U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
U.S. Crude Oil and Natural Gas Proved Reserves
With Data for 2011
| Release Date:
August 1, 2013
| Next Release Date:
In 2011, oil and gas exploration and production companies operating in the United States added almost 3.8 billion barrels of crude oil and lease condensate proved reserves, an increase of 15 percent, and the greatest volume increase since the U.S. Energy Information Administration (EIA) began publishing proved reserves estimates in 1977 (Table 1). Proved reserves of crude oil and lease condensate increased by 2.9 billion barrels in 2010, the previous record. Proved reserves of U.S. wet natural gas1 rose by 31.2 trillion cubic feet in 2011 to a new record high of 348.8 trillion cubic feet. Though this increase was lower than the 33.8 trillion cubic feet (Tcf) added in 2010, it was only the second year since 1977 that natural gas net reserves additions surpassed 30 Tcf.
|Crude oil and lease condensate
|Wet natural gas
trillion cubic feet
|U.S. proved reserves at December 31, 2010||25.2||317.6|
|Net adjustments, sales, acquisitions||0.7||6.0|
|Net additions to U.S. proved reserves||3.8||31.2|
|U.S. proved reserves at December 31, 2011||29.0||348.8|
|Percentage change in U.S. proved reserves||15.0%||9.8%|
|Notes: Wet natural gas includes natural gas plant liquids. Columns may not add to total due to independent rounding.
Source: U.S. Energy Information Administration, Form EIA-23 "Annual Survey of Domestic Oil and Gas Reserves."
Horizontal drilling and hydraulic fracturing in shale and other "tight" (very low permeability) formations continued to drive record increases in proved oil and lease condensate and natural gas reserves in 2011. Proved reserves of oil and lease condensate also increased in 2011 with higher crude oil prices, both to justify more drilling or development and to adjust forecasts of future production at the higher price levels. Lower natural gas prices had a dampening effect on natural gas proved reserves.
U.S. proved reserves of natural gas began growing sharply in the mid-2000s as operators adopted expanded horizontal drilling programs and applied new hydraulic fracturing techniques in shale formations. Starting with 2009, similar horizontal drilling programs were applied in several of the nation's tight oil formations – reserves additions from tight oil plays have reversed the long-term trend of generally declining proved U.S. oil and lease condensate reserves (Figure 1).
Proved reserves of crude oil and lease condensate increased in each of the five largest crude oil and lease condensate areas (Texas, the Gulf of Mexico federal offshore, Alaska, California, and North Dakota) in 2011 (Figure 2). Of these, Texas had the largest increase by a large margin, about 1.8 billion barrels (46 percent of the net increase), resulting mostly from ongoing development in the Permian and Western Gulf Basins in the western and south-central portions of the state. North Dakota reported the second largest increase, 771 million barrels (20 percent of the net increase), driven by development activity in the Williston Basin. Collectively, North Dakota and Texas accounted for two-thirds of the net increase in total U.S. proved oil reserves in 2011.
Proved wet natural gas reserves increased in each of the five largest natural gas producing states (Texas, Wyoming, Louisiana, Oklahoma, and Pennsylvania) in 2011. Pennsylvania's proved natural gas reserves, which more than doubled in 2010, rose an additional 90 percent in 2011, contributing 41 percent of the overall U.S. increase. Combined, Texas and Pennsylvania added 73 percent of the net increase in U.S. proved wet natural gas reserves (Figure 3). Expanding shale gas developments in these and other areas, particularly the Pennsylvania and West Virginia portions of the Marcellus formation in the Appalachian Basin, drove overall increases.
For both oil and natural gas, these increases in proved reserves reflect the growing role for domestically-produced hydrocarbons in meeting current and projected U.S. energy demand. Domestic production has risen along with reserves levels, displacing some imports of oil and gas (Figures 4 and 5).
This report summarizes changes to U.S. oil and natural gas proved reserves during 2011.
EIA provides annual estimates of U.S. proved reserves of crude oil, natural gas, lease condensate, and natural gas plant liquids based on filed responses to Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," an annual survey of about 1,100 domestic operators of oil and gas wells.
Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty2 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 as 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 using existing technology and prices.
The aggregated production data for crude oil, natural gas, lease condensate, and natural gas plant liquids include volumes that have been reported to EIA by operators on Form EIA-23, and volumes that are based on EIA estimates. These production numbers are offered only as an indicator of production trends and may differ from EIA's official production series based on state-reported data, which are provided elsewhere on the EIA website for oil and natural gas.
Several factors influence reserves estimates, but crude oil and natural gas prices are particularly important. 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.
Both EIA and the Securities and Exchange Commission (SEC) require oil and gas companies to provide information on their oil and gas reserves. There are important differences between these two reporting systems. First, EIA collects information from both publicly traded and privately held companies, while SEC reporting requirements apply only to companies with more than $10 million in assets and whose securities are held by more than 500 owners. Second, EIA requires companies (both public and private) to report the estimated proved reserves of each field they operate (irrespective of its ownership share, only one company is the designated operator of a given oil or natural gas field), while the SEC requires companies to report only their "owned" reserves (irrespective of field operatorship).
The 2011 reporting period represents the third year companies reporting to the SEC followed revised rules for determining the prices underpinning their proved reserves estimates. Designed to make estimates less sensitive to price fluctuations during the year, the revisions require companies to use an average of the 12 first-day-of-the-month prices. Prior to the 2009 reporting year, companies' estimates were based on the market price on the last trading day of the year. The 12-month, first-day-of-the-month, average crude oil and natural gas spot prices3 for 2011 were $95.84 per barrel and $4.15 per million British thermal units (MMBtu), representing an increase of 20 percent and a decrease of 6 percent, respectively, from the previous year. Because actual prices received by operators depend on their contractual arrangements, location, quality, and other factors, spot market prices are not necessarily the prices used by operators in their reserves estimates for EIA. They do, however, provide a benchmark or trend indicator. The average natural gas price used in estimating proved reserves for 2011 reflects a sustained downward trend in natural gas prices, which continued through much of 2012.
A partial look ahead to 2012
In addition to the effects of new discoveries, revisions to existing fields, and the changes made possible by application of new technology, prices play a very important role in the calculation of proved reserves. For the upcoming 2012 reporting period, the 12-month, first-day-of-the-month, average spot natural gas price fell nearly 34 percent from the 2011 average to $2.75 per MMBtu, reflecting both continued increases in domestic production (due largely to shale gas development) and significantly rising inventories. In the first half of 2012, the daily Henry Hub spot price dipped below $2.00 per MMBtu, averaging just $1.95 per MMBtu in April. The previous occurrence of natural gas prices below $2.00 per MMBtu was in November 1999. While 2012 natural gas prices rebounded somewhat to finish the year well above $3.00 per MMBtu, price-driven negative revisions can be expected to materially affect overall natural gas proved reserves additions in 2012.
On the other hand, the 12-month, first-day-of-the-month, average spot price of West Texas Intermediate (WTI) crude oil was relatively unchanged, dipping from $95.84 per barrel in 2011 to $95.01 per barrel in 2012. EIA therefore anticipates a comparatively modest influence of price-driven revisions on crude oil proved reserves in 2012.
Oil proved reserves (crude oil and lease condensate) 2011
EIA's U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves reports of 2009 and 2010 each cited the central contribution of the combination of horizontal drilling and hydraulic fracturing technologies to significant increases in oil proved reserves. The continued application of these technologies again played a key role in 2011, generating even higher volumetric gains, which as in previous years took place primarily onshore in the lower 48 states (Figure 6).
Overall reported U.S. crude oil and lease condensate proved reserves rose by nearly 3.8 billion barrels in 2011, attributable mostly to a fifth consecutive increase in (and a record volume of) total discoveries and, to a lesser degree, net revisions. Combined additions from these sources totaled 5.1 billion barrels, more than double the year's production (Figure 7). Among individual states, Texas had the year's largest volumetric increase in oil proved reserves (1,752 million barrels), driven largely by horizontal drilling and hydraulic fracturing activity in tight oil plays, (petroleum-bearing formations of relatively low porosity and permeability such as the Eagle Ford Shale, the Wolfcamp Shale, and other formations which must be hydraulically fractured in order to produce oil at commercial rates). Development of tight oil plays added significantly to proved oil reserves in other states, most notably North Dakota, where drilling in the Bakken and underlying Three Forks formations in the Williston Basin accounted for most of North Dakota's net addition of 771 million barrels of crude oil and lease condensate proved reserves in 2011.
Over 90 percent of the country's tight oil proved reserves in 2011 came from the four largest tight oil plays (Table 2). With estimated proved reserves of nearly 2 billion barrels, the Bakken Play in the Williston Basin ranked as the largest tight oil play in the United States by a considerable margin, followed by the Eagle Ford Play of southwest Texas, with 2011 proved reserves estimated at almost 1.3 billion barrels. Combined reserves of the next two largest tight oil plays — the Niobrara (Colorado, Kansas, Nebraska, and Wyoming), and the Barnett (Texas) — totaled 126 million barrels. EIA has a series of maps and animations on its website of the nation's shale and other tight oil (and natural gas) resources.
|Williston Basin||Bakken||ND, SD, MT||123||1,998|
|Western Gulf||Eagle Ford||TX||71||1,251|
|Denver-Julesberg||Niobrara||CO, KS, NE, WY||2||8|
|Other tight oil plays
(e.g. Monterey, Woodford)
|All U.S. tight oil plays||228||3,628|
| Note: Includes lease condensate.
Source: U.S. Energy Information Administration, Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves."
The weekly active horizontal rotary rig count can be a useful indicator of the pace of exploration and development activity in shale formations and other tight plays. During 2011, the overall number of active oil-directed drilling rigs in the United States rose by 54 percent, driven largely by continued increases in the use of horizontal rigs, up 79 percent for the year. Horizontal rigs, which made up 45 percent of active oil rigs at the beginning of 2011, accounted for 53 percent at year's end (Figure 8).
Total Discoveries. 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). Total discoveries added 3.7 billion barrels to U.S. oil reserves in 2011, the highest annual volume of total discoveries on record. As is typical, extensions made up the bulk (85 percent) of total discoveries.
Geographically, total oil discoveries in 2011 were sourced primarily from Texas, North Dakota, and the Gulf of Mexico federal offshore. Texas led by a considerable margin, with discoveries of 1.7 billion barrels (mostly in the Eagle Ford), while North Dakota added 695 million barrels, marking that state's third consecutive year as a major source of total discoveries. As in 2009 and 2010, North Dakota's discoveries in 2011 (mostly extensions) are associated with expanding drilling programs in the Bakken and Three Forks formations. Total oil discoveries in the Gulf of Mexico Federal Offshore added 441 million barrels in 2011, an increase of 90 percent over the 232 million barrels of discoveries in 2010. The resumption and quickening pace of exploration and appraisal activities in the deepwater Gulf of Mexico following the lifting of the drilling moratorium was the main contributing factor to the increase in discoveries in that area.
Net Revisions and Other Changes. Revisions to proved reserves occur primarily when operators change their estimates of what they will be able to produce from the properties they operate using existing technology and prices. Other small 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 more than 1.4 billion barrels to oil proved reserves in 2011, largely reflecting the significant increase in oil prices since 2010. Under the SEC rules adopted for the 2009 reporting year, the 12-month, first-day-of-the-month, average spot price for WTI crude oil in 2011 was $95.84 per barrel, an increase of 20 percent over the 12 first-day-of-the-month average price in 2010 ($79.79).
The net change to U.S. proved oil reserves associated with buying and selling properties and adjustments is typically modest compared with net revisions. Net of sales and acquisitions added 537 million barrels to proved reserves in 2011, significantly more than in most previous years, yet considerably below net revisions of more than 1.4 billion barrels. Adjustments (reserves changes that EIA cannot attribute to any other category) added 207 million barrels to reserves in 2011.Production. Operators reported oil production of 2.1 billion barrels in 2011, an increase of 4 percent from 2010. This represents the country's third consecutive annual production increase and the first year since 2004 in which U.S. annual oil production exceeded 2 billion barrels. Production from the onshore lower 48 states (primarily Texas, California, and North Dakota) rose 14 percent over the previous year. While production from Alaska rebounded moderately after several years of general decline, the Gulf of Mexico Federal Offshore experienced a significant production drop (23 percent), reflecting in part the lingering effects of the drilling moratorium, which delayed development activities in key producing areas of the Gulf.
Wet natural gas proved reserves (includes natural gas plant liquids) 2011
Total reported U.S. proved reserves of wet natural gas rose by 31.2 Tcf in 2011, second only to the 2010 reporting year's 33.8 Tcf as the highest annual volumetric increase since 1977. The addition increased the country's proved wet natural gas reserves to 349 Tcf (Figure 9). The increase was mostly attributable to a ninth consecutive annual rise in total discoveries, which added nearly 50 Tcf (primarily from extensions) (Table 3). While U.S. natural gas proved reserves have increased in every year since 1999, this growth has been especially pronounced in recent years as a result of expanding exploration and development activity in several of the nation's shale formations, (e.g., Barnett, Haynesville, Marcellus, Fayetteville, Woodford, and Eagle Ford shales)
|Year-end 2010 proved reserves||2011 discoveries||2011 revisions & other changes||2011 production||Year-end 2011 proved reserves|
|Other (Conventional & Tight)|
|Lower 48 Onshore||181.7||14.7||-3.5||-12.8||180.1|
|Lower 48 Offshore||12.1||0.8||-0.4||-1.7||10.8|
|Source: U.S. Energy Information Administration, Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves."|
While critical to the recent growth in the nation's oil proved reserves, the combination of horizontal drilling and hydraulic fracturing has driven increases in natural gas proved reserves for several years. These two factors played a key role again in 2011, when net additions in shale natural gas reserves of 34.2 Tcf easily outpaced the overall net decrease in proved natural gas reserves from all other sources combined. The share of shale gas relative to total U.S. natural gas proved reserves continued its rise, from less than 10 percent in 2007 to 38 percent in 2011 (Figure 10).
At the state level, Pennsylvania's had the largest volumetric increase in natural gas proved reserves in 2011 (12.7 trillion cubic feet), driven by continued development of the Marcellus shale formation. Texas had the second largest increase in total proved natural gas reserves (10,167 billion cubic feet), as development continued in many shale formations – notably the Eagle Ford, Barnett, and Haynesville/Bossier shale formations. Three states – Texas, Pennsylvania, and Louisiana – accounted for 72 percent of total U.S. shale natural gas proved reserves in 2011 (Figure 11).
Virtually all U.S. shale natural gas proved reserves in 2011 came from the six largest U.S. shale plays (Table 4). The Barnett again ranked as the largest shale gas play in the United States, with proved reserves totaling nearly 33 Tcf. The most significant increases over 2010 proved reserves, however, were in the Marcellus Play (which more than doubled 2010 reserves) and the Eagle Ford Play (which more than tripled the previous year's reserves). EIA has a series of maps on its website of the nation's shale gas resources for both shale plays and geologic basins.
|Basin||Play||State(s)||2010 production||2010 reserves||2011 production||2011 reserves||Production||Reserves|
|Appalachian||Marcellus||PA, WV, KY, TN, NY, OH||0.5||13.2||1.4||31.9||0.9||18.7|
|Texas-Louisiana Salt||Haynesville/Bossier||TX, LA||1.5||24.5||2.5||29.5||1.0||5.0|
|Western Gulf||Eagle Ford||TX||0.1||2.5||0.4||8.4||0.3||5.9|
|Other Shale Plays||0.2||4.0||0.3||3.6||0.1||-0.4|
|All U.S. Shale Plays||5.4||97.4||8.0||131.6||2.6||34.2|
|Notes: Some columns may not add up to its subtotal because of independent rounding. Natural gas is wet after lease separation. The above table is based on shale gas proved reserves and production volumes reported and imputed from data on Form EIA-23. For certain reasons (e.g. incorrect or incomplete submissions, misidentification of shale versus non-shale reservoirs) the actual proved reserves and production of natural gas from shale plays may be higher or lower. The production estimates are offered only as an observed indicator of production trends and may differ from EIA production volumes listed elsewhere on the EIA web site.
Source: U.S. Energy Information Administration, EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," 2010 and 2011 annual reports.
Total Discoveries. Total wet natural gas discoveries of 49.9 Tcf in 2011 represented the ninth consecutive annual increase and were the highest volume of discoveries since EIA began publishing proved reserves estimates in 1977. In 2011, 95 percent of total wet natural gas discoveries (and 97 percent of shale gas discoveries) came from extensions of existing fields (Figure 12). New field discoveries and new reservoir discoveries in previously discovered fields totaled 1.0 Tcf and 1.3 Tcf, respectively. Texas and Pennsylvania, with total discoveries of 13.8 Tcf and 10.8 Tcf, respectively, were the leading individual states, while Oklahoma and Louisiana each added approximately 6 Tcf. Volumetric increases in each of these states were driven principally by shale gas developments.
Net Revisions and Other Changes. Net revisions of wet natural gas proved reserves were a negative volume in 2011 (they reduced the U.S. total slightly, -112 billion cubic feet). Total U.S. revision decreases of 56.1 Tcf offset all revision increases in 2011, reflecting declines in both anticipated natural gas drilling and the average natural gas price. The 12-month, first-day-of-the-month, average spot price at Henry Hub declined from $4.39 per MMBtu in 2010 to $4.15 per MMBtu in 2011.
The net change to wet natural gas proved reserves from the purchase and sale of properties and adjustments resulted in a 3.3 Tcf addition, much higher than net revisions yet still well below 2011 extensions.
Production. Production of wet natural gas in 2011 totaled 24.6 Tcf, up 6 percent from 2010. This represents the sixth consecutive annual increase and the highest annual production volume since 1977. Production rose sharply in Louisiana and Pennsylvania. The combined increase from these two states alone more than offset the cumulative decline from eleven other states and the Gulf of Mexico federal offshore region, underscoring the major contribution of shale-focused drilling programs.
Dry natural gas reserves
Dry natural gas is that volume of gas that remains after all of the liquefiable hydrocarbons and non-hydrocarbon impurities are removed from the natural gas stream — first at lease separation facilities near the producing well (lease condensate), then downstream at natural gas processing plants (natural gas plant liquids). U.S. proved reserves of dry natural gas increased by 10 percent from 2010 to 2011, to 334.0 Tcf.
Lease condensate and natural gas plant liquids proved reserves
EIA provides separate estimates of lease condensate and natural gas plant liquids proved reserves. Operators of natural gas fields report their lease condensate reserves and production estimates to EIA on Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves." EIA calculates its estimate of natural gas plant liquids reserves using wet 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.
Prices for lease condensate and natural gas plant liquids are tied more closely to crude oil than natural gas. Since crude oil prices rose faster than natural gas prices during 2011, exploration and development activities continued their trend toward liquids-focused drilling (Figure 13). Throughout most of the 2000s, rigs targeting natural gas accounted for about 80 percent or more of the weekly active Baker Hughes rig count. The rig distribution began an appreciable shift in the second half of 2009, with oil-directed rigs comprising nearly sixty percent of actively drilling units at the end of 2011.
Proved reserves of lease condensate and natural gas plant liquids 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 (Figure 14). The annual crude-oil-to-natural-gas-price ratio, which averaged about 8.0 from 2000 to 2008, rose sharply thereafter, increasing from 16.5 in 2009 to 27.8 in 2011. Over the same period, lease condensate and natural gas plant liquids proved reserves climbed by 47 percent and 27 percent, respectively. It is useful to note that the average crude-oil-to-natural-gas-price ratio for 2012 was 41.6, suggesting further (and perhaps substantial) increases for lease condensate and natural gas plant liquids reserves for the 2012 reporting year.
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 other crude oil to enhance quality.
U.S. lease condensate proved reserves increased by 26 percent in 2011 to 2.4 billion barrels, mostly as a result of extensions. Texas had the largest increase in lease condensate proved reserves in 2011 (411 million barrels), followed by Oklahoma (55 million barrels). Additions to lease condensate proved reserves are associated in large part with expanding drilling programs in liquids-rich portions of shale and other tight formations, such as the Eagle Ford in Texas and the Woodford in Oklahoma. Lease condensate accounted for just over 8 percent of total oil proved reserves in 2011.
U.S. lease condensate production increased 3 percent, from 224 million barrels in 2010 to 231 million barrels in 2011, the highest production volume recorded for lease condensate since EIA began publishing proved reserves estimates.
Natural gas plant liquids
Liquids in the natural gas stream 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. Lease condensate is excluded. Products obtained include liquefied petroleum gases (ethane, propane, and butanes), pentanes plus, and isopentane. Component products may be further fractionated or mixed.
Although liquids contained in wet natural gas are an integral component of the natural gas stream, it is useful to estimate the amount of liquids available to be separated from proved reserves of natural gas. EIA calculates that U.S. natural gas plant liquids proved reserves rose from 9.8 billion barrels in 2010 to 10.8 billion barrels in 2011, an increase of 10 percent. Texas had the largest volumetric increase in natural gas plant liquids proved reserves in 2011, followed by Oklahoma and Wyoming. As is the case with lease condensate, increasing proved reserves of natural gas plant liquids is linked closely to expanding drilling activity in shale formations, including the Barnett in Texas and the Woodford in Oklahoma.U.S. natural gas plant liquids production increased by 5 percent in 2011, from 745 million barrels in 2010 to 784 million barrels in 2011.
Additional data tables and maps
For more detailed 2011 proved reserves information than discussed in the report see Tables 4-18 and Figures 15-18.
Figure 15 shows a thematic map of the 2011 crude oil proved reserves volumes by state and federal offshore areas, and Figure 16 shows the change in crude oil proved reserves by area from 2010 to 2011.
Similarly, Figure 17 shows a thematic map of the 2011 wet natural gas proved reserves volumes by state and federal offshore areas, and Figure 18 shows the change in wet natural gas proved reserves by area from 2010 to 2011.
Contact: Steven G. Grape or 202-586-1868