This year’s School of Energy dives into the interconnected world of North American energy markets — markets that have been evolving rapidly, from production booms in the U.S. and Canada to shifting infrastructure and cross-border flows. This module serves as an introduction to the full conference, which explores the current landscape and the future of North American natural gas, NGLs, oil and refined product markets.
North America is an integrated energy market that stretches from Texas and Florida to the mountains of British Columbia and Canada’s industrial heartland in Ontario/Quebec — a cross-border network so deeply connected that it functions as one massive, interdependent system for drillbit hydrocarbons. We’re two countries and one market, but one that is undergoing major shifts and challenges, driven not only by changing supply/demand dynamics and evolving infrastructure within the market itself, but also by powerful external forces, including regulatory policies and political pressures. In our opening module, we discuss why it’s more important than ever to talk about what’s going on and how that relationship will continue to evolve.
Understanding energy markets is not just about natural gas, crude oil, and NGLs — it’s about how the three commodity groups are linked. The interdependencies of the three commodities have never been more important than they are now. In this module, we discuss the fundamentals of commodities, from pricing and trading hubs to basic supply and demand. This module also focuses on NGL fundamentals, NGL products, and how the market has changed over the years.
The Domino Effect is the framework that RBN uses to make sense of the changes in the energy market caused by the Shale Revolution. In the early 2000s, natural gas production in the U.S. was declining until George Mitchell cracked the code on shale drilling. That first domino started a chain of events that has led the U.S. to become a leader in energy production. In this module, we go over the history of the Domino Effect and discuss the dominoes that are still falling today.
NGLs can be mind-numbingly complex and blindingly simple at the same time, impacting everything from production economics to infrastructure constraints. NGLs and the factors influencing them also provide great insights into what’s happening with natural gas and crude oil. The section provides an overview of NGL fundamentals, including U.S. and Canadian production, demand and exports.
What makes RBN’s School of Energy unique is that attendees are taken beyond the conceptual level down into the nitty-gritty of modeling. Rather than trying to keep our methods secret, we teach you how to use our models with hands-on instruction and explain how we use them for market analysis. This section serves as an introduction to the models that are woven throughout the course. Our goal is to show how models are useful and help you connect the dots to specific business problems.
One metric that we keep our thumb on at RBN is propane’s relationship to crude. Propane traders tend to focus a lot on the relative price of propane; that is, propane as a percentage of crude oil, rather than just the outright price. In this introductory model, we introduce the propane-to-crude ratio and discuss how RBN lays out our model spreadsheets, as well as some Excel shortcuts.
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
This introduction to production economics explores a typical Haynesville well, focusing on factors like drilling and completion costs, production rates, and commodity prices. It highlights the importance of metrics such as internal rate of return (IRR) and breakeven prices in evaluating the profitability of wells in different basins, or different well tiers within a basin. These benchmarks are pivotal in guiding producers’ drilling activity, reflecting current trends and economic conditions.
To understand the economics that drive producers’ decision making, we must understand the cost to drill a well and the value returned by the commodities it produces. Continuing the example of the Haynesville well introduced in Module 2.2, the Production Economics Model provides the framework for how RBN analyzes well performance. The model takes inputs such as drilling-and-completion costs, operating expenses, production taxes, royalty rates, type curves, NGL content, and commodity netbacks, and calculates the internal rate of return and breakeven price on an average well. A Permian well example is also considered to demonstrate the impact of associated gas and NGL production on well economics.
Drilling decisions are becoming more complex, making it increasingly difficult to predict how producers will respond in a given situation. Economics and an understanding of the commodity mix are important, but they won’t tell you the whole story. This overview of Producer Considerations will touch on several key factors, including the relationship between prices and rig activity, the impact of consolidation and optimization, drilling and completion strategies, and the importance of available inventory and reserves.
In this model, we build a forecast of crude oil and associated gas production using Loving County in the Permian Basin as an example. The forecast consists of three components: historical production, the decline of volumes from existing wells, and expected production from new wells. To build the forecast, initial production (IP) rates and decline curves are used as parameters to determine how future wells will perform over time. The ladder method is then used in conjunction with the well count to determine the total forecast. We walk through several examples to illustrate how changes to input parameters affect the total forecast.
There’s a lot of mixed signals right now in U.S. and Canadian oil and gas production. Rig activity has been trending down recently, but the most recent numbers for oil and gas production are at or near record levels. How does it all fit together? In this module, we’ll examine the current state of production, RBN’s forecast for where production is headed in the next five years, and a brief update on the current developments in the major producing basins.
Whether you want to focus on crude oil, natural gas or NGLs, to understand how U.S. and Canadian energy markets behave, it is imperative to understand the fundamentals of the crude oil market. To do this you need to understand what’s happening with production, imports, exports, refinery demand, storage, pricing, and how they all interact with each other. This section covers the fundamentals of the energy industry’s most popular commodity, crude oil, so you can build a better understanding of how it drives the decisions making process for all other energy commodities.
The price of Domestic Sweet (DSW) crude oil at Cushing, OK, represents a lot more than just a price. It’s a barometer of not only what was going on with the world economy at the time, but what’s going to happen in the future. After all, it is the price of the prompt-month futures contract. If you are trading, you’ve got to have a really solid understanding of what the number is — and more importantly, what it is not. Notably, DSW is not synonymous with West Texas Intermediate (WTI), which typically sells at a premium to the NYMEX benchmark. Not a lot of people know how these mechanics really work. This module addresses those issues, along with other pricing mechanisms that are used for physical crude oil transactions in North America and how to make sense of what those prices can tell us about the broader supply/demand picture in oil markets.
All crude oils are not created equally. Some are light (high API gravity) and some are heavy (low API gravity). Some are sweet (low sulfur content) and others are sour (high sulfur content). But that does not begin to scratch the surface of all the factors that refiners must consider regarding crude quality. Critically important is the potential mix of end products that various crude grades may yield. This module explains those crude characteristics and describes the regional differences in the qualities of crudes produced and refined. We’ll also look at the U.S. surplus of light oil that can attain a higher value in export markets and strong U.S. demand for medium and heavy grades, especially from Canada.
Crude oil exports are nothing new for Western Canada, but until recently nearly all of the export volumes moved by pipeline to one place — the U.S. Then came May 2024, when the 590-Mb/d Trans Mountain Pipeline Expansion from Edmonton to Vancouver’s Westridge docks came into service. It almost immediately did what it promised — narrowing the discounts caused by pipeline bottlenecks and apportionment. In this section, we’ll take an overall look at the Canadian crude market, including the physical and commercial value chains, refinery demand, crude quality, transportation and pricing, along with some key definitions.
To understand the fundamentals of refining, we need to understand what a refinery does — they’re not that much different than moonshiners! This includes a brief overview of several key refinery units and why they’re important. This includes crude oil distillation, hydrotreating, naphtha reforming, cracking, and coking units. We’ll also do a quick review of the history and current state of the North American refining sector.
Most refineries focus on the production of three key refined products — gasoline, diesel and jet fuel. As a result, these are often referred to as the “Big 3” refined products. Most of global crude oil demand is ultimately driven by the demand for these refined products. (Your car wouldn’t get very far on raw crude oil!) We’ll look at global and regional supply and demand for these products and how those trends will affect the U.S. and Canadian refining sectors going forward.
The crack spread is a market indicator widely used in the oil industry and serves as a good indicator of refinery profitability. It measures the difference between the cost of crude oil and the revenue generated from selling the refined products. The crack spread is a helpful rule of thumb and market indicator, but it's a blunt instrument that relies on weighted prices for crude, gasoline and diesel. This module also provides a brief overview of RINs and how they impact the headline crack spread but have little impact on refinery profitability.
This module, a follow-up to Module 4.3, examines the yield model, which provides more nuanced insights into which prices are affecting margins for a specific refinery setup. The model takes into account a representative yield of products that a sophisticated refinery might produce from various grades of crude under different configurations. It then calculates the refinery margin based on those weighted values, providing a much more comprehensive analysis.
To understand how gas is bought and sold, you have to start with the basics. This module, which kicks off our section on natural gas markets, will walk you through all the important fundamentals, including how natural gas is measured and treated, the major production basins in the U.S. and Canada, transportation options, the different demand sectors (Residential/Commercial, Power/Industrial and net exports), the critical role of storage, and natural gas pricing.
U.S. natural gas production is dominated by three regions — the Marcellus/Utica in Appalachia, the Permian Basin in West Texas and New Mexico, and the Haynesville in East Texas and Louisiana. This section looks at how production has changed over the years, how takeaway capacity (and the lack of it) can impact supply and demand, and our outlook for future production.
LNG export capacity in North America is more than 13 Bcf/d and growing with new projects under construction and nearing completion. This module discusses how North American LNG interacts with the global gas market as well as how growing LNG feedgas demand in the U.S. Gulf Coast impacts the U.S. Gas markets. The discussion will include some LNG fundamentals, project development, and Gulf Coast regional flows and infrastructure. We’ll also take a look at the new LNG projects on the horizon and what that means for the U.S. and global LNG markets.
To get natural gas to its end-use markets, new and existing pipelines are used to move those volumes around. How the value of the natural gas changes by location is heavily dependent on the cost for moving that gas. For interstate gas pipelines, those costs are subject to a pipeline’s regulated tariff, which is based on a complex set of regulations promulgated over decades of FERC (Federal Energy Regulatory Commission) oversight. Meanwhile, whether enough pipeline capacity even exists depends on approvals by that same Commission. This section describes the state of rate-setting under FERC rules and of the policies and rules for approving much-needed new gas pipeline projects. It also explains why, for intrastate pipelines, such as those out of the Permian basin in Texas, regulatory life is a lot simpler.
The premise of this model is that constraints exist that make your natural gas worth a lot more at the other end of a possible pipeline than it is where it’s produced. This model lets you get a rough estimate of what a new pipeline would cost to reach a more lucrative market, and what its transportation rate might look like. Although the estimate is only approximate, it can help you decide whether the gain in value (the “basis differential”) the gas can achieve by getting to the other end of the hypothetical pipeline is less or more than what transportation would cost — in other words, whether you should spend more time and attention on the subject. We walk through how to do this calculation at a very high, quick level, to be able to know how to proceed when the new pipeline is just an idea. The model is hands-on and simple.
The availability of pipeline flow data makes the North American natural gas market uniquely transparent, enabling analysts to grasp with reasonable accuracy how regional and national supply and demand stack up on a daily basis. If you understand how to wrangle and finesse this robust data source, you can track supply, demand and how gas moves across the country, and ultimately, what that all means for prices. This module will get you started with the basics of pipeline flow analysis.
Canadian natural gas plays an important, and sometimes underappreciated, role in the North American market. Canada is one of the largest producers of natural gas in the world, with about half of its production being exported to the U.S. and the rest consumed domestically. Starting this year, that export relationship is going to change as Canada begins to export natural gas in the form of LNG, creating an unprecedented shift in the U.S./Canadian gas relationship. Moreover, Canada’s internal gas consumption is also set to increase, possibly further impacting exports to the U.S. This module places Canada in the North American and global gas context and considers the developments that will be transitioning the Canadian gas market to a more globally connected gas player.
Trans Mountain Chief Financial Officer Todd Stack sat down with RBN’s Martin King for a fireside chat about the early success of the Trans Mountain Expansion Project (TMX), its impact on Western Canadian crude flows, and the plans underway to boost the pipeline’s capacity, including drag-reducing agents (DRAs), additional compression and upgrades to the Westridge export docks near Vancouver.
NGL production growth has outpaced both crude oil and natural gas. While the crude market has been subject to lower production growth, NGL production has been consistently increasing. The role of NGLs in the energy market is evolving, driven by NGLs’ diverse product mix and demand from the petrochemical markets, both here and abroad. This module discusses development in NGL production, exports, and market dynamics.
The job of removing NGLs from the natural gas stream is called natural gas processing. A natural gas processing plant is, therefore, the physical linkage between gas and NGL markets. With rich natural gas production growing again in places like the Permian and the prices for natural gas and NGLs dwindling near annual lows, the interplay between those commodities will have major implications from upstream to downstream – and particularly for the processors who work at the fulcrum of gas and NGL markets. To simplify those relationships, we use RBN’s frac spread model, which calculates the difference between the price of natural gas and the price of NGLs on a BTU basis ($/MMBtu). Simply put, the greater the spread, the more favorable the market is for natural gas processors and NGL production. The spread is a yardstick measure of the general financial health of the gas processing sector.
To compute the economics of gas processing at the level of an individual plant or at the regional level, we need to factor in some specific types of data, like the liquids content of gas, the BTU of inlet gas, the extraction efficiency of a plant, the cost of getting a plant’s production to market, and the value of that market relative to the industry benchmarks at Mont Belvieu. To understand these factors and to really grasp the current state of the natural gas processing marketplace, we need to move beyond the frac spread to something much more detailed and representative of the processing value chain. We’re going to walk you through each section of our gas processing model, using it to look at a 200 MMcf/d gas processing plant in the Eagle Ford. We can use the model to find out if processing the gas and extracting the NGLs will yield a positive gross margin, not counting things like cost of capital and plant expenses. This model is focused on the gas that comes in and then the gas and NGLs that go out.
A continuation of Module 6.1, we walk through RBN’s ethane rejection model, which we use to demonstrate how the economics of ethane rejection work in different regions of the country. The most significant variables between regions are the local price of gas and the transportation cost from the processing plant to the steam cracker where it will get used. In our model, that’s the Gulf Coast. We’ll use the model to look at four basins: Permian, Appalachia, Willison/Bakken, and the Rockies.
Western Canadian production of NGLs has increased steadily over the past decade, with current volumes now up about 50% from 2016. Most Y-grade, mixture of NGLs, is collected via pipelines that ship into the Edmonton/Fort Saskatchewan corridor, while additional volumes are railed or trucked for delivery. There is also diluent for the oil sands and the C5+ stream from gas processing plants, along with ethane, propane and butane. In this module, we’ll walk you through the basics of production, demand and transportation of Canadian NGLs.
NGL markets have been in a constant state of flux, with U.S. ethane, propane and butane all having to find new markets to balance the onslaught of rising production. As a result, exports have emerged as the most important demand segment today. Petrochemicals production remains the largest source of demand for ethane and also relies on other NGLs, so an understanding of petrochemical economics is essential to get a full picture of what’s happening in the market.
There are more than 50 steam crackers in the U.S. that “crack” a variety of feedstocks (ethane, propane, butane, naphtha, gas oil) to produce ethylene as well as smaller volumes of propylene and other useful products. More than half of the plants are designed to crack specific feedstocks (mostly ethane or ethane and propane), while the others can switch between several different feedstocks to maximize their profitability. How much money they make will be a function of feedstock prices and the quantity required to produce a pound of ethylene in addition to the other products yielded in the steam-cracking process. By knowing these estimated margins, it is possible to project industry trends such as which feedstock will be preferred in a given price environment, which will, in turn, have an impact on both upstream and downstream supply and demand markets. We’ll walk you through each section in the RBN Petrochemical (Steam Cracker) model step-by-step, spending most of our time on petrochemical feedstock tables. The model takes the prices that are input into it to calculate margins for a representative Gulf Coast steam cracker based on the yields of various petrochemical products and co-products.
There are major changes coming to the North American energy markets, and the wave you catch will depend on what you believe is going to happen in the increasingly interlinked crude oil, natural gas and NGL markets — including prices, regional infrastructure developments and producer sentiment. No one in this business has ever experienced the kind of transition that we’re going to see in the coming years. And last year? That’s ancient history. Most of the market will miss the major turns, and some players may not survive this cycle. But for those who know what to look for and where, fortunes can and will be made.
