This is a companion to the Sector KPI Glossary, not a replacement for it. The KPI glossary answers "how do I judge whether this company did well?" This one answers a different question: "what is actually being extracted, moved, and sold, and why does the industry talk about it this way?" Company financials only make sense once the underlying physical product and process are familiar — a "netback" is meaningless until you know why a barrel of heavy oil sells for less than a barrel of light oil in the first place. Built starting from Module 0004 (Integrated Oil Majors); will grow as later Energy modules (pipelines, uranium/gas) add midstream- and gas-specific terrain.
Not all crude oil is the same product. Two numbers do most of the work in describing what a given barrel actually is: how thick/dense it is, and how much sulfur it carries. Both drive what it costs to produce, transport, and refine — and therefore what it sells for.
A measure of how light or heavy a crude oil is, on an inverted scale set by the American Petroleum Institute: higher °API means lighter (less dense, more valuable, easier to refine into gasoline and diesel), lower °API means heavier (more dense, thicker, more valuable only after extra processing). Water sits at 10° API by definition — anything below that would sink in water.
| Class | °API | Example |
|---|---|---|
| Light | above ~31.1° | WTI (~39–40°) |
| Medium | ~22.3–31.1° | many Middle East grades |
| Heavy | ~10–22.3° | Western Canadian Select (~20–21°) |
| Extra-heavy / bitumen | below 10° | raw Athabasca oil sands bitumen (~8–12°, often listed as its own category rather than strictly "below 10") |
Separately from density, crude is classified by sulfur content. Sweet crude has low sulfur (generally under ~0.5% by weight) and is cheaper and easier to refine into clean fuels. Sour crude has higher sulfur, requiring extra refining steps (desulfurization) to meet fuel-quality and environmental standards, and so typically trades at a discount to a comparable sweet grade. A grade can be any combination — light sweet (most prized, e.g. WTI), light sour, heavy sweet, or heavy sour (least prized, most discounted, e.g. much of Canadian oil sands output before upgrading).
Thousands of distinct crude streams exist worldwide, so the market prices most of them relative to a handful of widely traded reference, or "benchmark," crudes rather than negotiating each one from scratch.
| Benchmark | Region | Character |
|---|---|---|
| WTI (West Texas Intermediate) | US (Cushing, Oklahoma delivery point) | Light, sweet — the main North American benchmark |
| Brent | North Sea | Light, sweet — the main global/European benchmark; most non-US crude is priced off Brent, not WTI |
| WCS (Western Canadian Select) | Alberta, Canada | Heavy, sour blend of oil sands bitumen and conventional heavy crude — the reference price for unupgraded Canadian heavy oil |
| Dubai/Oman | Middle East | Medium, sour — the main Asian benchmark for Gulf exports |
Every other grade trades at a differential to the nearest benchmark — a premium or discount reflecting (1) quality (lighter/sweeter earns a premium, heavier/sourer a discount) and (2) location (how expensive it is to move that barrel to where it's refined; limited pipeline capacity out of a landlocked producing region widens the discount independent of quality). The WTI–WCS differential referenced throughout Module 0004 is exactly this: partly a quality discount (WCS is heavy and sour versus WTI's light sweet), partly a transportation discount (Alberta oil sands production has repeatedly outpaced pipeline takeaway capacity to the US Gulf Coast and beyond).
Where oil physically sits underground, and how easily it flows, splits the industry into two broad categories.
Oil or gas trapped in porous, permeable rock (like sandstone) under a layer of impermeable rock (a "cap rock" or "trap") that keeps it from migrating further. Once a well is drilled into the reservoir, the oil flows toward the wellbore on its own (helped by natural reservoir pressure, and later by pumping) with comparatively little extra intervention. This is the "traditional" oil-well picture and remains the majority of global production.
Oil or gas that won't flow to a well on its own, because either the rock is too tight (shale, tight sandstone — the oil is present but the rock barely lets it move) or the oil itself is too viscous to flow (oil sands bitumen, which at reservoir temperature has roughly the consistency of cold molasses or tar and won't flow into a well under any natural pressure). Both require an engineered intervention to produce economically: hydraulic fracturing for tight/shale rock, or heat/dilution for oil sands bitumen (see below). Unconventional resources are typically far larger in place than conventional ones in the same basin, but historically cost more per barrel to produce — the balance between the two has shifted substantially over the past two decades as extraction technology (fracking, SAGD) improved.
Alberta's oil sands (bitumen mixed with sand, water and clay) are produced by one of two fundamentally different methods, chosen based on how deep the deposit sits.
Where bitumen deposits lie close enough to the surface (roughly the top ~75 meters), the sand is simply excavated with enormous shovels and trucks, like an open-pit mine, then processed with hot water to separate the bitumen from the sand. This is how CNQ's Athabasca Oil Sands Project (AOSP), the Syncrude joint venture (majority-owned and operated by SU, with IMO holding a ~25% non-operated stake), and Suncor's original Base Plant all operate. Mining is capital-intensive to build but, once running, produces bitumen with a lower incremental operating cost than in-situ methods — and the bitumen it recovers is typically higher-quality feedstock for upgrading into synthetic crude (see below).
For the roughly 80% of Alberta's oil sands that lie too deep to mine economically, bitumen is produced by drilling wells and injecting steam to heat the bitumen until it's fluid enough to flow to a well — without ever excavating the ground. The dominant technique is SAGD (Steam-Assisted Gravity Drainage): a pair of horizontal wells is drilled one above the other; steam injected into the upper well heats the surrounding bitumen, which drains by gravity into the lower well and is pumped to surface. An older, less efficient predecessor still used in some fields is CSS (Cyclic Steam Stimulation), sometimes called "huff and puff" — steam is injected into a single well for a period, then the well is shut in to let heat soak into the reservoir, then reopened to produce the now-mobile oil, repeating the cycle. Cenovus's Christina Lake and Foster Creek, and MEG Energy's Christina Lake-area assets (now part of Cenovus, per Module 0004), are SAGD operations, as are CNQ's Kirby and Jackfish; CNQ's Primrose/Wolf Lake uses the older cyclic-steam (CSS) method.
Raw bitumen is far too viscous to flow through a conventional pipeline or to be processed directly by most refineries built for lighter crude. Producers solve this one of two ways.
Dilbit (diluted bitumen) is raw bitumen blended with a much lighter hydrocarbon — usually natural gas condensate — in roughly a 70:30 bitumen-to-diluent ratio, just enough to thin it to pipeline-viscosity specifications. This is the majority path for oil sands production that doesn't get upgraded on-site: ship the diluted blend to a refinery (often in the US Midwest or Gulf Coast) configured to handle heavy crude, where it's separated back into its components. Synbit is a similar idea using synthetic crude oil (see below) as the diluent instead of condensate, typically a roughly 50:50 blend.
Alternatively, a producer can chemically upgrade bitumen on-site into synthetic crude oil (SCO) — a light, sweet, refinery-ready product that behaves like (and is priced close to) a light conventional crude, despite starting as extra-heavy bitumen. Upgrading uses a coker or hydrocracker to break bitumen's heavy molecules into lighter ones and add hydrogen, removing much of the sulfur along the way. This is a large, expensive piece of fixed infrastructure — CNQ's oil sands mining & upgrading segment and Syncrude both upgrade on-site — but the payoff is a product that sells at a premium to WTI rather than at the heavy-oil discount raw bitumen or dilbit would fetch (see Module 0004's KPI table, where CNQ's SCO sold at roughly a US$8/bbl premium to WTI in Q2 2026). Not every barrel a mining operator produces gets upgraded — some is sold as non-upgraded bitumen blend — so a company's realized price is a blend of both product streams.
The other major unconventional category — dominant in the US (Permian, Bakken, Eagle Ford) more than in the Canadian names covered so far — uses a different engineering solution for a different problem: not oil that's too thick to flow, but rock too tight to let conventional oil flow at all.
A well is drilled vertically down to the target rock layer, then turned to run horizontally through it for a mile or more, maximizing the rock surface the well contacts. Hydraulic fracturing ("fracking") then pumps a high-pressure mixture of water, sand and chemicals into the well to crack the tight rock open along that horizontal length; the sand ("proppant") lodges in the new cracks to keep them propped open after pressure is released, letting oil and gas that were previously trapped finally flow to the well.
Shale wells behave very differently over time than a conventional well: they typically produce a large fraction of their total lifetime output in the first 12–18 months, then decline steeply (often 60–70%+ in year one) before flattening into a long, low-rate "tail." This means a shale-focused producer must constantly drill new wells just to hold total production flat — a materially different capital-intensity profile than a conventional or oil sands asset, which declines much more gradually and can produce at a stable rate for decades.
Shale/tight formations often produce "wet gas" — natural gas carrying a mix of heavier hydrocarbon liquids that condense out of the gas stream as it's processed. These NGLs are usually reported and sold separately from both crude oil and dry natural gas: condensate (the heaviest, used as diluent above, priced closest to crude oil), butane and propane (used for heating, petrochemicals, and as diluent components), and ethane (the lightest, a key petrochemical feedstock). A producer's "liquids-rich" gas commentary refers to this NGL content, which materially improves the economics of an otherwise gas-focused well.
The industry's own shorthand for where in the process a business sits:
| Segment | What it does | This curriculum's examples |
|---|---|---|
| Upstream | Exploration & Production (E&P) — finding and extracting oil/gas from the ground | All four Module 0004 companies' core business |
| Midstream | Gathering, pipelines, storage, rail and marine transport — moving the product from the wellhead to a refinery or export terminal, and often processing raw gas into NGLs and pipeline-spec gas along the way | Module 0005 (Pipelines & Midstream: ENB, TRP, PPL) |
| Downstream | Refining crude into finished products (gasoline, diesel, jet fuel), plus marketing and retail | SU, CVE and IMO's refining/retail segments |
A fully "integrated" company (Module 0004's framing for SU, CVE and IMO) simply means it owns meaningful operations spanning more than one of these segments, rather than specializing in just one. To see where each company's production and refining physically sits, see the Canadian Oil Producer Asset Map.
A refinery's job is to turn one input (crude oil, a mix of many different hydrocarbon molecules) into several distinct, more valuable outputs (gasoline, diesel, jet fuel, asphalt, petrochemical feedstocks). Three core processes do most of the work:
A refinery's complexity — how much cracking/reforming capacity it has beyond basic distillation — determines how well it can process cheaper, heavier, sourer crude into the same valuable light products a simpler refinery could only get from expensive light sweet crude. This is exactly why SU's and IMO's heavy-crude-configured refineries can turn a wide WTI–WCS discount into an input-cost advantage (see Module 0004): their complexity lets them profitably run the cheap heavy barrel a simpler refinery couldn't use. The margin a refiner earns for doing all this — output product prices minus the input crude cost — is the "crack spread," covered as a KPI in the Sector KPI Glossary rather than here.
When a company reports how much oil and gas it "has," that figure follows a specific, standardized classification system (most companies use the SPE-PRMS framework, though the exact regulatory basis can vary by listing) — it is not simply "however much is in the ground."
| Category | Meaning | Confidence |
|---|---|---|
| Proved (1P) | Reasonably certain to be recoverable under current economic conditions and technology | ≥90% probability (P90) |
| 2P (Proved + Probable) | 1P plus additional volumes more likely than not to be recovered | ~50% probability (P50) — the figure generally used as the "best estimate" for project valuation |
| 3P (Proved + Probable + Possible) | 2P plus less-certain additional volumes | ~10% probability (P10) — a low-confidence, high-end case |
Reserves (any of the above) specifically means volumes judged commercially recoverable under current prices, costs and technology. Resources is the broader, looser term for everything estimated to be physically in the ground, including volumes not currently economic to produce. This distinction matters because a company's reserves can rise or fall meaningfully from one year to the next with no new discovery or depletion at all — simply because oil prices moved, making previously uneconomic barrels newly reserves (or vice versa). Don't read a reserves revision as automatically reflecting new geological information.
Several terms already used matter-of-factly in Module 0004 (Kearl, Syncrude, the Sturgeon refinery) describe a specific ownership structure worth naming explicitly.
A direct ownership share in a well, field, or facility, carrying both the right to a proportional share of production revenue and the obligation to pay that same proportional share of costs. This is distinct from a royalty interest (common in Module 0007's streaming/royalty companies), which receives a share of revenue with no obligation to fund any of the costs.
When multiple companies hold working interests in the same asset (a joint venture), one is designated the operator — it runs day-to-day operations, makes most operating decisions, and is usually the company whose name gets attached to the asset in the press. The others are non-operators: they fund and receive their working-interest share of costs and revenue, but have limited say in daily decisions (though typically some voting rights on major capital decisions). Module 0004's Syncrude (operated by SU at 58.74%, with IMO a 25% non-operator) are both examples; CNQ's 50% equity stake in the Sturgeon refinery (the other half belongs to the Alberta government) is a related partnership structure.
Three different bases get called "gross" or "net", and reading the wrong one can make the same asset look two or three times its size. 100% of the asset (or "total project") is the whole facility's output regardless of who owns it. In Canadian disclosure (the NI 51-101 convention that Canadian Natural, Suncor, Cenovus and Imperial follow), gross means a company's own working-interest share before royalties, and net means that share after royalties. US filers often use the words differently: there, "gross" frequently means 100% of the asset and "net" means the company's share. Always check which basis a number uses. Example: Kearl produced 257,000 bbl/d for 100% of the asset in Q2 2026, and IMO's 70.96% share of it was about 182,000 bbl/d; Imperial's own "gross" production total of 414,000 BOE/d adds up each asset at Imperial's share, so it is not a 100%-of-the-asset figure.
Added from Lesson 0005 — Pipelines & Midstream. A midstream company is paid mostly for a service (moving or processing someone else's product) rather than for the product itself — so the vocabulary is as much about contracts as about physical equipment.
Gathering systems are the small-diameter pipes that collect production from many wells and feed it to a processing plant or trunk line. Transmission (long-haul) pipelines move large volumes between regions — Enbridge's Mainline for crude, TC Energy's NGTL and Coastal GasLink for natural gas. Distribution is the last step for natural gas: the local utility network that delivers it to homes and businesses, and is regulated as a utility rather than priced as a pipeline.
A shipper reserves a fixed amount of pipeline capacity for a set term and pays for it whether or not it ships any product. The pipeline's revenue is therefore tied to reserved capacity rather than to volumes or commodity prices, which is why a heavily take-or-pay system behaves more like a toll road than a commodity business. The counterpart is interruptible service: no commitment, cheaper, and the first to be cut when the line is full.
For many gas pipelines and all gas utilities, a regulator sets the tolls or rates so the owner earns an allowed return on its rate base (the regulator-approved capital invested) plus its operating costs. Earnings then grow mainly by adding approved capital to the rate base, not by pushing volumes or prices — and risk shifts from price to regulatory outcomes, such as an unfavorable rate case.
When shippers' requested volumes (nominations) exceed what a pipeline can carry in a month, the operator cuts each shipper's allocation pro rata. A system that is chronically apportioned has demand for capacity that exceeds supply — usually a sign of pricing power and a reason to expand, and a reason refiners and producers lobby for more capacity. Spare capacity is the opposite condition and makes re-contracting harder.
Natural gas liquids (NGLs) — ethane, propane, butanes and heavier pentanes plus (condensate) — are the heavier components stripped out of raw natural gas at a processing plant. A fractionator separates the mixed NGL stream into those individual products. The frac spread is the margin between what the NGLs sell for and what the natural gas used to produce (or replace) them costs: when NGL prices are strong relative to gas, the spread widens and the NGL marketer earns more. It is a genuine commodity-price margin, unlike a pipeline toll.
Liquefied natural gas (LNG) is gas cooled to about −162°C so it shrinks roughly 600-fold and can travel by ship. A liquefaction plant at the export end cools it; a regasification terminal at the import end warms it back into pipeline gas. Capacity is quoted in mtpa (million tonnes per year). A floating LNG (FLNG) facility puts the liquefaction on a ship-like hull, as with Cedar LNG. For a pipeline company, an LNG project matters in two ways: it is a long-term anchor customer for a feeder pipeline (Coastal GasLink serves LNG Canada), and it ties demand for that pipeline to global gas prices and export policy.
Midstream assets are often held in joint ventures. Under equity accounting a company reports only its share of the JV's profit on one line; some companies' adjusted EBITDA instead adds in their proportionate share of the JV's EBITDA (and debt) so the numbers reflect what they economically own. Always check which basis a leverage or EBITDA figure uses — it can materially change a leverage ratio.
Natural-gas-specific terms beyond what's covered here (AECO/Henry Hub basis, LNG export economics) — added with Module 0006 (Uranium & Natural Gas). Midstream terms that only appear once a later module needs them (e.g. unit trains and crude-by-rail) are added at that point, not pre-written.