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2015-06-04 18:35:00



U.S. oil production has grown rapidly in recent years. EIA data, which reflect combined production of crude oil and lease condensate, show a rise from 5.6 million barrels per day (b/d) in 2011 to 7.5 million b/d in 2013, and a record 1.2 million b/d increase to 8.7 million b/d in 2014. Increasing production of light crude oil in low-permeability or tight resource formations in regions like the Bakken, Permian Basin, and Eagle Ford (often referred to as light tight oil) account for nearly all the net growth in U.S. crude oil production. Roughly 90% of the nearly 3.0 million b/d growth in production between 2011 and 2014 consists of sweet grades with an API gravity of 40 or above.

Although the rate of growth in light sweet crude slows from its pace between 2011 and 2014, in the Reference case, 56% of EIA's projected production growth between 2014 and 2020 consists of sweet grades with an API gravity of 40 or above (Figure 1). Another 33% of the growth is attributable to an increase in Lower 48 offshore production, which is categorized as medium sour with an API gravity between 27 and 35. Total U.S. oil production is projected to increase 23% between 2014 and 2020. After 2020, tight oil production declines, as drilling moves into less-productive areas.


The pace and duration of projected crude oil production increases are uncertain, and depend on crude oil prices and the quality and amount of technically recoverable resources. In the AEO2015 High Oil and Gas Resource and High Oil Price cases, the rate of growth in tight oil production is higher than in the Reference case. In 2025, projected domestic crude oil production is 2.7 million b/d higher in the High Oil Price case than in the Reference case and 3.9 million b/d higher in the High Oil and Gas Resource case than in the Reference case. U.S. total crude oil production is lowest in the Low Oil Price case. In 2025, projected domestic crude oil production is nearly 800,000 b/d lower in the Low Oil Price case than in the Reference case.

In the past several years, more than half of the additional production of U.S. crude oil has been absorbed by reducing oil imports of similar grades. Of the total 1.8 million b/d decline in crude oil imports between 2011 and 2014, roughly 56% was light crude (API 35+). Light crude imports fell from 1.7 million b/d in 2011 to 0.7 million b/d in 2014, and medium crude imports decreased from 3.3 million b/d to 2.5 million b/d. Imports of heavy crudes have remained near 4.0 million b/d since 2010.

Other responses to the increased production of light oil over the past several years have included additional crude exports to Canada and increased refinery runs based on the recent cost advantage of U.S. refiners compared with global competitors. For example:

  • U.S. exports of crude oil to Canada increased from 46,000 b/d in 2011 to 324,000 b/d in 2014, and reached 491,000 b/d in January 2015.
  • U.S. refinery utilization increased from 86.2% in 2011 to 90.4% in 2014 and was 88.4% in January 2015. From 2011 to 2014, refinery runs increased by 0.9 million b/d.

The dwindling amount of light crude imports available to be backed out through further like-for-like substitution, and the limits to increased utilization of existing refinery capacity, could cause absorption of additional increases in domestic production to rely heavily on some combination of the following:

  • Continued shifts in the refinery input mix, which can be enabled by investments to relieve constraints associated with running lighter crudes at refineries that were optimized to run heavier ones
  • Added splitter or hydroskimmer capacity to convert light crude into a mix of heavier fractions to feed domestic refineries and increase the production of light products available to other markets
  • Continued increases in crude oil exports, which will depend in part on the extent of any relaxation of current export restrictions

All of these options have implications for the value of existing refineries and specific refinery units, the mix of products produced by the refining sector, and the market value of each type of crude input and refinery product output. A change in crude production levels, which could be a further market adjustment mechanism, would come into play in the event that the market value of a particular stream reaches a level where production is not economic. Updated estimates of regional production by crude type will be valuable as new plays start commercial development, potentially changing the distribution of production by crude types in the regions where those plays are located.

U.S. average retail gasoline price increases, average diesel fuel price decreases, regional prices mixed

The U.S. average retail price of regular gasoline increased one cent from last week to $2.78 per gallon as of June 1, 2015, 91 cents lower than at the same time last year. The West Coast price decreased four cents to $3.44 per gallon, and the Gulf Coast price was down less than a penny to $2.48 per gallon. The Midwest price rose four cents to $2.69 per gallon. The East Coast and Rocky Mountain prices both increased one cent, to $2.67 per gallon and $2.74 per gallon, respectively.

The U.S. average diesel fuel price decreased one-half cent from the prior week to remain at $2.91 per gallon, $1.01 per gallon less than a year ago. The Rocky Mountain price rose one cent to $2.84 per gallon, while the Midwest price rose less than a cent to remain at $2.80 per gallon. The East Coast and West Coast prices each decreased one cent, to $3.00 per gallon and $3.16 per gallon, respectively. The Gulf Coast price was down less than a penny to remain at $2.80 per gallon.

Propane inventories gain

U.S. propane stocks increased by 3.8 million barrels last week to 77.0 million barrels as of May 29, 2015, 31.3 million barrels (68.3%) higher than a year ago. Gulf Coast inventories increased by 2.3 million barrels and Midwest inventories increased by 1.1 million barrels. East Coast inventories increased by 0.4 million barrels while Rocky Mountain/West Coast inventories remained unchanged. Propylene non-fuel-use inventories represented 6.8% of total propane inventories.