U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
U.S. Crude Oil and Natural Gas Proved Reserves
With Data for 2012
| Release Date:
April 10, 2014
| Next Release Date:
- U.S. crude oil and lease condensate proved reserves increased year-over-year by 4.5 billion barrels (15.4%) because of a large volume of extensions to existing fields (5.2 billion barrels) particularly in Texas and North Dakota.
- U.S. wet natural gas proved reserves decreased 26 trillion cubic feet (7.5%) in 2012. Low natural gas prices, reflected in a 34% decline in the 12-month, first-of-the-month, average spot price of natural gas at the Henry Hub between 2011 and 2012, led to large negative net revisions (-45.6 trillion cubic feet) to the reserves of existing fields that offset almost all gains from extensions of existing fields.
- Proved crude oil reserves in the Eagle Ford tight oil play in southwest Texas surpassed those in the Bakken Formation of North Dakota to become the largest tight oil play in the United States.
- Proved natural gas reserves in the Marcellus Shale gas play in Pennsylvania and West Virginia surpassed those in the Barnett Shale play of Texas to become the largest shale gas play in the United States.
- U.S. oil and natural gas production both increased in 2012—crude oil and lease condensate production rose about 16%, and, despite the drop in proved natural gas reserves, wet natural gas production rose about 6%.
- EIA anticipates that natural gas proved reserves for 2013 will be affected positively by the recovery in natural gas prices from 2012 to 2013.
Proved reserves are volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In 2012, oil and gas exploration and production companies operating in the United States added 4.5 billion barrels of crude oil and lease condensate proved reserves, an increase of 15.4% from 2011—the largest annual increase since 1970.1 U.S. proved reserves of crude oil and lease condensate have now risen for four consecutive years. Also, proved reserves of oil exceeded 33.4 billion barrels for the first time since 1976.
Proved reserves of U.S. wet natural gas2 decreased 7.5% (a loss of 26 trillion cubic feet) to 323 trillion cubic feet in 2012(Table 1). Total discoveries of oil and natural gas proved reserves both exceeded U.S. production in 2012, with the largest discoveries occurring onshore within the Lower 48 states. The 2012 decline interrupted a 14-year trend of consecutive increases in natural gas proved reserves (Figure 1).
|Crude oil and lease condensate
|Wet natural gas
trillion cubic feet
|U.S. proved reserves at December 31, 2011||29.0||348.8|
|Net adjustments, sales, acquisitions||0.6||12.7|
|Net additions to U.S. proved reserves||4.5||-26.1|
|U.S. proved reserves at December 31, 2012||33.4||322.7|
|Percentage change in U.S. proved reserves||15.4%||-7.5%|
|Notes: Wet 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."
U.S. proved reserves of natural gas declined in 2012 because of low natural gas prices. The average reference price of natural gas3 companies use to estimate reserves declined 34% between 2011 and 2012. Natural gas prices began to decline in the latter part of 2011 and continued to drop through spring 2012. This prompted large downward net revisions of 45.6 trillion cubic feet to the proved reserves of existing gas fields — enough to cancel out almost all the gains from total discoveries in 2012.
The average price of oil4, on the other hand, remained relatively constant in 2012 at an average daily spot price of $95 per barrel, and as a result, net revisions added almost a billion barrels of crude oil and lease condensate proved reserves.
Proved reserves of crude oil and lease condensate increased in three of the top five largest crude oil and lease condensate states (Texas, the Gulf of Mexico federal offshore, and North Dakota) in 2012 (Figure 2). Of the top five U.S. oil reserve states, Texas had the largest increase by a wide margin, about 3.0 billion barrels (67% of the net increase in 2012). The Texas increase is primarily from ongoing development in the Permian and Western Gulf basins in the western and south-central portions of the state. The Gulf of Mexico federal offshore added 137 million barrels (3% of the net increase). North Dakota reported the second-largest increase, 1.1 billion barrels (25% of the net increase). This increase was driven by development activity in the Williston Basin. In 2012, North Dakota’s proved reserves of crude oil and lease condensate exceeded those of Alaska and California, making North Dakota the third largest oil reserve state in the United States. Collectively, North Dakota and Texas accounted for 92% of the net increase in total U.S. proved oil reserves in 2012.
Proved wet natural gas reserves decreased in four of the top five U.S. gas reserve states (Texas, Wyoming, Louisiana, and Oklahoma) in 2012 (Figure 3). Pennsylvania was the only state in the top five to report an increase (9.8 Tcf) in natural gas proved reserves in 2012, as a result of development of the Marcellus Shale play. In 2012, Pennsylvania went from fifth to the second largest gas reserve state.
U.S. oil and natural gas production both increased in 2012, reflecting the growing role of domestically produced hydrocarbons in meeting current and projected U.S. energy demand. U.S. production of crude oil and lease condensate increased about 16% from 2011 to 2012 (Figure 4).
Despite the drop in natural gas proved reserves in 2012, U.S. natural gas production increased about 6% from 2011 to 2012 (Figure 5).
The U.S. Energy Information Administration (EIA) reduced the overall burden on respondents by implementing changes to its sample design and its methodology for estimation of proved reserves for state and state subdivision totals in 2012. The description of these changes and a summary of other statistical data are in the 2012 Proved Reserves Estimation Methodology Appendix.
This report provides estimates of U.S. proved reserves of crude oil and lease condensate, and natural gas for calendar year 2012. Starting with the data filed on Form EIA-23L, "Annual Survey of Domestic Oil and Gas Reserves," by 727 sampled operators of U.S. oil and gas fields, EIA estimated the U.S. total proved reserves and the subtotal for individual states and state subdivisions. EIA's estimation methodology is described in the 2012 Reserves Estimation Methodology appendix.
Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty5are 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. 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.
The Securities and Exchange Commission (SEC) requires some oil and gas companies to report their oil and gas reserves publicly. There are important differences between EIA's and SEC's reporting systems. First, EIA collects information from a sample of 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 sampled companies 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 the proved reserves they own (irrespective of field operatorship).
The 2012 reporting period represents the fourth 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.
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 crude oil spot price6 for 2012 was $95.01 per barrel, a 1% decrease in the average oil price from the prior year (Figure 6).
The 12-month, first-day-of-the-month average natural gas spot price for 2012 was $2.75 per MMBtu, representing a 34% decrease in the average gas price from the previous year (Figure 7).
For the 2012 reporting period, the decline in natural gas prices reflects both continued increases in domestic production 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. Natural gas prices rose by the end of 2012 to finish well above $3.00 per MMBtu.
Price Outlook for 2013.The 12-month, first-day-of-the-month, average spot price of WTI rose from $95.01 per barrel in 2012 to $97.28 per barrel in 2013. Because of this increase, EIA anticipates higher price-driven revisions to crude oil proved reserves in 2013. The average natural gas spot price continued to rise throughout 2013, resulting in an average annual natural gas spot price in 2013 of $3.66 per MMBtu. EIA anticipates that proved natural gas reserves for 2013 will be affected positively by the recovery in natural gas prices from 2012 to 2013.
The aggregated production data for crude oil and lease condensate, and natural gas, include volumes that have been reported to EIA by operators on Form EIA-23, and 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 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
OverviewThe continued application of horizontal drilling and hydraulic fracturing technologies again played a key role in adding crude oil proved reserves onshore in the Lower 48 states. The year 2012 is the fourth consecutive year in which U.S. crude oil proved reserves showed significant gains (Figure 8).
U.S. crude oil and lease condensate proved reserves rose by 4.5 billion barrels in 2012, attributable to 5.2 billion barrels of extensions and, to a lesser degree, net revisions (Figure 9). Among individual states, Texas had the year's largest volumetric increase in oil proved reserves (nearly 3 billion 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, the Wolfcamp, and other formations which must be hydraulically fractured to produce oil at commercial rates). Development of tight oil plays added significantly to proved oil reserves in other states, most notably North Dakota. Drilling in the Bakken and underlying Three Forks formations in the Williston Basin accounted for North Dakota's net addition of 1.1 billion barrels of crude oil and lease condensate proved reserves in 2012.
More than 90% of the country's tight oil proved reserves in 2012 came from five tight oil plays (Table 2). With estimated 2012 proved reserves of 3.4 billion barrels, the Eagle Ford play of southwest Texas passed the Bakken play of the Williston Basin (with 3.2 billion barrels of proved reserves in 2012) to become ranked as the largest tight oil play in the United States. EIA has a series of maps and animations showing the nation's shale and other tight oil (and natural gas) resources.
|Western Gulf||Eagle Ford||TX||71||1,251||209||3,372|
|Williston||Bakken||ND, MT, SD||123||1,998||213||3,166|
|Denver-Julesberg||Niobrara||CO, KS, NE, WY||2||8||3||14|
|Other tight oil||24||253||41||648|
|All U.S. tight oil||228||3,628||480||7,338|
| Note: Includes lease condensate. Other tight oil includes fields reported as shale or low permeability on Form EIA-23 not assigned by EIA to the Eagle Ford, Bakken, Barnett, Marcellus, or Niobrara tight oil plays.
Source: U.S. Energy Information Administration, Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves, 2011 and 2012.
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 5.4 billion barrels to U.S. crude oil and lease condensate reserves in 2012. As is typical, extensions made up the bulk (96%) of total discoveries.
Geographically, the largest total oil discoveries in 2012 were from Texas, North Dakota, and Oklahoma. Texas led by a considerable margin, with discoveries of 3.0 billion barrels (mostly in the Eagle Ford play), while North Dakota added nearly 1 billion barrels, marking that state's fourth consecutive year as a major source of total discoveries. North Dakota's 2012 discoveries were from the Bakken (and Three Forks) play. Oklahoma discovered 319 million barrels of proved oil reserves in 2012.
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 912 million barrels to oil proved reserves in 2012, despite a 1% decline in the average spot price.
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 415 million barrels to proved reserves in 2012. Adjustments (reserves changes that EIA cannot attribute to any other category) added 137 million barrels to reserves in 2012.
Production. The United States produced an estimated 2.4 billion barrels7 of crude oil and lease condensate in 2012, an increase of about 16% from 2011. This represents the country's fourth consecutive annual production increase. Production from the onshore Lower 48 states (primarily Texas, California, and North Dakota) rose 27% over the previous year. Alaska and the Gulf of Mexico Federal Offshore both experienced production drops in 2012, 8% for Alaska and 5% for the Gulf, compared with 2011.
Wet natural gas proved reserves (includes natural gas plant liquids) 2012
Total reported U.S. proved reserves of wet natural gas declined by 7% (a drop of 26.1 Tcf) in 2012, the first reported decrease in natural gas proved reserves since 1998. Prior to 2012, U.S. natural gas proved reserves had 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 plays) (Figure 9). The decrease was mostly attributable to a 34% drop in the average natural gas price, resulting in a net downward revision of 48.3 Tcf (Table 3).
|Year-end 2011 proved reserves||2011 discoveries||2012 revisions & other changes||2012 production||Year-end 2012 proved reserves|
|Other (Conventional & Tight)|
|Lower 48 Onshore||180.0||14.6||-22.2||-12.3||160.2|
|Lower 48 Offshore||10.8||0.5||-0.1||-1.4||9.9|
|Source: U.S. Energy Information Administration, Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," 2011 and 2012.|
Total discoveries. Total wet natural gas discoveries were 48 Tcf in 2012, and 98% of total wet natural gas discoveries came from extensions of existing fields (Figure 11). New field discoveries and new reservoir discoveries in previously discovered fields totaled 0.8 Tcf and 0.4 Tcf, respectively. Total discoveries of wet natural gas reserves were highest in Pennsylvania, with total discoveries of 13.3 Tcf, edging out Texas, which reported 13.2 Tcf of total discoveries. West Virginia and Oklahoma both discovered approximately 5.3 Tcf, while Louisiana discovered 3.2 Tcf. Total discoveries 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 reduced the U.S. total natural gas reserves by 45.6 trillion cubic feet from 2011 to 2012.
The net change to wet natural gas proved reserves from the purchase and sale of properties and adjustments resulted in an additional loss of 2.7 Tcf in 2012. When combined with the net revisions, the decline was greater than the 2012 volume of total discoveries.In 2012, the share of shale gas relative to total U.S. natural gas proved reserves continued its rise, from 38% in 2011 to 40% in 2012 (Figure 12).
At the state level, Pennsylvania and West Virginia reported the largest net increases in natural gas proved reserves in 2012 (9.8 and 4.3 trillion cubic feet, respectively), driven by continued development of the Marcellus Shale gas play. However, three states with mature shale gas plays—Texas, Louisiana, and Arkansas—all experienced declines in their shale natural gas proved reserves in 2012 (Figure 13).
Virtually all U.S. shale natural gas proved reserves in 2012 came from the six largest U.S. shale plays (Table 4). The Marcellus is now ranked as the largest shale gas play in the United States, with proved reserves totaling nearly 43 Tcf. The Marcellus, the Eagle Ford, and the Woodford Shale plays increased in proved reserves, while the more mature Barnett, Haynesville, and Fayetteville Shale plays recorded significant decreases. EIA has a series of maps showing the nation’s shale gas resources for both shale plays and geologic basins.
|Basin||Shale Play||State(s)||2011 production||reserves||2012 production||reserves||Production||Reserves|
|Appalachian||Marcellus||PA, WV, KY, TN, NY, OH||1.4||31.9||2.4||42.8||1.0||10.9|
|Texas-Louisiana Salt||Haynesville/Bossier||TX, LA||2.5||29.5||2.7||17.7||0.2||-11.8|
|Western Gulf||Eagle Ford||TX||0.4||8.4||0.9||16.2||0.5||7.8|
|Other Shale Gas||0.3||3.6||0.8||8.2||0.5||4.6|
|All U.S. Shale Gas||8.0||131.6||10.4||129.4||2.4||-2.2|
|Notes: Table values are 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. Other shale gas includes fields reported as shale on Form EIA-23 not assigned by EIA to the Marcellus, Barnett, Haynesville/Bossier, Eagle Ford, Woodford, or Fayetteville shale gas plays.
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 website. Natural gas is measured at 60 degrees Fahrenheit and atmospheric pressure base of 14.73 pounds per square inch (psia).
Source: U.S. Energy Information Administration, EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," 2011 and 2012 annual reports.
Production. U.S. production of wet natural gas in 2012 totaled 26.1 Tcf8, an increase of about 6% from 2011. This represents the seventh consecutive annual increase and the highest annual production volume since 1977. Production rose the most in Pennsylvania and Texas, but there were also production increases in Arkansas, Louisiana, and Oklahoma, even as proved gas reserves in these states declined in 2012.
Nonassociated natural gas
Nonassociated natural gas, sometimes called gas well gas, is defined as natural gas not in contact with significant quantities of crude oil in a reservoir. Proved reserves of nonassociated natural gas declined by 36.5 Tcf in 2012, a 12% drop from 2011 (Table 11). Estimated production of nonassociated natural gas increased 4%—from 21.9 Tcf in 2011 to 22.7 Tcf in 2012.
Associated-dissolved natural gas
Associated-dissolved natural gas, sometimes called casinghead gas, is defined as the combined volume of natural gas which 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 increased by 10.3 Tcf in 2012, a 24% increase from 2011 (Table 12). Estimated production of associated-dissolved natural gas increased 25%—from 2.7 Tcf in 2011 to 3.4 Tcf in 2012.
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 declined by 2.2 Tcf in 2012, a 2% drop from 2011 (Tables 13 and 14). Estimated production of shale natural gas increased 30%—from 8.0 Tcf in 2011 to 10.4 Tcf in 2012.
Coalbed natural gas
Coalbed natural gas, also called coalbed methane, is a type of unconventional natural gas emitted from coal seams, usually by desorption as the seam is dewatered. Proved reserves of U.S. coalbed natural gas decreased by 3.2 Tcf in 2012, a 19% drop from 2011 (Tables 15 and 16). Estimated production of coalbed natural gas decreased 6%—from 1.8 Tcf in 2011 to 1.7 Tcf in 2012.
Dry natural gas
Dry natural gas is the volume of gas (primarily methane) that remains after natural gas liquids 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).Designating the total U.S. supply of dry natural gas as "proved reserves" is a misnomer, because dry natural gas is a processed fuel. As part of the 2013 EIA NGL Realignment9of natural gas liquids and related terminology, EIA will no longer publish an estimate of dry natural gas proved reserves. An estimate of expected future production10 of dry natural gas from total wet natural gas reserves is presented in Table 17, "Expected natural gas plant liquids and dry natural gas from total wet natural gas proved reserves, 2012."
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 the expected yield of natural gas plant liquids using its 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.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, rose sharply thereafter, increasing from 23.1 in 2011 to 34.5 in 2012.Â It is useful to note that the average crude-oil-to-natural-gas-price ratio for 2013 was 26.6, suggesting that exploration for natural gas may recover some of its share from liquids-rich plays.
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 19% in 2012 to 2,874 million barrels, mostly as a result of extensions. Texas had the largest increase in lease condensate proved reserves in 2012 (393 million barrels), followed by Oklahoma (75 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 8.6% of total oil proved reserves in 2012. U.S. lease condensate production increased 19%, from 231 million barrels in 2011 to 274 million barrels in 2012.
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. Lease condensate is excluded. Products obtained include liquefied petroleum gases (ethane, propane, and butanes), pentanes plus, and isopentane. Components may be further fractionated or mixed.As with dry natural gas, the potential U.S. supply of natural gas plant liquids is not "proved reserves" because these liquids are extracted from wet natural gas downstream of the producing wells at a natural gas processing plant. As part of the 2013 EIA NGL Realignment, EIA will no longer publish an estimate of natural gas plant liquids proved reserves. Instead, an estimate of what volume of these liquids might be extracted from total wet natural gas reserves is presented in Table 17, "Expected natural gas plant liquids and dry natural gas from total wet natural gas proved reserves, 2012."
Reserves in nonproducing reservoirs
Not all proved reserves were contained in reservoirs that were actively producing in 2012. Nonproducing reserves are those waiting for well workovers, drilling additional development or replacement wells, installing production equipment or pipeline facilities, and awaiting depletion of other zones or reservoirs before recompletion in reservoirs not currently open to production. Table 18 shows the estimated volumes of nonproducing proved reserves of crude oil, lease condensate, nonassociated natural gas, associated-dissolved natural gas, and total wet natural gas for 2012.
Maps and additional data tables
For more detailed 2012 proved reserves information than discussed above, see maps below and tables for oil (5-8) and gas (9-17) top right.
7The oil production estimates in this report are based on data reported on Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves" They may differ from the official U.S. EIA production data for crude oil and lease condensate for 2012 contained in the Petroleum Supply Annual 2012, DOE/EIA-0340(12).
8The natural gas production estimates in this report are based on data reported on Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves." Estimates may differ from the official U.S. EIA production data for natural gas published in the Natural Gas Annual 2012, DOE/EIA-0131(12).
9EIA's NGL Realignment presentation can be viewed at http://www.eia.gov/petroleum/workshop/ngl/pdf/overview061413.pdf.
Contact: Steven G. Grape or 202-586-1868