- 1 Oil and Gas Global Benchmarks
- 2 Top Tier North American Basins
- 3 Related Reading for Energy
Oil and Gas Global Benchmarks
As crude composition varies greatly, benchmarks are required to standardize global trade. Oil does not naturally form into major tradeable benchmarks. The two main global benchmarks for crude oil are West Texas Intermediate (settled in Cushing, Oklaholma) and Brent (based on 4 North Sea light crudes).
In Canada, the main benchmarks are Edmonton Light Sweet (for light oil) and Western Canadian Select (for heavy oil). WCS is a relatively new benchmark brought to market by major Canadian oil producers to better market Canadian oil and realize better pricing. Edmonton is a light oil with similar characteristics to WTI while WCS is heavy and sour.
West Texas Intermediate
WTI is considered the North American standard while Brent is the benchmark for any oil that makes it to a coast (and thus is available to the rest of the world via tanker). Usually, WTI will trade lower than Brent, with the difference explained by the cost of transportation in getting oil to tidewater.
Before the recent lifting of the US oil embargo that restricted the export of oil in the mainland United States (ex-Alaska), WTI traded at a discount to Brent that exceeded the incremental cost of transportation to a coast when there was a continental oversupply in North America. However, this delta has narrowed since the cancellation of the embargo.
Brent is the major global oil benchmark along with WTI. Most oil traders feel that Brent is the only actual global benchmark while WTI is more representative of North America. Brent is a light, sweet crude, similar to WTI – although WTI is actually of slightly higher quality than Brent (in terms of API gravity as well as sulphur content), Brent tends to trade to a premium to WTI that is equal to the cost of transportation from Cushing (where WTI is settled) to the Gulf Coast. Once oil reaches water and tankers, it is compared against Brent.
Brent is a North Sea barrel (between Scotland and Norway) and comprises of four blends – Brent, Forties, Oseberg and Ekofisk (collectively known as BFOE). There has been talk of Brent’s effectiveness as a benchmark now that North Sea production has steadily declined.
Western Canadian Select (WCS)
WCS is a heavy (~20 API) and sour (3% sulphur) blended crude benchmark typically made up of bitumen diluted with sweet syncrude and condensate. WCS is the primary Canadian heavy oil benchmark and is the primary product of the oil sands, trading at a discount to WTI. As long as the majority of Canadian crude is landlocked (until Kinder Morgan’s TransMountain expansion opens and assuming Northern Gateway stays cancelled) without sufficient refining capacity in Canada, WCS will always be benchmarked to WTI as the US is the only possible point of sale.
The absolute price of WTI and WCS’s differential to WTI both affect revenues for oil producers in Canada and both of those variables impact Canada’s current account as oil is one of Canada’s largest exports. As such, a rise in WTI or a narrowing of a differential usually result in a strengthening of the Canadian dollar and vice versa.
Western Canadian Select is sold spot, month-to-month or on 30-60 day rolling evergreen contracts.
Mars is the main US domestic medium, sour blend of oil with an API gravity of ~30 and 2% sulphur content. Mars originates from the Gulf of Mexico (offshore US drilling). Major producers of Mars include BP and Shell.
Tapis or Tapis Light is the primary crude oil benchmark for Singapore (which has very little oil to its own name but is considered an oil capital due to refining capacity and role as a tanker hub due to strong legal frameworks). Most of the world’s Tapis production is actually in Malaysian waters (by Petronas).
Tapis is a very light crude with 43-45 API gravity and has minimal sulphur content. As such, Tapis tends to trade at a premium to Brent due to the higher margin product yield (gasoline versus fuel oil).
Maya is the flagship crude of Mexico and is heavy (22 API) and sour (3.5% sulphur content). As such, it is a direct competitor to Canadian WCS for US Gulf Coast complex refinery capacity as light oil refineries are not configured to treat heavier blends.
Similar to Canada, Mexico has large oil resources but ample red tape that constrains production directly or indirectly (through undeveloped infrastructure and refinery capacity), leaving few options other than the US. As such, when takeaway capacity is constrained or refineries go down for maintenance, Maya may trade at a large discount to WTI just like WCS does.
As competitors, they both constitute heavy oil supply (which is limited in the US) – if Maya production falls, the price of WCS will rise.
Henry Hub is the primary North American benchmark for natural gas and is traded in USD per million British thermal units (which is roughly energy equivalent to one thousand cubic feet or mcf of natural gas). Henry Hub in Louisiana is where NYMEX futures are delivered. All other natural gas benchmarks are priced at a differential to HH. A good summary can be found on Bloomberg via BGAS <GO>.
AECO is the most widely used Canadian benchmark for natural gas and is the quoted price for volumes traded on TransCanada’s Nova Gas Transmission system (NGTL). The price is quoted in gigajoules so an analyst may need to normalize to per million British thermal units or mcf for comparability purposes. The AECO basis is the price differential between AECO and Henry Hub traded on the NYMEX. Generally, the differential will be negative and be the same as the cost of transport to a demand market, however in times of severe electricity undersupply in Alberta (usually a weather shock), AECO prices can shoot to a multiple of its usual trading range.
AECO has suffered over the years because of a lack of end market demand, especially as Northeast demand was pushed out by exponential supply growth from the Marcellus satisfying energy markets there. Historically, the AECO basis has averaged US$0.50, widening to US$1 during the Marcellus’ growth. Attractive royalty and tax incentives have helped to make gas extraction increasingly economic and, coupled with demand growth, has seen the basis begin to narrow again.
The Permian is the hottest North American play at the moment, with constant updates of new discoveries on a large scale. The Montney and Duvernay are the top two fracturing plays in Canada. The Bakken, Eagle Ford and Marcellus complete the list of the most coveted plays in North America.
Top Tier North American Basins
Currently, the crown jewel of the basins is the Permian, which is in Texas (remember Friday Night Lights).
The Permian Basin, about 250 miles wide and 300 miles long, covers a portion of western Texas and southeast New Mexico and includes sub-basins like the Northwest Shelf, Delaware Basin, and the Midland Basin. It has been long regarded as one of the most prolific oil and gas plays within the United States. During World War II, the Permian was responsible for producing 25% of the world’s oil and was one of America’s greatest assets. The Permian holds largest crude oil fields in the United States, and at the peak of the Permian’s production, it was producing about 2 million barrels a day. Some reasons revolving around its popularity and profitability stem from two main reasons:
Infrastructure: As the Permian is also one of the oldest plays in the United States, many developments such as pipelines, drilling-rigs, pumps, and support businesses, have already been established. This allows for producers to access equipment and extract oil more efficiently and at a lower cost. It is also able to distribute its oil to trading hubs, allowing it to sell at global prices, which is not something available to every play.
Geographical features: The Permian is unique relative to other plays in that producers can access various layers of oil-bearing rocks from a single region. Ultimately, producers will only need to prepare one drilling site and can expect to extract large amounts of hydrocarbons from various levels of drilling. This greatly enhances the producer’s output and efficiency, while simultaneously reducing risk and resource usage.
Today, horizontal activity has been dominating the Permian and has greatly enhanced the oil output. Some of the major producers in the Permian include names like Chevron, Apache, ExxonMobil, Concho Resources, Occidental Petroleum, Devon Energy, EOG Resources, Pioneer Natural Resources, SM Energy, and many more.
The Eagle Ford is a Texas shale that is heavily oil weighted with ample energy infrastructure supporting getting production to end demand markets.
Discovered in 2008, the Eagle Ford is a relatively new shale play that was discovered through horizontal drilling and hydraulic fracturing. The Eagle Ford covers about 20,000 square feet and stretches over 400 miles across Texas. The northern region of the Eagle Ford is relatively more oil-rich, while the southern region is relatively more gas-rich.
The Eagle Ford originally rose in popularity due to its rich oil content, but has since declined from market down turns, declining oil prices, high break-even points and high extraction costs. Nonetheless, it remains a world-class oil and gas play and many producers expect it to return in time. A unique aspect of the Eagle Ford is that its shale is highly carbonated which makes it more frail, allowing it to be easier to fracture. Companies that have dominated the Eagle Ford play include names such as EOG Resources, Chesapeake Energy, and ConocoPhilips.
The Duvernay is a premier play in Canada which is liquids rich.
Western Canadian Sedimentary Basin
The WCSB has 15bcf per day of gas production, of which 5bcf is used for regional demand (in addition to gas-fired heating and electricity generation for normal residential and commercial business demand, a very large amount of gas is used for industrial purposes in the oil sands). There is ~500bcf of storage capacity in the area, allowing for flexibility in temporary oversupply beyond takeaway capacity.
Currently, condensate demand far outstrips condensate production, so each barrel of condensate will be sold at a dollar value that would cause a blended barrel of heavy crude or bitumen to be saleable in a synthetic crude market. Accordingly, many liquids rich gas fields in Canada are said to have “negative breakevens” because even if they take a loss on their gas production, the sale of the byproduct (condensate) will justify the economics.
The quality of the basin is heavily dependent on existing takeaway capacity. The Horn River and Liard Basins have very low extraction costs, but the gas is not nearly as saleable as the Montney as pipeline infrastructure is not as developed. The Montney does not require new transport capacity to grow.
Related Reading for Energy