Natural Gas Reserve Value: Location, Location, Location

As prices for natural gas and crude oil continue to lie in the gutter, operators across the country search for cost efficiency by reducing drilling budgets and practicing “high-grading”, or selectively drilling the locations they believe will return the best bang for their 2015 drilling buck. Denver’s BTU Analytics has covered this phenomenon well in recent months.  In the past when liquids and condensate captured a significant premium per BTU delivered, this selection process mostly meant heading to the locations with the ‘wettest’ gas, that is, the areas that brought the most liquid to the surface with the gas molecules. Since this is not the case anymore [see BTU uplift], the process is somewhat more complex.

In this article, I will focus on the gas portion of production and reserves. Every investor presentation focuses heavily on one variable in the revenue equation: how much gas can we produce? Leased acreage, IP rates, type curves and EUR all get detailed coverage. Equally important, however, is the projected value of the product. Simple right? “How much will someone pay for it?” has an equal weight in revenue calculation to “How much can I produce?”

The reason this calculation has become more interesting of late is because of the continued price decline in benchmark gas without a corresponding decrease in locational differentials. I’ll explain further.

In order to clarify the concept, let’s visit the crude oil arena briefly. To say the least, locational differentials can be volatile. Back when Cushing was fetching 3 digits, Bakken light crude sold for discounts up to $20+ behind the benchmark. West Texas differentials have swung from $20 discounts back to $10 or less.  In severe cases, these discounts can mean as much as 15-20% of the value of the product brought to the surface. No small matter as margins continue to thin and producers feel the pain of less than stellar returns. Lately, however, as infrastructure has improved,  the differentials across basins (with the exception of grade problems, such as extra light Utica and Eagle Ford condensates) have begun to equalize.

But in the natural gas world? Even as a producer brings a pipeline-quality dry gas to the surface, the value of that gas is being impacted more and more significantly by its location. For example, a Utica producer such as Eclipse Resources or Rice Energy currently faces a discount this summer of around $0.96 (Dominion South pricing) to the already low Henry Hub price of $2.83. This represents a hefty 34% reduction in value from the benchmark! (and doesn’t factor in gathering and processing fees). Future basis does not project much of an improvement, with the remainder of 2015 and all of 2016 trading at about a 32% discount, and 2017 at 27%. (Dominion South and CME Henry Hub)

Compare this to a gas producer with a significant portion of their reserves in the Permian basin such as Occidental Petroleum or Apache Corp. Each Mcf of gas produced will fetch a discount this summer of about $0.23 to Henry, representing an 8% discount. The remainder of 2015 looks about the same at 8%, and 2016 and 2017 are about 6% and 4% respectively. The tightening in the forward market in this case likely represents the expected advent of significantly increased exports to Mexico via several pipeline projects by that time.

It’s true that many producers in the Marcellus and Utica have been extremely aware of this issue and have made efforts to be proactive. Many have signed up for firm transportation commitments in an attempt to improve this ratio. Unfortunately the commitments provide only marginal uplift because of their own associated cost ($0.50-0.80 per MMBtu), and the commitments themselves represent a significant cost long after the pipeline infrastructure has been completed and basis differentials regulated. [See Pipeline Transportation: No Free Ride].

The bottom line? Assuming similar drilling and completions costs over the next 2-3 years across basins, every dollar invested by Utica producers in bringing an Mcf of gas to the surface will have roughly 25% less value than the same dollar invested by a Permian operator. In an already difficult environment with heavy debt loads, high royalty expenses, and low overall returns, that is a handicap that small operators can hardly afford.

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