U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
U.S. Crude Oil and Natural Gas Proved Reserves
Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty1 are recoverable under existing economic and operating conditions. Reserves estimates change from year to year as new discoveries are made, existing fields are more thoroughly appraised, existing reserves are produced, and prices and technologies change.
- U.S. proved reserves of crude oil and lease condensate increased for the fifth year in a row in 2013, and exceeded 36 billion barrels for the first time since 1975.
- A sharp increase in proved natural gas reserves in 2013 more than offset the significant decline experienced in 2012, and set a new record2 (354 trillion cubic feet) for U.S. natural gas proved reserves.
- An increase in natural gas prices used to characterize existing economic conditions contributed to the reported 2013 increase in proved natural gas reserves. For example, the 12-month, first-of-the-month average spot natural gas price at the Henry Hub increased from $2.75 per million Btu (MMbtu) in 2012 to $3.66 per MMBtu in 2013. Proved natural gas reserves had declined between 2011 and 2012 as the gas price declined (e.g., the 12-month, first-of-the-month average spot natural gas price at the Henry Hub decreased from $4.15 per MMBtu in 2011 to $2.75 per MMBtu in 2012).
- North Dakota's crude oil and lease condensate proved reserves surpassed those of the Federal Gulf of Mexico, ranking it second only to Texas among U.S. states.
- The Bakken/Three Forks play (covering portions of North Dakota, Montana, and South Dakota) regained its position as the largest tight oil play in the United States.
- Pennsylvania and West Virginia account for 70% of the increase in natural gas proved reserves.
In 2013, U.S. crude oil and lease condensate proved reserves increased to 36.5 billion barrels—an increase of 3.1 billion barrels (9.3%) from 2012 (Table 1). U.S. proved reserves of crude oil and lease condensate have now risen for five consecutive years (Figure 1), and exceeded 36 billion barrels for the first time since 1975.
Proved reserves of U.S. total natural gas3 increased 31 trillion cubic feet (Tcf) to 354 Tcf in 2013 (Table 1). This 10% increase offsets the 26 Tcf decline in 2012 and boosts the national total of proved natural gas reserves to a record high level.
|Crude oil and lease condensate
|Total natural gas
trillion cubic feet
|U.S. proved reserves at December 31, 2012||33.4||322.7|
|Net adjustments, sales, acquisitions||-0.2||2.0|
|Net additions to U.S. proved reserves||3.1||31.3|
|U.S. proved reserves at December 31, 2013||36.5||354.0|
|Percentage change in U.S. proved reserves||9.3%||9.7%|
|Notes: Total natural gas includes natural gas plant liquids. Columns may not add to total because of independent rounding.
Source: U.S. Energy Information Administration, Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves
Proved reserves of crude oil and lease condensate increased in Texas and North Dakota, two of the top five largest crude oil and lease condensate states in 2013 (Figure 2). In 2013, North Dakota had the largest increase in proved reserves, about 1.9 billion barrels (61% of the nation's total net increase in 2013). This increase was driven by continued development in the Williston Basin, site of the Bakken and Three Forks. In 2013, North Dakota's proved reserves of crude oil and lease condensate exceeded those of the federal offshore Gulf of Mexico, making it the second largest oil reserves state in the United States. Texas had the second largest increase, about 0.9 billion barrels, which came mostly from the Eagle Ford shale play and other tight formations in the Permian Basin. Collectively, North Dakota and Texas accounted for 90% of the overall net increase in U.S. proved oil reserves in 2013.
Proved natural gas reserves increased in each of the top five U.S. gas reserves states (Texas, Pennsylvania, Wyoming, Oklahoma, and Colorado) in 2013 (Figure 3). Pennsylvania had the largest increase (13.5 Tcf), the result of extensions to fields in the Marcellus shale play. The reserves additions in Texas and Oklahoma also were mostly from extensions in shale natural gas plays, but, in Wyoming and Colorado, positive net revisions to large conventional gas fields (associated with increased prices) added more gas reserves than extensions.
While U.S. oil reserves and production increased in 2013, imports of crude oil declined by nearly 10% (Figure 4). Similarly, U.S. natural gas proved reserves and production increased in 2013, and natural gas imports declined by 8% (Figure 5).
This report provides estimates of U.S. proved reserves of crude oil and lease condensate, and natural gas for calendar year 2013. Starting with the data filed on Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves, submitted by 480 sampled operators of U.S. oil and natural gas fields, EIA estimated the U.S. total proved reserves and the subtotal for individual states and state subdivisions. Results are summarized and tabulated in this report.
Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions. Reserves estimates change from year to year as new discoveries are made, existing fields are more thoroughly appraised, existing reserves are produced, and prices and technologies change.
Discoveries include new fields, identification of new reservoirs in previously discovered fields, and extensions, which are additions to reserves that result from additional drilling and exploration in previously discovered reservoirs. Within a given year, extensions are typically the largest percentage of total discoveries. While discoveries of new fields and reservoirs are important indicators of new resources, they generally account for a small portion of overall annual reserve additions.
Revisions occur primarily when operators change their estimates of what they will be able to produce from the properties they operate in response to changing prices or improvements in technology. Â Higher prices typically increase estimates (positive revisions) as operators consider a broader portion of the resource base economically producible, or proved. Lower prices, on the other hand, generally reduce estimates (negative revisions) as the economically producible base diminishes.
Because actual prices received by operators depend on their contractual arrangements, location, hydrocarbon quality, and other factors, spot market prices are not necessarily the prices used by operators in their reserve estimates for EIA. They do, however, provide a benchmark or trend indicator. The 12-month, first-day-of-the-month, average West Texas Intermediate (WTI) crude oil spot price for 2013 was $97.28 per barrel, a 2% increase over 2012 (Figure 6).
The 12-month, first-day-of-the-month average natural gas spot price at the Louisiana Henry Hub for 2013 was $3.66 per MMBtu, representing a 33% increase over the previous year (Figure 7). Despite the increase, the 2013 average price remains below the average prices observed in the previous years, 2008-11. Natural gas reserves with a low yield of natural gas liquids (prices for which are linked more closely to crude oil), those located in more remote locations lacking necessary infrastructure, or within deeper reservoirs, were at an economic disadvantage in 2013 when compared with those with higher liquids content or lower cost (e.g., shallower) wells.
Price Outlook for 2014.The first-day-of-the-month, average spot price of WTI crude oil from January to October 2014 averaged $98.69 per barrel, an increase of 1 percent over the 2013 12-month average. However, in November 2014, the WTI crude oil spot price declined below $80 per barrel and EIA forecasts an average December 2014 WTI crude oil spot price of $78 per barrel. This lowers the estimated 12-month, first-day-of-the month average spot price for WTI in 2014 to $95.31 (a 2% decline compared to 2013). EIA anticipates a commensurately modest decrease from net revisions to crude oil proved reserves in 2014. The average natural gas spot price through November 2014, on the other hand, has increased 25% to $4.58 per MMBtu at the Henry Hub in Louisiana. EIA forecasts an average December 2014 Henry Hub spot price of $4.10 per MMBtu, and this modifies the 2014 estimate slightly to $4.54 per MMBtu. This is a 24% increase in annual average spot price and exceeds the average price in the previous five years. EIA therefore anticipates a more robust increase from net revisions to natural gas proved reserves in 2014.
The aggregated production data for crude oil and lease condensate and for natural gas include volumes that have been reported to EIA by operators on Form EIA-23L, as well as volumes that are based on EIA estimates. The production numbers in the tables and figures of this report are offered only as an indicator of production trends and may differ slightly from EIA's official production series based on state-reported data, which are provided elsewhere on the EIA website for oil and natural gas.
Crude oil and lease condensate proved reserves
OverviewU.S. crude oil and lease condensate proved reserves increased for the fifth consecutive year in 2013 (Figure 8).
U.S. crude oil and lease condensate proved reserves rose by 3.1 billion barrels in 2013, attributable primarily to nearly 5 billion barrels of extensions to existing fields and, to a much lesser degree, net revisions (Figure 9a).Â For the past three years, the majority of oil reserves have been added by extensions to existing fields (Figure 9b).
North Dakota led all states in additions of proved oil reserves (1.9 billion barrels) because of ongoing development of the Bakken/Three Forks tight oil play in the Williston Basin. More than three-quarters of North Dakota reserves additions were from extensions in 2013.
Texas had the second-largest increase in crude oil and lease condensate proved reserves in 2013, adding 0.9 billion barrels. Extensions to fields in the liquids-rich section of the Eagle Ford shale play in south-central Texas (Railroad Commission Districts 1 and 2) and to oil fields in the Permian Basin (Districts 7C and 8) provided the largest portion of new Texas proved oil reserves.
As of December 31, 2013, tight oil4 plays accounted for 28% of all U.S. crude oil and lease condensate proved reserves. More than 95% of U.S. tight oil proved reserves in 2013 came from six tight oil plays (Table 2). The Bakken/Three Forks play in the Williston Basin regained its rank as the largest tight oil play in the United States (it was surpassed by the Eagle Ford play in 2012). EIA has a series of maps and animations showing the nation's shale and other tight oil (and natural gas) resources.
|Change 2012-13 Reserves|
|Williston||Bakken/Three Forks||ND, MT, SD||214||3,166||270||4,844||1,678|
|Western Gulf||Eagle Ford||TX||209||3,372||351||4,177||805|
|Permian||Bone Spring, Wolfcamp||NM, TX||12||236||21||335||99|
|Denver-Julesberg||Niobrara||CO, KS, NE, WY||3||14||2||17||3|
|Other tight oil||28||414||37||483||69|
|U.S. tight oil||480||7,338||701||10,043||2,705|
| Note: Includes lease condensate. Bakken/Three Forks tight oil includes fields reported as shale or low permeability on Form EIA-23L; "Other tight oil" includes fields reported as shale on Form EIA-23L not assigned by EIA to the Bakken/Three Forks, Barnett, Bone Spring, Eagle Ford, Marcellus, Niobrara, or Wolfcamp tight oil plays.
Source: U.S. Energy Information Administration, Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves, 2012 and 2013.
Total discoveries.Total discoveries added 5.5 billion barrels to U.S. crude oil and lease condensate reserves in 2013. Total discoveries consist of discoveries of new fields, identification of new reservoirs in fields discovered in prior years, and extensions (reserve additions that result from the additional drilling and exploration in previously discovered reservoirs).
Geographically, the largest total discoveries were from Texas, North Dakota, and the federal waters of the Gulf of Mexico. Texas had total discoveries of 2.0 billion barrels, while North Dakota had discoveries of 1.6 billion barrels. Total discoveries in the Federal Gulf of Mexico were almost 500 million barrels, 181 million barrels of which came from new field discoveries. In 2013, 95% of the nation's reserves additions from new field discoveries were from the Federal Gulf of Mexico.
Net revisions and other changes. Revisions to reserves occur primarily when operators change their estimates of what they will be able to economically produce from the properties they operate using existing technology and prices. Other changes occur when operators buy and sell properties (revaluing the proved reserves in the process), and as various adjustments are made to reconcile estimated volumes.
Net revisions added 545 million barrels to U.S. crude oil and lease condensate proved reserves in 2013. North Dakota had the largest positive net revision of 2013—339 million barrels of crude oil and lease condensate proved reserves—as operators developed existing Bakken formation fields through infill drilling. The largest negative net revision was in Alaska, a decline of 305 million barrels. Alaskan operators cited reductions in well performance as the reason for the net downward revision.
The net change to U.S. crude oil and lease condensate proved reserves associated with buying and selling properties was 389 million barrels in 2013. Adjustments (reserves changes that EIA cannot attribute to any other category) reduced U.S. proved oil reserves by 595 million barrels. The largest was a downward adjustment of 265 million barrels in the federal waters off Louisiana (a correction from 2012).
Production. The United States produced an estimated 2.7 billion barrels5 of crude oil and lease condensate in 2013, an increase of about 14% from 2012. This represents the country's fifth consecutive annual production increase. Production from the Lower 48 states rose 16% over the previous year. Alaska experienced a 3% production decline.
Natural gas proved reserves
U.S. proved reserves of total natural gas (including natural gas plant liquids) increased by 10% (31.3 Tcf) in 2013 and reached a record high for the United States of 354 Tcf (Figure 10). The reserves were added onshore in the Lower 48 States from ongoing exploration and development activity in several of the nation's shale formations, including the Barnett, Haynesville, Marcellus, Fayetteville, Woodford, and Eagle Ford plays. Natural gas proved reserves in Alaska and the federal waters of the Gulf of Mexico both declined in 2013.
At the state level, operators in Pennsylvania and West Virginia reported the largest net increases in natural gas proved reserves in 2013 (13.5 and 8.3 Tcf, respectively), driven by continued development of the Marcellus shale gas play. Texas added the third highest volume of natural gas proved reserves (4.4 Tcf), followed by Wyoming (2.9 Tcf); Arkansas and North Dakota each added over 2 Tcf.
|Year-end 2012 proved reserves||2013 discoveries||2013 revisions & other changes||2013 production||Year-end 2013 proved reserves|
|Conventional & Other Tight|
|Lower 48 Onshore||159.5||15.0||3.5||-12.0||166.0|
|Lower 48 Offshore||10.5||0.5||-0.5||-1.3||9.1|
Note: Lower 48 Offshore includes state offshore and Federal offshore. Components may not add to total because of independent rounding.
Total discoveries. The U.S. total of natural gas discoveries was 53.0 Tcf in 2013 (Table 3), of which 96% were extensions to existing natural gas fields (Figures 11a and 11b). New field discoveries and new reservoir discoveries in previously discovered fields were 0.3 Tcf and 1.7 Tcf, respectively. Total discoveries of natural gas reserves were highest in Pennsylvania, at 15.8 Tcf. West Virginia had the second-largest total discoveries, at 10.1 Tcf. Texas was third with approximately 9.7 Tcf of gas discoveries, and fourth-place Oklahoma had 4 Tcf of discoveries. Total discoveries in each of these states were driven principally by shale gas developments.
Net revisions and other changes. Net revisions added 2.8 Tcf to U.S. total natural gas proved reserves, wet after lease separation, in 2013. The 2013 average first-day-of-the-month spot prices of natural gas increased 33% to $3.66 per MMBtu. Certain states with large natural gas reserves that had large downward net revisions in reserves in 2012 because of historically low natural gas prices (which dipped below $2 per MMBtu in April 2012), had a portion of those reserves restored by positive net revisions in 2013:
- Wyoming had the largest positive net revision of natural gas proved reserves. Wyoming added 2.1 Tcf in 2013—compared with a downward net revision of 5.2 Tcf in 2012.
- Colorado added net revisions of 1.9 Tcf after a 2.6 Tcf downward net revision in 2012.
- Texas added 0.8 Tcf in net revisions after a 17.0 Tcf downward revision in 2012. The largest of the Texas net positive revisions were in Railroad Commission District 5, the core area of the Barnett shale play.
The increases in 2013 from net revisions to natural gas proved reserves did not completely offset the large declines of 2012, suggesting that operators are cautious about committing to drill natural gas prospects, or are diverting their attention to oil or liquids-rich prospects.
The largest negative net revision was in Alaska, -2.3 Tcf. This negative revision was due largely to the decline in associated-dissolved natural gas proved reserves, the result of deteriorating well performance in certain crude oil fields.
The net change to natural gas proved reserves from the purchase and sale of properties resulted in an additional gain of 1.3 Tcf in 2013. Adjustments (reserves changes that EIA cannot attribute to any other category) to U.S. total natural gas proved reserves totaled 0.7 Tcf.
Production. U.S. production of total natural gas in 2013 (estimated from data filed on Form EIA-23L) was 26.5 Tcf, an increase of 1.4% from 20126. Official EIA marketed natural gas production was 25.6 Tcf in 2013, an increase of 1.2% from 2012. This sets a new record for U.S. annual natural gas production, and is the eighth consecutive year that gas production rose. In Pennsylvania, 1.1 Tcf of additional production boosted that state's output by 47%, the nation's largest increase. The state with the largest estimated decline in natural gas production in 2013 was Louisiana (-0.7 Tcf, a drop of 23%).
Shale natural gas
Shale natural gas is a type of unconventional natural gas where a shale formation is both the source rock and the producing reservoir. Proved reserves of U.S. shale natural gas increased by 29.7 Tcf in 2013, a 23% increase over 2012.The share of shale gas relative to total U.S. natural gas proved reserves increased from 40% in 2012 to 45% in 2013 (Figure 12). Estimated production of shale natural gas increased nearly 10%—from 10.4 Tcf in 2012 to 11.4 Tcf in 2013.
Texas had the most shale gas proved reserves at year-end 2013, having the Barnett, the Eagle Ford, and a portion of the Haynesville/Bossier shale gas play within its borders. Pennsylvania, which had the second-largest volume of shale gas proved reserves, experienced greater growth of its shale gas proved reserves than Texas (Figure 13). West Virginia surpassed Oklahoma to become the third-largest shale gas reserves state. Oklahoma remained fourth-largest, and Arkansas and Louisiana were the fifth- and sixth-largest, respectively.
Six shale plays contained 94% of U.S. shale gas proved reserves at the end of 2013 (Table 4). The Marcellus remained the largest shale gas play, and added the most new shale gas reserves (22.1 Tcf) in 2013 through extensions in Pennsylvania and West Virginia. The second-largest shale gas play was the Barnett shale (the play that started the U.S. shale gas boom), where proved reserves were revised upward in 2013 mostly in response to higher natural gas prices.
|Basin||Shale Play||State(s)||2012 production||reserves||2013 production||reserves||Production||Reserves|
|Appalachian||Marcellus||PA, WV, OH, NY||2.4||42.8||3.7||64.9||1.3||22.1|
|Western Gulf||Eagle Ford||TX||1.0||16.2||1.4||17.4||0.4||1.2|
|Texas-Louisiana Salt||Haynesville/Bossier||TX, LA||2.7||17.7||1.9||16.1||-0.8||-1.6|
|Arkoma, Anadarko||Woodford||TX, OK||0.6||12.6||0.7||12.5||0.1||-0.1|
|Other Shale Gas||0.6||6.7||0.7||10.0||0.1||3.3|
|All U.S. Shale Gas||10.4||129.4||11.4||159.1||1.0||29.7|
Note: Table values are based on shale gas proved reserves and production volumes reported and imputed from data on Form EIA-23L. For certain reasons (e.g., incorrect or incomplete submissions, misidentification of shale versus nonshale reservoirs), the actual proved reserves and production of natural gas from shale plays may be higher or lower. "Other shale gas" includes fields reported as shale on Form EIA-23L not assigned by EIA to the Marcellus, Barnett, Haynesville/Bossier, Eagle Ford, Woodford, or Fayetteville Shale gas plays.
Although the Eagle Ford shale is primarily an oil and natural gas liquids play, it has substantial natural gas reserves, and added enough new reserves in 2013 to surpass the Haynesville. EIA has a series of maps showing the nation's shale gas resources for both shale plays and geologic basins.
Nonassociated natural gas
Nonassociated natural gas, also called gas well gas, is defined as natural gas not in contact with significant quantities of crude oil in a reservoir. EIA considers most shale natural gas and all coalbed natural gas to be nonassociated natural gas proved reserves. Proved reserves of U.S. nonassociated natural gas increased by 26 Tcf in 2013, a 10% increase from 2012 (Table 11). Estimated production of U.S. nonassociated natural gas decreased 1%—from 22.7 Tcf in 2012 to 22.4 Tcf in 2013. The largest decline in nonassociated natural gas production was in Louisiana, where production and reserves from the Haynesville shale have declined.
Associated-dissolved natural gas
Associated-dissolved natural gas, also called casinghead gas, is defined as the combined volume of natural gas that occurs in crude oil reservoirs either as free gas (associated) or as gas in solution with crude oil (dissolved). Proved reserves of associated-dissolved natural gas rose by 5.3 Tcf in 2013, a 10% increase from 2012 (Table 12). Estimated production of associated-dissolved natural gas increased 21%—from 3.4 Tcf in 2012 to 4.1 Tcf in 2013. The largest increase in associated-dissolved natural gas production in 2013 was in Texas, specifically in Texas Railroad Commission (RRC) Districts 1 and 8, coinciding with the gains in oil production from the Eagle Ford play and the Permian Basin.
Coalbed natural gas
Coalbed natural gas, also called coalbed methane, is a type of unconventional natural gas contained in and removed from coal seams. Extraction requires drilling wells into the coal seams and removing water contained in the seam to reduce hydrostatic pressure and release adsorbed (and free) gas out of the coal. Proved reserves of U.S. coalbed natural gas decreased by 1.2 Tcf in 2013, a 9% drop from 2012 (Tables 15 and 16). Estimated production of coalbed natural gas decreased 11%—from 1.7 Tcf in 2012 to 1.5 Tcf in 2013. Among individual states, Colorado experienced the largest decline in proved reserves and production of coalbed methane, followed by Alabama. New Mexico had the largest increase in coalbed methane reserves, gaining 84 billion cubic feet (3%) of proved reserves. Wyoming had the second-largest gain, increasing its coalbed methane reserves by 74 billion cubic feet (4%).
Dry natural gas
Dry natural gas is the volume of natural gas (primarily methane) that remains after natural gas liquids and non-hydrocarbon impurities are removed from the natural gas stream, initially at lease separation facilities near the producing well (lease condensate), and then downstream at a processing plant (natural gas plant liquids).In 2013, the increase in the estimated volume of dry natural gas contained in proved reserves of total natural gas mirrored the 10% increase observed in total natural gas proved reserves. The estimated U.S. total of dry natural gas increased from 308 Tcf in 2012 to 338 Tcf in 2013 (Table 17).
Lease condensate and natural gas plant liquids
Operators of natural gas fields report lease condensate reserves and production estimates to EIA on Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves. EIA calculates the expected yield of natural gas plant liquids using total natural gas reserves estimates and a recovery factor determined for each area of origin. Data from Form EIA-64A, Annual Report of the Origin of Natural Gas Liquids Production, are the basis of EIA's recovery factors.Proved reserves of lease condensate have increased significantly in recent years as operators sharpened their exploration and development focus on liquids-rich portions of natural gas plays to take advantage of comparatively higher liquids prices. The annual crude-oil-to-natural-gas-price ratio, which averaged about 8.0 from 2000 to 2008, was 34.5 in 2012 and 26.6 in 2013. The 2014 forecast for this ratio is 21.0 (based on average price estimates from Figures 6 and 7). Oil appears to be maintaining its price advantage over natural gas, giving crude oil and liquids exploration and development projects an economic advantage over those that would produce only (or mostly) dry natural gas (e.g., coalbed methane projects).
Lease condensate is a mixture consisting primarily of hydrocarbons heavier than pentanes that is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas plant liquids, such as butane and propane, which are recovered at downstream natural gas processing plants or facilities. Lease condensate is often blended directly into crude oil to enhance quality.U.S. lease condensate proved reserves increased by 10% in 2013 to 3,149 million barrels—mostly as a result of extensions. Colorado had the largest increase in lease condensate proved reserves at 133 million barrels, followed by Oklahoma at 104 million barrels. Lease condensate accounted for 8.6% of the U.S. total crude oil and lease condensate proved reserves in 2013. U.S. lease condensate production increased 13%, from 274 million barrels in 2012 to 311 million barrels in 2013.
Natural gas plant liquids
Natural gas plant liquids remain in gaseous form at the surface and must be separated as liquids at natural gas processing plants, fractionating and cycling plants, and in some instances, field facilities. Products obtained include ethane, liquefied petroleum gases (propane, butane, and isobutane), and natural gasoline. Components may be further fractionated or mixed. Lease condensate is excluded.As with dry natural gas, the potential U.S. supply of natural gas plant liquids is not "proved reserves" because these liquids are extracted downstream of the producing wells at a natural gas processing plant. An estimate of the volume of these liquids that might be extracted from total natural gas reserves is presented in Table 17. The estimated volume of natural gas plant liquids contained in proved reserves of total natural gas rose from 10.8 billion barrels in 2012 to 11.9 billion barrels in 2013 (an 11% increase).
Reserves in nonproducing reservoirs
Not all proved reserves are contained in actively producing reservoirs. Proved nonproducing reserves may be awaiting well workovers, drilling of additional development or replacement wells, installation of production equipment or pipeline facilities, or depletion of other zones or reservoirs that is required prior to initiation of recompletion activities in nonproducing reservoirs.Table 18 shows the estimated volumes of nonproducing proved reserves of crude oil, lease condensate, nonassociated natural gas, associated-dissolved natural gas, and total natural gas for 2013.
Maps and additional data tables
For more detailed 2013 proved reserves information than discussed above, see maps below and tables for oil (5-8) and gas (9-17) top right.
2The previous U.S. record high levels for total natural gas proved reserves, wet after lease separation were: 349 Tcf in 2011, 318 Tcf in 2010, and 303 Tcf in 1967. The 1967 estimate is based on an American Petroleum Institute (API) published U.S. natural gas reserve estimate of 293 Tcf that excludes natural gas plant liquids.Â (Sources: EIA, American Petroleum Institute (API). Prior to EIA’s creation in 1977, starting in 1925, U.S. crude oil and natural gas annual proved reserves were estimated by API.)
3Total natural gas (also known as natural gas, wet after lease separation) includes natural gas liquids that have yet to be extracted downstream at a processing plant, but does not include lease condensate.
4Tight oil is oil produced from petroleum-bearing formations with low permeability such as the Eagle Ford, the Bakken, and other formations that must be hydraulically fractured to produce oil at commercial rates. A kerogen-bearing, thermally-mature shale is the source rock, and typically lends its name to the play.
5The oil production estimates in this report are based on data reported on Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves. They may differ slightly from the official U.S. EIA production data for crude oil and lease condensate for 2013 contained in the Petroleum Supply Annual 2013, DOE/EIA-0340(13).
6The natural gas production estimates in this report are based on data reported on Form EIA-23L, Annual Survey of Domestic Oil and Gas Reserves. Estimates differ from the official U.S. EIA production data for natural gas published in the Natural Gas Annual 2013, DOE/EIA-0131(13).
Contact: Steven G. Grape or 202-586-1868