What do the dynamics of the gas-directed rig count say about natural gas economics?
Arguably, the inflection point in the rig count – from contraction to expansion – should correspond to the gas futures level at which E&P companies believe it would be economical to expand their drilling programs. Indeed, once futures prices cross above certain threshold, operators have the opportunity to layer in additional hedges to lock in the minimum return they require on incremental drilling capital. Acceleration in development activity should follow.
The “minimum required return” concept has been at the center of a heated debate with two prevailing polar view points.
One school of thought supports the “$5/MMBtu thesis” that the E&P industry is opportunity-rich but capital-short and will therefore direct scarce dollars to highest return projects, i.e. oil and “combo” plays such as the Bakken, Eagle Ford and Mississippian Lime, at the expense of drilling in lower-yielding dry gas plays. Consequently, before dry gas drilling activity can resume, natural gas prices would need to recover to substantially higher levels than those currently seen, so that dry gas economics improve to match the “very attractive” returns on oilier opportunities. The implication is that the very steep natural production declines will very soon push returns in dry gas fields, even with relatively high cost of supply such as the Haynesville, to “very attractive” levels and the natural gas industry will enjoy a “multi-year up-cycle” of above-normal profitability. Several prominent industry CEOs, including Aubrey McLendon of Chesapeake and Michael Watford of Ultra Petroleum, have been vocal proponents of this theory. Natural gas prices above $5/MMBtu have often been quoted. Some sell-side analysts have effectively lent their support to this concept suggesting that marginal cost of supply in the US is in the $5-$6/MMBtu range.
The opposing school of thought argues that the growing volumes of associated gas from oil and “combo” plays as well as super-productive dry gas sweet spots, such as the Susquehanna Marcellus, will be sufficient to offset natural declines from dry gas shales with higher cost of supply. As a result, low natural gas prices (perhaps in the low- to mid-$3/MMBtu range on average) are here to stay to induce further drilling activity reduction in marginal plays so that lower-cost volumes can be accommodated. The implication? The industry and investors should brace themselves for a protracted cyclical trough characterized by depressed returns and poor profitability and expect only a moderate cyclical recovery once the structure of the industry supply is reconfigured and stable.
The recent step-up in natural gas drilling that was likely triggered by a $4/MMBtu price signal speaks against the “$5+/MMBtu thesis” which suggests that dry gas drilling will continue to contract unless substantially higher prices become available to operators. The apparent low operators’ price threshold, combined with virtually unlimited and flexible supply deliverability from gas shales, effectively puts a cap on producer stock valuations at implied gas price of $4/MMBtu or less (in real dollars). Investment strategies and stock valuation models built on the expectation of substantially higher price realizations in the future ($5+/MMBtu Nymex) will likely prove highly disappointing. Moreover, the increasing possibility of a “mild containment” scenario during the first half of 2013 – which may push natural gas prices to levels at which drilling activity is curtailed (likely high-$2/MMBtu marks) – puts defensive strategies of investing in the sector higher on the agenda.
via Natural Gas: Will 2013 Goldilocks Turn Into A Bear? – Seeking Alpha.