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Oil & Gas Financial Modeling 101
Out of all the industry-specific courses I’ve released, Oil & Gas Financial Modeling has drawn the most interest.
That surprised me at first because there’s no obvious reason why it would be more popular than the others.
But once you start learning something about the oil & gas industry, the reason becomes obvious: the strategies you use when modeling oil & gas companies apply to more than just oil & gas companies.
The obvious example is mining , where there’s a lot of overlap, but almost anything that depends on commodity prices is similar.
The good news is that while bank and insurance modeling is almost a different game entirely, oil & gas modeling is more like a variation on a game you’re already familiar with.
How Does the Oil and Gas Industry Work?
Oil & gas, mining, and other natural resource companies have a simple business model: find and extract valuable stuff from the ground, turn it into something useful, and then sell it to customers.
But if you read that statement carefully, you’ll immediately see how it gets more complex:
- So, what do you focus on? Finding and extracting valuable stuff? Turning it into something useful? Transporting and selling it to customers? All of those?
- If you make software or widgets or clothes, you can pretty much set prices yourself… within reason. Some products sell for $10, some for $1000, and there’s always a reason why. But if you sell gold, oil, or gas, you can’t determine the price – “the market” does.
Let’s address point #1 above first and see how the industry is divided:
- Upstream Companies: Also known as Exploration & Production, or E&P, companies, they focus on finding and extracting minerals and resources from the ground.
- Midstream Companies: They focus on transporting oil, gas, and other commodities to companies that will sell them. This is mostly done via “pipelines” that carry these commodities over great distances.
- Downstream Companies: They refine and market commodities (hence the “R&M” name for them), turn them into something useful – AKA jet fuel, automobile gasoline, diesel, and so on – and then sell them to customers.
- Oil Field Services: They don’t find, transport, or sell oil & gas, but instead provide services to companies that do. They might maintain their oil fields, repair broken spots, upgrade the technology, or even provide security for workers.
- Integrated Majors: Think BP and Exxon Mobil. These companies do everything above, just in different proportions. The most common combination is to focus on upstream and downstream, and then leave the rest to dedicated specialists.
How Are Oil & Gas Companies Different, Modeling-Wise?
For purposes of this tutorial, we’re going to focus on Upstream , or E&P (Exploration & Production) companies because those are the most “different” from normal companies – and they’re the most common topic in interviews.
We will also touch on diversified , or integrated major , companies, such as Exxon Mobil since you can learn a lot about other segments by analyzing them.
So how is oil & gas modeling different?
- You Can’t Control Prices or Revenue – This is the big difference that results in most of the other differences.
- They are Balance Sheet-Centric – Just like banks or insurance firms, an E&P company is far more dependent on its balance sheet than, say, a technology or consumer retail company. The balance sheet contains its most important asset: the reserves that will generate future revenue and profit.
- Accounting is Different – You not only see different line items, but you also see two different accounting methodologies: full cost and successful efforts .
- Depleting Assets Galore – For a normal company, assets tend to move… up and to the right. Items like PP&E, inventory, accounts receivable, and so on increase as the company grows. But as an oil & gas company produces more and more and earns revenue, its assets decline because they use up all those valuable resources they found in the ground.
- Cyclicality – Going along with the first point, oil & gas companies follow commodity price cycles. Investing in an energy or mining company is almost like investing in the underlying commodity, which means you have to be comfortable with giant price swings.
The good news is that unlike banks and insurance firms, oil & gas companies still sell tangible products to people – so your models are more similar.
Oil & Gas Financial Statements – Projecting Revenue and Expenses
Before you begin projecting an energy company’s financial statements, you need to know something about the units used.
Oil is typically measured in Barrels (1 Barrel = 42 Gallons, and yes, even countries that use the metric system still use Barrels); natural gas is measured in Cubic Feet (even with the metric system), and mining companies use whatever makes sense (iron ore/coal/aluminum/copper/lead/zinc/nickel/manganese/uranium = tonnes, diamonds = carats, and gold/silver = ounces).
You measure the company’s reserves (how much they have on their balance sheet, ready to extract, produce, and sell) and production (how much they produce and sell each day, month, quarter, year, etc.) in these units.
When you project a natural resource company’s statements, you begin by projecting its production by segment based on its reserves and its historical patterns.
So let’s say that a company has 12,000 billion cubic feet (12,000 Bcf) of natural gas in its reserves and produces 500 billion cubic feet (500 Bcf) annually.
You might assume a modest increase over that number, especially if the company is spending a lot on finding new resources.
So maybe you assume that they produce 550 Bcf next year and then 600 Bcf the year after – which you would then cross-check with equity research and their reserves (you don’t want to assume that they produce 100% of their reserves in 1 or 2 years).
And then you deduct this production from their reserves… and (hopefully) replace it with sufficient CapEx spending, linking the dollar amount of that spending to a specific amount of reserves.
Revenue is trickier because you can’t set prices yourself.
But the solution is surprisingly simple: you use scenarios in Excel.
So you might create a “low” scenario where oil prices are, say, $40 per barrel, a “middle” scenario where oil prices are $70 per barrel, and a “high” scenario where oil prices are $100 per barrel.
Doing that lets you see the range of possible outcomes for a company based on commodity prices.
There’s more to it than that because you also need to take into account hedging and the fact that the company will never get the full market price due to middlemen, commissions, and so on – but that’s the basic idea.
Expenses are more involved because you have both production-linked expenses – which you estimate on a dollar per barrel of oil or per cubic foot of gas basis – and then non-production-linked expenses , such as stock-based compensation and smaller, miscellaneous items.
Generally you look at a company’s filings and figure out what is production-linked and what isn’t, and then assume an increasing dollar value for the production-linked ones over time and make the non-production-linked expenses a percentage of revenue or other items.
To see a real-world example of these projections, click here to view a sample lesson from the Oil & Gas Modeling course on Price Hedging and Revenue by Segment .
Energy companies’ income statements do not have the usual Cost of Goods Sold / Gross Profit and Operating Expense distinction that you see for normal companies.
Instead, they are split into Revenue and (Operating) Expenses and then Other Income / Expenses. Here are the typical items:
- Revenue: Sometimes it’s categorized by Upstream vs. Midstream vs. Downstream; if the company just does Upstream, it is split into energy categories such as Gas & Natural Liquids, Oil, and Miscellaneous.
- Expenses: Production (anything associated with extraction from the ground); Taxes, Transportation & Other; Exploration (the cost of finding energy and minerals); Depreciation, Depletion , and Amortization (not only normal D&A but also the reserves being depleted over time); Selling, General & Administrative; Derivative Fair Value Gain / (Loss) (for companies that hedge); the Accretion of Discount in the Asset Retirement Obligation (more on this below).
- Other Income / (Expenses): You might see items like interest and investment income and expense and also gains and losses on asset sales, partnerships, and royalty trusts here.
The presentation is very similar to what you see for normal companies: Revenue Minus Expenses = Operating Income, Operating Income Plus Other Income / (Expenses) = Pre-Tax Income, and Pre-Tax Income * (1 – Tax Rate) = Net Income.
One final point: oil & gas companies tend to have very high deferred income taxes . Sometimes 75% or more of a company’s income statement taxes are deferred, meaning that they’re not paid in cash in the current period.
You see such high percentages because of the sky-high depreciation, depletion & amortization (DD&A) numbers for oil & gas companies and because many companies record them differently for book and tax purposes.
This doesn’t really affect the income statement, but you do need to add back deferred taxes on the cash flow statement.
Let’s start with the easy part: Shareholders’ Equity is pretty much the same for oil & gas companies.
Assets and Liabilities are still split into Current Assets, Long-Term Assets, Current Liabilities, and Long-Term Liabilities, but there are a few new items.
Sometimes, E&P companies also create a category for PP&E (Plants, Property & Equipment) on their balance sheet and list their reserves by category there (Proved, Unproved, and Other – basically, the probability of those reserves actually turning into something real).
- Current Assets: Cash & Cash-Equivalents, Accounts Receivable, Inventories, Derivative Fair Value (for companies that hedge), Income Tax Receivables / Deferred Tax Benefits, and Other.
- Long-Term Assets: Investments, PP&E (Proved, Unproved, Other, and Accumulated DD&A), Goodwill & Other Intangibles, and Other Assets.
And then on the Liabilities side:
- Current Liabilities: Accounts Payable , Current Portion of Debt, Derivative Fair Value (for hedging), Deferred Income Taxes, and Other.
- Long-Term Liabilities: Long-Term Debt, Pension Benefits, Deferred Income Taxes, the Asset Retirement Obligation , and Other.
If you’re familiar with normal companies, most of these items are self-explanatory and similar to what you see elsewhere. So I want to focus on the ones that are different or that don’t exist in other industries:
- Derivative Fair Value: This can actually show up everywhere – current assets, long-term assets, current liabilities, and long-term liabilities. Energy companies use hedging to protect themselves from falling commodity prices, and these “derivatives” consist of contracts that say, for example, “Even if oil prices fall to $50 per barrel, I can still buy oil from you at $60 per barrel.” Derivatives on the assets side represent long positions and on the liabilities side they represent short positions.
- PP&E: Normal companies have this as well, but oil & gas companies often break it into categories such as Proved Reserves , Probable Reserves , and Possible Reserves ; Proved Reserves have a 90%+ chance of being recovered, Probable is between 50% and 90%, and Possible is less than 50%. Accumulated Depreciation, Depletion & Amortization is also huge and is a contra-asset that’s counted against Gross PP&E to arrive at Net PP&E here.
- Asset Retirement Obligation: Just as it costs money to open up new oil wells and gas fields, it also costs money to shut them down . This liability represents that future cost, and you add to it over time by adding in the future cost of shutting down each new well or field you develop (reflected in the accretion of the asset retirement obligation discount on the income statement).
Cash Flow Statement
Similar to other industry-specific cash flow statements, oil & gas cash flow statements are very similar to what you see for normal companies: start with net income, add back non-cash charges, take into account working capital changes , and then go through the normal investing and financing sections.
The main differences lie in the magnitude and frequency of some of the items:
- Depreciation, Depletion & Amortization: Massive for O&G companies and sometimes even bigger than their net income.
- Other Non-Cash Expenses: Besides the usual ones, you’ve also got the accretion of discount in the asset retirement obligation, gains and losses on asset, partnership, and royalty sales, and possibly something called the dry hole expense (see the upcoming section on Successful Efforts vs. Full Cost).
- Investing Activities: CapEx is massive for natural resource companies, once again often exceeding their net income. Asset sales are also very common. These companies spend a huge amount exploring and buying assets, and also receive a good chunk of change for selling assets like individual oil fields and gas wells.
- Financing Activities: Since oil & gas companies are constantly buying assets and spending a small fortune to find more assets and since they deal with volatile commodity prices, they have huge financing needs. So you see massive amounts of debt being raised and paid off, along with equity financing in some cases.
How Everything Flows Together
We already went through part of this one with the revenue and expense projections above, but just to recap:
- You start by projecting annual production on a per-commodity basis, and then assume low, mid, and high price cases for each commodity to build multiple scenarios in Excel.
- Based on these numbers, you calculate revenue . You project expenses either on a production-linked basis (e.g. Production, Taxes, Transportation, DD&A) or a non-production-linked basis (Stock-Based Comp., Derivative Gains / (Losses), etc.).
- On the cash flow statement , you start with net income, add back non-cash charges (mostly flowing in from the income statement), and make sure working capital links in properly from the balance sheet once you’ve projected the BS in the next step.
- You also link CapEx to production and translate the dollar amounts back to natural resource units (Barrels, Cubic Feet, Tonnes, Ounces, etc.) to keep a running tally of how the company’s Reserves change over time – subtract Production, add new discoveries and acquisitions, and subtract sales of reserves.
- Debt and equity financing activities would be determined by a debt schedule you create; you could set these to $0 to simplify the model, but almost all energy companies need to raise capital consistently so you should at least make a simple estimate.
- Most of the balance sheet items flow in from the cash flow statement or can be linked to income statement items (e.g. accounts receivable to revenue); you will hold many of the items constant (Goodwill) or set them to $0 to simplify in some cases.
To get a sense of what the financial statements look like for a real company, click here to check out XTO Energy’s statements from just before they were acquired by Exxon Mobil .
A diversified oil & gas company has slightly different statements and you see more items related to its midstream and/or downstream capabilities; for a good example, click here to view Exxon Mobil’s financial statements .
Successful Efforts vs. Full Cost
Remember how I said above that oil & gas companies use “different” accounting?
Revenue recognition is straightforward, but the expenses get tricky. You always capitalize acquisitions and development (actually constructing the field or well), and you always expense production.
But exploration costs are more subtle: it seems obvious that you’d capitalize successful explorations, i.e. if you go out into the fields and actually find oil, but what about unsuccessful explorations?
Under the successful efforts methodology, you expense them, and under the full cost methodology you capitalize them and add that CapEx to the PP&E on your balance sheet.
That seems straightforward, but it gets confusing on the other financial statements because some companies apply these standards inconsistently and use a “mix” of both.
That “dry hole expense” I mentioned above is another name for unsuccessful exploration , and some companies actually add it back on their cash flow statements (long story, but essentially they are using a mix of both standards).
But there is some good news: if you’re outside the US and therefore use IFRS, all companies must use the “successful efforts” standard.
Large companies tend to use successful efforts because they can afford the hit to their net income, while smaller companies tend to use the full cost method to boost their earnings.
One downside of the full cost method is that you need to test the PP&E balance every so often and apply write-downs if the book value gets out of line with the market value – so write-down and impairment charges are common on full cost companies’ income statements.
Oil & Gas Valuation
The good news is that most of the same valuation methodologies you’re used to seeing – public comps, precedent transactions, and even the DCF model – still apply to (most) oil, gas & mining companies.
The bad news is that the metrics and multiples involved are different:
- No P/E or Revenue Multiples: P/E is not terribly useful because many energy companies have odd tax situations, huge depreciation numbers, and lots of impairment charges and write-downs; revenue multiples are useless because oil & gas companies have limited control over their revenue due to their dependence on commodity prices.
- EBITDAX, not EBITDA: The “X” stands for Exploration Expense, and we add back it to EBITDA when working with E&P companies because of the issue with successful efforts vs. full cost accounting above: we’re normalizing the metric. Sometimes you do see EBITDA as well, especially for more diversified companies, non-E&P ones, and even for the occasional E&P set if the companies all use one accounting standard.
- Production and Reserves Multiples: Since oil & gas companies are so dependent on natural resources, why not make the resources into multiples? And that’s exactly what you do with their Proved Reserves and Daily or Annual Production numbers. You use Enterprise Value in the numerator for both of these, and the values might be anywhere from $1.00 to $50.00 depending on the companies, region, economy, and so on.
- Different Screening Metrics: Rather than using revenue or EBITDA, you might pick companies and transactions based on Proved Reserves or Production volume; other important metrics include the R / P Ratio (Proved Reserves / Annual Production), the % Proved Reserves in their Total Reserves, and the % Oil Mix.
So there are some differences, but the mechanics of selecting and calculating the metrics and multiples for comps remain the same.
You can still use a DCF, but there are a few issues with the traditional Unlevered Free Cash Flow approach :
- Capital Expenditures tend to be massive, which depresses Free Cash Flow and makes almost all of the company’s value depend on the Terminal Value.
- Perpetual Growth is a big leap for oil & gas companies. There’s a limited amount of oil and gas on planet Earth, so can you really assume that the company will grow at 3%, 2%, or even 1% into perpetuity?
You do still see DCFs sometimes, but they are more common for midstream, downstream, and oilfield services companies.
For E&P companies, there’s an alternate intrinsic valuation methodology called the Net Asset Value (NAV) model that often gives more accurate results.
The Net Asset Value (NAV) Model
The NAV model flips the traditional DCF on its head because you no longer assume perpetual growth .
Instead, you assume that the company adds nothing to its reserves and that it produces 100% of its reserves until it runs out of natural resources completely.
Here’s a rough outline of how it works:
1. Set Up Columns to Track Each Commodity, Revenue, Expenses, and Cash Flows.
You want to track the beginning and ending reserves each year, the annual production volume, and the average price for each commodity; typically you use the same low/mid/high price cases that you used in the company’s operating model.
2. Assume Production Decline Rates and Calculate Revenue Until the Reserves Run Out.
Depending on the company’s previous history, you might assume a decline rate of 5-10% per year – potentially more or less depending on how mature it is.
In each year, you assume that you produce either the production volume of that year or the remaining reserves – whichever number is lower.
Then, you’d multiply the production volume times the average price each year for all commodities to get the revenue by year.
3. Project (Some) Expenses.
You focus on Production and Development expenses here, both of which may be linked to the company’s production in the first place.
You don’t assume anything for Exploration since you’re pretending that the company finds nothing and dwindles to $0 in the future, and you leave out items like corporate overhead and SG&A because we’re valuing the company on an asset-level .
4. Calculate and Discount After-Tax Cash Flows
Simply subtract the expenses from the revenue each year and then multiply by (1 – Tax Rate) to calculate the after-tax cash flows.
Then, you add up and discount everything based on the standard 10% discount rate used in the Oil & Gas industry (no WACC or Cost of Equity here).
5. Add in Other Assets and Business Segments
For example, if the company has undeveloped land or if it has midstream or downstream operations, you might estimate the value of those based on an EBITDA multiple (or $ per acre for land) and add them in.
You add all those up to arrive at Enterprise Value , then back into Equity Value the normal way, and calculate the company’s Implied Share Price by dividing by the diluted shares outstanding.
So that’s a Net Asset Value model in a nutshell. It is widely used in oil, gas, mining, and other commodity-based sectors, and it often produces more accurate results than the standard DCF analysis.
To get a real world example of this NAV model, click here to view a sample video on how to set up the revenue side in a NAV analysis for XTO Energy .
Sum of the Parts
I hinted at this in the last part of the NAV explanation above, but sum of the parts is a very common valuation methodology in the energy industry.
For cases where the company is highly diversified – think Exxon Mobil – you need to value its upstream, midstream, downstream, and other segments separately and add up the values at the end.
So you might, for example, use traditional multiples like EBITDA for the midstream and downstream segments, and then use Proved Reserves or Production multiples for the upstream segment and add them together to arrive at the final value.
Or you might use NAV for upstream and a DCF for other segments and add those up.
Merger Models and LBO Models
There’s surprisingly little to say about merger models and LBO models in the oil & gas industry.
A merger model is a merger model is a merger model no matter how the company earns revenue, so nothing changes the fact that you need to combine all 3 statements, allocate the purchase price, and factor in synergies, acquisition effects, and so on.
The key differences with merger models:
- Purchase Method: Stock tends to be very common because oil & gas companies are often highly leveraged (little capacity to raise additional debt) and also don’t have much cash available.
- Commodity Prices: Both the buyer and seller should be using the same price cases – you don’t want an acquisition to look good just because you’re assuming $50 per barrel for the buyer and $60 per barrel for the seller.
- Synergies: You generally assume no revenue synergies because they just don’t make sense – remember that commodities companies cannot control their “product” prices. You might assume expense synergies based on reducing production costs on a per Barrel / Cubic Foot / Tonne / Ounce basis.
- Accounting: If you have a full cost company buying a successful efforts one or vice versa, you need to normalize both companies’ statements and use the same standard.
- Sensitivities: In addition to the usual criteria (purchase method and synergies), you also need to include commodity prices in your sensitivity tables because they will impact whether or not the deal is viable.
You could also base a contribution analysis or accretion / dilution calculation on non-financial metrics, such as Production Per Share or Proved Reserves Per Share.
But those make more sense for 100% stock-based deals (you wouldn’t see the impact of foregone interest on cash or interest expense on new debt for these non-financial metrics).
LBO models are even more similar to what you see for normal companies, and just like with merger models you need to include a sensitivity analysis on commodity prices somewhere in your model.
The most important point about Oil & Gas LBO models, ironically, is that oil & gas leveraged buyouts rarely happen .
And you already understand why if you’ve made it this far:
- Extremely Unstable and Unpredictable Cash Flows: If oil, gas, or gold prices swing one or the other, your returns may be hosed.
- High CapEx: This makes it much harder to repay additional debt.
- Already Highly Leveraged: This makes it difficult for the private equity firm to use a lot of new debt to acquire the company.
And the list goes on.
Yes, some PE firms do focus on energy and mining, but typically they stick to utility and/or power generation companies rather than unpredictable E&P companies.
Ready For Oil & Gas Financial Modeling Mastery?
Going into this, I actually thought the Oil & Gas tutorial would be the easiest and shortest one to write (whoops!).
There are a lot of differences with oil, gas, and mining companies but the overarching ones are that they cannot control prices and that they have depleting assets that constantly need to be replaced.
Remember that, the accounting tips above, and the NAV model, and you’ll be more than ready to dominate your interviews.
What is the Oil and Gas Industry?
How are oil and gas prices set, upstream, midstream, and downstream, reserves and resources, valuation methods for oil and gas producers, net asset value (nav), trading multiples, valuation method for oilfield services, additional resources, oil & gas primer.
Companies involved in finding, extracting, refining, and distributing the commodity
The oil and gas industry, also known as the energy sector, relates to the process of exploration, development, refinement of crude oil and natural gas. It is possible to invest in this industry directly and indirectly. An investor can choose to purchase the commodity using the spot market or futures market . Or, the investor can invest by buying shares through the stock market .
- The oil & gas industry includes all the companies involved in the process of finding, drilling, extracting, refining, and distributing the commodity.
- The industry comprises three categories: upstream, midstream, and downstream.
- Valuation methods include using discounted cash flow to find the net present value and industry-specific ratios such as enterprise value per flowing barrel.
Oil and gas prices depend on the supply and demand for the commodity. As the demand for the product falls, so does the price. As prices increase, more investment goes into drilling projects and inventing more efficient techniques. So, the supply for oil and gas is price-driven.
The Organization of the Petroleum Exporting Countries (OPEC) controls 75% of the reserves and 43% of oil production. Therefore, they exert a large influence on the supply and price of oil. On the other hand, segments of consumption drive the demand. The main segments are industrial consumption, residential consumption, and power generation.
There are three components of the oil and gas industry, one for each part of the value chain . Due to the complexity of each component, most companies focus on one.
Another name for the upstream industry is exploration and production (E&P) since the industry finds and produces crude oil and natural gas. It also comprises of service companies that assist the E&P processes, e.g., rig operators, engineering and scientific firms, and equipment manufacturers.
After the upstream industry finds and produces oil and gas, the midstream companies store and transport the products. Midstream companies work to connect the petroleum-producing areas to population centers where the customers are.
The connection is done through pipelines, rails, tankers, and trucks. Also, midstream companies possess the properties of upstream and downstream producers. For example, some companies own processing plants to remove sulfur and natural gas liquids.
While midstream companies deliver products, the downstream segment refines, markets, and distributes the end product to consumers. End products include gasoline, jet fuel, heating oil, and diesel. The end products are dependent on the complexity of the refinery. Some are capable of producing multiple types to be in line with current demands.
Oil and gas reserves and resources are volumes that might be commercially recoverable in the future. Reserves and resources are further categorized based on estimated volumes, which help determine the potential of a field.
The three categories of reserves are proved, probable, and possible reserves. Each category comes with a different probability of recovery. For example, the recovery rate of a proved reserve is 90%. On the other hand, resources provide less certainty relative to reserves. It is further split into contingent and prospective, with contingent resources offering more potential for recovery.
The net asset value or discounted cash flow helps determine the value of oil and gas producers. Most NAV is the present value of after-tax cash flows. To make the NAV calculation more reflective of actual value, it accounts for proven and probable reserves.
Trading multiples help investors compare the valuation of a company with their peers. Common multiples used are:
Enterprise Value per Flowing Barrel (EV/boe/d): determines the value of the company per barrel of production and helps investors compare the price of the company with the production volumes of the company
Field Netback: shows the margin created from a barrel of oil after subtracting standard costs and indicates the profitability of the asset without taking into account taxes and interest
Enterprise Value to Reserves (EV/boe): similar to EV per flowing barrel, but compares the price of a company with barrels still in the ground to determine the future potential of a company’s assets
Finding, Development & Acquisition (FD&A) costs: shows the cost of finding barrel reserves and producing it
Recycle Ratio: indicates the level of profitability of an oil or gas asset
Price/NAV (P/NAV): calculates how much an investor is paying for the underlying net present value of the company
Discounted cash flow is not the typical evaluation method for service companies. Instead, common methods are EV/EBITDA , P/E , and sum of the parts . The factors that influence EV/EBITDA and P/E include growth prospects, risk profile, and strength of the leadership team. Sum of parts is suitable for a company that is involved in more than one segment of the oilfield service industry.
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5 Common Trading Multiples Used in Oil and Gas Valuation
These numbers help analysts understand company performance
Katrina Ávila Munichiello is an experienced editor, writer, fact-checker, and proofreader with more than fourteen years of experience working with print and online publications.
The energy sector comprises of oil and gas, utilities , nuclear, coal, and alternative energy companies. But for most people, it's the exploration and production, drilling, and refining of oil and gas reserves that make the energy sector such an attractive investment. Choosing the right investment—whether that means purchasing shares in an oil and gas company, an exchange-traded fund (ETF), or a mutual fund—to help you make a profit means you'll have to do your homework, just like the professionals do.
Analysts in the oil and gas sector use five multiples to get a better idea of how companies in the sector are faring against their competition. These multiples tend to expand in times of low commodity prices and decrease in times of high commodity prices. A basic understanding of these widely-used multiples is a good introduction to the fundamentals of the oil and gas sector.
- EV/EBITDA compares the oil and gas business to EBITDA, and measures profits before interest.
- EV/BOE/D doesn't account for undeveloped fields, so investors should determine the cost of developing new fields to get an idea of a company's financial health.
- EV/2P requires no estimates or assumptions, and helps analysts understand how well a company's resources will support its operations.
- Price/Cash flow per share allows for better comparisons across the sector.
- Many analysts prefer EV/DACF because it takes the enterprise value and divides it by the sum of cash flow from operating activities and all financial charges.
The first multiple we'll look at is EV/EBITDA— enterprise value compared to earnings before interest, tax, depreciation, and amortization This multiple is also referred to as the enterprise multiple .
A low ratio indicates that the company might be undervalued . It is useful for transnational comparisons as it ignores the distorting effects of different taxes for each country. The lower the multiple the better, and in comparing the company to its peers, it could be considered undervalued if the multiple is low.
The EV/EBITDA ratio compares the oil and gas business—free of debt—to EBITDA. This is an important metric as oil and gas firms typically have a great deal of debt and the EV includes the cost of paying it off. EBITDA measures profits before interest. It is used to determine the value of an oil and gas company. EV/EBITDA is often used to find takeover candidates, which is common within the oil and gas sector.
Exploration costs are typically found in the financial statements as exploration, abandonment and dry hole costs. Other non-cash expenses that should be added back in are impairments , accretion of asset retirement obligations , and deferred taxes.
Advantages of EV/EBITDA
One of the main advantages of the EV/EBITDA ratio over the better-known price-earnings ratio (P/E) and the price-to-cash-flow ratio (P/CF) is that it is unaffected by a company's capital structure . If a company issued more shares, it would decrease the earnings per share (EPS), thus increasing the P/E ratio and making the company look more expensive. But its EV/EBITDA ratio would not change. If a company is highly leveraged , the P/CF ratio would be low, while the EV/EBITDA ratio would make the company look average or rich.
Enterprise Value/Barrels of Oil Equivalent Per Day
This is enterprise value compared to daily production. Also referred to as price per flowing barrel , this is a key metric used by many oil and gas analysts. This measure takes the enterprise value (market capitalization + debt – cash) and divides it by barrels of oil equivalent per day , or BOE/D.
All oil and gas companies report production in BOE. If the multiple is high compared to the company's peers, it is trading at a premium . If the multiple is low amongst its peers, it is trading at a discount .
As useful as this metric is, it does not take into account the potential production from undeveloped fields. Investors should also determine the cost of developing new fields to get a better idea of an oil company's financial health .
Enterprise Value/Proven and Probable Reserves
This is enterprise value compared to proven and probable reserves (2P). It's an easily calculated metric which requires no estimates or assumptions. It helps analysts understand how well its resources will support the company's operations.
Reserves can be proven, probable, or possible reserves . Proven reserves are typically known as 1P. Many analysts refer to it as P90, or having 90% probability of being produced. Probable reserves are referred to as P50 or having a 50% certainty of being produced. When used in conjunction with one another, they are referred to as 2P.
The EV/2P ratio should not be used in isolation, since reserves are not all the same. However, it can still be an important metric if little is known about the company's cash flow . When this multiple is high, the company would trade at a premium for a given amount of oil in the ground. A low value would suggest a potentially undervalued firm.
Because reserves are not all the same, the EV/2P multiple shouldn't be used on its own to value a company.
EV/ 3P can also be used. That is proven, probable, and possible reserves together. However, as possible reserves have only a 10% chance of being produced it is not as common.
Price/Cash Flow Per Share
Oil and gas analysts often use price compared to cash flow per share or P/CF as a multiple. Cash flow is simply harder to manipulate than book value and P/E ratio.
The calculation is simple. Take the price per share of the company that is trading and divide it by the cash flow per share . To limit the effects of volatility , a 30-day or 60-day average price can be used.
The cash flow, in this case, is the operating cash flow . That number does not reflect exploration expenses, but it does include non-cash expenses, depreciation, amortization, deferred taxes, and depletion.
This method allows for better comparisons across the sector. For the most accurate results, the share amount in calculating cash flow per share should use the fully diluted number of shares. One disadvantage of this method is that it can be misleading in case of above average or below average financial leverage.
Enterprise Value/Debt-Adjusted Cash Flow
This is EV/DACF—enterprise value compared to debt-adjusted cash flow . The capital structures of oil and gas firms can be dramatically different. Firms with higher levels of debt will show a better P/CF ratio, which is why many analysts prefer the EV/DACF multiple.
This multiple takes the enterprise value and divides it by the sum of cash flow from operating activities and all financial charges including interest expense , current income taxes, and preferred shares.
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Oil and Gas Valuation Methods
The energy industry is composed of oil and gas, nuclear, utilities, coal, as well as alternate energy firms. However, for many, it’s the oil and gas exploration, drilling, and refining of reserves that make the energy sector a very attractive means of diversifying their portfolio. Determining and picking the correct investment – whether through direct participation , an exchange-traded fund, or purchasing shares – to help an investor make a profit means that you will need to do your research.
Analysts in the oil and gas industry utilize 5 multiples and various oil and gas valuation methods to get an insight as to how firms in the sector are faring against their competitors. These multiples tend to decrease in times of high commodity prices and increase in times of low commodity prices.
1. Valuation Methods
Net Asset Value
The discounted cash flow, typically referred to as the net asset value helps identify the value of producers in the oil and gas sector. Generally, the net asset value is the current value after-tax cash flows. It accounts for probable and proven reserves.
2. Trading Multiples
There are 5 multiples that help investors compare a firm’s value over their peers. Commonly used are:
Enterprise Value per Flowing Barrel/EBITDA
Commonly called enterprise value, it identifies the value of a firm per barrel of production. It is a company’s value linked to earnings before tax, interest, amortization, and interest.
A low enterprise value suggests that a firm might be undervalued. In comparing a firm to its peers, the lower its multiple, the better.
Enterprise Value/Barrels of Oil Equivalent Per Day (EV/boe)
Also called price per flowing barrel, this multiple identifies the value of a company compared to daily production. It helps investors compare the production volumes of a firm with the price of the company.
All oil and gas firms report production in barrels of oil equivalent per day, or BOE/D. If the multiple is low compared to its peers, the company is trading at a discount. If the multiple is high amongst the company’s peers, the firm is trading at a premium.
It is important to note that investors should also take into consideration the cost of developing new fields to get a better insight into an oil firm’s financial health.
Enterprise Value to Reserves (EV/boe)
This multiple helps to identify the future potential of a particular company’s assets. It is quite similar to the enterprise value per flowing barrel, but compares the cost of a company with barrels still in the ground. This metric’s calculation is simple – no assumptions or estimates are needed. The EV/boe gives analysts an insight as to how well its given resources are able to support a firm’s operations.
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Price or Cash Flow Per Share
Analysts of oil and gas typically use P/CF or price compared to cash flow per share as a multiple. Compared to P/E ratio and book value, cash flow is more difficult to manipulate.
To calculate, take the company’s price per share that is currently trading and divide that figure by the cash flow per share. The cash flow refers to operating cash flow and does not reflect expenses on exploration, however, it does include depreciation, non-cash expenses, deferred taxes, amortization, and depletion.
Enterprise Value/Debt-Adjusted Cash Flow
This multiple is also commonly called EV/DAF. In terms of capital structures, oil and gas firms can differ dramatically. Companies with bigger debt will reflect a better P/CF ratio. Because of this, a lot of analysts prefer to use the EV/DACF multiple.
The EV/DAF takes the enterprise value, then divides it by all financial charges (which includes current income taxes, interest expense, and preferred shares) and the sum of cash flow from operating activities.
Gaining a better understanding of these oil and gas valuation methods and multiples will serve as a good introduction to the basics of the oil and gas industry. For more exclusive resources on oil and gas investing, diversified investment examples, tax breaks, and the latest happenings in the oil and gas market, we invite you to visit our Insights page .
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“Valuation Methodologies in the Oil & Gas Industry,” Stout, https://www.stout.com/en/insights/article/valuation-methodologies-oil-gas-industry
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Valuation Methodologies in the Oil & Gas Industry
The oil and gas industry's value chain is classified into three distinct segments or sectors:
- Upstream (also known as exploration and production, or "E&P")
The oilfield services segment can also be considered a distinct segment, which serves the upstream oil and gas companies.
Three standard valuation approaches — the Income Approach, the Market Approach and the Asset Approach — typically are applied in valuing companies in the oil and gas industry. The first step in choosing the appropriate valuation approach is to understand the sector of the value chain in which the subject company operates. For each sector, certain considerations must be taken into account.
The upstream sector, commonly referred to as the E&P sector, participates in the search for and the recovery and production of crude oil and natural gas. Activities within the upstream sector include searching for potential underground or underwater oil and gas fields, drilling exploratory wells, and drilling and operating wells that recover and bring to the surface crude oil, natural gas and related liquids. Examples of global E&P companies include Exxon Mobil Corporation, Royal Dutch Shell plc, and BP plc.
The midstream sector starts at the gathering system, which collects oil and gas from the wellheads. Gathering systems range in size from small systems that process gas close to the wellhead, to large systems consisting of thousands of miles of pipes that collect from hundreds of wells. At the processing plant, various products (for example, natural gas liquids like ethane and butane) are separated from the oil and gas. Examples of large midstream companies include Enterprise Products Partners L.P., Kinder Morgan Inc., and TransCanada Corporation.
Companies in the downstream sector are involved in refining crude oil and in selling and distributing natural gas and crude oil derived products such as liquefied petroleum gas, gasoline/petrol, jet fuel, diesel oil, other fuel oils, asphalt, and petroleum coke. The downstream sector includes refineries, petrochemical plants, petroleum product distribution companies, retail outlets, and natural gas distribution companies. Examples of large downstream companies include Valero Energy Corporation, Sunoco Inc., and Citgo Petroleum Corporation.
Oilfield services companies are important industry players that provide support services — drilling, cementing, surveying, treating (e.g., with acids or chemicals), and perforating — to upstream oil and gas producers on a fee or contract basis. An increasingly popular way in recent years for companies to extract oil and gas from shale formations, such as the Permian Basin in West Texas, the Bakken Formation in North Dakota, and the Eagle Ford in South Texas, is hydraulic fracturing, or “fracking”. Creating fractures in formations that allow oil and gas to be released. Examples of large oilfield services companies include Halliburton Company, Schlumberger Limited, and National Oilwell Varco.
Upstream Valuation Considerations
E&P companies’ primary assets are their oil and gas reserves — that is, hydrocarbons below the surface that have not yet been produced and are economically viable to extract. Reserves can be classified into two main categories: proved and unproved reserves. Proved reserves are quantities (volumes) of oil or natural gas that are recoverable in future years from known reservoirs under existing economic and operating conditions. Within the category of unproved reserves, probable reserves (referred to as 2P reserves when aggregated with proved reserves) have a 50% probability that reserve quantities will be higher than estimated and a 50% probability that the reserves quantities will be lower than estimated, in accordance with the engineering definition of the American Petroleum Institute. Possible reserves (referred to as 3P reserves when aggregated with proved and probable reserves) have a 10% probability that reserves quantities are higher than estimated and a 90% probability that reserves quantities will be lower than estimated.
Reserve Reports and Reserve Valuation: The value of an E&P company may be estimated by calculating the fair value of its reserves and then aggregating this with the value of other net assets on its balance sheet, assuming those net assets have been assigned market value. Reserve reports, generally prepared independently by petroleum (or reserve) engineers, are used for this purpose. These reports provide the gross quantities expected from wells, net such quantities to the subject company’s ownership interest, and estimate future prices, operating expenses and capital expenditures. Essentially, a reserve report is a discounted cash flow (“DCF”) model for a company’s reserves, on a pre-income tax basis, and it typically includes the present value of the projected income based on various benchmark rates, frequently ranging from 10% to 25%.
Below is a list of key items to consider in reviewing a reserve report and its underlying assumptions:
- What price deck (commodity price forecast) was used for the reserve report? (Note that engineers do not typically build the effect of hedges or other derivatives into their DCF model. The projections may be aggressive if the NYMEX strip pricing is significantly lower than the oil and gas prices used in the reserve report.)
- How do the projected volumes compare with historical production volumes? If they are materially different, determine why this is the case.
- Are proved undeveloped reserves (“PUDs”) included in the analysis? Are probable and possible reserves included in the projections? What drilling and capital expenditure assumptions were used in developing the projections associated with the PUDs?
- Were plug and abandonment costs considered? Liabilities related to plug and abandonment costs are also referred to as asset retirement obligations.
Valuing E&P Companies: E&P companies are commodity businesses that have limited control over the prices they receive. They may vary their production and capital expenditures based on current and future price expectations, and they can hedge their production by using the futures market. As discussed earlier, the DCF method under the Income Approach is one of the primary approaches used to value an E&P company’s oil and gas reserves. The value of the reserves is incorporated into the Asset Approach and the E&P firm’s balance sheet is marked to market using the Net Asset Value Method.
The Market Approach may also be an appropriate method of valuing an E&P company, depending on the availability of comparable publicly traded companies or M&A transactions (at either the asset level or the entity level). When analyzing historical or projected financial metrics to use in the Market Approach, consideration should be given to some unique aspects related to the accounting of E&P companies. Financial statements of E&P companies prepared in accordance with generally accepted accounting principles (“GAAP”) may use either successful efforts or full-cost accounting for oil and gas reserves. These accounting methods differ in their treatment of specific operating expenses — namely, exploration costs related to carrying and retaining undeveloped properties, collecting and analyzing geophysical and seismic data, and drilling exploratory wells. Rather than considering EBITDA (earnings before interest, taxes, depreciation and amortization) as a primary pricing metric for E&P companies, analysts usually consider EBITDAX, which is a company’s EBITDA before exploration costs for successful efforts. For full-cost firms, exploration costs are embedded in depreciation and depletion, so EBITDAX equalizes both accounting types.
The first step in employing the Market Approach is the selection of appropriate guideline companies. Some of the important screening criteria are the following:
- Size (in market capitalization or reserve volumes)
- Gas/oil mix (the percentage of reserves or production represented by natural gas versus oil)
- Reserve life (proved reserves divided by the previous year’s or current year’s production; also known as the reserves-to-production, or “R/P,” ratio)
- The ratio of PUDs to total proved reserves (an indicator of how much of the reserve base is currently generating EBITDAX)
- Areas/basins of operation (e.g., onshore versus offshore activities; specific geographies or shale plays)
Once guideline companies have been selected, the following pricing metrics may be considered:
- Enterprise Value (“EV”) / proved reserve quantities (i.e., EV / barrels of oil equivalent, or “BOE”)
- EV / daily production
- EV / EBITDAX
Due to the frequency of reserve acquisitions and divestitures among the publicly traded E&P companies, which could distort valuation indications, a forward- or current-year indication of reserves, production, and EBITDAX should be used. The development of forward- or current-year metrics, however, often requires a time-consuming review of press releases and other sources of information.
Midstream Valuation Considerations
Conventional variations of the Income and Market approaches (e.g., DCF and EBITDA-based multiples) may be appropriate in valuing midstream E&P companies, which are frequently incorporated as master limited partnerships (“MLPs”).
An MLP is a limited partnership that is publicly traded on a stock exchange qualifying under Section 7704 of the Internal Revenue Code. It combines the tax benefits of a limited partnership with the liquidity of publicly traded securities. MLPs traditionally pay out almost all available cash flow on a regular basis. They generally offer higher yields, stemming from their legal and tax structures as well as from the underlying companies’ operating business. Most publicly traded companies are structured as C corporations that pay entity-level corporate taxes, but MLPs pass through their taxable income to their unit holders rather than incur taxes at the entity level. As a result — and in contrast to C corporations, which must pay corporate income taxes, and whose shareholders are subject to taxes on any dividends received — MLPs avoid double taxation and offer higher distributions and yields to investors. Traditionally, MLPs have provided distribution growth by increasing the volume of products processed on existing assets, reducing costs through improved operations and scale, making accretive acquisitions, developing new assets, and capitalizing on new trends.
To obtain the tax benefits of a pass-through entity, MLPs must receive their income from qualifying sources, such as the exploration, mining, extraction, transportation, storage, distribution, and refining of oil and gas, and the production of alternative fuels such as biodiesel. To qualify for MLP status, a partnership must generate at least 90% of its income from what the Internal Revenue Service deems “qualifying” sources. The vast majority of MLPs are pipeline businesses, which generally earn stable income from the transport of oil, gasoline or natural gas. More specifically, energy MLPs are defined as those that own energy infrastructure — including pipelines, storage, terminals, or processing plants for natural gas, gasoline or oil — in the United States. MLPs frequently acquire assets used in the midstream segment, and their access to capital markets and low costs of capital on a pretax basis create a compelling valuation proposition in the transaction markets. Energy MLPs’ available yields make them an actively sought-out investment option in a low interest rate environment.
As such, in evaluating valuations for midstream companies, consideration should be given to yield data and trends for the subject company. Amid the current downturn in oil and gas commodity prices and the decline of the industry overall, midstream public companies’ yields have increased, but these higher yields are due primarily to lower valuations rather than to growth in distributions.
Downstream and Oilfield Services Valuation Considerations
Conventional variations of the Income and Market approaches (e.g., DCF and EBITDA-based multiples) may be appropriate in valuing downstream companies. Although lower oil and gas commodity prices adversely impact the valuation of E&P companies, the valuation of downstream companies, such as refiners, often benefits from lower prices of the commodity feedstock. The crude oil that E&P companies produce serves as a primary feedstock for downstream companies, and lower feedstock prices may result in higher crack spreads for downstream companies. Crack spread is the differential between the price of crude oil and the price of petroleum products extracted from it — that is, the profit margin a refinery can expect when it “cracks” crude oil. As a result, in the current oil and gas industry environment, downstream companies are expected to benefit from higher crack spreads in the near term, thus increasing their valuations. Another important factor affecting the crack spread is the relative proportion of various petroleum products produced by a refinery. The mix of refined products is also affected by the blend of crude oil feedstock processed by a refinery. Heavier crude oils are more difficult to refine into lighter products such as gasoline.
As with downstream companies, conventional variations of the Income and Market approaches (e.g., DCF and EBITDA-based multiples) may be used to value oilfield services companies. As with E&P companies, lower oil and gas commodity prices decrease oilfield services companies’ valuations. In an environment of lower commodity prices, such as the one we are currently experiencing, E&P companies significantly cut their capital expenditure budgets related to exploring and producing oil and gas. These budget reductions directly impact clients’ demand for an oilfield services company’s products. Although volatility in commodity prices affects oilfield services companies’ valuations in general, certain oilfield services companies may suffer more than others due to reductions in E&P capital expenditure budgets.
Figure 3 presents the variations in EBITDA valuation multiples for the different types of oilfield services companies.
Although the three standard valuation approaches — Income, Market and Asset — are applicable for companies in the oil and gas industry, each segment within the industry value chain has its own unique operations and characteristics, making certain approaches and methodologies for the valuation of these businesses more appropriate than others. In addition, modifications to the methodologies and certain commonly applied valuation metrics are required, depending on where in the oil and gas industry value chain the company operates.
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Valuing Oil & Gas Assets: the Complexities and Key Considerations
Valuing oil & gas assets: the complexities and key considerations.
By Aaron Kibbey, Robert Rasor & Brian Bostwick
Whether in court or out of court, in most restructuring situations involving stakeholders with various claims to a Company’s assets, the valuation of these assets is a critical component. In restructurings involving oil and gas reserves, the valuation analyses are often more complex because of the technical data and skillset required to value these reserves.
In the recent Sabine Oil & Gas and Energy XXI cases, stakeholders clashed over competing interests, and claims hinged on very different views of the value of the respective companies’ assets. These cases highlight the importance of retaining professionals who fully understand the technical aspects of performing a valuation analysis on oil and gas assets, and who can also apply their experience in valuing these types of assets in order to tailor their assumptions and inputs to the unique characteristics of the specific assets associated with the restructuring. In the Energy XXI case, Loughlin Management Partners + Company (“LM+Co”), a boutique restructuring advisory firm based in New York, partnered with HJ Gruy and Associates, Inc. (“Gruy”) a petroleum engineering firm based in Houston, to provide a comprehensive valuation analysis on a specifically targeted portion of the Company. This article outlines the general approach LM+Co and Gruy applied in their analysis, and also suggests several important considerations for teams attempting to value oil and gas assets.
Although valuing oil and gas assets is not necessarily more difficult than valuing other asset classes, valuing these types of assets requires a detailed understanding of the relative merits of traditional valuation methods. Valuing oil and gas assets, which comprise a depleting asset base where value is correlated to constantly changing commodity prices and historical production trends, demands a thorough understanding of the technical details included in a company’s reserve database. Although commodity prices fluctuate, the value estimates of the underlying oil and gas assets should be based on current conditions, and are not intended to reflect unforeseeable economic or environmental events that could alter the fair market value subsequent to the valuation date.
The Market Approach and Income Approach
When estimating the value of a company or a group of assets, both a Market Approach and an Income Approach should be employed, and this holds true when estimating the value of oil and gas assets. A Market Approach, such as a Comparable Company Analysis or Precedent Transaction Analysis, provides the relative value of the target assets based on how investors price similar assets. The Market Approach provides an estimate of value based on external information of the subject company, specifically how investors view the value of similar assets. An Income Approach, such as a Discounted Cash Flow (“DCF”) Analysis or, specifically when valuing oil and gas assets, a Net Asset Value (“NAV”) Analysis, provides an estimate of value based on internal information from the company, specifically the projected cash flows attributable to the target assets. It is key to recognize, when utilizing any of these methodologies, that there are relative merits and limitations associated with each, and these merits and limitations are magnified by the financial detail available in each unique situation.
The most common and widely accepted method to value an oil and gas company is a Net Asset Value Analysis, and nearly every valuation estimate for oil and gas assets will include a NAV analysis. However, relying solely on the results of a NAV analysis leaves the estimate of value susceptible to some potential shortcomings of this method. Although a NAV is essentially a very detailed DCF Analysis which includes very specific information on the selected oil and gas reserves, all of the other methods mentioned above should be considered and evaluated when performing a valuation analysis on oil and gas assets. The quality of the data available will ultimately dictate which methods to use and the appropriate weighting of each method.
A Market Approach provides an estimate of value based on how investors price similar assets by using a multiple on a common metric. Although sales, free cash flow, and EBITDA are commonly used metrics in this approach, the metric need only be observable, not necessarily financial. Care needs to be exercised when selecting the metric for a Market Approach valuation.
Comparable Company Analysis
A Comparable Company Analysis looks at publicly-traded, comparable companies and calculates a valuation using multiples of financial data based on the Total Enterprise Value (“TEV”, the combined value of the equity and the debt, net the cash on the balance sheet) of the chosen comparable companies. This approach provides the public market view on the value of similar companies or assets, but may be limited by the subjectivity inherent in trying to determine the relative similarity of the “comparable companies”. Comparable Company Analysis is recognized and well received by the US Bankruptcy courts. Two notable recent cases that included this method were Penn Virginia [i] and Swift Energy [ii] .
When using the Comparable Companies approach, the selection of the comparable companies is critical. Finding companies that are similar or nearly identical would be ideal when applying this approach; however, it is typically very difficult to find such companies. An important consideration when using a comparable company valuation analysis is that a comparable firm need not be identical, in all aspects, to the subject company. Rather, the key requirements are that a comparable firm have similar cash flows, growth potential and risk [iii] , [iv] . In the Energy XXI case, it is important to note that, although there were no other comparable publicly traded companies operating in the shallow waters of the Gulf of Mexico, other onshore oil and gas companies contained cash flows, growth potential and risk profiles similar enough to be used to estimate how the market would likely value the Energy XXI assets.
Precedent Transactions Analysis
A Precedent Transactions Analysis looks at companies comparable to the target company that were recently bought or sold and uses a multiple based on the purchase price to estimate the value of the target. This method is also susceptible to subjectivity of how “comparable” is defined, as well as the availability of information regarding recent and relevant transactions. To apply a Precedent Transactions Analysis, a multiple must be defined. Although earnings based multiples such as revenue or EBITDA generally provide the best indication of value, the multiple can be based on any observable, relevant metric. When valuing an oil and gas company, daily production may be a sector-specific metric on which to base a valuation. Regardless of the metric selected, this metric needs to be defined clearly and applied consistently across the transactions.
As critical as company selection is to Comparable Company Analysis, so too is the transaction selection in a Precedent Transactions Analysis. The transaction must stand up to the same level of scrutiny as the companies chosen for a Comparable Company Analysis. Recently acquired companies identical to the target would be ideal, but the data on acquisitions may be limited compared to the abundance of public market data. Because of this, a longer time frame is typically acceptable for Precedent Transactions Analysis. The characteristic of each transaction needs to be carefully reviewed and understood to ensure the metrics used and multiples applied are consistent across each transaction. Often times the reported consideration includes contingencies and considerations that can significantly alter the calculated value and this information should be taken into account as part of the Precedent Transaction Analysis.
Discounted Cash Flow Analysis
The traditional and most widely accepted Income Approach method is a Discounted Cash Flow Analysis. In the oil and gas industry, though, this is largely replaced by a NAV analysis. A DCF typically discounts the future projected annual aggregate free cash flow of the entire company. It requires a detailed understanding of the company and its economics. A Weighted Average Cost of Capital (“WACC”) reflective of the risk of the projected cash flows must also be calculated. Because a DCF analysis requires a complete understanding of the underlying assumptions used in the cash flow projections, without full access to company’s management, there may be limited opportunity to examine and audit the underlying assumptions. This is the most significant limitation of a traditional DCF analysis.
Net Asset Value Analysis
A Net Asset Value Analysis determines the value based on the subject company’s reserves and is the standard approach for oil and gas assets [v] . This method provides a detailed discounted net cash flow analysis that extends over the life of each property. To apply the NAV method, cash flow for individual wells or multi-well projects is forecast based on the projected income from the sale of produced oil, natural gas and natural gas liquid. Operating expenses, local production taxes and future capital requirements are included for each well, multi-well project and platform. The projected discounted net cash flow extends over the life of each entity, which may be up to thirty years from the effective date.
Net cash flow projections for the individual entities can be generated using the commercially available ARIES Petroleum Reserves and Economic Software with a provided ARIES Database. Aggregate net cash flow summary forecasts for the various hydrocarbon reserve categories are generated and used as the base for subsequent risk adjustment factor application, resulting in value determination. During the forecasting, minor changes and additions may be required in order to adjust for property reserve categorization or additional costs. In a low price environment, reserves data may not include critical wells or other assets due to economic write-offs, which could be temporary, but profitable if commodity prices increase. Inclusion of additional costs such as Asset Retirement Obligations (ARO), Lease Operating Expenses (LOE), and General and Administrative (G&A) costs is required to account for recognized expenses that are not included in an original ARIES Database. The costs can be incorporated within the primary forecasts or outside of the cash flow projections. Incorporation within the forecasts forces a more accurate economic limit on each projected property, typically resulting in a more correct forecast.
The prices used to project the cash flows are typically based on the West Texas Intermediate crude oil prices and Henry Hub natural gas prices. The applied price projections are based on NYMEX futures and should be selected as close to the valuation date as is reasonable to ensure the forecast takes into account the current market views. Because the valuation is based on current market sentiment, the NAV approach may not be an accurate indicator of Total Enterprise Value when the market prices are set near cyclical peaks or troughs. Additionally, because projected commodity prices are one of the strongest drivers in the computation of a NAV analysis, a sensitivity case should be presented wherein a completely independent crude oil and natural gas price forecast, such as the one available from the U.S. Energy Information Administration (EIA), is applied. Cash flows generated from the reserves and price forecasts are discounted using a WACC and then adjusted using Risk Adjustment Factors (“RAFs”). Adjustment is needed to account for the uncertainty associated with distinct reserve categories. The adjustment procedure is accomplished by applying an individual RAF to the discounted net present value for each reserve category. This method is well established in the oil and gas industry when performing a NAV approach to valuation. Three different sets of RAFs can be applied to generate low, mid and high market value estimates.
Despite its ubiquity in the oil and gas industry, the NAV analysis has limitations that can significantly alter the derived value of oil and gas assets. A NAV is only as accurate as the underlying reserves data and assumptions. An incomplete database or incorrectly applied RAFs can produce unreliable valuation estimates and ultimately have devastating consequences for investors. Additionally, the NAV approach may not be a good indicator of Total Enterprise Value when the “strip price” (pricing derived from the forward NYMEX curve) is set near cyclical peaks or troughs.
Risk Adjustment Factors used in a NAV analysis should also be vetted carefully. Applicable RAFs are dependent on circumstances and quality assessments surrounding a particular oil and natural gas property or portfolio of properties. The application of standardized RAFs, such as those from the Society of Petroleum Evaluation Engineers (“SPEE”) Annual Survey of Parameters used in Property Evaluation ignore the intricacies of NAV analysis. Notably, SPEE itself warns that the information in the Survey is limited in scope, possibly lacks real world detail and likely reflects biases based on individual respondent’s personal experience [vi] .
Understanding both the Science and the Art of Oil and Gas Valuation
Valuation is an inherently complex and imprecise process. The Market Approach (Comparable Company Analysis or Precedent Transaction Analysis) provides an estimate of value based on external information to arrive at a relative value. The Income Approach (Net Asset Value Analysis or a traditional Discounted Cash Flow) provides an estimate of value based on internal information from the subject company and attempts to arrive at an intrinsic value. Ideally, one should perform a thorough analysis using all of the accepted valuation methodologies to arrive at a comprehensive view of value. In practice, however, the quality of data available and the circumstances will dictate which methods to use. Based on the relative merits and limitations of each, not all approaches may be appropriate in each instance. Every effort should be made to combine the estimates of value derived from a Market Approach with the estimates of value derived from an Income Approach in order to estimate the value using both internally (company-specific) generated information and externally (market-specific) generated information. In a November 2012 publication on applying fair value measurement, Ernst & Young noted that
“The fair value of a business is often estimated by giving consideration to multiple valuation approaches; such as an income approach that derives value from the present value of the expected future cash flows specific to the business and a market approach that derives value from market data” (Ernst & Young Publication – November 2012 Fair Value Measurement, IFRS 13 Fair Value Measurement)
We believe this guidance holds true when valuing oil and gas assets, particularly when the valuation analysis is part of an overall restructuring plan. Whether in court or out, stakeholders should strongly consider retaining advisors/professionals who understand the complexities and technical issues unique to the oil and gas industry and relying on their experience and expertise. Hiring valuation professionals well-versed in both the science and the art of valuing oil and gas assets is a critical component of a stakeholder group’s ability to achieve a favorable outcome.
About the Authors
Aaron Kibbey is a managing director at Loughlin Management Partners with more than 20 years’ management experience in operations, restructuring, corporate finance, sales and marketing, business development, and mergers and acquisitions. Aaron also has significant experience serving in crisis management positions within companies facing operational and financial challenges. Through his education and professional experience, Aaron has developed expertise in valuing businesses in various industries, including oil and gas, media and entertainment, and telecommunications.
Robert Rasor is the Executive Vice President and Manager of Engineering of H. J. Gruy and Associates, Inc. With more than 30 years of experience in oil and natural gas valuation, Robert has performed hundreds of oil and natural gas valuations, and has served as an expert witness in numerous national and international litigation and arbitration proceedings.
Brian Bostwick is an associate at Loughlin Management Partners with experience in financial restructuring and process improvement. He graduated with honors from Northeastern University.
[i] “Expert Report of Richard Morgner, Jefferies LLC, Penn Virginia Case 16-32395-KLP Doc 438 filed July 18, 2016”
[ii] Swift Energy Company Valuation Analysis, Case 15-12670-MFW Doc 244-5 filed February 5, 2016
[iii] Damodaran, Aswath. Damodaran on Valuation, Security Analysis for Investment and Corporate Finance, Second Edition, John Wiley & Sons, Inc., 2006.Print.
[iv] Pratt, Shannon. Valuing a Business, The Analysis and Appraisal of Closely Held Companies, Fifth Edition, The McGraw Hill Companies, Inc., 2008.Print.
[v] Sinha, M.K. and Poole, A.V., “Selection of a Discount Rate or Minimum Acceptable IRR”, SPE Paper 16843, Proceedings of the 1987 SPE Annual Technical Conference and Exhibition. Print.
[vi] SPEE. “Society of Petroleum Evaluation Engineers Thirty-Third Annual Survey of Parameters Used in Property Evaluation,” June 2014
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Putting a price on the unknown: determining fair valuation in oil and gas exploration
James Veron , Executive Director, Business Strategy, S&P Global Commodity Insights
Ian Longley , Director, GIS-pax
The value of an oil and gas asset goes beyond the volume of hydrocarbons in place. Fair valuation incorporates volumes, risk and the value of mapped and future exploration potential in any particular area. In today's market, determining the fair valuation of an asset is more important than ever. Exploration upside is often a differentiator in competitive M&A deals when the producing assets are valued by different companies using the same price decks.
The oil and gas industry is in transition. In most companies, decision makers are focused on rapidly reshaping exploration portfolios into short-cycle and low carbon intensity opportunities, typically via divestment and M&A activity.
As more-demanding shareholders insist that operators exercise fiscal discipline, companies are shifting their focus to core assets and streamlining their portfolios. Portfolio Opportunity Ranker allows you to compare apples and apples and have an entire evaluation of your exploration portfolio within a truly global context.
Predictions beyond known data points
The fair valuation of an oil and gas exploration asset quantifies its risk and future exploration potential. It is determined by calculating the risk of volume and value of all the known and unknown prospects in a certain area or within a company portfolio. This can be done at the country, basin, prospect, license, or block level.
Portfolio Opportunity Ranker incorporates the risked volumes and values for around 30,000 S&P Global Commodity Insights prospects and has a methodology to estimate the yet to be discovered prospects. It uses machine learning driven by exploration history and a measure of exploration efficiency.
Subscribers can use their own prospects, edit all key inputs and re-run calculations to make their own global ranking of opportunities.
All companies struggle with consistent risking of global opportunities, as it is always subject to the influence of local/human bias. This human trait is impossible to eliminate entirely but Portfolio Opportunity Ranker mitigates its impact by using a systematic map and data-based methodology for estimating prospect risking. This methodology incorporates the exploration history of the area together with local aspects of each prospect as detailed in the S&P Global Commodity Insights prospect database. This transparent methodology is applied to 19 stratigraphic play intervals and incorporates many spatial elements such as charge/seepage presence, seismic datasets and local trap type descriptors. It is structured so that companies can modify the base assumptions and match their in-house risking methodologies to the global evaluation.
Economic evaluations are complex at an asset-by-asset level and are controlled by the local fiscal regimes and assumptions regarding commodity prices, production profiles, OPEX, CAPEX and well costs. It is impossible to do this systematically for +/-100,000 features. Portfolio Opportunity Ranker uses a base calibration dataset to establish the volumetric cut-offs for oil fields and gas fields in polygons that have common water depth/elevation ranges, distance to infrastructure and fiscal terms. Value metrics ($/boe) for low, base and high cases for oil fields and gas fields are then stochastically applied to the post cut-off risks and volumetric estimates to calculate risked values (EMVs). When convolved with the well costs and tax factors, a stochastic assessment is made for economic volumes and values.
Standardized datasets for better results
The new Portfolio Opportunity Ranker tool from S&P Global Commodity Insights and GIS PAX provides a standardized, spatial dataset of the value, volume, risk and rank of the entire world's oil and gas prospects, making it easier and faster to calculate fair valuation.
The data product is built solely on S&P Global Commodity Insights' spatial E&P data and is delivered on a GIS database platform with software that enables subscribers to modify key exploration and commercial inputs and then recalculate the volumes and value calculations. The workflow is simple and industry standard and is not a black box.
Make better decisions with fair valuation
A robust estimation of fair valuation allows companies to deploy and use their resources wisely in areas with the most perceived value. These value predictions can be customized to include proprietary data, local knowledge, and range of risk tolerances.
Before investing in an asset or company, E&P's evaluations aim to understand the remaining exploration potential. Comparing and ranking real and predicted future prospects in any set of blocks or basins in a systematic way should quickly identify the best opportunities and provide a consistent estimate of relative value.
Before divesting assets, companies should make sure they are selling the right asset for the right price. Knowing the fair market value for every asset in their portfolio will help determine which assets have potential and are aligned with their risk tolerance. In divestitures and farm-outs, fair valuation allows companies to sell the asset for its true worth.
New from S&P Global Commodity Insights and GIS PAX: Portfolio Opportunity Ranker
Portfolio Opportunity Ranker uses the world's best E&P data, spatial analytics and machine learning to predict and rank the remaining conventional exploration potential of the entire planet (outside of onshore North America). It risks, values and ranks 30,000 oil and gas prospects, and integrates this with an estimate of missing prospects. These estimates are commercially based and thus provide a meaningful basis on which to plan M&A acquisition and divestment decisions.
The tool is fully customizable, allowing users to incorporate their own data and local expertise. All calculations are editable and auditable.
Key features include:
● Polygons at the country, basin and block levels in a spatial platform ● YTF volumes values and rankings of the exploration potential in every proven charge area ● Risk, volume and value estimates of the world's known prospects ● Spatial predictions of volumes and values for global unidentified prospects ● Estimates of commercial yet to find volumes and values for all proven charge areas
Book your free demo today
This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.
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How to value oil companies in the biden era.
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Sunset for the oil business. Or dawn?
Like a small boat navigating a big sea, oil & gas valuations are impacted by a plethora of factors that can change almost instantly. Some factors help in arriving at a shareholder’s destination, others do not. Some factors the crew can control, others not so much (and some factors are more predictable than others). As this vessel heads for the destination shores of high returns, it must navigate through natural economic influencers such as production risk, commodity prices, supply logistics and demand changes. In addition, it also must face regulatory shifts that the Biden Administration is and could generate in the future such as tax changes, policy shifts and more. Most likely, these policies will create some volatility and headlines, but in the aggregate will not change valuations much. Let us examine a few of these regulatory items and how they might change the course of an oil and gas company’s valuation going forward.
There are several recent policy actions, and some that are being debated that are affecting the industry, primarily by disincentivizing new U.S. production. Actions already taken include a moratorium on federal oil & gas drilling permits and a construction stoppage of the Keystone XL pipeline. While it can grab a headline, from a valuation perspective it should not be a direction changing headwind. Most drilling is not done on federal lands, and a lot of companies with existing permits that will allow multiple years of drilling. Even if this becomes an enduring policy, the impact would likely be a revision too, rather than a material reduction of planned drilling activity.
There are also some long-standing tax incentives that may be ended as well: the intangible drilling cost deduction and the percentage depletion allowance. The intangible drilling cost deduction (which expenses as opposed to capitalizes certain drilling costs) has been around for over 100 years, and the percentage depletion allowance (15% reduction in gross income of a productive well) has also been around nearly that long. The rationale behind both is to encourage investment by allowing tax breaks for development activity by delaying or decreasing cash taxes in any given year. This is an enjoyed benefit for investors and has allowed cash flows to either be higher or come faster than if the tax breaks were nonexistent. This is considered a headwind for the industry However, since many upstream companies are not cash taxpayers these days, and capital expenditure budgets have already been slashed in the past year, this issue (if it comes to pass) may end up being not much more consequential than a slight breeze.
Another matter on U.S. producers’ radar is the expectation that Iranian oil sanctions will be lifted. Iran’s president Hassan Rouhani has said that a broad outline to end sanctions has been reached. Since November 2020 Iran’s crude and condensate exports have already gone up and the global market must contend with another 500 thousand barrels a day of exports. The good news is that the market may have already priced this in and WTI is still over $68 per barrel with Brent Crude over $70.
Not everything coming out of Washington is detrimental to upstream producers. In fact, some of it may end up being materially beneficial over the course of time. One example is the budget proposal to utilize federal funds for plugging old wells. Biden’s $2 trillion infrastructure proposal includes $16 billion for cleaning up disused wells and mines. Long a balance sheet issue for producers, this can has been kicked down the road for decades. The opportunity to be addressed from a subsidized standpoint would be a welcome development for producers. Even if it is executed inefficiently (North Dakota plugged 280 wells for $66 million: approximately $236k per well) as many government actions can be, it could help producers clean up over 50,000 “orphan” wells that can be over 100 years old in some cases. Considering the beating that oilfield service companies have taken in recent years, this initiative could be a shot in the arm for them as well.
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The other major tailwind is less about a direct policy, but more an indirect derivative of it. As the Biden Administration restricts drilling on federal lands, the supply of oil is (at least somewhat) constrained. Coupled with the multi-trillion dollar federal budget being proposed , these bring about inflationary pressures that are positive for commodities such as oil. As Sir Isaac Newton once said: “For every action there is an equal and opposite reaction.” Oil and gas companies have been consistently sailing towards capital discipline for several years now, as growth is out of favor in comparison to free cash flow. This strategy is expected to start showing fruit as cash flow and dividends become more prevalent in the industry, something that investors have been awaiting.
Tempests on The Horizon?
One area where headwinds and tailwinds could clash into a storm system is how inflationary pressures could impact production costs. As commodity prices rise, labor and material costs will impact production (particularly new drilling costs). There are varying opinions as to how much and how long the impact of inflation will be, but most analysts I have read agree that it is either coming or already here. One thing to consider is that while oil prices are global, development costs will be more constrained to the U.S.. Another disturbance will also be the costs of mineral rights payments as the shift of production moves to private lands and away from federal lands. Those items could counterbalance some of the expected commodity price gains and are something that should be on management teams’ radars.
There are two things that have been mentioned that could have seismic effects on the industry: banning fracking and limiting LNG exports. However, at this point the odds are low enough to place them in the fabled category. There have been state level fracking policies for years already (New York for example), but nothing about banning fracking has ever gone very far federally. Still, some voices who echo this idea are now close to the Biden Administration. Even with the 50/50 Senate split, most think Senator Manchin (D-WV) would never let it happen.
The other idea is to choke the nascent Gulf Coast LNG export industry for ESG or other related priorities. However, that is also highly unlikely. A few months ago Energy Secretary Jennifer Granholm said :
“[U.S. LNG is often headed to] countries that would otherwise be using very carbon-intensive fuels, it does have the impact of reducing internationally carbon emissions. However, I will say there is an opportunity here, as well, to really start to deploy some technologies with respect to natural gas in the Gulf and other places that we are siting these facilities for that we are obligated to do under the law.”
While an argument can be made that there may be some environmental reasons for shutting this down, pragmatically there is little to no way it will happen anytime soon. If it did somehow, the natural gas business in the US would take yet another ship sinking blow.
Heading For Home: High Returns
While upsetting a few, the Government’s action is mostly having the effect of accelerating a lot of things investors have pressed for some time now. Capital discipline is positive for prices. Prices have crept up for months, but announcements for more aggressive drilling plans have been sparse. Matador added a rig in February, but the stock price quickly dropped 5%. Most US producers are more wary of OPEC and Russia than they are of the Biden Administration. Besides, many producers have multiple years of drilling inventory already permitted so federal permit moratoriums do not stop drilling in any substantive sense. Capital has already fled the industry, some for economic reasons, some for more ideological reasons. However, if the prices keep going up and cash flow returns become the norm in an inflationary economy, this vessel could make itself a popular destination for high returns in the future.
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