Reserve-based lending for unconventional reserves

Sept. 28, 2015
Oil and gas exploration and production companies (producers) need lots of capital. Equity financing is often more expensive than the producer's managers desire.

Kevin L. Shaw
Mayer Brown LLP
Houston and Los Angeles

Editor's note: US producers in unconventional plays recently completed redeterminations of their borrowing base. Here's what bankers look for when producers request a reserve-based loan.

Oil and gas exploration and production companies (producers) need lots of capital. Equity financing is often more expensive than the producer's managers desire. Accordingly, for decades, producers have financed their operations using various debt products, including the so-called reserve-based loan (RBL). This article reviews the fundamental elements of reserve-based lending and how lenders financing unconventional oil and gas reserves have certain different considerations compared to conventional reserves.

Reserve reports are central in an RBL with the primary collateral typically being the producer's oil and gas reserves. These reserves can be challenging to value accurately, particularly in the current market with relatively large and quick changes in commodity prices. As detailed below, a reserve report prepared by an independent petroleum engineer will estimate the total volume of oil and gas reserves attributable to certain wells located or to be located on certain lands and then apply assumptions about cost and rate of production to those volumes in projecting quantities of future hydrocarbon production. Using those data, lenders calculate the value of such reserves using a forward-looking commodity price curve (sometimes called a price deck) to determine the revenues that can be expected from such volumes, and then apply a particular discount rate to arrive at their net present value.

Reserve report fundamentals

For a debt financing, a producer is typically required to engage an independent third-party engineer, who will produce a reserve report that estimates the net present value of the current and forecast revenue stream from existing wells, wells being drilled, and prospects on its oil and gas leases (reserve report). These revenue streams take into account the expected drilling and completion costs for the wells, the monthly operating expenses (LOEs), certain decommissioning costs at the end of the economic life of each well (often called plugging and abandonment or P&A costs), and the projected rate of production and ultimate economic recovery of the hydrocarbons.

In a reserve report, oil and gas reserves are classified according to schemes developed initially by petroleum engineers and, for public companies, governed by regulations of the US Securities and Exchange Commission. The primary categories are proved reserves, probable reserves, and possible reserves. Lenders are chiefly concerned with proved reserves, which are then subdivided into proved developed producing reserves (PDPs), proved developed not-producing reserves (PDNPs) and proved undeveloped reserves (PUDs).

In the context of RBL facilities, most borrowing base calculations are based upon a designated percentage of the cash flowing PDPs and some lesser percentage of the PDNPs; borrowing bases of so-called conforming loans seldom give significant value to PUDs, and almost never to probable reserves or possible reserves.

Those cash flows are then discounted at some rate, often 7-10%, to produce a net present valuation of the properties of the producer. In determining the forward looking commodity price curve, most lenders use their own internal price deck to run the borrowing base calculations. Historically, conservative lenders might advance 50% to 80% of the discounted present value of the future net cash flows attributable to the PDP reserves, and at certain times in the market, lenders might also give value to some portion of the PDNP and perhaps PUD reserves.

Over time, as a producer successfully develops its properties, and makes net additions of PDP reserves to the collateral package, availability under a typical revolving loan will increase. Of course, trends in commodity prices and the lender's price deck may work against the producer and cause availability to decrease. A typical RBL facility requires the borrower to deliver to the lender twice each year an updated reserve report, which then serves as the basis for redetermining the borrowing base.

Utilizing reserve reports

Lenders do not simply accept at face value the conclusions in the reserve report. Rather, lenders need to identify hidden costs and value adjustments in such a report, and to understand the scope and limitations of their collateral. Lenders should pay close attention to (i) the existing gaps in their collateral package, i.e., which of the producer's assets are unencumbered and available to be pledged as additional collateral, (ii) the extent, scope, and priority of statutory liens (sometimes referred to as mechanics' and materialmen's, or M&M, liens) in favor of the producer's vendors, including whether they may prime the lender's mortgages, (iii) the existence or absence of other liens or claims of third parties on the producer's cash flow, and (iv) the expenses related to the P&A costs that may not have yet been included in the cost estimates.

In addition, a lender will utilize its own staff engineers or a retained outside petroleum engineer to assess the work of the producer's reserve engineer. While reserve reports are based on objective data and stated assumptions, they often include a substantial element of professional judgment about the properties. Even though standards and methods for creating reserve reports are generally consistent, considerable differences lie in terms of how the risks are assessed and whether conservative or liberal assumptions related to recovery rates, decline curves, efficiencies including, among other factors are adopted and considered in computing the expected ultimate recoveries. Not surprisingly, some engineers and engineering firms are regarded as more conservative than others.

Finally, lenders typically require, and account for, commodity price hedges arranged by the producer with creditworthy counterparties. As revenues for production may be directly impacted by the strike price of a particular hedge or swap, borrowing base calculations generally take into consideration the existence, price, and duration of such hedges.

Legal due diligence

Legal due diligence involves understanding the nature of the leasehold interest and related conveyances and encumbrances. As the foregoing discussion suggests, the main economic assets of a producer, and in turn, the collateral to which lenders may look to for ultimate repayment, consist predominantly of the oil and gas leases (and, of course, the wells and improvements located or to be located on those lease properties) between the producer as lessee and the existing or prior owner(s) of the underlying mineral rights. The value truly lies in the recoverable hydrocarbon reserves attributable to the leases (and, if part of any joint development, the unitized field or other jointly developed property).

The producer's leasehold interest is examined As a threshold matter, a producer's title to the oil and gas will depend on the lessor's original title, as well as on the terms of the lease itself and any subsequent links in the chain of title to the lease. Often, title to mineral rights and leases in old fields is difficult to establish with certainty, but is generally based on searches of the records of the county or parish in the state where the land is located and tracking the ownership over the subsequent years. State and federally administrated leases govern oil and gas exploration and production on state lands, tribal lands, federal lands, and on the Outer Continental Shelf. Title to those types of interests is typically confirmed by examining the records of the applicable government agency.

Another consideration is prior conveyances. Analysis of a borrower's interest in oil and gas reserves is often further complicated by the fact that a producer may have already sold or conveyed some or all of its original interests under a particular lease. Accordingly, lenders will analyze the extent to which a producer may have transferred a portion of interests to third parties through farm-outs, or conveyances of some or all the lessee's working interests in the lease or by agreements to sell overriding royalty interests; or conveying net profits interests. In each case, the producer is diluting its original interest and future revenue in the lease.

Sometimes, these dilutive transactions are reflected in the most recent reserve reports; in other instances, they are not, but the lender will seek to understand the assets and the nature of any such transactions so as to make a more precise assessment of value.

While farm-outs agreements and production payments have been common in the exploration and production business for more than 50 years, and often constitute useful sources of liquidity for producers, lenders considering a RBL will lend against the net value of the producer's reserves, after accounting for the prior sale or encumbrance of some portion of the producer's original interest. In the next section, we address some particular RBL features in transactions involving unconventional oil and gas reserves.

RBL collateral for unconventional

The general process for arranging and closing a RBL secured by unconventional reserves follows the same path as an RBL with conventional reserves. However, the way in which the reserves are evaluated in the Reserve Report, and how the lender structures the loan, are subject to some different considerations based on the nature of the reserves themselves. These considerations are:

a. The rock itself: Conventional oil and gas accumulations are typically found in relatively porous sandstone rock contained in an anticline structure or stratigraphic trap. The precise location of the well is extremely important. The rocks that contain unconventional oil and gas are typically a less porous shale rock and the hydrocarbons are distributed more evenly throughout a large expanse of rock. The location of any well in an unconventional play is much less critical. The geologic risk of a dry hole is less.

b. Steeper decline rates: Although unconventional resource plays may have less geologic risk, the rate of decline in production is typically higher than conventional wells and formations.

c. Each well is more expensive: Unconventional wells are usually horizontal wells. These wells are more expensive to drill and complete than traditional vertical wells.

d. More infrastructure might be needed: The relatively larger number of wells to be drilled also means a larger investment will be needed for surface facilities such as tank batteries, water supply and disposal systems, gathering lines, gas processing, compression and other transportation infrastructure.

e. Larger blocks of land/leases: Because an unconventional play involves the drilling of numerous, and very similar wells, it often requires a larger block of lands to be leased and developed in a field wide exploitation plan. Producers will acquire more leases and lands.

f. Less title work available: Although larger blocks of leases and lands are needed to drill more wells in an unconventional play, at the commencement of the drilling program, there may be very little reliable title work available on undeveloped leases. As wells are drilled and completed, title work is usually done, but there may be no current title opinions or reports that assure a lender that gives some credit to PUDs that the producer has good leases for those PUD well locations.

g. Newer leases have tougher terms: While assembling the larger blocks of leases and lands, often in areas that are not currently producing oil and gas, producers will acquire new leases. Newer leases often have a higher bonus payment and royalty rate, a shorter primary term and a number of other terms and conditions that are less favorable to the producer. Sometimes leases require the consent of the lessor before they can be assigned.

h. Less flexibility in drilling schedule: Because of the shorter primary term in newer leases, the producer must drill wells more quickly in order to hold the leases. Since the leases, particularly in the more active unconventional areas, are more expensive, producers may be incentivized to drill wells at a faster pace, and in a less desirable sequence, than they would with older leases in conventional fields.

i. May be no right to go non-consent without complete forfeiture: A joint operating agreement in a conventional play typically gives each producer the right to opt out and not participate in the drilling and completion of a particular well, subject to payment of a "non-consent penalty." Operating agreements for unconventional plays often do not allow a producer to take that path. Rather, if the producer chooses to not participate in the drilling and completion of a well, the company may forfeit its interests in all other wells to be drilled under that operating agreement. Similarly, some unconventional well operating agreements do not have a separate casing point election. The overall effect is that the producer has less discretion and must keep funding all wells in order to maintain its position.

j. Time between drilling and completion is longer: Economies of scale are important in unconventional plays. One example is in the sequence of fracturing and completing a well. Rather than drilling and completing a well, and equipping it for production in relatively short order, a producer might drill a number of wells in a geographic area before returning to those wells some time later to fracture each of them and then equip them for production. The period of time between incurring drilling costs for a well and having that well go on stream can be longer than with conventional wells.

k. Fracturing and re-fracturing mean continuing capital requirements: Because of steeper decline curves, and increasing sophistication of fracturing techniques, producers may be expected to devote substantial capital to re-fracturing wells after their initial drilling and completion. While this may be economic even in a low commodity price environment, the effect is to require the producer to continue to invest in wells beyond the rate that would be experienced with conventional plays.

In conclusion, the process for arranging and closing a RBL secured by unconventional reserves is very similar to the process used for a RBL secured by conventional reserves. The lender will, however, account for the differences in the type of operations and resulting impact on the producer's cash flows, costs, and need for capital..

The author
Kevin Shaw is a partner in the law firm of Mayer Brown LLP. His practice emphasizes transactions involving energy projects and companies, as well as the mining industry. He practices in the Houston and Los Angeles. He began his legal career with Shell Oil Co. in its western exploration and production division in Houston. During the 1980s, he practiced in Denver.
In addition to other articles, Shaw has presented papers at special and annual institutes of the Rocky Mountain Mineral Law Foundation, and he currently is the California Oil & Gas reporter for RMMLF's quarterly Mineral Law Newsletter. He received his B.A. in 1976 from the University of Texas and his J.D. in 1980 from the University of Houston. He is admitted to practice in the States of California, Colorado, and Texas. He is a member of the State Bar of California, Colorado Bar Association, and State Bar of Texas. He has served as president of the Denver Association of Oil and Gas Title Lawyers (1986-87), and the Southern California Chairman of the Natural Resources Subsection of the State Bar of California (1994-97).