Boom, Bust, and Hedges - Part 2

This month, I’m taking a snapshot of where the industry stands financially. First was my take on how we arrived at where we are today, with an oversupply of both hydrocarbons and investment cash. Today I’m looking at why the price collapse was so painful, specifically why many companies did not take advantage of $100 oil prices to hedge their production.

Part 2. Why didn’t everyone hedge everything?

It’s abundantly clear, at least in hindsight, that hedging as much production as possible was a great idea during the first wave of investment in shale development. $100 oil and $4 gas made for stellar IRRs for a lot of producers. Some did hedge large portions of production for as long as possible, which looks great now and saved the financial bacon of many shops. Others did a lot less and face serious struggles now. Again through our hindsight glasses, this looks like the easiest choice ever. So why didn’t every shale producer lock in $100 oil? Several reasons:

Source: Bloomberg

Source: Bloomberg

First, it wasn’t really $100. The crude oil curve during much of the shale boom was steeply backwardated.  If you had been so lucky as to trade at the very peak of the market, on September 6th, 2013, the October WTI crude futures contract settled at $110.53. But locking in 5 years from Jan 2014 to December 2018 on the forward strip would’ve netted you an average price of $87.78 per barrel. For reference, here’s what the forward curve looked like back then (in blue), verus today’s forward curve (in orange), 

ot only that, but once differentials and transportation  expenses are accounted for, wellhead prices can be significantly less than the benchmark contracts. Back in 2013, Bakken crude at Clearbrook ran about $5 behind the WTI  benchmark, meaning that wellhead prices in North Dakota were anywhere from $7-$10 less than Cushing. So even at the peak of the market, the best hedge would’ve created a netback somewhere around $80 per barrel.

Second, cost. There are several vehicles popularly used to hedge oil and gas production, each of which comes with its own cost. Different ways of hedging have different expenses:

Locking in a floor price with options will protect from low prices, but will also reduce the effective price of every barrel sold by the price of the option. For instance, if you had paid a $4 premium to buy a put with a strike price of $90, every barrel you sell into the market will be $4 less competitive than the ones coming from your neighbor’s acreage who didn’t have this expense. Lack of liquidity on these options, especially farther along the curve where time value is high, can further increase prices until they become prohibitive.

Locking in a floor price with futures will negate the premium expense, but it can open up the possibility of margin calls. Meaning, if if a producer sells futures contracts and prices rise significantly (making your futures underwater), the company would be required to post additional cash to the exchange account to ensure they will make good on obligations at settlement. This tie-up of cash may limit the ability to develop acreage and grow reserves. Given that it’s also unpredictable which way futures prices will go and therefore whether or not cash will be needed for margin, it can make it more challenging to plan capital budgets.

Option collars can somewhat mitigate both of these issues, and have been extremely popular in the past. In this situation, the premium paid by the producer for the put option (floor) can be partially or fully offset by selling a call option at a higher level, locking in a ceiling price for the production. The rub here is that the higher the floor locked in, the lower the ceiling that must be accepted in order for the costs to be equivalent. That often means giving up a lot of upside, or paying more out of pocket for the options. Not only that, but the call-writing (ceiling) leg of the trade can expose the producer to margin calls if prices rise significantly. Once again the loss of cash from operations into the margin account can present a real problem for ongoing expenses as well as capital budgeting.

Many E&Ps with reserve-based lending mitigate these margin requirements with hedging executed through their bank group, or by executing an additional agreement that allows the hedging service provider to use the producing asset base as collateral for margin.

Other, more complex hedging strategies such as 3-way collars claim to solve some or all of these issues, but as with every situation in finance, we won’t ever arrive at the proverbial “free lunch”. Once a basic level of protection is purchased, more trades always and inevitably mean either A) more expense, B) more risk, or C) both. Not to mention that they muddy the waters and make it difficult for management to track how moves in the market affect the business, and therefore make effective decisions.

Third, Lost opportunity. Giving away upside is always difficult in any business, especially one whose heroes are those who took risks and hit it big. No one likes to be in a position of effectively selling $70 oil because of hedges when the prevailing market is $100, no matter what the IRR is at $70 per barrel.

Fourth, risk perception and financing. Lastly, not every CEO or CFO of an oil and gas company had full discretion as to how much production to hedge and when. Banks financing the assets often if not always have covenants that require a certain percentage of hedges, and limit the total amount hedged to lessen exposure to margin calls or the potential for over-hedging if production falls. On the other hand, funds backing some companies were in fact seeking commodity price exposure by investing in oil and gas assets, and therefore were not interested in eliminating that exposure via hedging.

So as it turns out, the decision isn’t always so easy. How then, does anyone decide at all? We’ll explore in part 3.

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