Increasingly BTU Analytics is getting asked to discuss the long term potential for natural gas markets. As a result, we have been sharpening our view on shifts in supply and demand fundamentals over the coming decades. While long term forecasting involves inherent risks, we believe quality forecasts should have detailed, transparent explanations of methodology and assumptions, in addition to a long-term price forecast. In this Energy Market Commentary we will discuss some of the forecast assumptions from BTU Analytics’ recently launched Long Term Gas Outlook. But to get to the punchline – long term gas – the end of shale or just the beginning? As is the answer to so many things… ‘it’s complicated’.
*BTU will be conducting a complimentary webinar covering our long term gas views on June 21. REGISTER HERE
In BTU Analytics’ view, the marginal tranche of production sets pricing, whether it was the Rockies from 2000 to 2007, or Appalachia from 2008 to 2016. If the U.S. is to meet growing demand levels, how long will the core acreage within shale plays last, and does the gas market eventually start to climb the cost curve as we burn through low level breakevens over time?
While exploration still occurs, BTU Analytics believes that we are at the end of the discovery phase, and that the best shale deposits within the Lower 48 have been found. Based on this assumption, the natural gas industry is transitioning from a period of massive growth in potential resources driven by unconventional shale development to a manufacturing model where resource depletion is a more meaningful factor. With this assumption in place, it is logical to assume that over the long term, the best locations in the cores of the best plays will be drilled first as the industry moves to secondary and tertiary acreage as shown in the illustrative chart below.
Based on assumed future demand levels, this will all result in an inventory ‘blow down’ over time. This does mean that eventually some out of favor plays such as the Barnett and Fayetteville, for example, will see increased activity in coming decades – it may just take a while as lower-breakeven acreage in Appalachia and Northern Louisiana will need to be depleted first.
The kicker is that remaining locations in the core of the shale plays represent a smaller proportion of the total number of locations, but proportionally more reserves. As an example, the chart below shows that while locations that breakeven under $3.00/MMbtu represent only 37% of remaining drillable locations, those same locations represent 65% of the region’s estimated reserves. This would imply once cores of the best plays are drilled out, lower IPs in remaining drillable locations require more wells drilled and the industry will accelerate the pace at which it moves through remaining breakeven inventory pushing prices levels higher. When and where this occurs will be key.