Simprug Field · Integrated field development · Economic analysis
An interactive case study of my role as an Economic Analyst in evaluating the commercial viability of an integrated oil & gas field development.
02My role
Every discipline in the team produced assumptions. My job was to turn all of them into one answer: is this development worth the capital it needs — and in which form?
Reservoir Engineering
Oil in place, recovery, scenario design
Production Engineering
Well performance, artificial lift
Drilling
Well design and drilling cost basis
Facilities
Separation, storage, flowline network
Commercial Strategy
Fiscal terms and investment criteria
Economic analyst
Economic decision support
Cost, fiscal terms, cashflow and risk in one model
Development scenario
Fiscal framework
Investment recommendation
Full economics scope
01 · Inputs
What will the field produce, and when?
02 · Cost
What does it take to build and run?
03 · Fiscal
How is value shared with the state?
04 · Value
Is it worth the capital?
03Field to value
The chain from rock to recommendation. The first four links are produced by the reservoir, drilling, production and facilities work. From cost onwards, the analysis is mine.
How much oil could be there?
905.6 MMSTB original oil in place (reservoir simulation model)
Executive summary, p. 7
How many producers, and when?
15 or 30 producers, drilled in phases 2022–2024
Tables 4.3–4.4, pp. 33–36
How much can be recovered?
Recovery factor 12.9% (A) vs 21.6% (B)
Table 4.5, p. 38
What must be built to handle it?
50,000 bbl/d separation, 6.8 km flowline, ESP lift
Executive summary, p. 7
Economic analyst scope begins
What does it cost to build and run?
Drilling, flowlines, surface facilities, crew, workover, ESP
Table 8.2, pp. 70–71
Who takes which share?
Gross Split: base 43% contractor / 57% government
Section 8.1, p. 69
When does money come back?
20-year horizon, 2019–2039, discounted at 10%
Sections 4.1.2 & 8.3
Is the value worth the capital?
Both scenarios clear the DPI hurdle of 1.6
Section 8.3, p. 74
Which development should be backed?
Scenario B, under Gross Split
Section 9, pp. 78–79
04Development strategy
The reservoir and production team proposed two development scales for a 20-year life. My task was to show how the extra scale changes investment, production, cost and value — together.
15
producing wells · Base case + 12 new producers (10 in 2022, 2 in 2023)
30
producing wells · Scenario A + 15 producers (9 in 2023, 6 in 2024)
Source: Tables 4.3–4.5 (production), Table 8.2 (cost), Tables 8.3–8.4 (economics). Log scale.
What the ladder says
Doubling the wells doubled drilling spend and needed a ten-times larger surface facility. It also lifted recovery 1.7× and NPV by 78% — while pay out time moved by only 0.07 years. The extra scale paid for itself.
05Cost of development
The raw cost table mixes units, so the useful question is not the totals but how each cost behaves when the development scales from 15 to 30 wells.
Capital deployment
Fixed
Same in both scenarios, regardless of well count.
Exploration investment
A → Bunchanged
Scales with wells
Grows in step with the number of producers.
Drilling & completion
A → B×2.0
Steps with capacity
Jumps when throughput needs a larger network or plant.
Flowline network
A → B×3.3
Surface facilities
A → B×10.0
Keeping the field producing
Fixed
Same in both scenarios, regardless of well count.
Crew
A → Bunchanged
Field operations
A → Bunchanged
Scales with wells
Grows in step with the number of producers.
Workover
A → B×2.0
ESP (artificial lift)
A → B×2.0
Steps with capacity
Jumps when throughput needs a larger network or plant.
Source: Table 8.2 (Rincian Pengeluaran), pp. 70–71. Bars show the ratio of Scenario B to Scenario A totals on a log scale (1×–10×).
Reading
CAPEX grows in steps; OPEX grows with wells. Drilling, workover and ESP double with the well count, while the flowline network and surface plant jump to a new capacity class.
Exploration, crew and field operations stay fixed — so in the larger development they are carried by roughly 1.7× the recovered oil.
06Fiscal framework
In Indonesia, production is shared between the contractor and the state. The contract decides when costs come back and how big each share is — so it changes the value of the same field.
Option 1
Conceptual widths. Split after cost recovery: contractor 15% / government 85% for oil. Strength: faster recovery of capital spent.
Option 2 · selected
Base split, adjusted by variable components (block status, field location, reservoir depth, infrastructure…) and progressive components (local content, production phase, oil price). The contractor funds all costs from its share.
The evidence
At the end of the 20-year horizon, Gross Split left the contractor with roughly 2–3× the discounted cashflow of Cost Recovery, in both scenarios.
Scenario A
≈2.2×
Scenario B
≈2.8×
Approx. — read from report chartSource: Figures 8.3 and 8.5 (PSC vs Gross Split discounted 10% cashflow), pp. 72–73. Contractor cumulative discounted cashflow at 2039.
07Cashflow
Each year of the 20-year life (2019–2039) becomes one line of cashflow. Discounting those lines at 10% turns a production profile into a single present value.
The shape of the investment
Both scenarios spend first — wells, flowlines and facilities — and only then earn. The curve bottoms out during build-out and turns positive once the new wells are on stream.
B spends more before it earns, then climbs faster and ends 1.8× higher.
Approx. — read from report chartSource: Figures 8.3 and 8.5, pp. 72–73. Contractor, Gross Split, 10% discount rate; end values match the reported NPV.
08Economic performance
I read the five indicators together rather than chasing one number. Each answers a different investor question: how much, how fast, how efficient.
NPV @ 10%
Present value of all future contractor cashflows, discounted at 10%.
A12,111
B21,596
B +78%
Value creation
Value added to the company by the development strategy.
A13,332
B23,176
B +74%
IRR
Discount rate at which the project's NPV becomes zero.
A52%
B57%
B +5 pts
DPI
Discounted profitability index: discounted net return per unit of discounted investment.
A6.95
B9.20
B +32%
Pay out time
Pay out time: years until cumulative cashflow recovers the investment.
A3.29 yrs
B3.36 yrs
Near tie: B pays back 0.07 yrs later
Source: Tables 8.3 and 8.4, p. 74. NPV and Value Creation are shown as reported by the project economic model (contractor, Gross Split, 10% discount rate).
Interpretation
Four of five indicators favour B by a clear margin; the fifth, pay out time, is effectively a tie. That consistency — not one large NPV — is what made the recommendation robust.
09Sensitivity
Which assumption could break the case? I flexed each input by 30% up and down and watched the contractor NPV.
Revenue
Production volume × oil price
Cost driver
CAPEX / OPEX (larger effect)
Cost driver
CAPEX / OPEX (smaller effect)
Source: Spider analysis, contractor NPV, Gross Split (Section 8.4, pp. 76–77). The chart legend in the report is cropped, so the two cost lines are shown together as CAPEX / OPEX.
±48%
NPV swing from a 30% change in revenue — price or volume.
≤ ±15%
Largest swing from the same change in a cost line.
Every tested case stays NPV-positive.
The economic risk sits in production delivery and oil price, not in cost overruns — so that is where monitoring and contingency should focus.
10Decision
The technical case said Scenario B recovers the most oil. The economic case had to show that the extra wells, flowlines and plant would repay themselves — and under which contract. Both answers pointed the same way.
Scenario B · 30 producers
Selected development
Selected economic framework
Source: Sections 8.3 and 9, pp. 73–79.
Technical potential becomes investment value only when someone can show the numbers behind it.
11What this project taught me