• Untitled Document
    Untitled Document

    Hedging is an effective risk management tool for upstream companies

    Kevin Price, Societe Generale, London

    Commodity price volatility has always been with us and is the single biggest variable in forecasting EBIT for non-integrated independent exploration and production companies. The recent volatility in oil prices and the collapse of the North American gas price suggest strongly this is not going to change.

    Hedging using derivatives can dampen the impact of price movement on earnings and is a staple tool in the oil or gas company treasury arsenal, particularly for North American CFOs.

    The use of commodity derivatives can mitigate or remove oil or gas price uncertainty as one of the fundamental industry variables, a variable which in turn directly impacts liquidity, (the poor management of which is the biggest predictor of a small cap's impending mortality).

    Like many useful tools, derivatives are a double-edged blade and their use either by CFOs or by bankers must be done cautiously with due respect to the risks both hidden and obvious. To quote Julius Caesar, "It is always the unseen dangers that are the most terrifying." There are many unseen dangers in the interaction between derivatives, the underlying reservoir, and the fiscal and commercial risks in upstream oil and gas endeavours.

    If used incorrectly, without a clear understanding of and regard for the interaction between the derivative product and its specific characteristics and the underlying reserve, production, timing and fiscal risks, derivatives can multiply losses in the case of reservoir-related production, under-performance.

    The North American model

    Hedging as a tool to manage price risk is long established in North America and often used by CFOs to manage price exposure. For bankers, it allows them to safely increase leverage to smaller oil and gas companies. Hedging tools can also be useful to underpin leverage or protect returns on equity in leveraged acquisition scenarios in volatile commodity price environments.

    Historically hedging was and still often is limited, both in lending policies of some banks and in oil company board-approved risk mitigation strategies to proved, developed, and producing (PDP) reserves over a time horizon of perhaps three to five years.

    On a diversified conventional reserve base of multiple wells, several producing horizons and fields with significant production history, predicting the future production performance over this sort of time horizon using type and decline curves is generally quite accurate. Companies with this sort of conventional reserve base can enter into contingent liability derivatives like swaps on a high percentage of their PDP production with a high degree of confidence that the physical production to back any hedge liabilities will be there regardless of availability of future resources like capital and rigs to drill and complete future wells.


    One feature of the US market not seen anywhere else is the volumetric production payment, or VPP.

    Unlike a conventional loan, in a VPP the holder of the instrument provides the producer with an upfront cash payment in return for receiving specific volumes of oil or gas (not a specific amount of cash) from specifically designated fields over a specified period of time. In most cases an agreement transferring the specified reserves to the VPP holder is executed as part of the transaction. In order to mitigate the price risk that has been transferred to the holder of the VPP, the VPP will often have a hedge in the form of swaps associated with the production volumes integrated into the commercial structure of the agreement.

    This structure is unique to the US because VPPs transfer ownership of a specific volume of oil or gas to the buyer in return for capital. The transfer of oil and gas ownership of reserves when "still in the ground" is not something that can be done in many places outside of the US as reserve ownership tends to be in the hands of the state with oil and gas companies receiving the right through a license or contract to extract and sell the oil (ownership of the oil or gas itself transferring at the wellhead).

    Where a hedge is integrated into the deal, the PDP production stream is sold forward on a locked-in price to result in a stable predictable revenue line that is used to repay the capital (and any embedded interest/profit) over the life of the VPP. Because all of the sales revenue is taken for repayment, the unhedged non-transferred volumes from the underlying parent oil or gas field or fields must be sufficient to cover all of the global field-level opex and any other liabilities or obligations of the field, including the operating costs of the VPP volumes.

    Depending on the economics of the underlying asset, including the nature of the lease operating expenses of the properties (fixed vs variable etc.) and the precise shape of the commodity forward curves, a VPP structure may or may not result in higher leverage than a traditional loan with hedging. Other considerations when using this structure include accounting and tax issues and the fact that a VPP may result in an actual transfer of reserves (whereas a reserve-based loan repayable in dollars does not) impacting reserve replacement ratios and other performance indicator statistics of the parent company.

    Resource plays, acquisitions, and predictable dividends

    In recent years the combination of the development of large resource plays in the US and the emergence of business models designed to ensure consistent dividend payouts to investors has led to the development of more aggressive hedging policies in companies and less restrictive covenants in bank loans. Typically such companies will hedge out a high percentage of their total proved reserves, including the proved undeveloped component but cap the volume of contingent liability derivatives at current actual production levels. Bank facilities may in turn have covenants that require that contingent derivatives volumes can at no time surpass "actual" production, and if the production drops may have clauses that require unwinding of the "open" hedge position to a level no more than the prevailing production rate.

    Resource plays in particular lend themselves to this sort of approach as the geological risk associated with proved undeveloped component of reserves is greatly reduced and spread over a scale of operations consisting of hundreds of wells a year. This means the geological risk of reservoir underperformance can largely be ignored. The key risk then becomes the ability of the company to continue to source sufficient capital and rig resources to convert undeveloped reserves quickly enough to at least maintain the existing production levels, avoiding any decline.

    Given reserve risk in resource plays is greatly reduced compared to conventional reservoirs. The risk being taken by investors and bankers with this kind of approach is more in line with the usual risk of continuation of a going concern, namely, can the company source sufficient resources to continue to maintain its operations at least at current levels.

    Finally, in some limited cases, the North American market has accepted a further level of uncertainty that relates to acquisitions where companies may hedge the price of production of "to be acquired" properties. This is done to ensure that the acquisition economics are protected in a situation in which the acquisition is being completed in a potentially falling commodity price market. Such hedging is only done when certain acquisition milestones are passed, and acquisition debt facilities may have specific requirements relating to the need to unwind the hedge if certain milestones are not reached or certain price thresholds breached.

    Ultimately, at high prices, the value of the company's resource base acreage (both existing and to be acquired) the reserve life and production half-life statistics (indicating the ability to restructure hedges over a longer period of time) and finally the ability to sell the acreage to raise capital (so called "right way risk") is the final backstop to the potential future liabilities of the hedge program in these situations.

    Given the recent drop in gas price and to a lesser extent of WTI in the US in particular, this approach to hedging has proved to be beneficial to companies that have managed to protect the economics of the business over a long term without unduly exposing themselves to physical delivery risk if the market price were to move above the strike of the swap.

    The graphic on page (20) is a conceptual example of a resource-based company hedge program (in this case oil) for a company in the middle of closing an acquisition.

    International markets

    The level of hedging risk acceptable outside of North America varies depending on the context but is normally far less than can be comfortably tolerated in the American context for a number of reasons.

    Undeveloped conventional reserves and contingent derivatives are a dangerous mix. Firstly, reserve risk is different, typically the reserve base is almost always conventional, and therefore the undeveloped components of reserves have far more geological-specific risk associated with them than in a resource play. In addition, reserves are often offshore, meaning additional drilling to make up any production shortfall is logistically far more expensive and time constrained in terms of resources to mobilize rigs. (Trying to drill your way out of trouble is never a very convincing strategy, but offshore cost and time considerations make it impossible.)

    Generally, the use of swaps in upstream project finance for conventional reservoirs against non-producing reserves is inadvisable. In the cases of an underperforming reservoir or even a delayed start up of production, "out of the money" swaps can quickly amplify the loss in the event of default. Puts, or differed variations of them, are generally used avoiding any potential contingent liability (apart from the option premium) unless and until reserves are producing. The only (rare) exception to this is perhaps where an asymmetrical collar structure can be used to offset the time uncertainty of first oil or gas in a new field development (floor now but with a high level call strike perhaps a year after predicted first oil or gas to allow room for unexpected delays).

    This strategy, while providing some mitigation to start-up delays, still does nothing to mitigate reserve risk itself, which is always higher on undeveloped "volumetrically" calculated reserves, so the banker providing the derivative and the oil company CFO must question if the costs saved in premiums for options is worth the potentially huge risk if the field significantly underperforms on first production at a time when the call is out of the money.

    It might be argued that such an approach is betting not just the loan, the careers of board members (and their bankers), but indeed the company itself on variables that are beyond the control of management in order to save some upfront costs.

    Tax – corporate or wellhead ? – it matters

    Fiscal regimes are far more variable and complex for companies operating outside North America and can have unintended consequences that amplify liabilities in the event of prices above the strike price of the derivative instrument being used.

    In high tax regimes like Norway (and indeed the situation was similar under Petroleum Revenue Tax [PRT] paying fields in the UK in the past), the tax, or a large component of it, is calculated at the "field" level on the wellhead price received for the oil or gas rather than as a corporate tax based on the financial profit or loss (including hedging gains and losses) of the parent company. This can lead easily to over hedging through unintended operational gearing.

    To give an example, say a tax rate is 80% on wellhead prices, and the company hedges 50% of its production at $50 a barrel. If the oil price goes to $100, the company will owe a tax liability of $80 to the host government and $50 to the hedge provider a total of $130 on every barrel of "hedged" oil produced. At the same time for the un-hedged barrel, they have just $20 post tax revenues to cover the $30 loss on the hedged barrels. As can be gleaned from this simple example, over-hedging via fiscal induced operational over gearing is a potentially rapid route to bankruptcy.

    Production sharing contracts (PSCs) seen in many emerging countries represent an even more complex minefield for the inexpert use of commodity derivatives, as the combination of the quantum of cost oil recovery and profit oil horizon uncertainties combined with the additional complexity of flows of cash from a hedging program can lead to unpredictable effects on future cash flow, leading to high cash flow volatility with cashflow in surplus in some periods being followed by unexpected deficits in others.

    Basis risk

    On top of all the risks outlined above, another risk occurs wherever the hedging instrument is not an exact match for the underlying physical crude. An example would be production from an oil reservoir being hedged by the purchase of Brent Crude swaps. While correlations can give some comfort that the spread between the price of different crudes, they cannot predict exactly how such a spread will move over time. The gap between the swapped price and the underlying market price of the physical crude being produced is the basis risk.

    Various strategies can be employed to manage this risk, including in some markets "basis" and synthetic swaps that are designed to cover the gap. However, basis risk remains an additional uncertainty in simple crude hedge swap strategies unless the underlying crude is a direct benchmark to the swap. Basis risk can come in various guises, for example on gas VPPs the calorific value of the gas can be a hidden source of this risk if the VPP is denominated in production volume rather than calorific content.

    GSA escalator hedging

    In some markets, long-term gas contracts are sold on prices linked to crude products like Gasoil or heavy fuel oil. Details will vary with the specific contract, but the price escalators typically have delays built in so the price movement on the gas price happens some months after a movement in price on the benchmark escalator. Hedge strategies attempting to synthetically tie in the gas price have to address two kinds of basis risk, time variant and product specific.

    Sentiment of the capital markets

    While North American investors seem to welcome a certain amount of hedging as a sign of good risk management, many stock market investors in other parts of the world are less keen. Putting aside the technical considerations above which are perhaps beyond the concern of all but the most sophisticated investors, oil stocks are often bought not just to have exposure to exploration upside but also to the oil price itself. Many international CFOs may feel little incentive to hedge downside significantly because they may receive criticism from shareholders for reducing high price upsides.

    Conclusion: One size (in this case price) does not fit all

    When it comes to the use of commodity derivatives, what constitutes a sensible risk management program depends on context. The nature of underlying reserves, the size, scale, maturity, and sophistication of the company's operations, the petroleum economics of the underlying asset(s), and the fiscal context of the country of operations. Correctly utilized, hedging tools represent a useful way of underpinning value, maintaining liquidity, and managing credit risk. Incorrectly used they can amplify risk significantly.

    About the author

    Kevin Price  

    Kevin Price is the managing director and global head of reserve-based finance at Societe Generale. He is responsible for all of the bank's reserve-based financing activities both internationally and throughout North America. Price has over 25 years' experience in the upstream oil and gas and finance industries, having started his career as a petroleum geologist, he spent 12 years working in the oil industry before moving into reserve-based lending and oil field development finance in 1997. Since 1997 he has held various positions in British and European Banks with specialist upstream financing teams, initially as a technical advisor and latterly as a senior banker responsible for arranging and structuring a number of innovative international borrowing bases and oilfield development financings both in the North Sea and in emerging markets. Price joined Societe Generale in 2006 as head of the international reserve-based finance business, becoming the global head in 2009.

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