DOUBLE HEDGE AIDS COMMERCIAL TERMS OF UPSTREAM ASSET PURCHASES

David Wood
International Petroleum Corp.
Dubai

In recent years many major oil companies have elected to rationalize their producing assets. Mature production-particularly onshore in developed countries, associated with high costs and small profit margins has been the major target.

The current weakness in oil prices has resulted in many such properties being on the market. However, much production marginal to a major can be highly profitable to a cost-effective independent, particularly if the production fits strategically with the independent's asset portfolio.

For example, if an independent already has small-scale producing assets in an area, a producing field on the market could be especially attractive because it can be tied into the company's existing operation.

Although many independents recognize that some of the producing assets on the market could be of potential value to them, in a period of volatile prices two important valuations have to be technically justified and negotiated to enable or persuade them to conclude a purchase agreement for a specific asset. These are:

• A purchase value for an asset that is acceptable to both seller and buyer.

  From the buyer's viewpoint it is necessary to establish a purchase value above which, based on its risk assessment and production commodity price and cost forecasts, the asset will make money for it at the appropriate discount rate. Unless a better price than that can be negotiated, the potential buyer will not conclude a deal.

• A loan value for the asset to establish the level of debt that the asset can support for the buyer. This assumes that most buyers will require leverage in the form of a loan to complete such transactions. There are few cash buyers in the market, and even for them the loan value of the asset is of interest as they may need to secure debt in the future based upon the asset being purchased.

Even if a buyer is in a position to complete the purchase with equity funds, maximizing the use of debt usually enables the purchaser to benefit from the cash flow of the acquisition immediately and allocate higher-cost equity funds to investments more suited to equity investment (i.e., exploration and appraisal).

In defining these two important values (both of which are usually established as ranges rather than single values) the independent has to protect itself against a downturn in commodity prices and exposing itself to an unserviceable level of debt.

REDUCING RISKS

Hedging in its various forms can offer means of reducing the risks associated with the assumptions made in defining both purchase and loan values.

To cover the downside risk the purchaser has to forgo some upside potential. As more sales have taken place, sellers and lenders have become aware of the independent's need for downside protection and are often prepared to negotiate more complex hedging arrangements. Indeed, there are several reasons why the sellers and lenders also find hedging arrangements attractive and often seek them from buyers.

For the seller:

• Hedging means sharing in the upside of the property after the sale and perhaps benefitting from the lower operating costs that the buyer may achieve in the future.

• Hedging the asset purchase price can help to persuade its shareholders that they are realizing a reasonable price for their assets. This is particularly the case where an asset has previously been highly valued by their company (and probably provided it with significant cash flow in the past). A hedging arrangement could provide them with additional payments should the oil price or production rate improve in the future, contrary to current forecasts.

For the leader:

• Hedging can justify placing a higher loan value on an asset or softer loan terms as the lender too can be protected from a downturn in market prices and take a share of the upside; i.e., it can reduce a lender's risk profile for the project.

• Hedging of the oil sales by the borrower, either in total or in part for a limited period, can provide the lender with more comfort that the borrower will be able to meet its debt repayments even during periods of weak commodity prices.

Hedging can potentially provide win-win positions for buyer, seller, and lender, in which case it offers powerful solutions to some of the problems that can frustrate asset sales.

PURCHASE PRICE HEDGE

In its simplest form a purchase price hedge includes establishing base case production and commodity price profiles from which an upfront component of the purchase price of the producing asset can be negotiated. It is then necessary to establish upside and/or downside thresholds in either or both of these profiles which will trigger supplementary payments between buyer and seller.

The seller may wish to secure additional payments from the buyer if production or oil price exceeds certain thresholds (referred to here as the upside hedge). This may be acceptable to the buyer if it can reduce the upfront purchase price in exchange for such deferred payments. Much of the negotiation usually revolves around the mechanism of the hedge as well as the actual size of the payments to be made. Procedures that optimize the tax position of either buyer or seller can be important considerations.

On the other hand, the buyer may wish to secure a refund of the initial purchase price if certain production targets or product price thresholds are not achieved (referred to here as the downside hedge).

It is often difficult to persuade sellers to concede a downside hedge. It will depend upon the prevailing market conditions (i.e., is it a buyer's or seller's market?), the urgency with which the seller needs to divest the asset, and the confidence buyer and seller have in the future market and production capabilities of the asset.

A recently published example of a deal including both upside and downside hedging components linked to future oil price was Apache's 1991 purchase of U.S. production assets from Amoco (Forbes, September 1992).

With some of the commodity price and production rate risks managed through hedging contingencies within the framework of a purchase agreement, the buyer remains primarily exposed to the risks of cost overruns in addition to the standard insurable risks. Unforeseen costs or inflation of costs are the main risks for the buyer to manage.

As most independents buying assets from majors are confident that they will be able to cut operating costs, they are usually prepared to take on such risks. Nevertheless, this exposure emphasizes the need for the purchaser to review costs carefully.

The following hypothetical example illustrates how a purchase price hedge can have benefits for both buyer and seller.

HEDGED PURCHASE PRICE EXAMPLE

An independent engineer, commissioned by a prospective buyer, indicates that a producing license containing several oil fields and undrilled prospects has proven oil reserves of 30 million bbl and additional unspecified upside potential.

Two production profiles are generated by the independent engineer related to a minimum case (i.e., proven producing reserves) and a base case (i.e., proven producing plus undeveloped proven reserves requiring capital to bring them on stream). The seller accepts these figures and, provides the buyer with its forecast of capital and operating costs (Table 1).

The buyer's own study indicates that it could achieve significant reductions in operating costs relative to the seller's forecast (Table 1). The buyer and seller use slightly different oil price forecasts to generate future cash flow estimates and discount rates to place their respective values on the asset (Table 2).

As the ranges of these values overlap, negotiations should result in a deal. The example assumes that free market conditions prevail and that a negotiated price will be based upon a fair market value (i.e., neither seller nor buyer is being driven by external forces)

Common external forces are:

• The seller needs to raise cash urgently (e.g., to pay creditors or shareholders or secure a more profitable deal) and may be willing to sell cheap.

• The buyer has significant tax losses that can be offset against the producing asset in question and may persuade him to pay above the fair market value.

• Either the buyer or seller is negotiating the deal for-road corporate purposes rather than on the profitability of the project in isolation (e.g., to reduce debt burden or staff levels to improve corporate profitability on the part of the seller or to increase debts and liabilities on the part of the purchaser as a poison pill to fend off a corporate raider.

• Strong competition for an asset of strategic importance.

  All such forces can distort the negotiated price away from a fair market value based on discounted cash flow analysis and may also influence the structure of a resulting sale and purchase agreement.

Table 2 indicates that the seller will seek a sale price of $135-150 million (net present value-NPV-at 7.5% of the seller's base case cash flow estimate). On the other hand, although the buyer believes, based on its cost reduction expectations, that the asset could still be profitable for it at about $158 million (NPV at 10% of buyer's base case cash flow), its initial offer of $130 million is based upon the cost estimates produced by the seller.

At a purchase price of $130 million ($4.30/bbl) the buyer could achieve, based on its price and cost estimates, a real rate of return from the project of 20% and an NPV discounted at 10, of $21 million.

In ensuing negotiations, the buyer is prepared to increase its offer, because of its valuation of the asset. However, it is constrained to a price limit of $135 million due to equity limitations and the amount of debt that the asset can support. The buyer also has a more pessimistic view of future oil prices than the seller.

The seller, on the other hand, recognizes the effect of lower oil prices on the asset (e.g., the spot oil price falls by 50/bbl during negotiations) and, as it is keen to secure cash for another purpose, is prepared to accept a slightly lower value. However, it would like a deal of close to $150 million to present to its shareholders.

The seller's technical team also believes that the asset is capable of outperforming the base case production profile and therefore believes there is additional upside to the asset, especially when appraisal and exploration potentials are considered.

PRICE ELEMENTS

The hedged purchase price that the buyer and seller agree upon consists of three elements:

1. An upfront payment to the seller of $135 million.

2. Potential deferred payments to the seller of up to a total of $15 million spread over years 2, 3, and 4 of the project based upon 30% of incremental revenue generated from specified incremental production above the base case production profile, with a specified oil price ceiling (Table 3).

3. Potential oil price protection refund to buyer of up to a total of $15 million spread over years 2, 3, and 4 of the project based upon the oil price falling below specified values (Table 4).

This settlement satisfies the seller because it enables it to share in potential upside production revenue (i.e., what it perceives as it main risk of underselling the asset) as well as receiving an upfront payment within its expected range.

This settlement satisfies the buyer because the upfront payment is kept within its equity and dept constraints, and it has achieved some downside protection from a downturn in future oil prices (i.e., what is perceives as its main risk of paving too much for the asset).

Fig. I illustrates what this hedged purchase price agreement means to both buyer and seller under three oil price and production scenarios. As the seller considers that Scenario 2 is more likely than Scenario 3, and the buyer is more concerned about Scenario 3 than Scenario 2, the hedge sales price agreement provides a win-win solution to the negotiation.

LOAN VALUE ANALYSIS

Having reached a deal with the seller, the buyer, seeking a leveraged acquisition, has only partially completed its negotiation and cash flow sensitivity analyses. It remains for the buyer to justify to the lender (1) the Liability of the asset, (2) the purchase value is has agreed for the asset, (3) the ultimate loan value that the asset can support, and (4) the ability of the buyer to repay the loan it is seeking based upon its overall corporate liabilities.

The ability of the buyer to succeed in point (4) depends not only upon its satisfactorily demonstrating points (1), (2), and (3) to the lender, but also on its overall corporate accounts and balance sheets and past performance in terms of debt repayment.

The lender's conclusions on point (4) will ultimately influence the loan value it assigns to the asset and the terms that it is prepared to agree with the borrower. The more established the borrower's track record and the healthier its financial standing, the better the chance it has of securing a loan close to the full loan potential of the asset.

Lenders generally take a more conservative view of a project (e.o,., proven reserves with flat, low oil price and high cost forecasts) than the equity investor. This is because the returns from the lender's investments are generally only derived from the interest margin on the loan (i.e., lenders are more risk-averse than equity investors because their potential returns are significantly less).

Project variables that influence the loan value a lender is prepared to advance include:

• Commodity prices (current and near term forecast).

• Proven reserves (probable reserves may in some cases be considered).

• Possible reserves and exploration upside, which are usually discounted.

• Production performance (e.g., decline curve analysis).

• Time to production start-up for a development project.

• Capital and operating costs.

• Tax and royalty liabilities.

The lender's loan value is usually based upon net present values of base and downside cases discounted at the applicable interest rates plus margin for the loan. A positive side for the borrower is that the discount rate applicable to debt funds is also less than that usually applied to equity funds (i.e., the security investor works for a bigger return so equity funds cost more).

The lender is usually prepared to lend only a portion of this discounted value (0-75%) depending upon the risk profile it associates with the asset, the borrower, the geographic location, and the borrower's development and production plans and personnel.

For limited recourse or nonrecourse project finance, lenders are more comfortable if borrowers are injecting significant amounts of equity into the project (at least 20%). If the borrower does not stand to lose should the project fail, the lender is rightly concerned.

Because of significant risks and financial exposure early in a development project, it is not uncommon for a lender to require that the borrower initially inject a high proportion of equity finance (an equity "kicker," sometimes as high as 160% of the costs). Once the field is on stream and the reserves enter the category of proven producing, the lender will often be prepared to refinance part of the buyer's initial equity injection.

In high risk areas it is only when an oil or gas field's production is established and reserves categorized as proven producing that it realizes its maximum loan potential. In mature production areas with low technical and political risks, undeveloped assets can achieve their full loan potential.

AGREEMENT STRUCTURE

The structure of a project finance loan agreement will vary from project to project and borrower to borrower, depending upon the main risks perceived by the lender.

Using information from an independent engineer as regards base case production and cost profiles in conjunction with its own view of prices, a borrower may calculate a base case loan value. To evaluate accuracy of a base case loan value it is generally necessary to run several sensitivity cases based upon higher costs, lower production, lower commodity prices, and project delays.

The lender may also run a worst case scenario combining all the downside sensitivities. These sensitivities provide both lender and borrower an insight to the asset's strength, weaknesses, and flexibility. This insight may indicate that additional hedging of the oil price is advisable to make a project more robust.

Specific debt cover ratios are usually defined by the lender in a loan agreement, based upon its base case and worst case cash flow models and interest and fee structure, to define the appropriate level of revenue dedication to repay the loan plus interest and the term of the loan.

Because there is usually production uncertainty, unexpected costs, and higher economic risks during the final years of production from a depleting oil field, lenders usually assume a reserve tail (20-30% of remaining recoverable proven reserves) during which no outstanding debt will be allowed. Loan values and debt cover ratios are generally calculated over the full life of the loan and the portion of the project excluding the reserve tail.

A loan agreement generally stipulates that if specific values of defined cover ratios for base case and/or worst case models are breached, a higher proportion of project revenue (up to 100%) will be dedicated to repay the loan. Moreover, the agreements also generally stipulate that if higher specific values of these ratios are breached, the borrower is placed in default and the lender can take possession of the appropriate security, and/or additional default penalty interest rates become effective.

Hence, the sensitivity of the project to the specific values of the cover ratios defined in the loan agreement are very important for both lender and borrower.

Thus, before going to the time and expense of seeking project finance, a borrower should carry out its own detailed analysis of a project's ability to support the level of debt it will need or wishes to take on to secure the assets and whether the asset is robust enough to avoid the unpleasant consequences of defaulting on its loan cover ratios.

For these reasons it is prudent for the borrower to conduct loan support cash flow modeling in parallel to purchase-price cash flow modeling; i.e., to eliminate assets that are not robust enough to raise suitable levels of project finance on acceptable terms and assets that are beyond its equity capabilities.

LOAN VALUE HEDGE

The profitability of producing assets, particularly those sheltered from significant tax liabilities, is sensitive to commodity prices.

For such assets during periods of commodity price uncertainty, the lender's worst-case scenario will take a more conservative view of commodity prices, which will obviously affect the ultimate loan value and loan terms a lender is prepared to assign to the project. Commodity price hedging offers the buyer a method of reducing the commodity price uncertainty and thus positively influence a leader's loan value.

As commodity price hedging has become a more widely adopted method of risk management, the types of hedging mechanisms available have become more sophisticated and flexible. It is now possible to tailor the commodity price hedge to suit the risk profile of the project and the requirements of the borrower.

Indeed, most lenders now offer hedging pro,rams to buyers. These programs enable lenders to participate in the upside of an asset and justify an increase in the loan value with out necessarily increasing their exposure to the project's risk.

Thus, most lenders specializing in energy finance have teams including project finance and commodity risk management experts. The type of price hedges available range from the simple price swap to the more complex price option, with defined floor and cap prices triggering various levels of participation by the buyer and seller of the price hedge.

In a price swap, the buyer of the hedge (generally the producer; i.e., the buyer of the asset in the current context) agrees to receive a defined fixed price for a specified volume of production over a specified period of time in exchange for providing the seller of the hedge with the floating or market price for that volume of production during the period of the hedge. If the average market price falls below the fixed price, the seller of the hedge has to pay the buyer of the hedge the revenue difference. If the average market price rises above the fixed price, the buyer of the hedge has to pay the seller of the hedge the difference.

This method guarantees the buyer of the hedge a fixed price and products it from the downside of a weak commodity price in exchange for giving up the upside of potentially high commodity prices in the future.

There are several alternative methods for structuring the more-flexible price options, which are readily tailored to the requirements of the project. The option enables the buyer of the hedge to Guarantee its minimum commodity price (floor price), for the period and volume of production negotiated in the hedge, in exchange for sharing with the seller of the hedge the incremental revenues from commodity prices above a defined price cap.

The buyer has the flexibility of deciding the percentage of production to be included in the hedge and the range of prices in which it wants to participate. It is possible for a producer to hedge different portions of its production by different means to optimize value of the asset.

The time period and volume of production incorporated in a hedge agreement are the key factors that the buyer has to decide upon. The time period is generally influenced by the term of the loan. The longer the period, the more upside value that the buyer risks losing if the oil price rises during the period. The volume dedicated to the hedge will depend upon the level of downside protection required.

How such commodity price hedges can influence the loan value for 0 an asset purchase is best illustrated by further consideration of the hypothetical hedged purchase agreement example.

HEDGED LOAN VALUE EXAMPLE

The loan-supported cash flow analysis of the asset purchase example discussed above, based upon the project cash flows listed in Table 2, is summarized in Table 5. This cash flow analysis compares cases with no oil price hedge with a price swap for 100% of production over a 2 year period at a fixed price of $18.50 bbl.

During the 2 years of the price swap, almost 50% of the loan is repaid. By taking advantage of a price hedge the borrower can limit the lender's worst case scenario and therefore increase the maximum loan value a lender will assign to the asset.

By imposing the limitations of a 25% reserve tail and a maximum loan cover ratio of 66.7% (values commonly used by lenders), the borrower can vary the revenue dedications required to repay the loan to model the term of the maximum loan facility each project cash flow can support without breaching one or both of these limitations.

In practice, this kind of analysis is performed quarterly (or, in some cases, monthly for the initial years of a project) to calculate the detailed exposure of both borrower and lender. Customized spreadsheets offer an effective means of conducting such analysis.

The results shown in Table 5 indicate that, by incorporating an oil price hedge for the first 2 years, the borrower should be able to secure at least $4 million more in a loan facility than without such a hedge and establish profitability from even the low case.

By performing this kind of analysis, the potential borrower can establish the range of debt a lender is likely to provide at an early stage of evaluation of an asset purchase negotiation, The calculated figures suggest a maximum range of debt of between $78 million and $94 million could be supported by this hypothetical asset, which would leave the borrower/buyer to inject between $3-7 million and $41 million of equity into the deal.

The net equity cash flows shown for years 1-5 in Table 5 are the actual cash flows the borrower/buyer can hope to achieve from buying the asset under debt leveraged terms. Varying debt/equity ratios and oil price hedging terms to model the net equity cash flows can help the borrower optimize the type of oil price hedge (if any) and the level of debt.

CONCLUSIONS

From the foregoing discussion and example it is concluded that the market conditions and strategies of several major oil companies prevailing in the upstream oil industry currently offer opportunities for independent oil companies to buy high quality producing assets.

The commercial terms under which such assets might be purchased and financed can, in many cases, be enhanced by incorporating hedging arrangements in both the purchase and loan agreements.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.