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When investing in oil and gas, there are two main types of opportunities:

1. Producing Wells

2. Projects Yet to Be Drilled

Each comes with its own cost, risk profile, and potential reward.

1. Producing Wells

• What It Is: You’re investing in a well that is already producing hydrocarbons. You know the current production rate and cash flow.

• Cost and Risk:

  • The upfront investment is typically higher because the well’s performance is known and cash flow is immediate.

  • The risk is lower since production is proven, but the upside can be more limited.

• Appeal: This is a less speculative option with predictable income, though wells do decline in production over time.

2. Projects Yet to Be Drilled

• What It Is: These are opportunities where a well is proposed but has not yet been drilled. Investors buy into a working interest before drilling begins.

• Cost and Risk:

  • The upfront cost is lower, but the risk is higher since the well’s success is unknown.

  • If successful, the potential upside is significant, as production can generate cash flow for years.

• Appeal: Investors willing to take on the uncertainty of exploration can achieve higher returns than investing in proven wells.

Investing in oil and gas projects comes with inherent risks, primarily due to the uncertainty of returns. The downside could mean a total loss, while the upside might deliver a rapid payback within months, followed by continuous production for years.

In well-established drilling regions like the Permian Basin or the Eagle Ford Shale, calculating ROI is relatively straightforward. The geology is well understood, and operations often resemble a manufacturing process. However, for individual wells or exploratory ventures, predicting returns becomes more complex. While neighboring wells can offer useful indicators, these projects are significantly different from more predictable investments, like a suburban laundromat.

This is a high-risk, high-reward opportunity. That said, we believe the location(s) we’ve selected, combined with the expertise of a seasoned geologist, sets our project(s) up for success. As the old adage goes: the best way to find oil is to look where it’s already been found.

If you’re seeking an investment vehicle with guaranteed returns, this isn’t it. But if you’re ready to take on some risk for the chance at significant rewards, this could be an excellent opportunity. I won’t insult your intelligence or bait you with overly optimistic ROI predictions. In this business, there are no guarantees—only the potential for success and the excitement of being part of something bold.

Finally, let me leave you with this: Anyone in the oil and gas industry who claims they can predict a well’s production before drilling is most likely lying to you.

There are two primary ways people earn from oil and gas wells: the royalty side and the business side. Both involve revenue from production, but the structures and responsibilities differ significantly.

1. The Royalty Side

• What It Is: Royalty owners typically hold mineral rights or an overriding royalty interest (ORRI). They receive a percentage of the revenue generated from the sale of oil or gas produced from their land.

• How It Works: Royalty payments are “off the top”, meaning they are calculated before any operating expenses are deducted. This ensures that royalty owners are paid their share regardless of the well’s operational costs.

• Example: If a lease agreement grants a landowner a 20% royalty interest, the royalty owner receives 20% of the revenue from the oil or gas produced.

• Key Benefit: Royalty owners don’t bear the costs of drilling, production, or maintenance. They simply receive payments as long as the well produces hydrocarbons.

Important Note: Royalty interests can pass down through generations, be bought or sold, and last in perpetuity as long as production continues.

2. The Business Side (Working Interest)

• What It Is: Working interest owners are business partners in the oil and gas operation. They share in the profits after all operational costs—like drilling, completion, and lease operating expenses (LOE)—have been covered.

• How It Works:

  • Working interest owners contribute funds to drill and operate the well.

  • After hydrocarbons are sold, revenues are first used to pay royalty owners and cover ongoing expenses.

  • The remaining revenue is distributed among working interest owners based on their percentage of ownership.

• Example: If an oil and gas well generates $100,000 in revenue:

  • $20,000 (20%) goes to the royalty owners.

  • Remaining $80,000 covers lease operating expenses (LOE) and other costs.

  • Any leftover profit is divided among working interest partners proportionate to their investment.

The Appeal: Working interest can offer substantial returns, especially in successful wells, but it comes with the responsibility of sharing operational costs and risks.

What Are Royalties and Mineral Rights?

Mineral rights and royalty interests are key components of oil and gas production. They represent ownership and income potential but differ in responsibilities, risks, and rewards.

1. Mineral Rights

• What It Is: Mineral rights grant ownership of the subsurface resources (like oil, gas, or minerals) beneath a property.

• How It Works:

  • If you own mineral rights, you have the option to lease those rights to an oil and gas company.

  • In exchange, you typically receive an upfront bonus payment and an ongoing royalty interest (a percentage of production revenue).

• Speculative Nature:

  • Owning mineral rights is highly speculative—there’s no guarantee the land will ever be drilled.

  • However, mineral rights are often cheaper to acquire because of this uncertainty. If drilling does occur, the value can increase dramatically.

• Example: If a company leases your mineral rights for 20%, you’ll receive 20% of the production revenue if oil or gas is extracted, while the company covers all costs.

2. Royalties

• What It Is: Royalties are the ongoing payments made to mineral rights owners (or royalty interest holders) as a share of the revenue generated from production.

• Key Features:

  • Royalty owners get paid “off the top”, meaning they receive their share before operating expenses are deducted.

  • No Costs or Risks: Royalty owners do not pay for drilling, operations, or maintenance of the well.

• How Royalties Are Created:

  • When an oil and gas company leases mineral rights, the mineral owner retains a royalty percentage in the lease agreement.

  • The typical royalty percentage ranges from 12% to 25% of the production revenue.

Overriding Royalty Interest (ORRI)

An ORRI is a type of royalty interest carved out of a company’s working interest:

• It allows smaller companies, landmen, or investors to earn a percentage of production revenue without owning the mineral rights.

• For example, a small company might lease mineral rights at 20% and then sell that lease to a larger oil company for 25%, retaining a 5% ORRI for themselves.

What is Working Interest?

Working interest refers to the ownership stake in an oil and gas well that carries both the financial benefits and responsibilities of the operation. All working interest partners are responsible for their share of the costs associated with drilling, completing, and maintaining the well; however, it’s important to note that working interest partners are not required to handle any operational activities—those responsibilities fall on the operator.

Once the well is in production, ongoing monthly expenses, known as Lease Operating Expenses (LOE), such as maintenance or repairs (e.g., replacing a motor), are typically deducted directly from the monthly revenue stream. This ensures the well remains operational without requiring additional upfront contributions.

Years down the road, if the well requires significant work, such as a rework to restore production, a new expense plan will be proposed. Per the terms of our Joint Operating Agreement (JOA), if the cost of this work exceeds $75,000, a cash call will be issued to all partners proportionate to their ownership percentage. A new Authorization for Expenditure (AFE) will outline the proposed work (what we plan to do) and the expected cost (what it will take to achieve it).

At this point, partners have two choices:

1. Pay your share and remain part of the program.

2. Go non-consent, meaning you decline to contribute further funds. By doing so, you forfeit your equity and any future revenue from the well.

Working interest ownership allows you to participate in the financial upside of production without needing to get involved in day-to-day operations. While it does come with the responsibility of covering your share of costs—such as LOE and any significant future expenses—it also provides an opportunity to benefit proportionally from the well's success.

Are there Tax Benefits to Investing in Oil and Gas?

Yes, oil and gas investments offer very substantial tax benefits. However, I prefer not to emphasize these as the primary incentive for investing. While many in the industry lead with tax advantages, I believe this approach can sometimes overshadow the real reason to invest: the extraction of hydrocarbons. The goal should always be a successful well, not just tax deductions. That said, the tax incentives in oil and gas can significantly enhance the overall financial return for investors.

Here are the primary tax benefits associated with working interest in oil and gas projects:

1. Intangible Drilling Costs (IDCs)

• IDCs are expenses with no salvage value, such as wages, fuel, hauling, and drilling services.

• These costs typically comprise 75% to 85% of the total well cost and are 100% deductible against taxable income in the first year they are incurred.

• This can provide a significant upfront tax benefit, which is particularly advantageous in reducing taxable income.

2. Tangible Drilling Costs (TDCs)

• TDCs include costs for physical equipment, such as casing, tanks, and pump jacks.

• While these expenses cannot be deducted immediately, they are capitalized and depreciated over a 7-year period, providing longer-term tax relief.

3. Depletion Allowance

• The IRS recognizes that oil and gas reserves are finite resources.

• A 15% depletion allowance shelters a portion of the well's gross income from taxation each year, as long as the well remains productive.

• This is a powerful incentive that provides recurring tax advantages throughout the well's lifespan.

4. Intangible Completion Costs (ICCs)

• ICCs include completion-related expenses, such as labor, fluids, and rig time, that have no salvage value.

• These costs average around 15% of the total well cost and are 100% deductible in the year they are incurred.

5. Amortization of Geology and Geophysical Costs

• Geological and geophysical costs can be amortized under IRS Section 167(h), allowing deductions over a 24-month period:

  • 25% in the first year,

  • 50% in the second year, and

  • 25% in the third year.

6. Lease Operating Expenses (LOE)

• LOE refers to the ongoing monthly costs to operate the well.

• These expenses are deductible in the year they are incurred, further reducing taxable income.

Additional Tax Considerations

• 1031 Exchange Compatible: Under IRS Section 1031, investors can defer capital gains taxes by reinvesting proceeds from the sale of real estate into a working interest drilling program.

• IRA Suitability: Oil and gas working interest programs can be included in self-directed IRAs, offering the potential to shelter monthly cash flow from immediate taxation.

• State-Specific Benefits: For example, in Oklahoma, severance taxes on new wells are reduced to 2% for the first 36 months of production before returning to the standard rate. This can add substantial revenue in a well's early life.

In Summary
While the tax benefits of oil and gas investments are undeniably strong, I believe they should serve as a bonus rather than the central reason to invest. The focus should always remain on the geology, the prospect, and the potential for hydrocarbon production. If you’re looking to maximize these incentives, I strongly recommend consulting a qualified tax professional to ensure you take full advantage of the laws applicable to your situation.

When Do I Get Paid as a Working Interest Owner?

As a working interest owner, you begin receiving payments after the well starts producing and generating revenue. However, the timing and amount of these payments depend on several factors:

1. Initial Production and Revenue Cycle

• Once the well begins producing, the hydrocarbons (oil or gas) are sold.

• Most operators follow a monthly payment cycle. Revenue from production is typically paid 30-60 days after the hydrocarbons are sold, depending on the operator’s accounting processes and the terms of the Joint Operating Agreement (JOA).

2. Costs Are Deducted First

As a working interest owner, your payments are calculated after expenses have been deducted, such as:

• Lease Operating Expenses (LOE): Monthly costs to operate and maintain the well (e.g., repairs, electricity, or maintenance).

• Production Taxes: State and local taxes on oil and gas production.

• Other Operating Costs: Costs for transportation, compression, or treating hydrocarbons.

The remaining revenue—after these expenses are covered—is distributed proportionally to working interest owners based on their ownership percentage.

What Are the Phases of a Well?

An oil and gas well progresses through several phases, from concept to the end of its productive life. Each phase involves distinct activities, costs, and goals:

1. Geologist Has an Idea

• A geologist identifies a potential drilling location based on geological studies, seismic data, and historical production nearby.

• This is the exploration phase, where the well’s potential is evaluated before any investment is made.

2. Land Acquisition

• Once the location is identified, mineral rights must be acquired or leased from landowners.

• This phase involves negotiating leases, legal title work, and preparing the surface location for drilling.

3. Drilling

• The drilling phase begins with mobilizing the drilling rig and crew.

• The wellbore is drilled to the target depth, and data is collected (e.g., logs and cores) to evaluate the presence of hydrocarbons.

• If hydrocarbons are not found, the well may be declared a dry hole.

4. Completions

• If hydrocarbons are found, the well enters the completion phase to prepare it for production.

• Key activities include:

  • Setting casing and tubing.

  • Installing pumps or artificial lift equipment.

  • Stimulation techniques (e.g., acidizing or hydraulic fracturing) to enhance flow.

5. Production

• Once completed, the well begins producing oil or gas.

• Production is monitored, and revenues are generated as hydrocarbons are sold.

• This phase can last years or even decades, depending on the well’s performance.

6. Workover (if needed) and Additional Production

• Over time, production naturally declines. A workover may be performed to restore or enhance production.

• Workovers involve re-entering the well to repair, clean, or stimulate the reservoir, allowing for additional production.

7. Plug and Abandon (P&A)

• At the end of the well’s productive life, it is safely plugged and abandoned.

• This process involves sealing the wellbore to prevent environmental contamination and restoring the land to its original condition.

Summary

The lifecycle of a well moves through exploration, development, production, and ultimately, decommissioning:

1. Geologist Has an Idea

2. Land Acquisition

3. Drilling

4. Completions

5. Production

6. Workover (if needed) → More Production

7. Plug and Abandon (P&A)

Understanding these phases helps investors see the process, risks, and rewards involved at each stage of the well’s lifecycle.

What If the Well Is a Dry Hole?

If the well turns out to be a dry hole—meaning no commercially viable hydrocarbons are found—then the project stops after the drilling phase. This has several implications:

1. No Completion Costs

   • Since the well won’t be completed, there’s no need for the second cash call. Completion costs (e.g., setting tubing, installing pumps, or performing stimulation) are only required if the well has production potential.

2. Drilling Costs Only

   • As a working interest partner, your financial exposure would be limited to your share of the drilling phase costs (the “dry hole cost”), which covers the drilling, testing, and evaluation to determine whether the well is productive.

3. Learning from the Results

   • Even with a dry hole, valuable geological and offset data is collected. This information can help refine future drilling locations and improve the chances of success in subsequent wells.

What’s My Liability?

As a working interest investor, your liability is primarily financial—you are responsible for your share of the well’s costs. However, the operational and environmental liabilities of the well are handled by the operator.

• Joint Operating Agreement (JOA): When you invest, you sign a Joint Operating Agreement (JOA) with the operator (e.g., MB Energy LLC). This agreement clearly outlines the roles and responsibilities of all parties.

• Operator Assumes Liability: Under the JOA, the operator assumes all environmental and operational liability associated with drilling, production, and maintenance of the well.

• What This Means for You:

  • If an environmental incident, accident, or operational issue occurs, the operator is responsible, not you.

  • You will not be approached, held accountable, or exposed to liability in such events.

Your Role as an Investor

• You are a non-operating partner under the JOA. Your only responsibility is to cover your share of costs (e.g., drilling, completion, and Lease Operating Expenses).

• The operator handles all day-to-day operations, legal compliance, and risk management for the well.

Summary

By entering into a Joint Operating Agreement, you are protected from operational and environmental liabilities. Your exposure is limited to your financial investment, while the operator takes on the risks and responsibilities of operating the well.

What Happens When the Well Needs to Be Plugged?

At the end of a well’s productive life, it must be plugged and abandoned (P&A) to ensure environmental safety and regulatory compliance.

How Is P&A Managed?

1. Costs Are Built Into the Initial Budget:

   • During the fundraising phase, the operator—such as MB Energy LLC—includes the projected costs of P&A in the financial planning for the well.

   • This ensures funds are available and allocated for plugging the well when it reaches the end of its economic life.

2. Operator’s Legal Responsibility:

   • Under the Joint Operating Agreement (JOA), the operator is legally responsible for ensuring the well is safely plugged and abandoned.

   • This protects investors from unexpected liabilities.

Why Is This Important for Investors?

• Avoid Unexpected Bills: Without proper planning, investors could face a large cash call at the end of the well’s life, wiping out years of production revenue.

• Investor Confidence: Operators know that attempting a cash call for P&A at the end of the well’s life risks investors disappearing or refusing to pay. Including P&A costs upfront ensures the work will be completed without relying on last-minute contributions.

A Warning for Investors

Be cautious of any operator or company that does not account for P&A costs upfront. This lack of planning could leave you vulnerable to unexpected financial obligations when the well is no longer producing profitably, whether due to declining production or unfavorable commodity prices.

Summary

Responsible operators like MB Energy LLC factor P&A costs into the initial fundraising to:

1. Fulfill their legal obligation to plug the well.

2. Ensure investors are protected from unexpected financial hits at the end of the well’s life.

Proper planning for P&A ensures a smooth, predictable end to the well and demonstrates the operator’s commitment to both compliance and investor confidence.

Who Is the Operator?

For most of my projects, I work with MB Energy LLC. I know their team very well—Ryan, for example, is not only the operator I work with but also part of my race car team, and my car is currently sitting at his house. This level of familiarity and trust means I have complete confidence in their operational capabilities and commitment to excellence.

However, from time to time, I may promote projects with other operators and geologist teams. Rest assured, any projects I share will be fully vetted and carefully reviewed to ensure they meet my standards for quality, expertise, and potential.

If at any point you would like to see data about the operator—such as their standing with the Texas Railroad Commission (TRRC) or other regulatory bodies—this information is available upon request. Transparency is key, and I want to ensure you feel confident in the operators and teams involved in these projects.

My goal is to present only projects that I believe in, operated by trusted teams with proven track records.

How Long Do Wells Produce For?

Just like ROI, the exact amount of time a well can produce is unpredictable. Wells can produce for many years, but their lifespan depends on a variety of factors, including production levels, costs, and commodity prices.

Factors That Affect Well Longevity

1. Production Levels vs. Lease Operating Expenses (LOE)

   • The well must produce enough hydrocarbons to cover its Lease Operating Expenses (LOE) and remain profitable.

   • For example, decades ago, wells producing just 5 barrels a day were often capped as they weren’t financially viable. Today, with improved efficiency and higher commodity prices, those same production levels could justify keeping the well alive.

2. Commodity Prices

   • Oil and gas prices play a critical role. When prices are high, even wells with lower production can remain profitable. When prices drop, wells with marginal output may be shut in or capped.

3. Mechanical Problems

   • Persistent issues, such as a well “eating up rod pumps,” can shorten the well’s life. For instance, a well producing 20 barrels per day might seem profitable, but if it requires repairs that consume two months of profit every three months, it may no longer be worth operating.

4. Geology of the Well

   • Conventional Wells: Typically have steady, long-term production but decline gradually.

   • Non-Conventional Wells (e.g., shale): Tend to produce at high initial rates but experience sharper declines over time.

5. Production Methods

   • The production method used can significantly impact longevity:

     • Artificial Lift: Methods like pump jacks or ESPs (electric submersible pumps) are common for keeping wells flowing.

     • Enhanced Oil Recovery (EOR): Techniques like water flooding or gas injection can extend a well’s productive life by stimulating the reservoir.

In Summary

The lifespan of a well depends on production levels, operating costs, commodity prices, and mechanical factors. While some wells may produce for only a few years, others can remain productive for decades with the right economics and maintenance. Understanding the geological type of the well and the production method used is key to estimating its potential longevity.

Ultimately, the decision to continue operating a well comes down to a balance of profitability and sustainability.

What Is the Exit Strategy for My Investment?

Because this investment is structured under a Joint Operating Agreement (JOA), your working interest is considered an asset that can be sold on the open market.

• Transferability: You can sell your interest to any other entity, whether it’s another investor, a company, or an individual looking to acquire working interest in a producing or potential well.

• Market Value: The value of your interest will depend on factors such as current production levels, remaining reserves, commodity prices, and the well's overall performance.

Selling your interest allows you to exit the investment and potentially realize a return without waiting for the well to reach the end of its productive life.

Key Point

Your working interest is a liquid, transferable asset that can be sold to another party, providing flexibility if you decide to exit the investment before the well's lifecycle ends.

Do I Have to Put the Interest in an LLC or Personal Name?

The decision to hold your working interest in an LLC or in your personal name is up to you, and it depends on your specific goals regarding liability, taxation, and asset management.

• Holding in Your Personal Name:

  • Simplifies the process—ownership is direct, and revenue is taxed as personal income.

  • However, you may be personally liable for financial obligations tied to your interest.

• Holding in an LLC:

  • Limits your personal liability: If something happens with the well, your risk is contained within the LLC.

  • May provide additional tax benefits, as LLCs allow for flexible taxation structures (e.g., pass-through income).

  • Helps with estate planning and simplifies ownership transfer or sale of the interest.

Recommendation

While you are not required to place your interest in an LLC, many investors choose to do so for liability protection and more efficient tax management. It’s best to consult with a qualified attorney or tax advisor to determine the structure that aligns with your personal situation and financial goals.

What Are the Different Types of Wells?

In oil and gas operations, there are several types of wells, each serving a unique purpose. Understanding these distinctions helps clarify the role of each well in exploration, development, and production.

1. Wildcat Well

• Definition: A speculative well drilled in an area with no established production history or proven reserves.

• Purpose: To discover new oil or gas fields.

• Risk/Reward: High risk but potentially high reward if a new field is discovered.

2. Exploratory Well

• Definition: A well drilled in areas where geological data suggests hydrocarbons but reserves are not yet proven.

• Purpose: To confirm the presence, quantity, and quality of hydrocarbons.

• Difference from Wildcat: Guided by seismic data or nearby offsets, making it slightly less risky.

3. Developmental Well

• Definition: A well drilled in a proven oil or gas field to maximize production and recover additional reserves.

• Purpose: To develop and extract known hydrocarbons.

• Risk: Lower risk since hydrocarbons are already confirmed.

4. Injector Well

• Definition: A well used to inject fluids or gas into a reservoir to enhance production.

• Purpose: Part of Enhanced Oil Recovery (EOR) methods to maintain pressure and push hydrocarbons toward producing wells.

• Common Methods: Water injection, gas injection, or steam flooding.

5. Appraisal Well

• Definition: A follow-up well drilled after a discovery to assess the size, scope, and potential of the reservoir.

• Purpose: To evaluate reserves, flow rates, and the field’s development potential.

6. Step-Out Well

• Definition: A well drilled just outside the proven boundaries of a reservoir.

• Purpose: To test the reservoir’s extent and identify additional production zones.

7. Sidetrack Well

• Definition: A new wellbore drilled from an existing well to bypass problems (e.g., stuck equipment) or target a new zone.

• Purpose: To enhance production or salvage a previously drilled well without starting from scratch.

8. Disposal Well

• Definition: A well used to safely dispose of produced water or other non-commercial fluids into underground formations.

• Purpose: To meet regulatory and environmental requirements for managing fluids produced during operations.

9. Monitoring Well

• Definition: A well drilled to monitor pressure, fluid levels, or environmental impacts.

• Purpose: To track reservoir performance, ensure safety, or monitor water quality near production zones.

What Are Lease Operating Expenses (LOE)?

Lease Operating Expenses (LOE) are the ongoing costs required to operate and maintain an oil or gas well after it has been drilled and completed. These are the day-to-day expenses necessary to keep the well producing and are shared proportionally among the working interest owners.

What Do LOE Include?

LOE can vary depending on the well’s location, age, and production method, but common costs include:

1. Labor Costs

   • Wages for field workers, pumpers, and maintenance crews.

2. Utilities and Power

   • Electricity, fuel, and other energy costs to power pumps, compressors, and other equipment.

3. Equipment Maintenance and Repairs

   • Replacing rod pumps, repairing tubing, or fixing production equipment as needed.

4. Water Disposal

   • Costs to manage and dispose of produced water from the well.

5. Chemicals and Treatments

   • Chemicals needed for flow assurance, corrosion control, and other treatments to keep the well operational.

6. Transportation Costs

   • Costs to transport oil, gas, or water from the wellsite to sales points or disposal facilities.

7. Regulatory and Environmental Compliance

   • Costs to meet environmental standards, inspections, and reporting requirements.

8. Insurance

   • Policies to cover the well and liability associated with operations.

9. Well Servicing and Workovers

   • Periodic maintenance or smaller-scale operations to enhance or restore production.

Why Are LOE Important?

• LOE directly impacts the profitability of a well. If operating costs exceed production revenue, the well may become financially unviable.

• Efficient management of LOE ensures that wells continue to produce profitably, even during periods of lower commodity prices.

How Are LOE Paid?

• LOE are typically deducted monthly from the gross production revenue before distributions are made to working interest owners.

• Each working interest owner pays their proportional share of the LOE based on their ownership percentage in the well.

Summary

Lease Operating Expenses (LOE) represent the ongoing costs to operate a well and keep it producing. They include labor, power, equipment repairs, transportation, and other necessary expenses. Efficiently managing LOE is critical to maximizing profitability and extending the life of a well.

What Are These Geology Terms and What Do They Mean?

In oil and gas exploration and production, various geological tools and concepts are used to evaluate reservoirs, understand the subsurface, and determine a well’s potential. Here’s a breakdown of some key terms:

1. Wireline

• Definition: A cable-based tool used to lower instruments into a wellbore to collect data.

• Purpose: It provides information about the formation's properties, such as density, porosity, and fluid content, helping to evaluate the reservoir.

2. Isopach

• Definition: An isopach map shows the thickness of a particular subsurface layer or reservoir.

• Purpose: It helps geologists understand how thick a formation is across an area, which is critical for estimating potential hydrocarbon volumes.

3. 3D Seismic

• Definition: A geophysical technique that uses sound waves to create a three-dimensional image of the subsurface.

• Purpose: It allows geologists and engineers to visualize the structure and location of reservoirs, identify faults, and determine the best drilling locations.

4. Neutron-Density

• Definition: A type of wireline log that measures both neutron and density responses of a formation.

• Purpose: By combining these measurements, geologists can determine the porosity (empty space in the rock) and identify whether hydrocarbons, water, or gas are present.

5. Gamma Spectral (Gamma Ray)

• Definition: A tool that measures natural gamma radiation emitted by rocks.

• Purpose: Gamma logs help distinguish between shale (high gamma readings) and sand or carbonate reservoirs (low gamma readings). Gamma spectral tools provide a detailed breakdown of radioactive elements like potassium, uranium, and thorium.

6. Permeability

• Definition: The ability of a rock to allow fluids to flow through it.

• Measured In: Millidarcies (mD).

• Purpose: High permeability means hydrocarbons can flow easily, leading to better production rates. Low permeability requires stimulation techniques like fracturing.

7. Porosity

• Definition: The percentage of empty space (pores) within a rock that can hold fluids (oil, gas, or water).

• Measured In: Percentage (%).

• Purpose: Porosity determines the reservoir’s storage capacity. High porosity means more hydrocarbons can be stored in the rock.

Can I Buy into a Project After the Well Has Been Drilled and Oil Has Been Discovered?

Yes, you can buy into a project after the well has been drilled and oil has been discovered. However, this changes your role from being an investor to being a buyer of cash flow.

What Does This Mean?

• Once oil is proved, and the well is producing, the risk is significantly reduced, but the cost of entry increases dramatically.

• At this stage, the price of interest can be 5 to 10 times higher than the original investment cost.

• You’re essentially buying a share of the revenue stream generated by the producing well.

Why Does the Price Go Up?

• All working interest points are typically sold before drilling begins to fund operations.

• Early investors take on the risk of drilling a dry hole, which is why they pay less upfront.

• Buyers of producing wells are paying for a proven, cash-flowing asset with less risk.

Key Considerations

• When you buy into a producing well, you are not funding exploration or drilling but purchasing cash flow from another partner’s share.

• This type of investment offers stability and immediate income but comes at a premium cost.

Risk and Reward Perspective

• Early investors bear the uncertainty of whether the well will produce.

• Buyers of producing wells avoid this risk but pay significantly more for the reduced uncertainty.

Example Context

While payout timeframes vary, we generally target an 18-month payout for investors who enter pre-drilling. Once the well is producing, this timeline may not apply, as the initial risks and costs have already been accounted for.