Distributions begin after first sales and net back lease operating expenses, taxes, and any hedging settlements. Partnerships issue Schedule K‑1s annually so investors can claim IDCs, depreciation, and depletion as applicable.

The resource center includes material on wind and solar for investor education, while current core projects focus on Oklahoma oil and gas.

After funding, site prep and drilling commence, then the rig releases to completion crews. Completions typically take one to five weeks. First sales occur once facilities are ready and pipeline or trucking is scheduled.

Projects comply with Oklahoma Corporation Commission rules on spacing, completions, and water handling. Engineering and well control standards are built into planning and execution.

The operator maintains lean corporate overhead so more capital goes into the well. Contracts target predictable drilling and completion cycles to protect returns.

Expect an AFE that details capital, a Joint Operating Agreement that governs project decisions, and ongoing statements covering volumes, prices, and LOE. Tax reporting is delivered annually.

Distributions are based on Net Revenue Interest (NRI), not just working‑interest percentage. NRI equals WI × (1 − royalty burden). Revenues are paid after royalties and operating costs.

Projects are offered to accredited investors and require a suitability review. A brief questionnaire confirms status before documents are provided.

Yes. Management participates in each program at the same level as investors, which strengthens alignment on cost discipline and capital efficiency.

Geoscientists confirm source, reservoir, seal, and trap, integrate offset well data, and apply 3D seismic to map targets. Only after this de‑risking does a prospect advance to spud.

Current projects focus on Oklahoma, including historically productive counties where modern technology can unlock remaining value. Local regulation and established infrastructure support efficient development.

Provides direct access to drilling projects, aligns capital by co‑investing, maintains low overhead, and emphasizes transparent reporting. The firm is independently owned and family operated.

Confirm accredited status, review a project’s AFE and geology, and subscribe to a direct participation program that fits your goals and risk tolerance. Expect a Joint Operating Agreement to govern rights and duties.

Direct participation can pair attractive after‑tax cash flow with ownership of a tangible, domestic asset. The structure aims to reduce risk through modern geology, focused basins, and careful cost control.

Three core benefits drive after‑tax returns:

• IDCs: Often 60–85 percent of upfront costs, typically deductible when incurred for working‑interest owners who elect to expense.
• TDCs: Equipment is depreciated, generally on 5‑ or 7‑year MACRS schedules, with bonus depreciation where eligible.
• Depletion: Eligible owners may deduct 15 percent of gross income per property, subject to limits.

Either buy futures and ETFs or acquire a working interest in a well. A working interest ties returns to actual barrels produced and passes through powerful deductions.

Consider diversified ETFs or mutual funds for low minimums and liquidity. Direct interests often require higher checks and longer holding periods.

Choose indirect exposure through public markets or direct participation in specific wells. Direct participation gives you working‑interest ownership, cash flow from sales, and access to tax benefits.

Public options include energy stocks and ETFs. Direct programs are private placements where you fund drilling and completion and receive your share of revenues and deductions.

It can be attractive when you want real‑asset exposure, cash flow potential, and tax efficiency. It also carries geological, operational, price, and liquidity risks. Model both pre‑tax and after‑tax cases.

After a well is drilled and completed, oil and gas flow to the surface through production tubing and surface equipment. Output starts high, then declines over time.

Subsurface work and leasing can run months or longer. Drilling and completion often require weeks to a few months. Completions alone commonly take one to five weeks after the rig moves off location.

Teams map the subsurface with gravity, magnetic, and 3D seismic data, lease minerals, and drill to prove hydrocarbons. Only a well confirms commercial volumes.

Exploration identifies drill‑ready prospects using geoscience and seismic. Production begins once completions and facilities are in place, and continues through primary, secondary, and sometimes tertiary recovery.