Beneath the Surface: Valuing oil and gas assets in litigation

Saturday, November 28, 2015 - 13:52

Recent technological developments in the oil and gas industry have provided access to vast new reserves throughout the world and led to significant growth in oil and gas production. The expansion in drilling and producing operations has also coincided with an increase in litigation and international arbitration related to oil and gas assets. This is largely because of the capital-intensive, long-term, and multiparty nature of oil and gas development.

Central to much of this litigation are issues affecting these assets’ fair market value. Although the valuation methods for other assets are similar, the characteristics of this industry deserve special consideration in a litigation context. This article considers four of these characteristics:

• Estimation of cash flows in discounted cash flow (DCF) valuation of oil and gas assets through the use of decline curves

• Use of discount rates to address the varying degrees of market risk underlying the types of reserves being valued

• Comparables valuation metrics commonly used in oil and gas assets valuation

• The acreage pricing method for valuing assets with undeveloped reserves

Oil and Gas Litigation Will Likely Increase

Litigation involving oil and gas assets will likely increase for two primary reasons. First, recent technological developments, such as hydraulic fracturing (fracking) and horizontal drilling, have greatly increased the amount of recoverable reserves from known reservoirs. In addition, fracking and horizontal drilling have also spurred the development of lower-cost and more readily available fuel sources, such as shale gas and oil. This has effectively expanded the world’s supply of accessible oil and gas and sparked a rapid increase in shale development. The rise in development, combined with the complexity of oil and gas operations, will likely cause a variety of disputes that may lead to more litigation.

Second, the current decline in oil prices is likely to increase the number of transactions and, consequently, cause more potential contract and royalty disputes. For example, a recent three-part article in Law360 noted that the decline in oil prices has producers in Eagle Ford and other large plays (groupings of oil or gas fields with similar characteristics) attempting to cut costs and scale back operations.[1] While operators struggle and reduce operations, production declines will cause a decrease in royalties paid to landowners, which may lead to an additional wave of lawsuits. The decline in cash flows may also lead to more transactions as operators consider buying assets at discounted values.

Oil and gas development issues have been a growing cause of international arbitration. In its 2015 annual report, the International Centre for Settlement of Investment Disputes (ICSID) noted that it administered a record 243 cases in 2015, including 52 new ICSID-registered cases and nine new cases under United Nations Commission on International Trade Law’s arbitration rules. The report notes that 14 of the new cases were brought on the basis of the Energy Charter Treaty (ECT).. Importantly, 27 percent of the new cases under ICSID involved oil, gas and mining issues, making that segment the second most commonly arbitrated by the ICSID.

Valuing Oil and Gas Assets

Valuation issues are central to many types of litigation relating to the oil and gas industry. Since oil and gas assets represent the majority of a developer’s value, the method by which reserves are valued plays a significant role in any transaction. Contract and royalty disputes among stakeholders in a reservoir are also sensitive to valuation issues that determine the economic relationships among the parties.

With the growing importance of oil and gas assets in litigation and international arbitration, it is crucial to understand some of the common methods of determining their value. An initial consideration is the appropriate standard of value. Fair market value is the most widely accepted standard in oil and gas valuation. As defined in the Litigation Services Handbook, fair market value is

[t]he price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.[2]

As with most other assets, there are multiple ways to value oil and gas reserves. Two of the most common methods are the income approach and the market approach. The income approach, commonly implemented through a DCF analysis, relies on the basic financial premise that the value of an asset is derived from the cash flows that the asset is expected to generate in the future. To value an oil and gas asset, a projected stream of future cash flows is first developed based on production expectations for the reservoir at issue.

The market approach, or market comparables method, is based on the fundamental assumption that similar assets should have similar values. This valuation method can provide a check on the “reasonableness” of a DCF valuation. The analyst first identifies transactions that are comparable to the property being valued. A valuation metric is then calculated for each transaction as the ratio of the transaction value to a given performance measure (e.g., proved reserves, daily production). Finally, the value of the oil or gas property is estimated by multiplying the selected valuation metric from the comparable transactions to the corresponding measure for the property being valued. Although these methods are generally straightforward, their use in the context of oil and gas valuation deserves closer consideration.

Estimating Production from Reserves

Anticipated future production from a reservoir, perhaps the most important factor in an oil and gas DCF valuation, is derived from a detailed statistical and engineering analysis of the reserves in question. As a well produces oil or gas, economically recoverable reserves are depleted and will ultimately decline to zero.

Decline curves: A decline curve estimates the rate at which the production from an oil or gas well will decline on the basis of two variables: (1) the well’s initial production rate at the time of the estimate, and (2) a mathematical formula that relates the initial production to the well’s production in the future.

The parameters of the mathematical formula for proved reserves are typically estimated utilizing the known production data on the well in question and/or similar wells in the same area. Past production trends are extended to the point where production from the well no longer justifies the costs of operation. The rate at which a well’s production declines depends on where it is in its lifecycle. Oil and gas wells typically reach their highest daily production rate shortly after they are drilled and completed. Once production begins to decline, the rate of decline can change over the life of the well.

The different decline rates are factored into the analysis through the use of different functions to build the trend lines. For example, a hyperbolic function, as demonstrated in the early part of the decline curve shown here, often applies to the early years of a shale well’s life. Use of a hyperbolic function in a decline-trend analysis results in a steep decline in the well’s forecasted production level. Following a well’s early years, the decline typically levels off, resulting in a shallower decline curve over the remainder of the well’s useful life. This type of decline curve is calculated through an exponential decline function. The specific models used in determining the appropriate decline curve will depend on the well’s characteristics. For example, horizontal wells drilled in the Niobrara formation of the Denver-Julesburg basin in Colorado typically follow a hyperbolic decline curve in their first eight to 10 years, followed by an exponential curve for the remainder of their useful life.

Type curves: Since undeveloped wells have no past production data, their future production is estimated through the use of type curves. Type curves are very similar to decline curves except that the entire curve is based on assumptions derived from comparable wells in the area or play. These inferences are established through a process known as “de-risking,” in which a developer will strategically develop wells in a given area to gain a better understanding of the characteristics of the reservoir. As more wells are drilled, more information becomes known about the production potential of future wells. Type curves use averages of historical data for these initial wells to predict the two parameters needed to produce the curve. Since they are based on historical information, type curves are commonly updated as more information becomes available.

Discount Rates Capture Market Risk

Once a reasonable cash flow estimate has been developed, the cash flows are discounted to obtain a present value. The discount rate for a given asset will depend on the time value of money and the risks associated with the asset. In general, risks can be categorized into project-specific (diversifiable) and market (non-diversifiable) risks. Project-specific risks are unique to a particular project (e.g., the risk of a well having lower-than-expected reserves). Because project-specific risks can be eliminated by holding a diversified portfolio of investments, these risks are not reflected in the discount rate. Market risk is the risk that an asset’s value will change in response to changes in the overall market (e.g., a decrease in oil prices). Unlike project-specific risks, market risks cannot be eliminated through diversification and are reflected in the discount rate.

While benchmark discount rates exist within the industry, benchmarks should be used only as a starting point for determining the applicable discount rate. One benchmark discount rate that is commonly used in reserve reporting is the 10 percent rate prescribed in the financial reporting guidelines of the Securities and Exchange Commission (SEC), commonly called PV10. PV10 was developed in the late 1970s by the Financial Accounting Standards Board (FASB) and the SEC to address the issue of inconsistent reserve reporting by industry participants. The guidelines issued by the SEC and FASB, specifically FAS No. 69, established the standardized measure of oil and gas, which requires that all companies report the value of future reserves on a standard PV10 basis. However, the guidelines clearly state that the PV10 value of reserves should not necessarily be considered a measure of fair market value. As a result, although PV10 provides a convenient basis for comparing reserves across different companies, specific risk factors must be considered when developing a discount rate for oil and gas assets.

One of the most important factors is the type of reserves being valued. Oil and gas reserves are generally categorized as either proved or unproved. Proved reserves are quantities of petroleum that can be estimated with reasonable certainty to be commercially recoverable from a known reservoir under current economic conditions, operating methods, and government regulations. Proved reserves are in turn categorized according to their production and development status and ordered by increasing level of market risks, such as commodity price risk, increases in government regulation, and industry-wide cost inflation:

• Proved developed producing (PDP) reserves are expected to be recovered from a well currently producing.

• Proved developed nonproducing (PDNP) reserves are expected to be recovered from existing wells that are not currently producing or that require additional completion.

• Proved undeveloped (PUD) reserves are expected to be recovered from new wells on undrilled acreage or require a relatively large expenditure in order to recomplete an existing well.

These varying degrees of market risks for different reserve types should be captured in the discount rate used to value the reserves. Under the SEC’s PV10, for example, it would be inappropriate to value both PDP and PUD reserves. To illustrate this point, consider the difference in commodity price risk, a type of market risk, between PDP and PUD reserves. While PDP reserves are expected to be recovered from an already producing well, PUD reserves may not be developed for several years. PDP reserves are expected to be produced before PUD reserves and are therefore less exposed to changes in commodity prices. Economists typically apply higher discount rates (than PV10) for reserves that are less likely to be recovered in order to account for the relatively higher market risk.

Comparable Transaction Metrics

When analyzing oil and gas transactions, valuation metrics for the market comparables method are frequently calculated on the basis of current production or proved reserves. One of the most common valuation metrics measures the dollars paid per barrel of oil equivalent (BOE) acquired (typically, in terms of proved reserves). For example, suppose that a comparable property to the one being valued has 2 million BOE of proved reserves and was recently acquired for $20 million. The valuation metric for this transaction can be calculated as the $20 million purchase price divided by proved reserves of 2 million BOE, or $10/BOE. The subject property may then be valued by multiplying $10/BOE by the proved reserves for the subject property. For developed properties with significant current production, $/daily BOE is an additional commonly used metric, which measures the dollars paid per BOE of daily production.

As an important caveat, oil and gas transactions often include other assets besides proved reserves, and it may be inappropriate to ascribe the full transaction value to proved reserves. For example, in addition to proved reserves, a given transaction may also include significant undeveloped acreage. Therefore, before calculating a metric such as $/BOE, it may be necessary to adjust the transaction price to account for other assets. For example, if a $50 million transaction includes $5 million of value allocated to undeveloped acreage, the analyst would deduct the $5 million from the value before calculating a $/BOE metric using proved reserves.

In order for the market comparables method to produce a meaningful estimate, the selected transactions must closely match the property being valued. There are a variety of reasons why two transactions may not be comparable, including different geography (i.e., region or play), percentage of developed reserves and mix of hydrocarbon acquired (e.g., oil, natural gas). For example, a transaction metric from a liquids-rich basin (i.e., a geological formation containing oil and gas reserves) would not be meaningful for a property in a relatively gassy basin, given the significantly different mix of reserves. Selecting comparable transactions requires a significant amount of judgment, and while analyzing many different data points can help to identify factors that drive valuation, a few close comparable transactions are better than many dissimilar transactions.

The primary advantage of the market comparables method is that it can be used as a check on the income approach as well as the discount rate applied. Specifically, this method can be used to confirm that the $/BOE or $/daily BOE metrics implied by a given discount rate are consistent with other comparable transactions. For example, if the metrics calculated based on a DCF valuation are in line with the metrics for market transactions, this suggests that the discount rate is reasonable. However, despite this advantage, the market comparables method should only be used as a check on the DCF approach and not as a stand-alone valuation method. While the market comparables approach can provide a quick approximation, the DCF approach is superior because it utilizes factors (e.g., decline curve, reserves mix, and oil and gas prices) that are specific to the property being valued.

Acreage Pricing in Undeveloped Reserves

Undeveloped reserves (i.e., proved undeveloped and unproven reserves) can be difficult to value using the income approach, particularly in areas where little development has occurred and where not much is known about reserves and production potential. Because undeveloped acreage has yet to be de-risked, the lack of information needed to identify DCF parameters can make the analysis highly speculative. Acreage pricing (a specific application of the market comparables method) is an alternative that is commonly used by industry practitioners to value undeveloped reserves. Acreage pricing involves determining a $/acre price for contemporaneous sales or leases of comparable plots of undeveloped land and comparing it to the $/acre price of the transaction at issue.

Because of the different economic terms included in acreage transactions, analysts using the market comparables method must be careful to select transactions with similar structures to the property being valued. A fee simple transaction involves the outright sale of the acreage and mineral interests (e.g., oil and gas). A lease transaction is an agreement by a mineral owner to lease mineral development rights to a producer. In a lease transaction, the mineral rights owner typically receives an upfront bonus payment (paid on a $/acre basis) and a royalty interest (i.e., a percent share of production, excluding costs). The $/acre price used in the market comparables approach should reflect the nature of the property being valued (i.e., a sale or lease interest).

Because the comparable transactions should closely match the property being valued, the analyst should also consider different valuation drivers for acreage transactions. The value of undeveloped acreage may be affected by the

• Distance from existing production. Undeveloped acreage near already productive wells is generally more valuable than unexplored acreage.

• Acreage size and concentration. Buyers may be willing to pay a premium to acquire larger, contiguous blocks of land (especially if the buyer has adjacent acreage).

• Production status. It is typical for mineral leases to extend indefinitely as long as oil and gas is being produced in paying quantities on the leased property. Such leases are said to be “held by production.” All else equal, acreage held by production may be worth more than acreage not held by production because of the lessee’s lower renegotiation risk.

While the DCF method is the preferred valuation method for proved developed reserves, the market comparables method is often the preferred method for undeveloped reserves. Because geological and reservoir data may not exist for undeveloped acreage (i.e., potential reserves have not been de-risked), the analyst may not be able to develop cash flow projections for the subject property.

Conclusion

The oil and gas industry requires particular methodologies to value assets involved in litigation. Those methods can be different depending on the types of resources involved, their locations, the stage of development of the resources, and the market risks associated with development, production, and sales. 

The views expressed in this article are solely those of the authors, who are responsible for the content, and do not necessarily reflect the views of Cornerstone Research.

This article, “Beneath the Surface: Valuing Oil and Gas Assets in Litigation” first appeared in International Law News, Volume 44, Number 3, 2015. © 2015 by the American Bar Association. Reproduced with permission. All rights reserved. This information or any portion thereof may not be copied or disseminated in any form or by any means or stored in an electronic database or retrieval system without the express written consent of the American Bar Association.

 

[1] Jess Davis, “Sinking Oil Prices Drive Fresh Legal Work in Eagle Ford,” Law360 (Feb. 10, 2015)

[2] Litigation Services Handbook: The Role of the Financial Expert 10-27 to -28 (Roman L. Weil et al. eds., 5th ed. 2012).

 

Cagatay Koc, Principal in the Washington, D.C., office of Cornerstone Researchckoc@cornerstone.com

John SzczepanskiManager in the Washington, D.C., office of Cornerstone Researchjszczepanski@cornerstone.com