Module 2 - Production

Topics in Module 2 include:

Module 2.1a — Production Economics: Economics, Type Curves and Other Variables

Presenter: David Braziel

We could be at the precipice of an inflection point for the energy industry. U.S. producers have shown a lot of capital discipline — not responding as exuberantly as they may have in eras past to capture the high energy prices seen today — something we’ve rarely seen since the start of the Shale Revolution. But that may be about to change, and some of the majors have discussed an increase in drilling activity.

This module focuses on the drivers of oil and gas production, starting with where things stand today. We discuss the basics of conventional and unconventional production,  look at the factors that led us to this stage of the game, then examine how producers behave in different price environments. From there, we get into RBN’s approach to production forecasting, which starts with price scenarios, then models what those scenarios mean for producer investment returns and, finally, how all that gets tied to production.

Module 2.1b — Production Economics Model

Presenter: David Braziel

To understand a producer’s economics is to understand the value of the commodities yielded by the drill bit versus the costs to bring them to market. Continuing the example of the Haynesville Shale introduced in Module 2.1a, the Production Economics Model provides the framework for how RBN analyzes well performance. We're going to use what we know about the well — the drilling and completion costs, the operating expenses, the production taxes, royalty rates, initial production rates, decline curves, NGL content, and commodity netbacks — to calculate the producers’ internal rate of return and their breakeven price on an average well. We expand on the example of a Haynesville gas well by looking at a well from the Permian’s Delaware basin yielding substantial volumes of oil, gas and NGLs.

Module 2.2a — Production Forecasting: Concepts and Methodologies

Presenter: David Braziel

In the past, rig counts have been used as a benchmark for how producer activity behaves over time in response to different market conditions. As prices rise and fall, rig counts generally follow those same trends, but the relationship has been decoupled following COVID-19’s market impacts. What does that mean for production volumes going forward?

To answer that question, several methodologies exist. RBN utilizes the ladder forecast method, which is calculated by multiplying a forecast well count by an assumed type-curve. The resulting forecast production volume is combined with historical production and layered on top of a forecast of existing production as it naturally declines. From there, forecasts can be aggregated up to the county, regional or nationwide level. The method is straightforward and flexible, allowing us to pivot quickly to analyze and understand how changes to the production equation will affect future supplies.

Module 2.2b — Production Forecast

Presenter: Jeremy Meier

Depending on the need for specificity, RBN models production on a national, regional, sub-regional and even individual county scale. In this example, we forecast crude oil and associated gas production in Loving County in Texas’s Delaware Basin in the Permian. The model is laid out in three sections. For the first two, we analyze historical production and its rate of decline. To that, we add in our assumption for future drilling plans, which, along with an assumed type curve, is used to build up a production forecast using the ladder method.

Module 2.3 — Oil, Gas and NGL Production Forecasts

Presenter: Jeremy Meier

For the last decade, North America’s produced volumes of oil, gas and NGLs have surged except for the mid-decade hiccup brought about by low commodity prices. Now  COVID-19’s demand-crippling impacts have pressured prices and hammered production volumes. How much and Putting together a production forecast involves more than historical pricing and production data, it must also make sense within the broader context of the market. Perhaps the most important factor today is the midstream conundrum mentioned in Module 1.1. If midstreamers can’t secure financing for additional takeaway capacity needed to get supplies to market, what does it mean for total U.S. production? The drill-bit hydrocarbon markets are interlinked, and supply-and-demand dynamics that determine prices are not isolated. It's a delicate balancing act. In this module, we’ll look at RBN’s forecasts for crude oil, gas, and NGLs.