

Table I. Data Collection Method

Data source	Method	Data type	Purpose
Company project data	Reports, archives, company procedure	Financial (OPEX, CAPEX, other parameters, etc.), technical (Production, Project data, etc.)	Detailed inputs for economic models, sensitivity analysis, probability analysis and risk assessments.
Regulatory bodies	Policy analysis	Fiscal, regulatory	Evaluation of government incentives and compliance requirements.
Industry reports & journals	Archival research	Market, contextual	Oil price trends, global benchmarks, and market conditions.
Academic publication	Literature review	Theoretical, methodological	Benchmarking economic models, identifying CEOR trends and innovations.

In Indonesia’s Production Sharing Contract (PSC) system, cost recovery refers to the mechanism through which contractors recover their exploration, development, and operating costs incurred during upstream operations. Costs are deducted from the gross revenue before the remaining profit is shared between the government and the contractor based on the agreed-upon profit-sharing formula. This system ensures contractors are incentivized to invest while the government retains control over resource management.

The First Tranche Petroleum (FTP) is a distinctive feature of Indonesia’s Production Sharing Contract (PSC) framework, designed to ensure that the government receives a share of production regardless of whether the contractor has recovered their costs. This mechanism reflects the government’s priority to secure immediate revenue from resource extraction activities. Under Pratama Energy’s PSC Amendment III, the FTP rate was reduced to 5% of gross production as part of a government incentive package aimed at encouraging investment in upstream oil and gas projects.

$$\begin{array}{r}\text{FTP}=\text{5}\text{\% }\times \text{Gross}\text{Revenue}\end{array}$$

The Domestic Market Obligation (DMO) is a policy mechanism aimed at ensuring a sufficient supply of crude oil for the domestic market. Under this requirement, contractors are obligated to sell and deliver a portion of their crude oil entitlement to the Government of Indonesia (GOI). Additionally, contractors must deliver and sell up to 25% of their gas entitlement to domestic gas buyers to support local energy demand.

Contractor Take refers to the portion of revenue from oil and gas production that remains with the contractor after the host government’s share is allocated. It represents the contractor’s compensation for the risks, capital, and expertise provided during exploration, development, and production activities under the PSC framework.

$$\begin{array}{rcl}& & \text{Contractor Cash Flow}\\ & & =(\text{CTR FTP}+\text{Investment Credit}+\text{Cost Rec}.\\ & & +\text{CTR ETBS})-(\text{DMO}+\text{Tax})\\ & & -(\text{CAPEX}+\text{OPEX})\end{array}$$

Government Take refers to the portion of revenues from oil and gas production that the government receives under a Production Sharing Contract (PSC).

$$\begin{array}{rcl}& & \text{Government}\text{of}\text{Indonesia}\left(\text{GOI}\right)\\ & & =(\text{GOI}\text{FTP}+\text{GOI}\text{ETBS}\\ & & +\text{DMO}+\text{TAX})\end{array}$$

Capital budgeting is the process of evaluating and selecting long-term investment projects to determine profitability and viability. It is a critical financial management tool for companies to decide whether to undertake major projects such as developing new facilities, launching new products, or exploring oil and gas fields.

In the context of upstream oil and gas projects, such as in a Production Sharing Contract (PSC), capital budgeting helps assess the economic feasibility of exploration, development, and production activities under uncertainty and high capital costs.

Discounted cash flow (DCF) methods account for the time value of money by discounting future cash flows to their present value. This approach is essential for evaluating oil and gas projects, providing a robust and comprehensive measure of their financial viability while addressing risk and long-term cash flow considerations.

NPV is a financial metric used to evaluate the profitability of an investment by calculating the difference between the present value (PV) of cash inflows and the present value of cash outflows over a project’s lifetime. In upstream oil and gas, NPV is widely used for project appraisal to determine whether exploration, development, and production activities will generate sufficient returns. Oil and gas projects often span decades, with revenues distributed over time. NPV accounts for the time value of money, ensuring future cash flows are appropriately discounted.

$$\begin{array}{r}\text{NPV}=\sum _{\text{t}=\text{1}}^{\text{n}}\frac{\text{C}{\text{F}}_{\text{t}}}{{(\text{1}+\text{r})}^{\text{t}}}-\text{C}{\text{F}}_{\text{0}}\end{array}$$

where

CF_t – net cash inflow/outflow in year t

R – discount rate (reflecting risk and opportunity cost)

t – time period (years)

CF₀ – initial investment cost

IRR represents the discount rate at which the NPV of a project equals zero. It provides a percentage return expected from the project, helping compare it to the required rate of return or hurdle rate. Projects with an IRR higher than the discount rate are generally accepted. Upstream oil and gas projects are subject to price volatility, reservoir uncertainties, and cost overruns. IRR provides a percentage-based return measure to balance these risks.

$$\begin{array}{r}\text{\$ }\text{0}=\sum _{\text{t}=\text{1}}^{\text{n}}\frac{\text{C}{\text{F}}_{\text{t}}}{{(\text{1}+\text{IRR})}^{\text{t}}}-\text{C}{\text{F}}_{\text{0}}\end{array}$$

where

CF_t – net cash inflow/outflow in year t

t – time period (years)

CF₀ – initial investment cost

The Profitability Index (PI) is a financial metric used to evaluate the attractiveness of an investment by comparing the present value (PV) of future cash inflows to the initial investment. It is also known as the Benefit-Cost Ratio (BCR). In upstream oil and gas projects, PI helps assess whether a project will generate sufficient value relative to its cost. PI enables ranking of projects with varying costs and scales, ensuring optimal use of limited resources. This is particularly useful when comparing large projects like offshore developments with smaller, marginal fields.

$$\begin{array}{r}\text{Profitability}\text{Index}\left(\text{PI}\right)=\frac{\text{PV}\text{of}\text{Future}\text{Cash}\text{Flows}}{\text{Initial}\text{Investment}}\end{array}$$

where

PV of Future Cash Inflows – the present value of all future cash inflows, discounted at an appropriate rate (e.g., WACC or hurdle rate)

Initial Investment – the total upfront capital required for the project

In the upstream oil and gas industry, the payback period is often used as a quick measure to determine how long it will take to recover substantial capital investments in exploration and production.

$$\begin{array}{r}\text{Payback}\text{Period}=\frac{\text{Initial}\text{Investment}}{\text{Anual}\text{Cash}\text{Flow}}\end{array}$$

The Weighted Average Cost of Capital (WACC) represents the opportunity cost of using capital and is a critical parameter in project evaluation, including in the upstream oil and gas sector. WACC is used as the discount rate in Discounted Cash Flow (DCF) analysis to determine the present value of future cash flows. Oil and gas projects face significant risks, including commodity price volatility, regulatory changes, and geological uncertainties. WACC reflects these risks through its components, particularly the cost of equity. Projects with an Internal Rate of Return (IRR) higher than the WACC are considered value-accretive, as they generate returns exceeding the cost of capital.

$$\begin{array}{r}\text{WACC}=\left({\text{w}}_{\text{i}}\text{x}{\text{r}}_{\text{i}}\right)+\left(w_s\text{x}{r}_s\right)\end{array}$$

where

WACC – weighted average cost of capital

w_i – proportion of long-term debt in the capital structure

r_i – cost of long-term debt

w_s – proportion of equity in the capital structure

r_s – cost of equity

Sensitivity analysis plays a crucial role in evaluating the economic viability and resilience of Chemical Enhanced Oil Recovery (CEOR) projects. These projects are characterized by high capital expenditures (CAPEX), significant operational expenditures (OPEX), and long-term uncertainties related to oil production levels and market dynamics. Conducting sensitivity analysis allows stakeholders to understand how fluctuations in key parameters impact project outcomes, such as Net Present Value (NPV), Internal Rate of Return (IRR), and Payback Period (PP). This insight is essential for informed decision-making and risk management, particularly in the context of upstream oil and gas projects.

Probability analysis is a key component of project evaluation, particularly for high-risk, capital-intensive endeavors such as Chemical Enhanced Oil Recovery (CEOR) projects. Unlike deterministic approaches that rely on fixed input assumptions, probability analysis incorporates the variability and uncertainties inherent in the key parameters influencing project outcomes. This method provides a more comprehensive understanding of the economic risks and helps stakeholders make informed decisions about project feasibility and investment.

Monte Carlo simulations provide a sophisticated approach to understanding the economic risks and uncertainties associated with CEOR projects. This method equips stakeholders with actionable insights for decision-making and risk mitigation (Palisade Corporation, 2021).

Finding and Discussion

Berani Chemical Enhanced Oil Recovery (CEOR) project is part of the Pertama Energy’s Long-Term Plan for the tertiary development of the Berani oil and gas field in the Makaram Block. The company’s current aspiration is to conduct a pilot test by 2027 and achieve full-scale field implementation by 2030. This project is expected to achieve a cumulative production of 12.7 million barrels (MMbbl) of oil and 5.7 billion cubic feet (Bcf) of gas. The detailed annual production forecast is illustrated in Fig. 2.

Fig. 2. Production profile: (a) oil production, barrel/day and (b) gas production rate, MMSCFD.

The estimated capital expenditure (CAPEX) for this project is approximately USD 98.13 million USD23 or USD 113.91 million USD_MOD (Money of the Day), assuming an annual inflation rate of 2.5% as the basis for calculation. The estimated operating expenditure (OPEX) for this project is approximately USD 506.75 million USD₂₃ or USD 609.58 million USD_MOD (Money of the Day), assuming an annual inflation rate of 2.5% as the basis for calculation. Tables II and III summarize CAPEX and OPEX, respectively.

Table II. CAPEX Breakdown Summary

Parameter	Unit	2023	2024	2025	2026	2027	2028	2029	2030	Total
CAPEX	Million USD23	3.95					4.73	30.40	59.05	98.13
	Million USDMOD	4.24					5.33	34.96	69.38	113.91

Table III. OPEX Breakdown Summary

Parameter	Unit	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034	2035	2036	2037	Total
OPEX	Million USD23	0.83	0.83	0.83	4.91	41.19	32.78	58.17	110.12	67.96	23.71	55.66	24.65	55.06	19.22	10.83	506.75
	Million USDMOD	0.83	0.85	0.87	5.28	45.31	36.88	66.90	129.39	81.55	29.04	69.58	31.43	71.58	25.47	14.63	609.58

Scenario Without Government Incentives

In this scenario, the evaluation is conducted based on the initial terms of the PSC agreement, prior to the incentives being granted to Pertama Energy. Fig. 3 presents the net cash flow (NCF) for both the Contractor (CTR) and Government of Indonesia (GOI) across the project timeline, along with their cumulative cash flows.

Fig. 3. Net cash flow of non-incentives scenario.

The chart indicates that the project achieves positive cash flows for both parties, validating its economic feasibility under the modeled assumptions. However, the long payback period for the contractor emphasizes the need for strong financial resilience and possibly enhanced fiscal terms.

This cash flow figure demonstrates the shared economic benefits of the CEOR project under the PSC framework. While the government secures significant early returns, the contractor faces extended payback periods, emphasizing the importance of favorable fiscal terms and cost management. The positive long-term trends for both parties validate the project’s viability, provided key risks such as oil price volatility and cost overruns are effectively managed.

The summary of the discounted cash flow analysis for this scenario (without incentives) is presented in Table IV. The results indicate a positive Net Present Value (NPV) of 3.32 million USD, an Internal Rate of Return (IRR) of 13%, and a Profitability Index (PI) of 1.05. These key financial indicators suggest that, even in the absence of incentives, the project remains economically viable. However, the figures highlight that the feasibility is marginal, as the metrics are close to the threshold values typically used for investment decisions. This underscores the importance of carefully managing costs and mitigating risks to ensure sustained profitability.

Table IV. DCF Summary of Non-Incentives Scenario

PSC	Unit of measurement	Contractor (Pertama energy) & BUMD
Cash in stream
FTP	Million USD	64.78
Cost recovery	Million USD	758.00
Contractor split	Million USD	(2.79)
Investment credit	Million USD	–
Total revenue stream	Million USD	819.99
DCF revenue	Million USD	367.89
Cash out stream
CAPEX	Million USD	(113.91)
OPEX	Million USD	(638.40)
Abandonment	Million USD	(5.70)
DMO	Million USD	(5.79)
TAX	Million USD	(20.37)
Total cost stream	Million USD	(784.17)
DCF cost	Million USD	(364.57)
Net cash flow	Million USD	35.82
Discounted net cash flow (NPV)	Million USD	3.32
IRR		13%
Payback period		2033
Profitability index		1.05

The results of the sensitivity analysis are presented in Table V and corresponding spider chart (Fig. 4). These visualizations provide a clear depiction of how variations in key parameters impact the project’s economic performance. For this analysis, Microsoft Excel Add-In (Crystal Ball) is used to perform simulation. Net Present Value (NPV) is utilized as the primary metric to evaluate the project’s sensitivity to changes in critical factors, such as oil prices, production levels, CAPEX and OPEX.

Table V. Sensitivity Analysis of Non-Incentives Scenario

Input variable	60%	80%	100%	120%	140%
ICP	(27.70)	(12.23)	3.32	18.95	34.57
Prod oil	(27.70)	(12.23)	3.32	18.95	34.57
OPEX	29.22	16.27	3.32	(9.63)	(22.48)
CAPEX	10.03	6.68	3.32	(0.03)	(3.39)

Fig. 4. Spider chart of non-incentives scenario.

The sensitivity analysis results for the non-incentive scenario, as shown in the table and spider chart, reveal how changes in key input variables Indonesian Crude Price (ICP), Production Oil, Operational Expenditures (OPEX), and Capital Expenditures (CAPEX) affect the Net Present Value (NPV) for the contractor. At the base case (100% for all variables), the NPV is 3.32 million USD, which is positive but close to the breakeven point. Any significant decrease in ICP, production, or increase in OPEX will lead to a negative NPV. This indicates that the project is economically feasible under the base case but remains highly marginal. Without incentives, there is little buffer to absorb adverse changes in key variables.

Probability analysis is a key component of project evaluation, particularly for high-risk, capital-intensive endeavors such as Chemical Enhanced Oil Recovery (CEOR) projects.

Out of 1000 trials, the probability of NPV > 0 is approximately 55%, as NPV becomes positive at the 45th percentile. There is a slightly better than even chance that the project will be economically viable, but the probability of achieving a significant positive NPV is limited. Table VI and Fig. 5 provide a comprehensive summary of the probability analysis results for scenarios without incentives.

Table VI. Probability Summary of Non-Incentives Scenario

Parameter	NPV · CTR	CAPEX	ICP	OPEX	Prod oil
Trials	1000	1000	1000	1000	1000
Base case	3.32	100%	100%	100%	100%
Mean	4.02	100%	100%	100%	101%
Median	3.10	99%	100%	100%	101%
Standard deviation	19.60	15%	15%	15%	15%
Variance	384.24	2%	2%	2%	2%
Skewness	0.2494	−0.0256	0.0705	0.0911	0.0827
Kurtosis	3.37	3.07	3.02	3.14	3.10
Coeff. of variation	4.87	0.1514	0.1512	0.1525	0.1513
Minimum	(58.80)	48%	55%	50%	55%
Maximum	83.31	149%	154%	150%	161%
Range width	142.11	101%	98%	100%	106%
Mean std. error	0.62	0%	0%	0%	0%

Fig. 5. Cumulative distribution of non-incentives scenario.

Scenario with Government Incentives

In this scenario, the evaluation follows the terms outlined in PSC Amendment III, which includes fiscal incentives for the Makaram Block, operated by Pertama Energy. These incentives aim to improve the project’s economic viability by addressing key financial and operational challenges in the block.

Fig. 6 presents the net cash flow (NCF) for both the Contractor (CTR) and Government of Indonesia (GOI) across the project timeline, along with their cumulative cash flows. The contractor bears significant upfront costs, a common characteristic of capital-intensive upstream oil and gas projects like CEOR. These negative cash flows underscore the need for robust financing or government incentives to support project economics during the early phases.

Fig. 6. Cash flow of incentives scenario.

The summary of the discounted cash flow analysis for this scenario is presented in Table VII. The results indicate a positive Net Present Value (NPV) of 7.75 million USD, an Internal Rate of Return (IRR) of 17%, and a Profitability Index (PI) of 1.13. The government incentives reduce the financial burden on the contractor, accelerated cost recovery, reduced tax obligations, improving liquidity during the high CAPEX and OPEX phase and ensuring a more balanced partnership under the PSC framework. Without these incentives, the project remains financially viable but is far more sensitive to operational and market risks.

Table VII. DCF Summary of Incentif Scenario

PSC	Unit of measurement	Contractor (Pertama energy) & BUMD
Cash in stream
FTP	Million USD	16.19
Cost recovery	Million USD	729.18
Contractor split	Million USD	55.92
Investment credit	Million USD	–
Total revenue stream	Million USD	801.30
DCF revenue	Million USD	359.95
Cash out stream
CAPEX	Million USD	(113.91)
OPEX	Million USD	(609.58)
Abandonment	Million USD	(5.70)
DMO	Million USD	(5.79)
TAX	Million USD	(24.04)
Total cost stream	Million USD	(759.02)
DCF cost	Million USD	(353.93)
Net cash flow	Million USD	42.28
Discounted net cash flow (NPV)	Million USD	6.02
IRR		15%
Payback period		2033
Profitability index		1.10

The results of the sensitivity analysis are presented in Table VIII and corresponding spider chart (Fig. 7). The sensitivity analysis for this scenario reveals that ICP, oil production, and OPEX are the primary drivers of project profitability. Although investment credit contributes to improving financial performance, its impact is relatively minor compared to these key variables. To maximize the benefits of the incentives and enhance project viability, Pertama Energy should focus on optimizing production, and controlling costs. These strategies will help mitigate downside risks and unlock the project’s full economic potential.

Table VIII. Sensitivity Analysis of Incentives Scenario

Input variable	60%	80%	100%	120%	140%
Prod oil	(26.06)	(10.12)	6.02	22.17	38.32
ICP	(26.06)	(10.12)	6.02	22.17	38.32
OPEX	30.84	18.43	6.02	(6.38)	(18.79)
CAPEX	12.73	9.38	6.02	2.67	(0.68)

Fig. 7. Spider chart of incentives scenario.

The probability analysis for the scenario with incentives highlights the improved financial viability of the project, with ~70% probability of achieving a positive NPV. However, the variability in key parameters, particularly production oil, ICP, and OPEX, still poses significant risks. To maximize the benefits of the incentives, the focus should remain on optimizing production, managing costs, and mitigating oil price volatility. These measures will enhance the project’s resilience and ensure sustainable profitability under this scenario. Table IX and Fig. 8 provide a comprehensive summary of the probability analysis results for scenario with incentives.

Table IX. Probability Summary of Incentives Scenario

Parameter	NPV · CTR	CAPEX	ICP	OPEX	Prod oil
Trials	1000	1000	1000	1000	1000
Base case	6.02	100%	100%	100%	100%
Mean	5.75	100%	100%	101%	100%
Median	5.47	100%	100%	101%	100%
Standard deviation	19.76	15%	16%	16%	15%
Variance	390.49	2%	2%	2%	2%
Skewness	0.3019	0.0215	0.0424	0.0803	0.1416
Kurtosis	3.08	2.94	2.97	2.83	3.04
Coeff. of variation	3.43	0.1497	0.1556	0.1549	0.1539
Minimum	(47.42)	54%	54%	58%	55%
Maximum	71.21	148%	148%	151%	158%
Range width	118.63	93%	94%	93%	103%
Mean std. error	0.62	0%	0%	0%	0%

Fig. 8. Cumulative distribution of incentives scenario.

Conclusion

Government incentives are essential for the economic viability of the Berani CEOR project. They significantly improve financial metrics such as NPV, IRR, PI, and payback period, making the project more attractive to investors.

Sensitivity analysis highlights the importance of key economic parameters, particularly oil price, production rates, and operating costs, in determining project feasibility.

Monte Carlo simulations further enhance the understanding of economic risks, providing a robust framework for risk management and informed decision-making.

By leveraging fiscal incentives and managing critical economic factors effectively, the Berani CEOR project can achieve financial success while mitigating potential risks.