Minimizing Risk in A&D

Energy commodities have a proven history of sudden and significant commodity price declines—and there might be no worse time for a steep drop than when your company is trying to do an acquisition.

A company that signs an agreement to purchase an energy asset typically commits to paying a fixed price. But the purchased asset’s value can float with the underlying commodity’s forward price curve in that 30- to 45-day period before the acquisition’s close. E&P and production master limited partnership (MLP) enterprises seeking to grow through acquisition face the dilemma of commodity price fluctuation eroding, or even wiping out, the financial benefits of the deal.

It doesn’t have to be that way, though. Smart use of hedging techniques can minimize or eliminate the risk. And the hedging can start when the papers are signed, even before the assets are formally purchased.

First, let’s illustrate the kind of price move that can jeopardize a deal. Figure 1 shows the forward three-year West Texas Intermediate (WTI) crude oil curve over a 45-day period in the spring of 2012. Assume a company (we’ll call it “BuyCo”) had priced a transaction in mid-April with the three-year strip at $99.85. By the time the deal closed at the end of May, the three-year curve had declined by $17.98, or 18%, to $81.87. This would affect the deal economics and, ultimately, the payout at some future liquidation event. In the MLP world, it could restrict the ability to pay the distributions needed to remain attractive to investors.

Shown is the forward three-year WTI crude oil curve over a 45-day period in the spring of 2012, illustrating how price movements can jeopardize a deal.

Options

Put options are the building blocks for hedge transactions that do not create exposure. A put option is a contract between two parties to exchange an asset (the underlying), at a specified price (the strike), by a predetermined date (the expiry). One party, the buyer of the put, has the right, but not an obligation, to sell the asset at the strike price by the future date, while the other party, the seller of the put, has the obligation to buy the asset at the strike price if the buyer exercises the option. The buyer of the put option pays a premium to the seller.

In our view, producers tend to overpay for put options. A purchased put protects the producer in the unlikely event that prices fall to zero. We think prices below $65 are not sustainable in the long term, since nonconventional oil projects become unprofitable. Therefore, price protection below $65 has marginal utility, especially if the bank price deck is at or above this level. A producer is better off selling off protection below $65 via a put spread.

The put spread is the combination of a long put option and a short put option at different strike prices for the same time period. The cost of a put spread is lower than a put option because the producer collects a premium for the sold put option. The range between the purchased put and sold put is called a protective spread.

The put swaption is an option granting its owner the right—but not the obligation—to sell an underlying swap at a specified price. It also requires the buyer to pay a premium to the seller. Put swaptions exercise into swaps if the market price at expiration is below the strike price. If the market is above the put swaption strike price, the producer would not exercise and is free to hedge. If the acquisition has not closed at the exercise date, then the put swaption will cash settle and the producer remains unhedged. The expiration date of a put swaption should be set a few weeks after the closing date to account for minor delays in closing.

Now, how can our hypothetical BuyCo use the hedging tools to protect itself? Let’s look at options that require an upfront cash outlay as well as options that require no money down.

Paying to hedge before the close

If BuyCo has the free cash, it can purchase a combination of puts, put spreads or put swaptions to hedge 100% of the price risk. Pricing changes in the energy markets can make it easy to overspend for price protection or choose the wrong structure. For instance, in a low-volatility environment, puts or put swaptions may be superior to put spreads in cost effectiveness. A market in steep backwardation (future prices far below the current spot price) is not the best environment to use swaps or put swaptions.

After the acquisition closes, BuyCo can attempt to recoup its hedging costs. It can sell call options to convert new put positions into collars or put spread positions into producer three ways. It can also turn swaps into protective spreads by selling puts against the swaps that were created through exercise of the put swaptions. These techniques could allow BuyCo to collect all—or even more—than the original hedging costs.

The puts, spreads and swaptions could cost a significant amount of money, however. Alternatively, BuyCo can hedge with swaps and post a margin, a technique that could significantly reduce out-of-pocket costs. Margin is the collateral a bank needs to offset the risk and exposure created when the bank transacts with a producer that has not pledged assets. Only hedges that are out of the money compared to daily settlement prices require margin, because in-the-money hedges do not expose the bank to hedge losses.

After the acquisition closes, the acquisition assets secure the margined swaps and BuyCo returns the posted margin. The big risk with cash margining is cash availability should the market explosively move higher before the close. For example, a 1,000-barrel-per-day short WTI swap for three years would incur $1.095 million in margin for every $1 that WTI moved higher.

Cash-free hedging

What if BuyCo does not have enough cash on hand to purchase price protection for the acquisition? Not to worry. Let’s examine three means of reducing acquisition risk without spending a dime.

First, assuming BuyCo already has assets, it could use its spare hedge capacity or restructure existing hedges. To use spare hedge capacity, BuyCo will have to hedge to the fullest extent allowed by the covenant in its credit facility. For example, if BuyCo has a hedge covenant in its credit facility allowing a maximum hedge volume of 80% of PDP but is just 50% hedged, it can hedge an additional 30% with swaps against existing assets. If BuyCo is acquiring a similarly sized asset, essentially doubling its size, BuyCo would be just 40% hedged on the combined PDP after the acquisition closes.

The second method is restructuring the existing hedge portfolio, if possible. An in-the-money portfolio (positive mark-to-market) offers far more possibilities than an out-of-the-money portfolio (negative mark-to-market).

Assume BuyCo has an existing 100-barrelper-day Cal 14 WTI producer collar in place: a long $85 put and a short $105 call. Here are two ways BuyCo can restructure this hedge without a cash outlay.

BuyCo can buy back the existing short $105 call and defer the premium payment until 2014. The remaining position would be the long $85 put, which does not create exposure and does not count as a hedge per the credit agreement. BuyCo could then sell a Cal 14 WTI swap for 100 barrels per day. After the acquisition is closed, BuyCo could sell a Cal 14 call to offset the deferred premium.

Alternatively, BuyCo can extract value by “rolling” the puts and/or calls. Lower put strikes are cheaper, so BuyCo can receive a premium payment by selling the existing long $85 put and buying a $75 strike. And since lower call strikes are more expensive, BuyCo could get another premium payment by buying the $105 call back and selling a $95 call to replace it. BuyCo can invest the premiums in new hedges covering acquisition volumes.

The third method looks to the seller. If the seller has hedges, they can be included as part of the acquisition, locking in hedge economics. The acquisition sales price is simply adjusted up or down based on the mark to market of the hedges at the signing of the PSA. It’s possible to avoid costs for transferring the hedges, especially if the buyer and seller have a common bank for their credit facilities.

These are the ways you can protect a deal’s economics between signing the agreement and the closing.

Regardless of the strategy, however, producers need to look deep into the market to ensure they get the most hedge coverage for the cheapest possible price. Hedging is an art, not a science. The optimal combination of puts, put spreads and put swaptions should be created with careful attention to market view, curve structure volatility and option skew so that the producer can get the most price protection for the least cost. Most importantly, producers should treat their hedges like assets and manage them—much as they would manage the assets bought in a deal.

Bob DeMan, senior vice president, Asset Risk Management LLC (ARM), Houston, has more than 20 years of energy industry experience. He can be reached at 281-655-3237 or bdeman@asset-risk.com.