An introduction to School of Energy, including the program’s goals and agenda, faculty introductions, and guidance on using the course materials to get the most out of the program.
The North American energy market has evolved since the Shale Revolution. U.S. crude and natural gas production have surged, while the industry has shifted from aggressive growth toward capital discipline and free cash flow. The Permian has become the dominant production basin, driving infrastructure expansion and exports. With domestic demand largely saturated, U.S. energy markets are increasingly tied to global prices, geopolitics and supply disruptions. Understanding these fundamentals is essential for navigating volatility and an increasingly interconnected market.
What makes 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 Novi Labs 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 we lay out our model spreadsheets, as well as some Excel shortcuts.
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 market fundamentals and the five primary NGL products: propane, ethane, normal butane, isobutane and natural gasoline.
This presentation introduces energy fundamental analysis as the study of physical forces - supply, demand, logistics, storage and infrastructure - that drive commodity prices. It emphasizes the interconnectedness of crude oil, natural gas and NGL markets and the importance of translating data across commodities and regions. Rather than relying on unreliable outright price forecasts, analysts should focus on price differentials and how physical constraints affect them.
The Domino Effect is a framework for making sense of the changes in the energy market caused by the Shale Revolution, first described in Braziel’s book, “The Domino Effect”. 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.
This section 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 Novi Labs’ 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.
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 Novi Labs 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.
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 Novi Labs 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.
This presentation examines U.S. oil and gas production trends, producer economics and the evolution of Novi Labs’ forecasting approach. It highlights continued efficiency gains despite lower rig counts, while noting that drilling improvements are entering a period of diminishing returns. Basin-level economics vary widely, with the Permian remaining central to oil growth and gas development increasingly dependent on infrastructure. Rather than a sharp shale production peak, the outlook calls for a prolonged plateau and gradual decline, with infrastructure and consolidation shaping long-term supply potential.
Learn how to build an oil and gas production forecast using the “ladder method,” which combines declining output from existing wells with production from new drilling. The model incorporates historical production, natural decline, prices, rig counts, well completions and type curves, including Arps hyperbolic decline. An Excel-based example demonstrates how these inputs are linked to forecast production. The presentation also emphasizes reasonableness checks, including comparisons with historical results, gas-to-oil ratios and sensitivity cases for price and drilling assumptions.
This module provides a five-year U.S. oil, natural gas and NGL production outlook under low-, mid- and high-price scenarios. The mid-case projects modest oil growth to 14.6 MMb/d by 2031, driven almost entirely by the Permian, while gas production rises to 128 Bcf/d as Gulf Coast LNG demand expands. Basin dynamics vary, with the Haynesville positioned for growth and Appalachia constrained by takeaway capacity. A key risk is the link between oil drilling and associated gas, which could create future gas supply shortfalls if crude prices weaken.
An overview of the crude oil value chain, from upstream production and midstream transportation to refining and exports. The module explains how supply, demand and storage interact, highlighting the Permian’s role in U.S. production and the Gulf Coast’s importance for refining and storage. It also examines crude quality, trade flows and the impact of the Shale Revolution on U.S. logistics. Finally, it introduces key pricing benchmarks, including WTI and Brent, and explains how quality, location and infrastructure influence crude prices.
Learn the basics of crude oil quality metrics, focusing on API gravity (density) and sulfur content (sweet vs. sour). The module explains how these and other properties impact refiner yields, energy costs and market pricing, and why lighter, sweeter crudes command higher prices than heavier, sourer grades. Additionally, it details regional production trends, highlighting how shale growth shifted U.S. supply and refinery feedstocks toward lighter crude, whereas Western Canada predominantly produces heavy oil and bitumen requiring blending.
Explore the history, takeaway capacity and pricing dynamics of Permian crude oil. The module examines how sub-basin rig counts, improved drilling efficiencies and rising gas-to-oil ratios influence production growth. The presentation details the primary oil grades and traces how pipeline infrastructure expanded over time, but not always timely enough, leading to temporarily widening basis differentials. Finally, it categorizes long-haul pipeline flows across four key destination corridors and analyzes future capacity outlooks relative to projected production growth.
This module examines how the U.S. has become a major crude oil exporter, where those barrels originate, which Gulf Coast ports handle them, where they ultimately go and where export volumes are headed. Today U.S. crude exports are running at roughly 4.5 MMb/d, consisting primarily of light crude from the Permian and other shale plays. The presentation explains why the U.S. exports these barrels while continuing to import heavier crude better suited to many domestic refineries. It also explores why Corpus Christi has emerged as the dominant export center, handling more than half of U.S. crude exports, and how Permian pipeline constraints, available terminal capacity and marine transportation economics - particularly the ability to more efficiently load VLCCs at Ingleside - are shaping competition among the four major export areas: Corpus Christi, Houston, Beaumont and Louisiana.
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. We’ll look at global and regional supply and demand for these products and how those trends will affect the 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.
A comprehensive introduction to the North American natural gas market, the module covers industry fundamentals, including measurement units like BTUs and standard cubic feet, pipeline compression and transport, and the distinction between wet and dry gas. Additionally, it explores U.S. production streams, regional flow dynamics, trading hubs like Henry Hub, and basis pricing mechanics.
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.
Examine U.S. natural gas demand across residential, commercial, industrial, power and export markets. Because production is relatively steady while demand is highly seasonal, underground storage helps balance the market and optimize pipeline utilization. The outlook points to continued demand growth from LNG, data centers and electrification, potentially creating supply challenges and higher prices later in the decade. The module also emphasizes the volatility producers face and the tradeoff between hedging and exposure to market swings.
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.
Canada is a major producer and exporter of natural gas. Production is concentrated in Western Canada, with the Montney formation driving growth, while Alberta and Ontario account for much of domestic demand. Pipeline export constraints are increasing the importance of LNG projects on Canada’s west coast, with exports potentially exceeding 6 Bcf/d by 2033. Storage capacity is also expanding
It has been a tumultuous year for global gas and LNG, with the ongoing war in the Middle East continuing to depress global LNG supply and put upward pressure on prices. LNG export capacity is slowly increasing and has stalled out somewhat, but the stall won't last for long. We are at the tail end of an incredible wave of U.S. LNG development that began in 2025 and has seen nine projects across seven LNG terminals reach a final investment decision (FID). This section discusses how North American LNG interacts with the global gas market as well as how growing LNG feedgas demand along the U.S. Gulf Coast impacts 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.
Rising production and demand are reshaping regional markets. Our Arrow Model divides the Texas-Louisiana region into 11 interconnected areas to estimate pipeline flows, utilization and basis prices. Growing LNG feedgas demand, data centers and power generation are driving major infrastructure investments. The analysis expects Gulf Coast basis discounts to narrow as new pipelines and LNG facilities come online, with Houston Ship Channel prices moving closer to Henry Hub while Northeast Texas remains relatively cheaper.
Netbacks, net forwards and net spreads help analysts evaluate natural gas flow economics. By accounting for destination prices, supply costs and variable transportation expenses, these measures identify attractive markets, supply sources and pipeline routes. Examples from the Permian demonstrate how capacity constraints, infrastructure expansions, weather and regional price differences can reshape flow economics. The analysis is useful for evaluating day-to-day and seasonal flows, assessing potential pipeline projects and understanding how infrastructure changes can affect neighboring markets.
Natural gas is playing a growing role in meeting electricity demand from data centers, with another 6-8 Bcf/d of gas demand possible over the next five years, driven partly by “bring your own power” solutions and data centers’ need for highly reliable electricity. Key challenges include permitting, infrastructure and speed to market, while integrated companies can coordinate gas, generation and grid needs. The discussion also explores PJM capacity constraints and interconnection queues, noting that proposed projects may overstate actual future demand.
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, increasing production and demand from both exports and domestic demand. This module discusses development in NGL infrastructure, flows 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 Novi Labs’ 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.
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.
This module examines the outlook for U.S. NGL supply, domestic demand, exports and the new infrastructure projects needed to balance a rapidly growing market. U.S. recovered NGL production is projected to increase from 7.5 MMb/d in 2025 to 9.5 MMb/d by 2031, with the Permian accounting for about 75% of the growth. With domestic demand expected to be relatively flat, essentially all incremental supply will need to reach overseas markets. The presentation explores the resulting expansion of fractionation and Gulf Coast export capacity, including rapidly growing ethane exports supported by new flex terminals and a growing fleet of large ethane ships – the VLECs. It also examines continued growth in propane and LPG exports, changing international destinations, steam-cracker feedstock economics, and how these supply/demand trends are expected to influence NGL prices through the end of the decade.
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), 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 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.
This discussion examines Phillips 66’s role across the global liquid-hydrocarbon value chain and the broader fundamentals shaping energy markets. It highlights the importance of economic growth, demographics and energy security in driving demand, with petrochemicals offering a particularly strong long-term outlook. The discussion also covers P66 infrastructure investments, U.S. export advantages and the limited prospects for new refinery construction. Finally, it explores geopolitical risks, manufacturing trends and the potential for sustained high refined-product margins to weaken demand and economic activity.
This conference’s concluding presentation examines the increasingly interconnected North American energy landscape, where crude oil, natural gas, NGLs and renewables are closely linked and increasingly influenced by global markets. North America’s growing role as a major energy producer and exporter is driving infrastructure investment and expanding international influence. The discussion also highlights how policy, tariffs and regulation affect investment and energy prices. To navigate volatility, industry professionals should emphasize flexibility, optionality, connectivity and balance while staying grounded in fundamentals and maintaining a broad market perspective.
