Intangible Drilling Costs: Everything an Accredited Investor Needs to Know
This is the complete reference guide to intangible drilling costs for accredited investors — from the basic definition through §1254 recapture on sale, the OBBBA 2025 changes, K-1 filing, AMT modeling, and how to size a position for your specific tax situation. For the shorter, decision-focused version, see the main IDC page. If you want everything, you are in the right place.
Request Your Program OverviewWhat Qualifies as an Intangible Drilling Cost?
Tangible drilling costs cover the physical equipment and infrastructure that remain part of the well after drilling is complete — the casing itself, the wellhead assembly, the pump, the separator, the storage tank. These retain value and are recovered through depreciation under §168. The One Big Beautiful Bill Act (OBBBA, July 2025) permanently restored 100% §168(k) bonus depreciation, meaning the TDC equipment component is now also fully deductible in Year 1.
| Intangible Drilling Costs (IDC) — §263(c) | Tangible Drilling Costs (TDC) — §168(k) |
|---|---|
| Drilling rig day rates and drilling services | Casing and tubing |
| Fuel, power, and consumable drilling inputs | Wellhead assemblies and flow-control equipment |
| Drilling fluids, mud systems, and chemicals | Pumps and artificial lift equipment |
| Drilling and completion labor | Tanks, separators, and production vessels |
| Cementing, wireline, and completion services | Surface production equipment and facilities |
| §263(c): Deductible in full in Year 1 — a permanent reduction, not a deferral | §168(k): 100% deductible Year 1 — permanently restored by OBBBA July 2025 |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Illustrative categories only. Actual classification depends on program structure, operator reporting, and the specific facts of each well. Consult your CPA.
Why Accredited Investors Pay Attention to Intangible Drilling Costs
Why Intangible Drilling Costs Remain the Most Powerful Deduction for High-Income W-2 Earners
The appeal is direct. If you sit in the 35% or 37% federal bracket, a legitimate current-year deduction against active income materially reduces your after-tax cash exposure in the year of drilling. Intangible drilling costs are not a novel strategy — the §263(c) provision has been in the tax code since 1913, survived every major reform including TCJA, and was strengthened by the OBBBA in July 2025.- Meaningful current-year deduction — 65–80% of total program cost is typically classified as intangible drilling costs
- Direct participation in domestic development drilling — not a fund, not a stock, not a REIT
- §469(c)(3) active income classification — intangible drilling costs deductions offset W-2 wages with zero hours required
- Long-term production income from the same asset — monthly distributions for 20–30+ years
- §613A 15% percentage depletion on production income — perpetually, even after full cost recovery
★The right question is not 'How large is the projected deduction?' The better question is: How does this specific program work, how will the operator report costs, and how does it look when your CPA models it against your full tax picture? Texas Oil Investments facilitates introductions to programs where those questions have clear, verifiable answers.
The §263(c) Election: How Intangible Drilling Costs Are Deducted
Before relying on IDC treatment, verify each of the following directly from offering documents or the operator:
- Program structure: non-limiting LLC or general partnership — limited partnership does NOT qualify for §469(c)(3) active income treatment
- Operator's planned intangible drilling costs / TDC allocation — confirm from the line-item AFE, not a headline percentage
- Projected drilling and spud timeline — must align with your tax year (spud date before December 31)
- §263(c) election statement — included in offering documents or available on written request
- Prior year K-1 samples from the operator — your CPA should verify reporting consistency before you subscribe
§469(c)(3): The Provision That Makes Intangible Drilling Costs Usable for W-2 Earners
| Feature | Oil Working Interest (§469c3) | Real Estate (without REPS) |
|---|---|---|
| Offsets W-2 wages directly | ✓ Yes — automatic, no election | ✗ Passive only — suspended losses |
| Hours required | ✓ None — zero hours required | ✗ 750+ hrs/yr (REPS) — impossible for most professionals |
| NIIT (3.8%) applies | ✓ Exempt — active income classification | ✗ Yes — passive income subject to NIIT |
| Year 1 deduction rate | 65–80% IDC + 20–35% TDC (post-OBBBA: approaching 100%) | Spread over 27.5–39 years via depreciation |
| Ongoing tax benefit | §613A depletion 15% of gross income — perpetually | Depreciation ends when adjusted basis reaches zero |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Illustrative comparison. Actual treatment depends on structure, at-risk rules, basis, AMT, state law, and investor-specific circumstances. Not tax advice.
For high-income professionals — physicians, attorneys, executives, and business owners — this distinction is not academic. Real Estate Professional Status requires 750+ hours per year and 50%+ of all working time in real estate. A physician working 50 hours per week in clinical practice spends 2,600 hours annually in medicine. The REPS hours requirement is simply not achievable for most full-time professionals. The §469(c)(3) exception for intangible drilling costs requires nothing — it is automatic based on entity structure. See the full comparison on our Oil Investments vs Real Estate — The Tax Analysis for W-2 Earners page.
The OBBBA (2025): What Changed for Intangible Drilling Costs Programs
| §168(k) Bonus Depreciation — Permanently Restored to 100% | |
|---|---|
| Before OBBBA: | §168(k) bonus depreciation had declined to 60% in 2024 under the TCJA phasedown schedule |
| After OBBBA: | 100% bonus depreciation permanently restored for qualifying property placed in service after January 19, 2025 |
| Impact: | the TDC component (typically 20–35% of the AFE) is now fully deductible in Year 1 — up from 60% in 2024 |
| TDC bonus depreciation is NOT an AMT preference item: | unlike intangible drilling costs, no Form 6251 addback required |
| Combined with IDC: | 2026 Year 1 deductibility of a working interest program can approach 100% of total investment |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Practical 2026 Impact — $200,000 Investment Illustrated
- • Investment: $200,000 | Intangible drilling costs (75%): $150,000 | TDC (25%): $50,000
- • §263(c) IDC deduction Year 1: $150,000 — unchanged by OBBBA
- • §168(k) TDC bonus depreciation Year 1: $50,000 at 100% — up from $30,000 (60%) in 2024
- • Total Year 1 potential deductions: $200,000 — approaching 100% of investment
- • Potential federal tax savings at 37%: approximately $74,000
- • Effective net investment cost after potential tax benefit: approximately $126,000
Illustrative only — not a projection. AMT, state taxes, structure, and CPA analysis determine actual results.
→ Full OBBBA Guide: What Every Oil Investor Needs to Know in 2026
§199A QBI Deduction — Made Permanent
The TCJA's 20% qualified business income deduction was temporary — OBBBA made it permanent.
Whether working interest income qualifies depends on program structure and investor income thresholds.
Consult your CPA: real benefit for some investors, inapplicable for others based on their specific situation.
Timing: The Spud Date Controls the Tax Year
- Confirm projected spud date in writing before committing capital — not an estimate, a written confirmation
- Review the line-item AFE showing intangible drilling costs vs TDC allocation — not a headline summary percentage
- Have your CPA model the full-year tax picture including AMT before subscribing to any year-end program
- Verify subscription and funding timing requirements for the specific offering
★Texas Oil Investments provides spud date confirmation for programs in our partner network as part of every introduction. Never commit year-end capital without this in writing.
→ Year-End Tax Planning with Oil & Gas: The Complete Deadline Guide
The AMT Question: Model It Before You Invest
Intangible Drilling Costs and AMT: The Calculation Every High-Income Investor Must Run First
Intangible drilling costs deductions are preference items under §57(a)(2). When calculating Alternative Minimum Tax, the IDC deduction amount must be added back on Form 6251 Line 2j to calculate Alternative Minimum Taxable Income. This does not eliminate the deduction — it means the net benefit may be reduced for investors already in AMT territory. TDC bonus depreciation under §168(k) is explicitly NOT an AMT preference item. Only the intangible drilling costs component carries the AMT addback requirement.Before investing, have your CPA model all of these:
- Regular federal tax treatment — the headline deduction number from the offering materials
- AMT exposure — how much of the intangible drilling costs benefit survives after the AMTI addback on Form 6251
- Basis and at-risk limitations — confirm you have sufficient basis and at-risk amount to absorb the deduction
- State tax treatment — Texas: 0% state income tax; California: 13.3%; New York: 10.9%; New Jersey: 10.75%
- Expected timing — confirm the deduction tax year and how the K-1 will report the intangible drilling costs
Investors who model AMT before sizing their investment position more intelligently. Investors who skip this step often discover their net benefit is 20–30% lower than the offering summary implied.
Worked Example: $200,000 Permian Basin Working Interest
Assumes full usability under regular federal tax, no AMT limitation, no passive loss limitation, non-limiting LLC entity structure, no state tax adjustment. Not a projection or guarantee. Actual results depend on your complete tax picture. Consult your CPA before investing.
| Line Item | Amount | Notes |
|---|---|---|
| Working interest investment | $200,000 | Minimum in Texas Oil Investments partner programs: $50,000 |
| Intangible drilling costs — IDC (75% of AFE) | $150,000 | Deductible in full Year 1 under §263(c) |
| Tangible drilling costs — TDC (25% of AFE) | $50,000 | Deductible in full Year 1 under §168(k) post-OBBBA |
| Total Year 1 potential deductions | $200,000 | Approaching 100% of investment — 2026 programs |
| Potential federal savings at 37% | ~$74,000 | Before AMT, state taxes, and investor-specific factors |
| Effective net cost after potential benefit | ~$126,000 | Before any production income — well has not yet produced |
| Ongoing depletion on production income | 15% of gross | §613A — perpetual, for productive life of the well |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
→ Run your own numbers: IDC Tax Savings Calculator
What Happens if the Well Is Nonproductive?
For Permian Basin development programs, this question should be viewed in context. Wolfcamp A and B development wells in core Midland Basin counties carry approximately 5–10% dry hole risk — significantly lower than exploratory wells at 30–60%+. Texas Oil Investments facilitates introductions exclusively to development programs in proven formations with verifiable operator track records in the Texas Railroad Commission database.
How Intangible Drilling Costs Interact with Percentage Depletion
The 20-Year Tax Benefit Stack for a Permian Basin Well:
- Year 1: §263(c) intangible drilling costs + §168(k) TDC — near 100% deductibility in the year of drilling
- Years 2–30+: §613A percentage depletion — 15% of gross production income tax-free, perpetually
- Years 2–30+: Lease operating expenses (LOE) — fully deductible against production income in proportion to working interest
- All years: §469(c)(3) active income classification — no passive activity trap on any income
- NIIT exemption: Working interest income is exempt from the 3.8% Net Investment Income Tax
→ Oil Depletion Allowance: The Complete §613A Guide for Investors
Intangible Drilling Costs vs Other Tax Shelters: The Honest Comparison
| Feature | Oil WI (IDC) | Conservation Easement | Real Estate | QOZ Fund | DB Plan |
|---|---|---|---|---|---|
| Offsets W-2 Year 1 | ✓ Yes | ⚠ Yes* | ✗ Passive | ✗ Deferral | ✓ Yes |
| IRS Listed Transaction | ✗ None | ⚠ YES — 2024 | ✗ None | ✗ None | ✗ None |
| Ongoing income stream | ✓ Monthly dist. | ✗ None | ✓ Rent | ✓ On exit | ✓ Retirement |
| Contribution cap | ✗ None | ~ Appraised | ✗ None | ~ Cap gain | ~ Age/income |
| Congressional durability | ✓ Since 1913 | ~ Under attack | ✓ Longstanding | ~ 2017 (newer) | ✓ Longstanding |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Syndicated conservation easements designated as IRS Listed Transactions in October 2024 — automatic audit risk, mandatory disclosure, potential 40% penalties. Consult your attorney before proceeding with any conservation easement strategy in 2026.
⚠ The Conservation Easement Warning — What Changed in October 2024
The §263(c) intangible drilling costs deduction carries none of the risks now associated with syndicated conservation easements. IDC is explicit statutory law since 1913 — reaffirmed in every major tax reform, strengthened by the OBBBA in 2025. It is not a listed transaction. For the complete 2026 comparison including penalty exposure and three investor scenarios, see our dedicated analysis. If a promoter offers you a conservation easement in 2026, have your attorney review the October 2024 Treasury regulations before any decision.
IDC vs Qualified Opportunity Zones
QOZ funds defer — not eliminate — capital gains. Intangible drilling costs deductions against active income are a different mechanism serving a different purpose. QOZ investments require existing capital gains, a 10-year hold for maximum benefit, and exit into an uncertain future market. Many investors use both in the same tax year: a QOZ fund to defer capital gains from an asset sale, and a working interest program for the ordinary income deduction. They are complementary, not competing.
IDC vs Defined Benefit Plans — Use Both, In Order
Defined benefit plans should be maxed before oil investments are sized — they provide guaranteed deductions with zero investment risk, up to $200,000–$275,000 annually depending on age and income. Once the DB plan ceiling is hit, intangible drilling costs investing addresses the remaining taxable income. Max the DB plan first, then size the oil investment to the income above that ceiling.
→ Tax Reduction Strategies for High Income Earners: All Options Compared
§1254 Recapture: What Happens When You Sell a Working Interest
| Scenario | Tax Treatment on Sale |
|---|---|
| Gain below prior IDC deductions | Entire gain taxed as ordinary income under §1254 recapture |
| Gain above prior IDC deductions | Excess above IDC amount may be eligible for capital gains treatment |
| Sale at a loss | No §1254 recapture — ordinary loss treatment may be available depending on structure |
| Hold through well life — no sale | No §1254 recapture triggered — the issue only arises on disposition |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Simplified illustration only. §1254 recapture analysis depends on individual facts, holding period, basis, prior depreciation, and state tax treatment. Consult your CPA before any sale or disposition.
Most Permian Basin development investors hold through the productive life of the well — 20–30+ years — and never trigger §1254 recapture. It becomes material for investors who receive acquisition offers or are part of program buyouts. Model the §1254 recapture exposure with your CPA before accepting any offer to purchase a working interest. The headline offer price may look attractive; the after-tax proceeds may be materially lower.
IDC Amortization: When the Alternative Election Makes Sense
- AMT-heavy years: intangible drilling costs are AMT preference items. If you are already deeply in AMT, expensing creates a large addback that partially offsets the regular-tax benefit. Amortizing reduces the AMT preference item size — at the cost of spreading the deduction over 5 years.
- Anticipated higher-income years: if income will increase materially in Years 2–3 (practice sale, large bonus, earn-out), the deduction may be worth more in those future years than the current year.
- State non-conformity: some states do not conform to federal IDC expensing. If your state disallows the immediate deduction regardless of your federal election, the marginal benefit of expensing federally requires careful modeling with your CPA.
★The amortization election is binding and irrevocable. Have your CPA model the full multi-year picture under both scenarios — expensing and amortization — before making this decision.
How to Read Your Oil and Gas K-1: A Line-by-Line Guide
| K-1 Box | What It Shows | Where on Return | Most Common Error |
|---|---|---|---|
| Box 1 — Year 1 | Ordinary loss — intangible drilling costs allocation | Schedule E, Part II — ACTIVE (non-passive) | Filing on Part I as passive — traps entire IDC deduction |
| Box 11 / Supplemental | TDC bonus depreciation | Form 4562 or directly to Schedule E | Confusing TDC with IDC — different boxes, different forms |
| Box 17 or 20 — AMT | IDC preference item — must addback for AMT | Form 6251, Line 2j | Omitting AMT addback — underreporting AMT liability |
| Box 1 — Years 2+ | Production income allocation | Schedule E, Part II — ACTIVE | Switching to passive treatment in later years — wrong |
| Supplemental depletion | §613A percentage depletion | Reduces taxable income from production | Failing to claim depletion at all — very common with general CPAs |
| Box 20Z / supplemental | §199A QBI information | Form 8995 | Not modeling §199A applicability — may miss 20% deduction |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
Verify Your K-1 Is Being Filed Correctly — Ask These Questions
- • Ask your CPA: 'Is the Box 1 oil K-1 loss on Schedule E Part II as non-passive active income?'
- • Review your Schedule E draft: Part II should show the working interest entity and the loss in the non-passive column
- • Confirm Form 6251 Line 2j shows the IDC addback — if your CPA skips this, AMT may be understated
- • Confirm the depletion schedule from the K-1 supplemental is being used, not just the Box 1 figure
- • If your CPA has not prepared an oil and gas K-1 before, engage a CPA with energy partnership experience for this return
Three Investor Profiles: How Intangible Drilling Costs Work Across Tax Situations
Profile 1: Physician in Texas — Maximum Benefit
- Occupation: W-2 surgeon, private practice
- Income: $750,000 W-2
- State: Texas — 0% state income tax
- AMT status: Not in AMT — full regular-tax benefit applies
- $200K investment net cost: ~$126,000 after ~$74,000 potential federal benefit
- Outcome: Maximum benefit scenario — Texas residency + no AMT = full value of intangible drilling costs deduction
Maximum benefit scenario
Profile 2: Executive in California — AMT and State Tax Reduce the Net
- Occupation: Technology executive — salary + RSU vesting
- Income: $1,200,000
- State: California — 13.3% top state rate
- AMT status: In AMT — IDC addback reduces net benefit
- Net federal benefit (illustrative): ~$50,000–$56,000 after AMT reduction vs. ~$74,000 without AMT
- Key action: CPA must model AMT before sizing — do not rely on headline deduction number
CPA must model AMT before sizing
Profile 3: Business Owner in a Peak Income Year — Size to the Moment
- Situation: Business owner — sale earn-out year + normal S-Corp income
- Income: $800,000 (higher than normal due to earn-out)
- State: Texas — 0% state income tax
- Investment sized to: $300,000 to match the peak-income event
- Net cost (illustrative): ~$189,000 after ~$111,000 potential federal benefit
- Key insight: Peak-income years justify larger sizing — the earn-out creates the tax problem, IDC solves it
Peak years justify larger sizing
All three profiles are illustrative examples only — not projections or guarantees. AMT figures in Profile 2 are simplified estimates. Actual tax results depend on your complete tax picture, CPA analysis, program structure, state law, and many other factors. Not tax advice.
Evaluating Intangible Drilling Costs Programs: Green Lights and Red Flags
✓ Green Lights — Signs of a Well-Structured Intangible Drilling Costs Program
- • Line-item AFE provided upfront with clear intangible drilling costs / TDC separation on every cost category
- • Non-limiting LLC or general partnership entity — explicitly confirmed in the PPM, not just described verbally
- • Operator has 5+ years of verifiable production history in the Texas RRC database matching or exceeding type curves
- • §263(c) election statement included in offering documents or available on written request
- • Operating agreement includes cash call caps — typically 10–20% above original AFE amount
- • Spud date confirmed in writing before year-end — not projected or estimated
- • Prior year K-1 samples provided so your CPA can verify reporting format before subscribing
✗ Red Flags — What Should Make You Stop and Ask Questions
- • IDC percentage cited without a line-item AFE — 'our wells are typically 75% intangible drilling costs' is not verifiable
- • Limited partnership structure — this eliminates §469(c)(3) active income treatment entirely
- • Operator with no verifiable RRC production history or fewer than 3 wells in the target formation
- • Subscription deadline with no time for CPA or attorney review — pressure tactics are a warning, not urgency
- • Projected returns without conservative WTI pricing ($45–$50) scenarios included in the model
- • No operating agreement or vague cash call provisions — uncapped overruns mean unlimited downside
- • Marketing leads with deduction size and buries production economics — both must make sense independently
- • IDC percentage above 85% without explanation — request the line-item AFE breakdown
The 110-Year History: Why the Intangible Drilling Costs Provision Has Endured
- 1913: Revenue Act — intangible drilling costs deductibility established the same year the modern federal income tax was created
- 1954: Internal Revenue Code codified the election in §263(c) — the exact provision in force today
- 1969: Tax Reform Act — restricted percentage depletion for major oil companies; intangible drilling costs completely untouched
- 1975: Tax Reduction Act — eliminated depletion for major integrated producers; IDC untouched
- 1986: Tax Reform Act — the most sweeping overhaul in modern history — created §469 passive activity rules with an explicit §469(c)(3) carveout for oil working interests
- 2017: Tax Cuts and Jobs Act — significant tax changes; §263(c) and §469(c)(3) both completely unchanged
- 2025: One Big Beautiful Bill Act — strengthened oil and gas tax treatment by permanently restoring §168(k). The opposite of elimination.
No major federal tax legislation in 110 years has eliminated the §263(c) intangible drilling costs deduction. The provision has broad bipartisan support rooted in domestic energy policy. The provisions most actively under legislative threat in 2026 are newer, more aggressive strategies — syndicated conservation easements designated as Listed Transactions in October 2024, certain captive insurance arrangements, and other recent shelter structures. Intangible drilling costs, with 110 years of statutory history and an explicit congressional rationale in domestic energy production, occupies a fundamentally different position.
Sizing Your Intangible Drilling Costs Investment: The Four-Step Framework
| Step | Action | What This Determines |
|---|---|---|
| 1 | Project full-year taxable income | Your CPA calculates estimated AGI for the tax year after all other deductions — retirement accounts, business deductions, charitable contributions. This is the gross number the intangible drilling costs investment targets. |
| 2 | Subtract non-IDC deductions | Identify remaining taxable income above the 32% bracket threshold. Intangible drilling costs deliver maximum value at 35–37%. Income below 32% produces diminishing returns on the deduction. |
| 3 | Run the AMT model | Your CPA models AMT exposure specifically. AMT reduces but does not eliminate the net benefit. The AMT model determines actual net deduction value, not just the headline intangible drilling costs number. |
| 4 | Calculate investment size | Target deduction ÷ IDC percentage = investment size. Example: targeting $150,000 in intangible drilling costs deductions from a 75% IDC program requires a $200,000 investment ($150,000 ÷ 0.75). Size to your tax picture, not to the program maximum. |
Illustrative example only. Actual tax savings and investment returns depend on individual circumstances including tax bracket, AMT exposure, state tax treatment, program structure, and well performance. Not a projection or guarantee of results. Consult a qualified CPA before making any investment decision.
★Texas Oil Investments partner programs start at $50,000 per unit. Contact our team to discuss current program availability and whether your tax situation supports single or multi-unit participation. We do not recommend sizing without a CPA conversation first.
Common Mistakes Investors Make With Intangible Drilling Costs
Five Common Intangible Drilling Costs Mistakes That Cost Investors the Deduction
- 1. Wrong entity structure — eliminates the entire active income benefit: A limited partnership interest does not qualify for §469(c)(3) active income treatment. The intangible drilling costs deduction sits in suspended passive losses and cannot offset W-2 wages. Confirm non-limiting LLC or general partnership before subscribing to any program. This is the first question, not the last.
- 2. Focusing on the headline deduction without modeling AMT: The top-line intangible drilling costs estimate in a program summary is not your net federal tax benefit. It is the starting point. Run the AMT model before you invest. Investors who skip this step often discover their net benefit is 20–30% lower than the summary implied.
- 3. Accepting estimated IDC percentages without a line-item AFE: Offering materials show expected allocations. The final intangible drilling costs percentage depends on actual expenditures and the operator's final tax reporting. Verify from the line-item AFE, not a percentage on a summary sheet.
- 4. Investing without verifying the operator's Texas RRC track record: Intangible drilling costs improve after-tax efficiency. They cannot replace operator execution or offset production economics that do not make sense at conservative oil pricing. The Texas Railroad Commission database at rrc.texas.gov provides free, public access to every Texas operator's actual production history. Use it before you invest.
- 5. Not accounting for state taxes in the net benefit calculation: Federal tax treatment is only part of the analysis. Texas investors pay zero state income tax on production income — one reason Texas Oil Investments focuses primarily on Permian Basin programs. Investors in California, New York, or New Jersey face materially different net economics on the same gross deduction and production income. Model state tax with your CPA before sizing.
Frequently Asked Questions
Can I claim an intangible drilling costs deduction in the first year I invest?
+
Does §469(c)(3) active income treatment apply automatically?
+
Will AMT reduce the value of the intangible drilling costs deduction?
+
What did the OBBBA change for 2026 intangible drilling costs programs?
+
Does percentage depletion apply to working interest owners?
+
What is §1254 recapture and when does it apply?
+
Should I expense or amortize intangible drilling costs?
+
What is the most common K-1 filing error for oil and gas investors?
+
Can I hold a working interest inside my IRA?
+
How Texas Oil Investments Helps You Explore These Opportunities
The operators and energy sponsors we work with structure and manage the investments, bringing decades of technical expertise in Permian Basin geology, drilling operations, and reservoir management. Our focus is access, education, and strategic connections — helping qualified investors understand what they are considering before they engage with any specific program.
When programs in our partner network meet our evaluation criteria — verified operator RRC track record, line-item AFE with clear intangible drilling costs / TDC separation, appropriate entity structure for §469(c)(3) treatment, and sound development economics at conservative WTI pricing — we facilitate introductions. Every introduction comes with the documentation investors need to review with their own CPA and attorney.
Minimum investment: $50,000 per unit. Accredited investors only. SEC Regulation D Rule 506(b). Fort Worth, Texas.
The information on this page is for educational purposes only and does not constitute investment advice, tax advice, or legal advice. Oil and gas working interest investments involve significant risks including commodity price volatility, geological risk, operational risk, and potential loss of entire invested capital. All tax benefit descriptions reference IRC provisions as currently in effect; tax law is subject to change and individual tax treatment varies. All dollar examples and projections are illustrative only — not representations of actual returns. Programs are offered exclusively to verified accredited investors as defined by SEC Rule 501, under SEC Regulation D Rule 506(b). This page does not constitute an offer to sell or solicitation of an offer to buy any security. Consult a qualified CPA, attorney, and financial advisor before making any investment decision.
Request Your Program Overview
Complete this 60-second form to receive our current investment program details.
By requesting information, you represent that you believe you qualify as an accredited investor as defined by SEC Rule 501. This is not an offer to sell or solicitation to buy any security. Programs available only to verified accredited investors under SEC Regulation D Rule 506(b). No obligation to invest.
Accredited Investors Only · No Obligation
Discover If You Qualify for Our Current Program
Complete our 60-second investor questionnaire to receive our program overview.
Request Your Program OverviewBy requesting information, you represent that you believe you qualify as an accredited investor as defined by SEC Rule 501. This is not an offer to sell or solicitation to buy any security. Programs available only to verified accredited investors under SEC Regulation D Rule 506(b). No obligation to invest.