Conventional vs. Unconventional Oil and Gas Drilling: The Differences That Actually Impact Your Returns

Not all oil and gas investments are the same. That might sound obvious, but it is one of the most common and costly assumptions investors make when they first start evaluating direct participation programs.

The type of drilling behind an investment determines nearly everything that matters to you as an investor: how capital is deployed, what kind of risk you are taking on, how income flows over time, and how the IRS treats your deductions. Two programs can both be called “oil and gas investments” and behave in fundamentally different ways, because the wells behind them are built on entirely different geological and operational foundations.

At BassEXP, we focus exclusively on conventional drilling in Oklahoma’s proven legacy fields. We have made that choice deliberately, through decades of field experience, and we want to help you understand exactly why it matters. Before you evaluate any drilling program, including ours, you need to understand the difference between conventional and unconventional drilling. That foundation shapes everything that comes after it.

Why the Type of Drilling Matters Before Anything Else

When investors come to us after evaluating other programs, we often find that they have been comparing apples to oranges without knowing it. A shale-focused unconventional program and a conventional development program in a proven Oklahoma basin are not simply different versions of the same investment. They are structurally different in how they operate, how they produce, and how they behave over time.

Skipping this step creates real problems:

• Investors apply the wrong return expectations to the wrong type of program
• Cost structures get compared without accounting for fundamental differences in well complexity
• Production timelines and income profiles get misread
• Tax strategies, including depletion calculations, get evaluated without the geological context that makes them make sense

Understanding drilling type does not require an engineering degree. It requires a plain-language explanation from someone who has spent years in the field, which is exactly what we are going to give you here.

What Is Conventional Oil and Gas Drilling?

Conventional drilling targets naturally occurring reservoirs where oil and gas have migrated and accumulated over millions of years. Think of it this way: source rock generates hydrocarbons over geologic time, and those hydrocarbons migrate upward through permeable rock until they encounter a geological trap, usually a dome-shaped fold, a fault, or a stratigraphic boundary, and collect there in a reservoir.

The reservoir rock itself, typically sandstone or certain limestones, is porous and permeable. That means it holds the oil and gas in its pore spaces, and those fluids can flow naturally toward a wellbore under reservoir pressure. In a conventional well, you are working with the formation. The geology does a significant portion of the work.

What this looks like in practice:

• Wells are typically vertical in design, simpler to drill and complete
• The target reservoir has usually demonstrated commercial production in nearby wells before a new well is drilled
• Geological uncertainty is reduced because the formation has already proven itself in the immediate area
• Completion costs are generally lower because the rock does not require artificial stimulation to produce
• Production can begin relatively quickly after the well reaches total depth

Oklahoma’s legacy basins are a prime example of this model. Fields developed in the 1970s and 1980s established production in multiple formations across the state. Many of those fields still contain overlooked stacked-pay zones, intervals that were either bypassed by older technology or not fully evaluated at the time. We return to those fields with modern geological tools and field knowledge, identify the pay zones that remain, and develop them responsibly using today’s capabilities.

This is low-risk oil and gas drilling in the truest operational sense: proven geology, established production history, and disciplined execution by a team with decades of experience in those specific formations.

What Is Unconventional Oil and Gas Drilling?

Unconventional drilling targets formations where hydrocarbons are not stored in a classic reservoir trap. Instead, the oil and gas remain trapped within the source rock itself, typically shale or tight sand formations, in rock that is too dense and impermeable to allow natural flow.

Because the geology will not deliver production on its own, unconventional drilling depends heavily on engineering to unlock the resource. Two technologies make this possible:

1. Horizontal drilling allows the wellbore to turn and travel laterally through the formation for thousands of feet, maximizing the surface area of rock the well contacts
2. Hydraulic fracturing (fracking) pumps high-pressure fluid into the formation to create a network of fractures, giving the trapped hydrocarbons a pathway to flow toward the wellbore

The unconventional model, which drove the U.S. shale revolution, dramatically expanded domestic energy production and proved that enormous quantities of previously unrecoverable oil and gas could be accessed. That is a legitimate and significant achievement for American energy.

The tradeoff is that this approach is capital-intensive, operationally complex, and depends on continuous reinvestment to maintain production. It operates more like a manufacturing process than traditional exploration, with large numbers of wells drilled systematically across wide resource fairways.

The Differences That Actually Matter to Investors

This is where the technical distinctions translate into investment reality. Let’s walk through the key differences on the dimensions that matter most when you are evaluating a direct participation program.

Cost Structure and Capital Deployment

Conventional wells are generally less expensive to drill and complete than unconventional wells. The reasons are straightforward: simpler wellbore design, no multi-stage fracking operations, shorter completion timelines, and less reliance on specialized high-cost equipment.

Unconventional programs require substantial upfront capital. Horizontal laterals can extend two to four miles through the formation. Multi-stage fracking operations involve significant materials, equipment, and crew costs. The capital requirements per well are meaningfully higher.

For direct participation investors, this matters because it affects how much of your capital is actually working in the ground versus being absorbed by operational complexity. At BassEXP, we maintain a lean overhead model: no corporate offices, no unnecessary infrastructure, no excess administrative cost. More of your capital reaches the formation, and that improves the economics for everyone involved.

Geological Risk vs. Execution Risk

This is one of the most important distinctions for investors to internalize, and it is one that rarely gets explained clearly.

In conventional drilling in a proven field:

• Geological risk is reduced because the formation has already demonstrated it can produce commercially in nearby wells
• The primary risk shifts to operational execution: drilling mechanics, completion quality, and reservoir variability within the known formation
• Commodity price exposure applies to both approaches equally

In unconventional drilling:

• Resource presence risk is reduced because the shale or tight formation is broadly known to contain hydrocarbons
• Technical and economic risk increases because profitability depends heavily on extraction efficiency, well spacing, fracking design, and sustained capital deployment
• The program depends on a continuous drilling cadence to maintain overall production levels

Neither approach eliminates risk. All oil and gas investment carries it, and we will address that directly in a moment. But understanding which category of risk you are taking on is essential before you evaluate any program.

Our stacked-pay strategy adds another layer of risk distribution to the conventional model. In a three-well program targeting five pay zones per wellbore, you have fifteen separate opportunities to encounter commercial production. It is often not a question of whether we will find oil and gas in a proven area. It is a question of how much we find and in which formations.

Production Profiles: Steady Output vs. Steep Decline

How a well produces over time is one of the most consequential and least-discussed differences between conventional and unconventional programs.

Conventional wells tend to produce at moderate, steady rates over extended periods. The production curve declines gradually, which creates a more predictable income profile. Investors receive monthly revenue that, while it may decline slowly over time, does so in a measured and manageable way across a well life that can stretch for decades in a productive formation.

Unconventional wells often feature high initial production rates that decline sharply. In many shale plays, wells can lose the majority of their peak production within the first two years. This front-loaded production profile means income arrives quickly but diminishes rapidly, requiring continuous new drilling to replace declining wells and sustain overall program output.

For investors, this difference is not just about cash flow timing. It is also the foundation of your depletion picture, which is where the tax implications of your investment take shape. We will connect those dots in the next section.

Asset Longevity and Long-Term Value

Related to production profile is the question of how long the asset produces and what that means for long-term value.

Conventional wells in productive formations can generate income for decades. The asset life is genuinely long, which matters both for cash flow planning and for the ongoing depletion benefits available to investors throughout the production period.

Unconventional programs, by contrast, require a drilling treadmill to sustain production. Because individual well decline is steep, operators must continuously drill new wells to replace the output of aging ones. The program-level production can remain strong, but it depends on sustained capital investment rather than the natural longevity of existing wells.

Investors who are looking for long-lived, income-producing assets with a stable production profile will find the conventional model more aligned with that objective.

How Production Profiles Connect to Depletion Strategy

This is the bridge that most investor education content never builds, and it is one of the most practically useful things you can take away from this article.

Oil and gas depletion allowances exist because the reserves behind your investment are a depleting asset. As production occurs, the resource diminishes. The U.S. tax code recognizes this and allows investors with a working interest to deduct that diminishment from their taxable income, a benefit that few other asset classes can match.

There are two primary methods for calculating this deduction:

1. Percentage depletion allows you to deduct 15% of gross income from the property each year the well produces, regardless of what you originally invested. This benefit continues as long as the property generates income and can exceed your original investment over time.
2. Cost depletion calculates your deduction based on your original investment in the property and the proportion of total estimated reserves produced during the year.

Here is where production profile becomes critical. A conventional well with steady, long-term production creates a very different depletion picture than an unconventional well that front-loads production and declines sharply. The timing of income, the reserve life, and the production curve all influence which method is most advantageous in a given year and over the life of the investment.

Understanding your well type is step one. Understanding how that well generates income over time is step two. Evaluating which depletion method serves your tax position most effectively is step three, and that conversation belongs between you and your CPA, informed by the foundational knowledge this article has given you.

For a complete explanation of how percentage and cost depletion work in a working-interest program, visit our Percentage vs. Cost Depletion in Oil and Gas resource. It is the logical next step from here.

Why We Focus on Conventional Drilling in Oklahoma’s Proven Fields

Everything we have covered so far reflects the reasoning behind BassEXP’s deliberate focus on conventional drilling. This is not a default position or a limitation of our capabilities. It is a considered, experience-driven choice that aligns with the kind of investment we believe serves our investors best.

Oklahoma’s legacy basins contain fields with documented production histories stretching back generations. The formations have proven themselves. The geology is understood. And many of those fields contain stacked-pay intervals that were bypassed or incompletely evaluated during their original development, creating real opportunity for disciplined redevelopment using modern tools.

Our approach to every project reflects these principles:

• Proven geology first. We target areas where offset wells have already established commercial production in the formations we plan to develop. We are not wildcatting into unproven territory.
• Stacked-pay strategy. We structure projects around multiple wells and multiple formations per wellbore, creating numerous opportunities for commercial success within each project.
• Lean operations. We keep overhead low and capital deployment high. More of your investment reaches the formation, where it does its work.
• Boots-on-the-ground oversight. Preston is in the field during drilling and completion, communicating directly with operators and relaying updates to investors consistently throughout the process.
• Aligned interests. We invest alongside our partners. Our capital is at risk alongside yours, which is the only structure we believe reflects genuine alignment.
• Transparency at every stage. From daily drilling updates to monthly owner statements, we communicate clearly and consistently throughout the life of every project.

Three generations of Bass family experience in Oklahoma’s oilfields is not a marketing line. It is the operational foundation behind every lease evaluation, every vendor relationship, and every well we bring to completion. That longevity in an industry where many operators do not survive is, in our view, the most honest proof of credibility we can offer.

Questions Every Investor Should Ask Before Choosing a Drilling Program

Regardless of which operator or program you are evaluating, these are the questions that separate a well-considered investment decision from an uninformed one:

1. Is this a conventional or unconventional program, and what is the geological basis for the project?
2. What does the expected production profile look like, and how does that affect income timing and cash flow?
3. How is capital deployed, and how much goes into the ground versus overhead, fees, and infrastructure?
4. How does the operator communicate during and after drilling?
5. Does the operator evaluate all viable pay zones, or is there a pattern of premature well abandonment?
6. What is the operator’s track record, and can you speak directly with existing investors?
7. Have you reviewed the PPM and AFE with a qualified CPA and independent legal advisor?

These are the questions we walk every investor through before they make a decision with BassEXP. We ask them because we believe informed investors make better partners, and because we have clear, honest answers to every one of them.

A Note on Risk — Because Every Honest Operator Will Tell You

Conventional drilling in proven fields with a disciplined, stacked-pay strategy reduces certain categories of risk in meaningful ways. We believe that. But we will never tell you that it eliminates risk, because it does not.

Every oil and gas investment carries exposure to the following:

• Commodity price risk: Oil and gas markets fluctuate. Production income rises and falls with them, regardless of how well a well is drilled.
• Operational execution risk: Drilling is a complex physical process. No outcome is guaranteed, even in proven geology with experienced operators.
• Reservoir variability: Even within proven formations, individual wells can underperform expectations. Stacked-pay strategy spreads this risk but does not eliminate it.
• Regulatory risk: The regulatory environment can shift, affecting operations, permitting timelines, and program economics.

We share this not to discourage you, but because we believe you deserve the full picture from day one. That is how we operate. That is how three generations of this family have operated. Investors who understand the risks they are taking on are better positioned to make decisions that are right for their financial situation, and they make better long-term partners.

Ready to Go Deeper?

If this article has given you a clearer picture of how drilling type shapes an investment, you are ready for the next layer of the conversation.

The logical next step is understanding how production from a conventional well flows through to your tax picture, specifically how percentage depletion and cost depletion work within a working-interest program. Visit our Percentage vs. Cost Depletion in Oil and Gas resource to continue building that foundation.