Oil & Gas Modeling 101: The Upstream, Midstream, and Downstream Crash Course

Oil & gas modeling is difficult to summarize because each vertical is quite different.

It’s not like FIG, where you can broadly create two groups (banks/insurance vs. everything else), or even like mining, where there are also two broad groups (producers vs. miners)

Instead, the three main verticals – Upstream, Midstream, and Downstream – are basically different industries.

And to make things even more complicated, there are other verticals outside of those, such as Oilfield Services (drilling and energy equipment/services), Integrated Majors that do everything, and royalty companies that do not produce or drill anything but simply earn land that does and earn royalties based on that.

So, there is no simple way to summarize the entire sector. But if you look at the 3 main verticals, my summary would be:

• Upstream (Exploration & Production or E&P): Very CapEx-intensive companies that are also highly sensitive to commodity prices and which have a ton of specialized lingo, metrics, and valuation methodologies.
• Midstream (Storage & Transportation or S&T): These are like utilities companies with high margins, predictable revenue and cash flows, and far less sensitivity to commodity prices than Upstream firms.
• Downstream (Refining & Marketing or R&M): These are low-margin industrials companies with less predictable revenue and cash flows, and moderate sensitivity to commodity prices.

Here’s a comparison table with a full breakout:

For interview purposes, Upstream is the most important segment because most deal activity occurs there, but you should also know the main points of the others.

So you can better understand these concepts, we’re offering several simplified Excel models based on our Oil & Gas Modeling course (focused on Upstream and Midstream).

The Full Video Tutorial:

If you’d prefer to watch rather than read, you can get everything in [very long] video form below:

Table of Contents:

• 0:00: Introduction
• 1:20: The Short Version
• 4:34: Part 1: Upstream Crash Course
• 7:09: NAV Model Overview
• 14:26: Part 2: Midstream Crash Course
• 22:51: Part 3: Downstream Crash Course
• 29:00: Part 4: Oilfield Services, Integrated Majors, and Royalty Co’s
• 33:24: Recap and Summary

Files & Resources:

• Oil & Gas Modeling 101 – Slides (PDF)
• Simplified NAV Model (XL)
• Dividend Discount Model for DT Midstream (XL) | Dividend Discount Model Tutorial
• Simple Type Curve (XL) | Type Curve Tutorial

Oil & Gas Modeling: The Upstream Vertical

Upstream companies, also known as Exploration & Production (E&P) companies, have Reserves of oil and gas in the ground, and they produce a certain amount from these Reserves each year.

Since these Reserves deplete, companies try to replace them via exploratory drilling and acquisitions. If they do not do this, their “economically feasible” Reserves will eventually fall to ~0, and they will no longer generate cash flow.

You normally split E&P companies into existing, producing Reserves and Reserves that have not yet been developed to create forecasts.

The production and cash flow forecasts for the existing, producing Reserves are straightforward: Assume a decline rate for the production and make assumptions for the oil and gas prices, variable/fixed expenses, and any maintenance CapEx required.

For the undeveloped Reserves, it is more complicated because you must make assumptions for the number of wells to drill each year, the initial production from the “average well,” a variable production decline rate, and all the associated expenses and CapEx.

There’s additional complexity because of different Reserve types and different types of energy, each of which is measured in slightly different units.

For example, oil is measured in Barrels of Oil, where 1 Barrel = 42 Gallons (~159 Liters), but natural gas is measured in “Thousand Cubic Feet” (Mcf).

Most E&P companies produce a mix of oil, gas, and natural gas liquids (NGLs), so you must be comfortable converting the units.

Both oil and natural gas liquids (NGLs) are measured in Barrels of Oil (Bbl) or Barrels of Oil Equivalent (BOE); the normal conversion factors are:

• 1,000 Barrels of oil (1 MBbl) = 6 million cubic feet equivalent of gas (6 MMcfe).
• 1 million Barrels of oil (1 MMBbl) = 6 billion cubic feet equivalent of gas (6 Bcfe).
• 1 billion Barrels of oil (1 BBbl) = 6 trillion cubic feet equivalent of gas (6 Tcfe).

To analyze Upstream companies, you must convert different types of energy into standardized units and make varied modeling assumptions for the different Reserve and well types.

The standard Reserve categories and their “successful extraction” probabilities are shown below:

Most financial models focus on the Proved Developed (PD) and Proved Undeveloped (PUD) categories since these roughly correspond to the “existing, producing Reserves” and the “Reserves that have not yet been undeveloped.” Also, they have the highest probability of successful extraction.

Forecasts and the Net Asset Value (NAV) Model

The building block of most E&P company financial models is the Type Curve, which describes how much in CapEx (“Drilling & Completion Costs” or D&C Costs) it takes to drill a new well, how much in oil/gas/NGLs it initially produces, and how much it declines over time.

We previously covered the Type Curve in another tutorial, so please refer to that for all the details.

In theory, you can use Type Curve data to plot the production profile of each new well the company drills; in practice, the data is often sparse and disclosed in a confusing way, so you may have to settle for “rough estimates.”

If you want to forecast an E&P company’s cash flows and financial statements and value it, everything flows from the Net Asset Value (NAV) model, which is an asset-level forecast of the company’s long-term cash flows with no Terminal Value.

To set up a NAV model, start by gathering data from the company’s annual and quarterly reports, investor presentations, and recent earnings calls.

Once you’ve done that, the basic steps in the modeling process are as follows (see the section below this outline for screenshots demonstrating examples of each step):

• Step 1: Proved Develop Production and Cash Flows – Assume that Proved Developed Production declines over time until it’s no longer economically feasible; forecast revenue, expenses, and cash flows based on model-wide commodity prices and $ / Mcfe or $ / BOE assumptions.
• Step 2: PUD Assumptions, Production, and Cash Flows – Create a production decline curve for each new well, assume a certain number of new wells drilled each year, and aggregate the total production over all these wells. The commodity prices used to drive revenue should be the same as in Step 1, but the $ / Mcfe and $ / BOE assumptions for the expenses may differ.
• Step 3: Hedging and Optional/Other Features – If the company is using swaps, collars, or other instruments to modify its realized oil/gas prices, you might include them here. There may also be additional schedules for taxes, depreciation, and other model features.
• Step 4: Cash Flow Rollup – Once the PD and PUD forecasts are complete (and any others, such as PROB and POSS), you aggregate all the cash flows into a single schedule and discount them to their Present Value. This rollup should also have projections for the corporate-level expenses and taxes.
• Step 5: NAV Calculation – You take the PV of these cash flows and then subtract the PV of various corporate-level expenses over the forecast period, add non-core assets and undeveloped land, and add/subtract the usual items in the Enterprise-Value-to-Equity-Value bridge to get the Net Asset Value. Divide by the share count to get the NAV per Share.

To give you a sense of how this works, you can get a simplified NAV Model here.

Here are a few examples of different parts of the process:

Step 1: PD Production and Cash Flows – As shown below, this NAV Model assumes a constant decline rate for all the existing, producing wells:

The revenue, asset-level expenses, and cash flows are all derived from these production figures:

Step 2: PUD Assumptions, Production, and Cash Flows – This is probably the most difficult part of the model and requires some complex Excel formulas based on TRANSPOSE and OFFSET:

However, the revenue, expenses, and cash flows are still set up in the same way and derive from overall $ / Mcfe or $ / BOE assumptions for aggregate production.

Step 3: Hedging and Optional/Other Features – We are skipping this step in this simplified model, but you may have to modify the effective realized prices for a portion of the production if the company uses hedging.

Step 4: Cash Flow Rollup – You normally aggregate all the revenue and expenses and factor in corporate-level expenses and taxes as well. This part is mostly a set of TRANSPOSE functions with some additional calculations for the corporate-level line items:

Step 5: NAV Calculation – In this final step, you sum up the Present Values of all these line items and go through the normal Enterprise Value/Equity Value bridge items to get the Net Asset Value and NAV per Share:

At this point, you have a few options.

If you want, you could extend this NAV Model into 3-statement projections because most of the revenue and expense line items flow in directly from the NAV, which goes out much further than the typical 3-statement model.

However, you don’t “need” a full 3-statement model to value an E&P company. Even if you want to use comparable public companies and precedent transactions, you should be fine if you have the Reserve and Production information and simple financial metrics such as EBITDA/EBITDAX.

If you do want to create the financial statements, there will be some complexity around the Debt, Dividends, DD&A, and Taxes, because these items were all either ignored or treated differently in the NAV Model.

For example, the DD&A shown on the statements might differ from the NAV numbers, you’ll have to forecast the company’s Debt and Equity issuances based on its overall corporate-level cash flows, and you’ll have to link Dividends to Net Income or cash flow.

The financial statements themselves are not tremendously different for E&P companies. As you might expect, Net PP&E is huge due to the Reserves, Debt is substantial for most companies, and Gains and Losses on Derivatives can make a big impact on companies that hedge.

Other Valuation Methodologies and Multiples

You never use a traditional Discounted Cash Flow (DCF) model to value pure-play E&P companies because the Terminal Value assumption does not make sense.

Similarly, the Dividend Discount Model doesn’t make much sense in this sector due to the Terminal Value assumption and the highly irregular Dividends.

However, you can use Public Comps and Precedent Transactions to value E&P companies. The key differences are as follows:

• Screening Criteria: Rather than financial metrics such as Revenue or EBITDA, you typically screen based on O&G-specific operational ones, such as Proved Reserves or Daily Production.
• Metrics and Multiples: You normally use E&P-specific metrics such as EBITDAX (EBITDA Before Exploration Expense), Proved Reserves, and Daily Production, all of which pair with Enterprise Value. The operational metrics and KPIs also differ (e.g., Proved Developed / Proved Reserves, Oil Mix %, and the R / P Ratio).

You can see an example of the output from E&P Public Comps below:

EBITDAX is a common metric because of accounting differences: Some E&P companies use “successful efforts” accounting and expense unsuccessful exploration costs, while others use “full cost” accounting and capitalize them.

EBITDAX, like EBITDAR for retail and airline companies, normalizes for this and enables proper comparisons.

Oil & Gas Modeling: The Midstream Vertical

Midstream firms are like utility companies with far more revenue visibility and a bit of exposure to commodity prices.

The concepts of Production and Reserves are not relevant to Midstream companies because they transport and store oil, gas, fuel, and water (!) from other companies, but they do not explore for or extract anything (unless they have Upstream operations).

Midstream firms typically earn Revenue based on a “fee per unit transported/stored” model, and these fees are usually governed by long-term contracts that provide pricing visibility.

As a result, companies in this vertical are the least sensitive to commodity prices out of anything in oil & gas. However, “least sensitive” does not mean “insensitive.”

Commodity prices still affect them because higher prices incentivize Upstream companies to drill and extract more, leading to higher transported volumes.

But since these prices mostly affect volume rather than fees per unit, Midstream firms experience less impact than Upstream or Downstream firms.

The standard Midstream business model looks like this:

The MLP Structure, Financial Statements, and Projections

Many Midstream firms in the U.S. are structured as Master Limited Partnerships (MLPs), which are pass-through entities that pay no corporate-level taxes (or minimal taxes) and instead make Distributions to unitholders, who are taxed at their personal rates.

To qualify for this treatment, the MLP must earn 90% of its income from “qualifying sources,” such as the production, processing, storage, and transportation of natural resources – but there are no federal requirements around the percentage of Net Income they must distribute (unlike REITs).

MLPs have General Partners (GPs) that own a small percentage (e.g., ~2%) and Limited Partners (LPs) that own the vast majority of units and act as passive investors – but the tricky part is that Distributions are not always split proportionally between them, and this split may change based on overall performance.

Ever since corporate tax rates fell in the U.S. following the 2017 tax reform, the MLP structure has become less common, so many firms have converted to standard C-Corporations that pay 21% federal taxes and a small percentage of state and local taxes.

Regardless of the corporate structure, metrics such as the Distributable Cash Flow (DCF) and Distribution Yield, defined as Distributions / Equity Value, are critical.

Investors judge companies based on the consistency of their Distributions and their growth potential over time.

These firms tend to have high EBITDA and FCF margins, so it’s plausible to see Distribution Yields of 8%, 10%, or even higher.

You can still use metrics such as Revenue Growth and EBITDA, but this focus on Distributions, regardless of the corporate structure, is a core difference in Midstream.

A Midstream company’s financial statements are not that different from a standard company’s.

As with E&P companies, Net PP&E and Debt are both very large, and you’ll occasionally see industry-specific line items, such as Asset Retirement Obligations (AROs) and Derivatives if the firm practices any hedging (unlikely, but possible if it has operations outside of Midstream).

Probably the biggest difference with Midstream firms – especially MLPs – is that line items related to partial ownership and stakes in other entities are very common.

For example, you’ll see Equity Investments and Noncontrolling Interests all the time, and “Common Equity” may be split into the GPs’ portion vs. the LPs’ portion.

To forecast a Midstream company’s financial statements, you normally follow these steps:

• Step 1: Capacity, Utilization, and Revenue – Forecast the company’s transportation/storage Capacity, Utilization Rates, and Fees to determine its revenue; you may split this by resource type or region.
• Step 2: Capital Expenditures and Operating Expenses – Midstream companies always spend something on Maintenance CapEx, but the bulk of their CapEx is growth-related. Operating expenses are mostly fixed, but some components may be variable.
• Step 3: Financial Statement Projections – The financial statements are mostly straightforward, but you must pay special attention to the assumptions around the Distributions, Debt Issuances/Repayments, and Stock Issuances/Repurchases.
• Step 4: Distributable Cash Flow, Distributions, and Key Metrics – The Distribution Coverage Ratio (DCR), DCF Yield, and Distribution Yield should all stay in reasonable ranges over time, even if the company changes its capital structure.

We’re not sharing an example of a full 3-statement model for a Midstream company at this time, but you can review this example of Cash Flow and Dividend Projections for DT Midstream, which we used in the Dividend Discount Model tutorial.

A few examples of the steps above, taken from the Western Midstream Partners case study in our Oil & Gas course, are as follows:

Step 1: Capacity, Utilization, and Revenue – All the numbers in this model are based on simple percentage growth rate assumptions, informed by the historical trends and management’s estimates:

We do something similar for DT Midstream, but it’s simpler since it’s a smaller company with more limited operations.

Step 2: Capital Expenditures and Operating Expenses – We split CapEx into Growth and Maintenance, and OpEx into several different categories:

Step 3: Financial Statement Projections – The DT Midstream model does not have full financial statement projections since it’s “cash flow and dividends only.”

The WES model in the full course includes these, and we pay special attention to the cash flow spent on Debt Repayments and Stock Repurchases, as the company has excess cash in each period:

The Distributions to the investor groups are all percentages of different Net Income metrics.

Step 4: Distributable Cash Flow, Distributions, and Key Metrics – You can see some of the key metrics below:

If WES were a C-Corporation rather than an MLP, the “LP Distributable Cash Flow” calculation would be simply “Distributable Cash Flow” and not deduct the Distributions to the GPs.

The Cash Taxes would also be significantly higher, and the Yield metrics would be lower as a result.

Valuation Methodologies and Multiples

Valuation is standard in the Midstream vertical, as you still use comparable public companies, precedent transactions, and the DCF analysis based on Unlevered Free Cash Flow.

The main differences are slightly different metrics and the usefulness of the Dividend Discount Model, in addition to the DCF.

A few differences in the screening process for both public comps and M&A comps include:

• Financial Metrics: It’s safest to screen by EBITDA because other metrics are inconsistently defined and not always available on all sources. You can certainly use metrics like Distributable Cash Flow, Distributions, and the Distribution Yield, but more for the valuation rather than screening.
• MLPs vs. C-Corporations: It is not ideal to include MLPs and C-Corporations in the same set because the very different tax rates result in different DCF and Distribution numbers. If you do mix them, focus on metrics like EBITDA that ignore taxes.
• Business Similarity: If you can, it’s better to screen by companies with similar businesses within Midstream, such as pipeline companies, rather than a mix of pipeline and maritime shipping companies.

You can see an example of the output from the WES valuation below:

The DCF and Dividend Discount Model are both quite standard.

Note that for MLPs, the DDM is labeled “Discounted Distribution Analysis” (DDA) instead, since the firm technically issues “Distributions” rather than “Dividends.”

You can see the full setup for DT Midstream in the Dividend Discount Model; the main point is that Dividends must be based on the Distributable Cash Flow and a consistent Coverage Ratio:

Since DT Midstream’s implied share price from the DDM was ~50% higher than its share price at the time of the analysis, it seemed greatly undervalued.

And, sure enough, in the ~2 years after this valuation, the company’s share price went on to double (going from $49 to over $100).

Oil & Gas Modeling: The Downstream Vertical

Downstream companies earn money based on the margin between the price of oil (plus ancillary/processing costs) and the price of finished oil products, such as diesel and gasoline.

For example, if a company pays $70 per barrel for oil and $20 per barrel in processing and overhead fees, and it sells that oil as diesel for the equivalent of $100 per barrel, its Refining Margin is $100 – $90 = $10.

Another key driver, the “Crack Spread,” is $100 – $70 = $30; it factors in only the raw oil price.

Downstream companies are sensitive to commodity prices in the sense that the Refining Margin often follows oil/gas prices – and this Margin is what matters.

You can think about it like this:

• Upstream: Revenue follows commodity prices almost 1:1, but expenses do not.
• Midstream: Neither revenue nor expenses are very sensitive to commodity prices.
• Downstream: Both revenue and expenses trend with commodity prices, but not necessarily 1:1.

Production and Reserves do not matter for Downstream companies since they don’t explore for or extract oil and gas directly (unless they own Upstream operations).

The overall business model looks like this:

Some Downstream companies in the U.S. use the MLP structure, but it’s much less common than in Midstream. Companies’ EBITDA and cash flow margins are also far lower, so Dividend Yields and tax efficiency are less important.

Growth is extremely difficult for Downstream firms in developed markets due to significant regulations and restrictions around new refineries (the last major U.S. oil refinery was built in 1976!).

So, in most models, “Growth CapEx” is not significant; if a refining company wants to grow, it must acquire other companies or assets or upgrade existing ones.

Financial Statements and Forecasts

As always, you don’t “need” a 3-statement model to value a Downstream company.

Income Statement forecasts and a partial Cash Flow Statement are enough, since you value Downstream companies with a standard DCF and multiples such as TEV / EBITDA and P / E.

The overall forecasting process for the statements looks like this:

Step 1: Capacity, Utilization, and Refining Margins – Forecast the company’s daily and annual Refining Capacity, Utilization Rates, Refining Margins, and Oil Prices to determine its revenue and expenses; scenarios are quite important here.

Step 2: Capital Expenditures – These will mostly be Maintenance CapEx since organic growth is expensive and difficult in this vertical.

Step 3: Other Business Segments (If Applicable) – Many Downstream companies also have segments for retail (e.g., gas stations), chemicals, or electricity production. These tend to use simple projection methods, but can be more complex in certain cases.

Step 4: Financial Statement Forecasts – The financial statement forecasts are like those for Midstream companies, but the Distributions/Dividends are less predictable/consistent and, therefore, matter less.

You can see a few examples of the steps above taken from the Downstream model for Saras S.p.A. (Italy) in the Oil & Gas course:

Step 1: Capacity, Utilization, and Refining Margins – Oil prices varied by a tremendous amount in the historical period here ($40.00 to $100.00 USD over just 4 years), so assume a spread that’s nearly as wide in the forecasts.

The Capacity and Daily Production (“Refinery Runs”) stay almost the same, but we also build in scenarios for the Refining Margins, as they usually follow oil prices:

• Average Cost per Barrel of Fuel Sold = Oil Price + “All-In Cost” Premium
• Average Price per Barrel of Fuel Sold = Average Cost per Barrel + Refining Margin

Step 2: Capital Expenditures – Most of the CapEx here is maintenance-related and is framed on a € / Bbl / year basis.

However, just to illustrate how a small amount of Growth CapEx might work, we assume modest expansion in the projected years (the Capacity then increases based on this):

Step 3: Other Business Segments (If Applicable) – In this case, Saras also produces electricity from a natural gas plant and from renewable sources (solar and wind).

We forecast the Capacities in MW and the Utilization Rates and Tariff Rates to estimate the revenue from these:

Step 4: Financial Statement Forecasts – Most of the drivers here are straightforward; AR is linked to Revenue, Inventory is linked to COGS, and most of the Operating Expenses are linked to Revenue or the Refining Capacity.

One difference is that since the cash flows are much less predictable than in Midstream, there will be periods in which the company issues additional Debt or Stock rather than repaying/repurchasing them.

This also means that Dividends will fluctuate heavily, even in “baseline” scenarios in which the commodity prices and Refining Margins follow normal trends:

Valuation Methodologies and Multiples

As with Midstream, EBITDA is the best financial screening metric (in addition to the usual geographic and industry screens).

The metrics and multiples used in the public comps and precedent transactions are all standard (TEV / Revenue, TEV / EBITDA, and P / E, with a focus on the latter two), but the screening process can be tricky.

Outside the U.S. and Canada, there aren’t many independent, pure-play Downstream companies, so you may have to use a much wider geographic screen than normal (e.g., “EMEA” rather than just “Europe”).

Also, many Downstream companies operate in other business segments, so you must be careful with the revenue from different sources; ideally, 50%+ should come from Downstream operations.

The public comps we used for Saras S.p.A. are not particularly good, but they work:

The two Greek companies here – Hellas and HELLENIQ – are reasonable choices, but the Romanian company (Rompetrol) is much smaller and has questionable financials, and Esso S.A.F. is a small French company majority-owned by Exxon-Mobil, so it’s not ideal.

It probably would have been better to use a global screen and include U.S. and Canadian companies in this case.

The DCF is very standard in the Downstream segment; most of the complexity comes from the need to include scenarios in your model, especially if it extends beyond the end of the 3-statement projection period:

You may also have to pick a wider range of Terminal Multiples and Growth Rates than normal due to the industry’s cyclicality; multiples could span a huge range, depending on the macro environment:

The NAV Model does not apply to Downstream companies, and the Dividend Discount Model is not very useful.

You might consider using a Sum-of-the-Parts (SOTP) valuation, especially if the company’s revenue is highly diversified beyond refining & marketing operations.

Oil & Gas Modeling in Other Verticals: Oilfield Services

The main categories here are oil & gas drilling and energy equipment and services.

Companies in this category operate mostly like standard business/professional services firms, but with different drivers and much more exposure to commodity prices.

You would normally start by forecasting the operating days, utilization rate, and daily rates for something like an offshore drilling company.

You can see examples from China Oilfield Services Limited below:

Expenses are linked to the number of vessels operating, fuel costs, employees required, and amounts owed to subcontractors.

This vertical might seem completely divorced from commodity prices, but, as with Midstream, higher oil and gas prices tend to encourage more drilling, which in turn drives higher demand for drilling and well-maintenance services.

So, it is still worth building scenarios into an Oilfield Services model to reflect different day rates and utilization rates.

To value these companies, you can still use public comps, precedent transactions, and the DCF, with screening based on EBITDA, geography, and industry, and mostly standard multiples, such as TEV / EBITDA and P / E.

One potential difference is that you could see the P / NAV multiple as well, especially for service companies that rely on fleets of ships.

The idea here is to assign a “market value” to all the company’s ships, add it to the rest of the Assets, and then subtract the Liabilities to determine the company’s “Net Asset Value.”

Confusingly, this is different from the “NAV” used in the Upstream segment.

This is more like a liquidation valuation based on individual Asset and Liability values, but with a more optimistic view of these values based on a sustainable, healthy company.

Oil & Gas Modeling in Other Verticals: Integrated Majors

Integrated majors include large, diversified companies that do a bit of everything, such as Exxon-Mobil, Shell, and BP, as well as state-owned entities that do the same thing, such as Saudi Aramco in Saudi Arabia, CNOOC in China, and Rosneft in Russia.

Since these companies operate across other verticals, the Sum-of-the-Parts (SOTP) valuation is often used to value them.

This requires a lot of time and effort because you must set up a NAV Model for the Upstream business and then build separate forecasts for Midstream, Downstream, and other segments.

In some cases, it might not even be worth it because the Upstream segment tends to represent 50%+ of the earnings and cash flows for these firms:

The risks and potential returns can also be difficult to assess because state-owned firms may have different incentives and might not be able to “fail” as a normal company could.

So, the Discount Rate calculation deserves special attention for anything in this category.

Oil & Gas Modeling in Other Verticals: Royalty Companies

Royalty companies are usually considered a subset of the Upstream or E&P segment because they are quite similar, as they both earn revenue based on the oil and gas produced and sold from specific regions.

But there is a key difference: Royalty companies do not actually drill or produce anything themselves. They simply own the land on which other companies operate to do this, and they earn a percentage of those companies’ revenue.

As a result, the financial statements are extremely simple, and to forecast revenue, you need to estimate the production levels of other companies that operate on their land.

Here’s an example for the Permian Basin Royalty Trust:

Yes, these are the company’s entire “financial statements.” There’s not much to them.

Like MLPs, royalty companies are structured as pass-through entities that distribute their earnings to unitholders without paying corporate taxes first.

To value a royalty company, you could use valuation multiples such as TEV / Revenue or TEV / EBIT (since there is no real Depreciation), but you could also use a variant of the NAV Model where you forecast drilling, production, and revenue over the life of the royalty agreement and discount the cash flows to Present Value.

Because royalty companies track commodity prices almost 1:1, it’s normal to see wild swings in their multiples, such as jumps from 5x to 50x EBIT (or the reverse).

Oil & Gas Modeling 101: Final Thoughts

At the start, we mentioned that oil & gas modeling is difficult to “summarize” because each vertical is effectively a different industry.

That’s true, but there’s also an important corollary: Most of these verticals are close to other, standard industries, such as industrials and utilities.

Upstream is the main one that’s very different, with specialized terminology and valuation methodologies.

So, if you focus on that vertical, yes, oil & gas modeling takes time to learn properly, especially when it comes to finding the data and incorporating it into your own models.

But if your team focuses on Midstream, Downstream, or Oilfield Services, it’s mostly about different drivers and projections, but with standard valuation multiples and methodologies.

For an industry that defies simple summaries, this is just about the simplest one you can come up with.