January 31, 2018 | Charles Nevle
In this issue of Get the Point, the first of a two-part series, we delve into the trends in the relationship between wellhead and dry gas volumes focusing on Texas, the biggest regional driver in production trend changes. In Part 2, we will drill down into the implications of those trends on the implied dry production from the all-important Permian basin, and, ultimately, on the impact on pipeline constraints on takeaway capacity from the Permian.
Dry gas production is clearly growing in the Lower 48, and PointLogic expects this growth to continue in 2018. Dry production is a derivative of wellhead production, gas produced at the wellhead (otherwise known as gross withdrawals). The difference between dry gas and wellhead can be thought of in broad terms as ‘shrink,’ or production losses. The volume of these losses, where they are occurring and the dynamic of this over time are extremely important to understanding how much dry gas is being produced and where.
First, let’s get some definitions and methodology out of the way. The Energy Information Agency (EIA) defines wellhead (gross withdrawals) and dry production as follows:
Gross Withdrawals: Full well-stream volume, including all natural gas plant liquids and all nonhydrocarbon gases, but excluding lease condensate. Also includes amounts delivered as royalty payments or consumed in field operations.
Dry Production: The process of producing consumer-grade natural gas. Natural gas withdrawn from reservoirs is reduced by volumes used at the production (lease) site and by processing losses. Volumes used at the production site include (1) the volume returned to reservoirs in cycling, repressuring of oil reservoirs, and conservation operations; and (2) gas vented and flared. Processing losses include (1) nonhydrocarbon gases (e.g., water vapor, carbon dioxide, helium, hydrogen sulfide, and nitrogen) removed from the gas stream; and (2) gas converted to liquid form, such as lease condensate and plant liquids. Volumes of dry gas withdrawn from gas storage reservoirs are not considered part of production. Dry natural gas production equals marketed production less extraction loss.
From a practical perspective, wellhead production, or gross withdrawals, is gas produced at the wellhead. It is what is reported by each state agency as ‘gas production.’ It is what comes out of the ground.
Dry production is what hits the pipeline grid after processing. It is the net of any gas used at the production site and net of any natural gas liquids (NGLs) stripped out at a processing plant. It is, essentially, what hits the pipeline grid ready to be delivered to customers.
What we are going to focus on in this two-part series is the difference between wellhead and dry production. For purposes of this discussion, we will refer to this difference as ‘shrink’. In our analysis below we will be looking at state level detail only through December 2016, the latest date that the EIA has state level dry production available. While PointLogic reports dry production by state through current day, our analysis in Part 1 of this series will focus on EIA available data, and in Part 2 we will expand into our estimates of dry production through the current period.
No big surprises in the chart above – as production has grown, so has shrink. The interesting story jumps out when this data is broken down by state. Eight states make up over 90% of Lower 48 shrink volume: Colorado, Louisiana, New Mexico, Oklahoma, North Dakota, Texas, West Virginia and Wyoming. By contrast, these eight states make up just over 60% of dry production.
Clearly, Texas stands alone in terms of the overall volume of shrink as well as the growth trajectory of shrink over the past few years. Using EIA data, we can dive deeper into what makes up this shrink in Texas. Remember, that shrink is comprised of several different components, including gas used for repressuring, gas flared, non-hydrocarbon gasses removed and NGLs removed in processing.
There is a lot of good information in the above table. First, let’s focus on the components of Gross Withdrawals at the top of the table. Overall production has grown in Texas, but it has not been dramatic; however, the shift of components of production has certainly been dramatic.
Production from gas wells in Texas has declined significantly since 2010, while production from shale and oil wells has risen. In fact, production from gas wells made up nearly 60% of overall Texas production in 2010 and fell to under 20% by 2016, while oil and shale gas production rose from 42% to 81% over the same time period.
Looking at the components of shrink, the most dramatic change has been the increase in the volume and percent makeup of NGL production of the overall shrink, rising from 5.7% in 2010 to 10.2% in 2016. Clearly, Texas gas production is getting wetter as the makeup of Texas production has shifted away from conventional gas-directed drilling to shale- and oil-directed drilling. In other words, Texas production has become ‘wetter’.
Let’s look deeper. PointLogic breaks Lower48 production into 92 separate Producing Areas—a collection of counties that closely represent a geological basin or play. Texas is home to 17 of these Producing Areas. Breaking production into this granularity allows us to shed light on important trends taking place within the state that will help us understand the implications of a state becoming wetter with a higher shrink rate.
In the chart above of Texas wellhead production, we’ve combined our 17 Producing Areas into six areas to provide a clearer view of the trends in the state. It is obvious that although overall state production is not growing dramatically, production from the Eagle Ford and Permian has grown significantly since 2010 while the rest of the state has been in decline.
Given what we know from the discussion earlier, Texas production has been getting wetter and overall shrink in Texas has been growing. Moreover, combined with the trends of growth in Eagle Ford and Permian production over the same time period, it stands to reason that growth in the Permian and Eagle Ford could be the cause for the growing shrink in Texas.
While this may seem obvious, what is not so obvious is that the general market consensus for ‘shrink’ in the Permian is about 15%. Given that average shrink in Texas was approaching 25% by the end of 2016 and on an upward trajectory, it seems that 15% could be too low of a shrink rate to assume for the Permian--in fact, it could be way too low. In Part 2 of this series we will discuss what PointLogic believes the appropriate shrink factor to apply to Permian production should be and the implications of this shrink on dry production from the basin and by extension on the volume of available pipeline capacity existing from the Permian.