Most physical product sale “optimization” decisions come naturally to oil and gas producers. Management teams negotiated the midstream contracts which provide the right to sell products when and where it is most profitable. Marketing teams tasked with placing physical molecules understand the variable and fixed costs well enough to sell physical products for the highest net-back price for the upcoming months.
However, determining the appropriate financial derivative trades to execute alongside physical “optimization” trades is often not as intuitive. If physical sales are re-positioned to maximize forward revenue, but financial derivatives are not re-positioned accordingly, the “optimized” physical sales could end up reducing—rather than enhancing—total revenue.
As you will see in the first example below, making one-sided adjustments to a derivative hedge book is not guaranteed to maximize revenue in hindsight. The goal of optimization is not to maximize revenue; rather it is to maximize expected revenue for a given level of risk. If management decides affirmatively to increase risk when prices are “low,” that is certainly an acceptable, if not desirable, strategy when such a decision is within the confines of defined risk parameters. However, it should not be confused with optimization.
Crude Oil Contango During Covid
An interesting example of physical sales “optimization” occurred this past spring when front month crude oil swaps approached $10/BBL to $15/BBL while deferred months were still over $30. Instinctually, producers knew they did not want to sell their production for $10 and tried to store their oil, slow down truck sales, or delay completions until they could achieve prices 2 to 3 times greater in just a few months. But what actions did they take with their financial hedge books?
While many producers had the foresight to buy back financial hedges in the months where they planned to reduce production, not all of them looked out on the forward curve and added hedges in months that they planned to bring deferred production to market. This unnecessarily increased risk in their forward revenue expectations, decreased their percentage hedged, and did not definitively guarantee higher total revenue. In short, it was not optimal.
As it turns out, contrary to what this article is espousing, buying back near-term swaps, and not selling forward swaps at $30, has been the revenue maximizing decision so far. Of course this is only true with oil trading close to $40 today (assuming there is eventually a sale or hedge of the stored oil above $30). However, we only know this in hindsight. The possibility existed that forward prices could have moved lower than $30 in months when deferred production was intended to be brought back online, and total annual revenue could have eventually been reduced by the decision to defer production. The higher returns so far have been earned due to increased risk taking and not because of optimization. The following oversimplified example will ideally make this point clearer:
Suppose a producer has a 100% swap hedge on 1 BBL/month of production at a price of $50 in a $50 market for Cal 2021 and has unlimited ability to store oil. Revenue is theoretically locked in at $50/month or $600 for the year, and risk is $0. In late 2020, the first half 2021 market for swaps plummets to $10, while the second half swaps stay at $50. The producer decides to store 100% of production for the first half of 2021 and sell it all ratably during the second half 2021. Done properly, the producer can still be 100% hedged, and be guaranteed a revenue that is $240 higher if the following steps are adhered to:
- Stores all production 1H 2021
- Buy back 1 BBL/month 1H 2021 $50 swaps for $10; earn $40 for 6 months; collect $240 of derivative revenue
- Concurrently, Sell 1 BBL/month of additional 2H 2021 swaps for $50 to stay 100% hedged in the months when production is now intended to be sold
- Sell physical volumes out of storage along with originally planned 2H flowing production for $50 in 2H 2021; earn $600.
- No matter where prices realize, total revenue will be $840, or $240 more than the pre-optimization opportunity. Risk = $0
Conversely, if the producer stores all production in 1H 2021 and buys back $50 swaps without selling additional financial swap volumes in 2H 2021, only $540 of locked in revenue is guaranteed if physical prices actualize at $0 in 2H 2021. Downside risk is $300 compared to $0 in the hedged example. However, a producer choosing not to concurrently sell more 2H 2021 swaps effectively has only 50% of production hedged. As a result, the producer does have exposure to rising prices. If this were the chosen path the producer did not need storage assets or any other expensive contractual rights to get exposure to rising prices—they could have simply bought back $50 swaps for $10, curtailed production (or not), and waited for prices to rise.
There are numerous examples of hedging physical sales “optimization” decisions with financial derivatives in ways that increase risk. While they are usually much more complex than the over-simplified example above, the punch-line is always the same: a failure to properly adjust a derivative hedge book increases risk, and can result in lower revenue than expected had the “right” physical sales decision not been made in the first place.
Some common examples where special attention needs to be paid to the derivative portfolio, in order to avoid unintentionally adding risk, are as follows:
- Slowing down completions and tie-ins without buying back near-term/selling deferred derivatives
- Failing to re-orient a forward basis portfolio when transportation spreads move in and out of the money
- Increasing first-of-the-month physical natural gas sales during bid-week to take advantage of high prices without concurrently selling NYMEX and Basis Swaps (or vice-versa)
- Failing to adjust near-term and forward Natural Gas and NGL hedges when ethane rejection and recovery economics change
- Storing oil or gas without selling deferred swaps
By changing the timing, location, and product mix of physical sales as allowed under contractual agreements, producers can be guaranteed to enhance revenue over time—but only if derivative hedge books are adjusted accordingly each time a change in physical sales occurs. In addition, routinely updating economic optimization models (production, transportation, ethane rejection, storage, etc.), and diligently adjusting the forward hedge book to match exposure generated by those models, extracts the maximum expected revenue from a producer’s portfolio of assets. Importantly, this process also keeps overall risk at the same target level, or in other words, it optimizes revenue for a given amount of risk.
Matt has 15 years of experience trading natural gas and crude oil derivatives at energy hedge funds, investment banks, and energy merchants. Matt’s primary responsibilities include evaluating market risk, derivative hedging, and physical marketing of both natural gas and crude oil. Prior to Joining Mobius, Matt was a portfolio manager for Goldfinch Capital and Sandridge Capital in Houston, Texas. He also has experience as a natural gas option trader at Merrill Lynch and Koch Industries, and as an auditor at Price Waterhouse. Matt holds an MBA from the University of Texas, is a CFA charterholder, and a Certified Public Accountant.