Not all oil wells are created equal. A $9 million well in the Permian Delaware might generate twice the returns of an identical investment in the Bakken—or vice versa, depending on the specific location and operator.
This guide breaks down what drives well economics and how different basins compare.
The Cost Picture: What It Takes to Drill a Horizontal Well
Modern shale wells are horizontal wells—they drill down vertically, then turn and extend horizontally through the oil-bearing rock for thousands of feet. This allows a single well to access far more reservoir than a traditional vertical well.
Drilling & Completion Costs by Basin (2024)
| Basin | Total D&C Cost | Lateral Length | Cost per Foot | EUR (BOE) |
|---|---|---|---|---|
| Permian Delaware | $8.5-10.5M | 10,000 ft | $850-1,050 | 730,000-920,000 |
| Permian Midland | $8.0-10.0M | 10,000 ft | $800-1,000 | 600,000-750,000 |
| Eagle Ford | $8.5-10.0M | 8,000 ft | $1,060-1,250 | 230,000-470,000 |
| Bakken | $9.0-11.0M | 10,000 ft | $900-1,100 | 530,000-875,000 |
| SCOOP/STACK | $7.5-9.5M | 10,000 ft | $750-950 | 450,000-600,000 |
EUR = Estimated Ultimate Recovery—the total oil and gas expected over the well’s lifetime.
The Permian Delaware stands out: similar costs to other basins, but significantly higher expected production.
Where Your Money Actually Goes
When you invest in a drilling program, here’s how a typical $9M well breaks down:
Intangible Drilling Costs (IDC): 72% — Tax Deductible Year 1
| Item | Cost | % of Total |
|---|---|---|
| Drilling rig (25 days) | $750,000 | 8.3% |
| Frac services (the expensive part) | $2,500,000 | 27.8% |
| Frac sand/proppant | $600,000 | 6.7% |
| Drilling fluids | $400,000 | 4.4% |
| Directional drilling | $350,000 | 3.9% |
| All other IDC | $1,900,000 | 21.1% |
| IDC Subtotal | $6,500,000 | 72.2% |
Tangible Costs (TDC): 22% — Depreciated Over Time
| Item | Cost | % of Total |
|---|---|---|
| Casing & tubing | $1,200,000 | 13.3% |
| Wellhead equipment | $300,000 | 3.3% |
| Surface facilities | $500,000 | 5.6% |
| TDC Subtotal | $2,000,000 | 22.2% |
Contingency: 6%
| Item | Cost | % of Total |
|---|---|---|
| Contingency reserve | $500,000 | 5.6% |
| Total AFE | $9,000,000 | 100% |
The fact that 72% of well costs are immediately deductible (IDC) is why oil and gas investments are so tax-advantaged. But remember: a tax deduction on a losing investment is still a loss.
Breakeven Prices: When Wells Make Money
Cash breakeven = the oil price needed to cover ongoing operating costs Full-cycle breakeven = the oil price needed to recover ALL costs including the initial drilling investment
| Basin | Cash Breakeven | Full-Cycle Breakeven | Margin at $75 WTI |
|---|---|---|---|
| Permian Delaware | $35-40 | $56-62 | $13-19/bbl |
| Permian Midland | $38-45 | $62-68 | $7-13/bbl |
| Eagle Ford | $40-48 | $64-70 | $5-11/bbl |
| Bakken | $42-50 | $65-72 | $3-10/bbl |
| SCOOP/STACK | $35-42 | $58-65 | $10-17/bbl |
At $75 oil, the Permian Delaware has the best margins. But if oil drops to $55, all basins except the best Delaware and SCOOP/STACK wells are underwater on a full-cycle basis.
The Decline Curve: How Production Falls Over Time
This is the most important concept in oil and gas economics that most investors don’t understand.
Shale wells don’t produce steadily. They start strong and decline rapidly:
| Time Period | Daily Production | Cumulative | % of Total |
|---|---|---|---|
| Month 1 (peak) | 1,200 BOE/day | 36,000 | 6% |
| Month 6 | 600 BOE/day | 175,000 | 29% |
| Month 12 | 360 BOE/day | 280,000 | 47% |
| Month 24 | 220 BOE/day | 385,000 | 64% |
| Month 36 | 160 BOE/day | 450,000 | 75% |
| Year 5 | 100 BOE/day | 520,000 | 87% |
| Year 10+ | 40 BOE/day | 600,000 | 100% |
Key insight: Nearly half the oil comes out in the first year, and 75% in the first three years. This is why cash flow from oil wells is heavily front-loaded—and why operators need to keep drilling new wells just to maintain production.
Decline Phases
Flush Production (Months 1-6): Initial decline of 50-60%. This is when you get your biggest checks.
Primary Decline (Months 7-36): Annual decline of 25-35%. Still meaningful cash flow.
Secondary Decline (Years 4-10): Annual decline of 12-20%. Lower maintenance, but smaller distributions.
Tail Production (Years 10+): Annual decline of 5-8%. Minimal cash flow, but the well keeps producing.
What Makes a Good Well?
Here’s how to evaluate the wells in any program you’re considering:
| Metric | Poor | Average | Good | Excellent |
|---|---|---|---|---|
| EUR (total BOE) | <300,000 | 400-500K | 500-700K | >700,000 |
| D&C Cost | >$11M | $9-11M | $7-9M | <$7M |
| Initial Production | <500 BOE/d | 700-900 | 900-1,200 | >1,200 |
| Year 1 Decline | >75% | 65-75% | 55-65% | <55% |
| LOE (operating cost) | >$25/BOE | $18-25 | $12-18 | <$12 |
| Full-Cycle Breakeven | >$70 | $60-70 | $50-60 | <$50 |
If a sponsor shows you projections claiming 1,500 BOE/day initial production with only 50% decline and $45 breakeven, be skeptical. Those are top-decile numbers that most wells don’t achieve.
The Economics at Different Oil Prices
What happens to a $9M well at various oil prices?
| WTI Price | Gross Revenue | Net Cash Flow | ROI | IRR |
|---|---|---|---|---|
| $50 | $14.7M | $4.6M | -49% | Negative |
| $60 | $16.8M | $6.2M | -31% | 5% |
| $70 | $18.9M | $7.9M | -12% | 15% |
| $75 | $20.0M | $8.8M | -2% | 18% |
| $80 | $21.0M | $9.6M | +7% | 22% |
| $100 | $25.2M | $13.0M | +44% | 35% |
Assumptions: 600,000 BOE EUR, 80% NRI, $15/BOE operating costs, 70/30 oil-gas mix.
Notice that even at $75 oil (roughly today’s price), the straight ROI is slightly negative. The well returns your capital plus a small profit, but the IRR of 18% looks better because you get most of your money back in the first few years.
This is why tax benefits matter: a 37% bracket investor can add 8-10 points to their after-tax IRR from IDC deductions.
Multi-Well Economics: Why Pads Are Better
Drilling multiple wells from a single pad location significantly improves economics:
| Metric | 4 Single Wells | 4-Well Pad | Savings |
|---|---|---|---|
| Total Cost | $36.0M | $32.0M | $4.0M (11%) |
| Per Well Cost | $9.0M | $8.0M | $1.0M each |
| Drilling Time | 100 days | 80 days | 20 days |
Sponsors who drill in pad development (multiple wells at once) generally achieve better returns than those drilling single wells. Ask about development strategy when evaluating programs.
Key Takeaways
- Basin selection matters: The Permian Delaware has the best current economics, but that can change
- Decline curves are steep: Expect 50%+ decline in year one—projections assuming gentler declines are often unrealistic
- Full-cycle breakeven is what matters: Cash breakeven is irrelevant if you never recover your drilling costs
- Most wells are average: Be skeptical of projections showing excellent metrics across the board
- Tax benefits help but don’t save bad deals: An 8-10 point IRR boost doesn’t fix a well that loses money pre-tax
Questions to Ask About Any Drilling Program
- What basin and specific formation are the target wells in?
- What are the D&C costs per well, and how does that compare to industry averages?
- What EUR assumptions are you using, and how do they compare to offset wells?
- What decline curve model are you using?
- What oil price does the model assume, and what happens if oil drops 20%?
- Are these single wells or pad development?
A sponsor who can’t answer these questions clearly—or who gets defensive when asked—is probably not someone you want managing your capital.
Data reflects 2024 market conditions. Actual economics vary by specific location, operator efficiency, and market conditions. This is educational content, not investment advice.