Another year of stronger oil and natural gas prices increased 2018 oil and natural gas proved reserves in the United States to another all-time record level. Crude oil and lease condensate proved reserves rose by 12%, and natural gas proved reserves rose by 9% (Table 1). U.S. crude oil and lease condensate production increased by 17% (Table 5), and U.S. total natural gas production increased by 12% (Table 9). Highlights are listed below.

Oil highlights

Proved reserves of crude oil in the United States increased 12%, from 39.2 billion barrels at year-end 2017 to 43.8 billion barrels at year-end 2018, setting another U.S. record for crude oil proved reserves (Table 7). The previous record was set in 2017 (39.2 billion barrels).

Proved reserves of lease condensate in the United States increased 14%, from 2.8 billion barrels at year-end 2017 to 3.2 billion barrels at year-end 2018 (Table 8). Adding lease condensate to crude oil yields total liquids proved reserves of 47.1 billion barrels, a 12% increase over year-end 2017 (Table 6).

U.S. crude oil and lease condensate production increased 17% from 2017 to 2018 (Table 5).

The annual average spot price for a barrel of West Texas Intermediate (WTI) crude oil at Cushing, Oklahoma increased 29% in 2018, from $51.03 in 2017 to $65.66 (Figure 6).

Producers in Texas added 2.3 billion barrels of crude oil and lease condensate proved reserves, the largest net increase of all states in 2018 (Table 6). The increase was a result of increased prices and development in the Permian Basin of West Texas.

The next largest net gains in crude oil and lease condensate proved reserves in 2018 were in New Mexico (750 million barrels) and in North Dakota (422 million barrels)(Table 6).

Natural gas highlights

Proved reserves of natural gas increased 9%, from 464.3 trillion cubic feet (Tcf) at year-end 2017 to 504.5 Tcf at year-end 2018—another U.S. record for total natural gas proved reserves (Table 10). The previous U.S. record was set in 2017.

U.S. total natural gas production increased 12% from 2017 to 2018 (Table 9).

Natural gas proved reserves from shale increased from 66% of total U.S. gas proved reserves in 2017 to 68% at year-end 2018 (Figure 12).

The annual average spot price for natural gas at the Louisiana Henry Hub increased by 12% from $2.99 per million British thermal units (MMBtu) in 2017 to $3.35 per MMBtu in 2018 (Figure 7).

Producers in Texas added 22.9 Tcf of natural gas proved reserves, the largest net increase of all states in 2018 (Table 10), as a result of increased prices and development of the Wolfcamp/Bone Spring shale play.

The next largest net gains in natural gas proved reserves by volume in 2018 were in Pennsylvania (14.2 Tcf) and New Mexico (4.2 Tcf) as a result of development of the Marcellus shale play in the Appalachian Basin and the Wolfcamp/Bone Spring shale play in eastern New Mexico (Table 10).

Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty[1] are recoverable under existing economic and operating conditions. Reserves estimates change from year to year as new discoveries are made, as existing fields are thoroughly appraised, as existing reserves are produced, as prices and costs change, and as technologies evolve.

To develop this report, EIA collects independently developed estimates of proved reserves from a sample of operators of U.S. oil and natural gas fields with its survey Form EIA-23L. EIA uses this sample to further estimate the non-reported portion of proved reserves. Responses were received from 415 of 426 sampled operators, which provided coverage of 90% of oil and gas natural gas proved reserves at the national level. Estimates were developed for the United States, each state, and state subdivisions. States with subdivisions are California, Louisiana, New Mexico, Texas, and the Federal Offshore Gulf of Mexico.

National summary

Table 1. U.S. proved reserves, and reserves changes, 2017–18 Crude oil

billion barrels Crude oil and lease condensate

billion barrels Total natural gas

trillion cubic feet U.S. proved reserves as of December 31, 2017 39.2 42.0 464.3 Extensions and discoveries 6.6 7.2 79.5 Net revisions 0.6 0.4 -27.7 Net adjustments, sales, acquisitions 1.2 1.4 22.5 Estimated production -3.7 -4.0 -34.1 Net additions to U.S. proved reserves 4.7 5.1 40.2 U.S. proved reserves as of December 31, 2018 43.8 47.1 504.5 Percent change in U.S. proved reserves 11.9% 12.1% 8.7% 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 Report of Domestic Oil and Gas Reserves

From the late 1970s to 1996, natural gas and crude oil reserves experienced a steady decline (Figure 1). In 1997, the downward trend for natural gas reversed because of innovations in horizontal drilling and hydraulic fracturing techniques that successfully increased natural gas proved reserves and production from shale formations. In 2008, the downward trend for crude oil reversed when innovations in horizontal drilling and hydraulic fracturing were applied to tight oil-bearing formations, such as the Bakken Shale of the Williston Basin. The upward trends continued until 2015, when the industry experienced a significant price drop for both oil and gas, and natural gas proved reserves were revised downward because of economics. From 2016 to year-end 2018, prices and reserves trended upwards, annually.





Proved reserves of combined crude oil and lease condensate increased in all of the top seven U.S. oil reserves states in 2018 (Figure 2). In 2018, Texas held the largest proved reserves of any state and saw the largest volumetric increase—a net increase of 2.3 billion barrels of crude oil and lease condensate proved reserves from 2017 to 2018. Most reserves additions were made in the Wolfcamp/Bone Spring shale play in West Texas (Texas Railroad Commission District 8).

New Mexico had the second-largest crude oil and lease condensate proved reserves increase—a net addition of 750 million barrels. Most reserves additions, as in Texas, were made in the Wolfcamp/Bone Spring shale play in eastern New Mexico. The third-largest net increase in proved reserves of crude oil and lease condensate was in the Bakken shale play in North Dakota, at 422 million barrels.





Proved natural gas reserves increased in five of the top eight U.S. natural gas reserves states in 2018 (Figure 3). Texas had the largest net increase in proved natural gas reserves of any state, adding 22.9 Tcf of proved natural gas reserves.

Pennsylvania had the second-largest net increase in 2018, adding 14.2 Tcf of proved natural gas reserves. Extensions to natural gas proved reserves exceeded net downward revisions by operators in the Marcellus shale play. The third-largest net increase in proved natural gas reserves was in New Mexico, where operators added 4.2 Tcf of proved reserves to the Wolfcamp/Bone Spring shale play.

Three of the eight largest gas reserves states reported a net decrease in proved reserves in 2018: Louisiana, Colorado, and Ohio. This decrease was a result of net downward revisions to natural gas proved reserves in 2018, despite each reporting an increase in proved reserves greater than 9 Tcf in the previous year (2017). Strong supply growth has reduced the U.S. natural gas price in 2019, and operators have curtailed some of their anticipated field development plans because of this price reduction.





Official EIA Oil and Gas Production Data EIA’s official production volumes are published by EIA in the Petroleum Supply Annual 2018, DOE/EIA-0340(18), and the Natural Gas Annual 2018, DOE/EIA-0131(18), DOE/EIA-0131(18), and are based on the EIA-914 report. The production numbers in the tables and figures of this report are based on data reported on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, and are used because they are consistent with EIA’s calculations of U.S. reserves. The data may differ from EIA’s official production numbers and are offered here as an indicator of production trends. Hence, they should not be cited as EIA’s official production statistics.

In 2018, U.S. crude oil and lease condensate production increased 583 million barrels (17%) from 2017’s production level, and imports of crude oil decreased 73 million barrels (-3%) from 2017’s import level (Figure 4).

U.S. natural gas production increased 12% (3.7 Tcf) in 2018, and natural gas imports decreased 5% (144 Bcf) from the 2017 level (Figure 5).





Background

This report provides estimates of U.S. proved reserves of crude oil and lease condensate and proved reserves of natural gas at the end of 2018. Changes for 2018 are measured as the difference between year-end 2017 and year-end 2018 estimates. EIA collates the data filed on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, which was submitted by 415 of the 426 sampled operators of U.S. oil and natural gas fields. EIA then estimates the non-reported portion of proved reserves for the United States, each state, and state subdivisions. State subdivisions (e.g., California Coastal Region Onshore, Louisiana North, Texas Railroad Commission District 1) are defined geographic areas within a large producing state or offshore area. State subdivision boundaries typically align with the boundaries of internal state conservation commission districts that collect production data. Within this report, EIA publishes proved reserves for state subdivisions of California, Louisiana, New Mexico, Texas, and the Federal Offshore Gulf of Mexico

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, as existing fields are more thoroughly appraised, as existing reserves are produced, as prices and costs change, and as technologies evolve.

Discoveries include new fields, identification of new reservoirs in previously discovered fields, and additions to reserves that resulted from additional drilling and exploration in previously discovered reservoirs (extensions). Extensions are typically the largest percentage of total discoveries. New fields and reservoirs generally account for only a small percentage of overall annual reserve additions. Beginning with the 2016 report, operators reported to EIA on Form EIA-23L their discoveries as a single, combined category, extensions and discoveries, and totals for that category are presented in one column on the data tables in this report.

Revisions primarily occur 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 fuel prices typically increase estimates (create positive revisions) as operators consider a broader portion of the resource base economically producible with reasonable certainty, or proved. Lower prices, on the other hand, generally reduce estimates (create negative revisions) as producers estimate that less of their resource base is producible economically.

The U.S. Securities and Exchange Commission (SEC) procedure for determining the prices underpinning their proved reserves estimates were revised in 2008 to make reserves estimates less sensitive to price fluctuations. The 2008 SEC rules require companies to use an average of the 12 first-day-of-the-month prices. EIA requires companies to follow the same procedure. (SEC and EIA estimates are not exactly the same, however; the SEC requires companies to report their owned reserves, and EIA requires companies to report their operated reserves.)

Spot market prices are not necessarily the prices used by operators in their reserve estimates for EIA because actual prices received by operators depend on their particular contractual arrangements, location, hydrocarbon quality, and other factors. However, spot prices do provide a benchmark or trend indicator. The 12-month, first-day-of-the-month average WTI crude oil spot price for 2018 was $65.66 per barrel—up 29% from 2017 (Figure 6).





The 12-month, first-day-of-the-month average natural gas spot price at Louisiana’s Henry Hub (the U.S. benchmark location for natural gas) for 2018 was $3.35 per MMBtu—a 12% increase from the previous year’s average spot price of $2.99 per MMBtu (Figure 7). A price spike of $6.24 per MMBtu was observed in January 2018, but prices declined the following month.





Proved Reserves Outlook for EIA’s next report (2019). November 12, 2018, was the first day in 2018 that the spot price of WTI crude oil was lower than $60 per barrel. On December 17, 2018, the price declined lower than $50 per barrel and stayed lower than $50 per barrel until January 8, 2019. Throughout most of 2019, the spot price of WTI hovered at or near an average of $55 per barrel. The 12-month, first-of-the-month average price of WTI for 2019 was $55.72 per barrel, a 15% drop from the 12-month, first-of-the-month average price of $65.66 per barrel in 2018. Consequently, operators may log more downward revisions of their proved reserves in 2019 because of a lower price assumption, as they curtail some of their forecasted exploration and development activity.

The 12-month, first-of-the-month average natural gas spot price at the Henry Hub in Louisiana in 2018 was $3.35 per MMBtu. However, the price dropped lower than $3.00 per MMBtu in February 2019 and remained lower than that level throughout most of 2019. The 12-month, first-of-the-month average natural gas spot price at the Henry Hub in 2019 was $2.63 per MMBtu—a decline of 21% from 2018. Consequently, it is likely that natural gas operators will revise down their proved reserves in 2019 because of a lower price assumption as well.

Throughout 2018, the number of U.S. rotary rigs in operation increased from 937 to 1,077.[2] But in 2019, the number of rigs in operation has declined 25% since the beginning of the year, dropping to 802 by November 27, 2019. As a result, EIA expects less proved reserves additions from extensions and discoveries in the 2019 reserves report.

According to EIA production statistics and its Short Term Energy Outlook forecast, U.S. production for both crude oil and natural gas in 2019 will surpass 2018’s volume by an estimated 12% for crude oil and 10% for natural gas.[3] When combined with lower prices, reduced rig counts, and increased annual production, EIA anticipates that total U.S. proved reserves will decline in 2019 for both crude oil and natural gas.

Crude oil and lease condensate proved reserves

EIA estimates that the United States had 47,053 million barrels of crude oil and lease condensate proved reserves as of December 31, 2018—an increase of 12.1% from year-end 2017. Proved reserves rose 12% (4.1 billion barrels) onshore in the Lower 48 states (U.S. Total not including Alaska, Federal Offshore [both Pacific and the Gulf of Mexico], and State Offshore reserves), and proved reserves rose 20% in Alaska and 10% in the Federal Offshore (both Pacific and the Gulf of Mexico)(Figure 8).





U.S. crude oil and lease condensate proved reserves increased by 5.1 billion barrels (12%) in 2018, as the combination of total discoveries (7.19 billion barrels) and net revisions, net acquisitions, and adjustments (1.85 billion barrels) exceeded 2018 annual production of 3.98 billion barrels (Figure 9a).





Texas saw the largest net increase in crude oil and lease condensate proved reserves (2.3 billion barrels) of all states in 2018—an increase of 13% from 2017. In 2018, the largest proved reserves gain was in the Permian Basin of West Texas (Texas Railroad Commission District 8) where operators developed the Wolfcamp/Bone Spring shale play within the Delaware Basin and the Spraberry Trend Area of the Midland Basin.

The second-largest net increase in crude oil and lease condensate proved reserves was in New Mexico (750 million barrels) in 2018—an increase of 28% from 2017. In eastern New Mexico (portions of which are within the Permian Basin) operators developed the Wolfcamp/Bone Spring shale play.

North Dakota had the third-largest increase in crude oil and lease condensate proved reserves (422 million barrels) in 2018—an increase of 8% from 2017. North Dakota (and western Montana) is the core area of the Bakken shale play in the Williston Basin.

Alaska saw the fourth-largest net increase of crude oil and lease condensate proved reserves of all states in 2018—405 million barrels (20% increase).

Louisiana experienced the largest net decline in proved reserves in 2018, a decline of 32 million barrels (-6%) of crude oil and lease condensate proved reserves

In 2018, operators reported the largest volume of extensions and discoveries of crude oil and lease condensate proved reserves in the past decade. Extensions and discoveries in 2018 outweighed the net increases of all other components of proved reserves in 2018 (Figure 9b). Figure 9b summarizes the components of U.S. crude oil and lease condensate annual reserves changes over time:





Extensions and discoveries. Reserves additions—including discoveries of new fields, identification of new reservoirs in fields discovered in previous years, and reserve additions that result from the additional drilling and exploration in previously discovered reservoirs (extensions)—added 7.2 billion barrels to U.S. crude oil and lease condensate reserves in 2018.

The largest extensions and discoveries of crude oil and lease condensate proved reserves in 2018 were in Texas, New Mexico, and Oklahoma. Texas had 3.4 billion barrels, New Mexico had 1.1 billion barrels, and Oklahoma had 0.7 billion barrels of extensions and discoveries in 2018.

Net revisions and other changes. Revisions to reserves occur primarily when operators change their estimates of what they are able to economically produce using existing technology and current economic conditions. Current prices are critical in estimating economically producible reserves. Other changes occur when operators buy and sell properties (revaluing the proved reserves in the process) and when various adjustments are made to reconcile estimated volumes.

Net upward revisions increased U.S. crude oil and lease condensate proved reserves by 413 million barrels in 2018. The largest net upward revisions of crude oil and lease condensate proved reserves were in the Federal Offshore (599 million barrels) and Alaska (441 million barrels).

The U.S. crude oil and lease condensate proved reserves associated with buying and selling properties[4] had a net increase of 676 million barrels in 2018.

Adjustments. Adjustments are the yearly changes in the published reserve estimates that cannot be attributed to the estimates for other reserve change categories because of the survey and statistical estimation methods employed. If last year’s year-end reserves for a state or state subdivision fail to match this year’s beginning year reserves, an adjustment must be made to account for that difference. Changes in the sampled reporting companies from the previous year, and imputations for missing or unreported reserve changes, are reasons why adjustments may be necessary.

In 2018, adjustments increased U.S. proved oil reserves by 764 million barrels.

Production. EIA’s official published estimate of total U.S. crude oil production is 4,011 million barrels in 2018, an increase of 17% from 2017. As estimated using Form EIA-23L responses, the United States produced 3,984 million barrels of crude oil and lease condensate in 2018, an increase of 17% from 2017 (Table 6).[5] Production onshore in the Lower 48 states (3,141 million barrels) was 21% higher than the 2017 level (2,589 million barrels), and Federal Offshore (both Pacific and Gulf of Mexico) production experienced a 5% increase based on the Form EIA-23L data.

Crude oil and lease condensate from U.S. shale plays

As of December 31, 2018, seven major shale plays[6] accounted for 49% of all U.S. crude oil and lease condensate proved reserves (Table 2). The Wolfcamp/Bone Spring shale play in the Permian Basin remains the largest oil-producing shale play in the United States. EIA publishes a series of maps and animations showing major U.S. shale plays where oil and natural gas are produced.

Table 2. Crude oil production and proved reserves from selected U.S. tight plays, 2017–18

million barrels Basin Play State(s) 2017

Production 2017

Proved

reserves 2018

Production 2018

Proved

reserves 2017–18

Reserves

change Permian Wolfcamp/Bone Spring NM, TX 592 8,319 922 11,096 2,777 Williston Bakken/Three Forks ND, MT, SD 387 5,447 458 5,862 415 Western Gulf Eagle Ford TX 411 4,815 449 4,734 -81 Anadarko, South Oklahoma Woodford OK 36 412 34 560 148 Appalachian Marcellus* PA, WV 17 279 17 345 66 Denver-Julesburg Niobrara CO, NE, WY 11 232 25 317 85 Fort Worth Barnett TX 2 20 2 20 0 Sub-total 1,456 19,524 1,907 22,934 3,410 Notes: Includes lease condensate. Bakken/Three Forks oil includes proved reserves from shale or low-permeability formations reported on Form EIA-23L. Wolfcamp/Bone Spring includes proved reserves from shale or low-permeability formations reported on Form EIA-23L in TX RRC 7C, TX RRC 8, TX RRC 8A, and NME.

* The Marcellus play in this table refers only to portions within Pennsylvania and West Virginia.

Source: U.S. Energy Information Administration, Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, 2017 and 2018

Natural gas proved reserves

The United States had 504.5 Tcf of proved natural gas reserves as of December 31, 2018. U.S. proved reserves of total natural gas (including natural gas plant liquids) increased by 40.2 Tcf (9%) (Figure 10).

Unlike in 2017, when net revisions added 41.3 Tcf to U.S. natural gas proved reserves, net revisions decreased the U.S. total by 27.7 trillion cubic feet in 2018. This decrease was far outweighed by extensions and discoveries in 2018, which added 79.5 Tcf to U.S. total natural gas proved reserves (a 12% increase in extensions and discoveries compared with 2017) (Figure 11a).

Operators in Texas, Pennsylvania, and New Mexico reported the largest net increases in natural gas proved reserves in the United States in 2018. Texas and New Mexico natural gas proved reserves each increased by 20% (net increases of 22.9 Tcf and 4.2 Tcf, respectively) because of higher prices and the development of the Wolfcamp/Bone Spring shale play in the Permian Basin. Pennsylvania reported a 16% (14.2 Tcf) increase from the Marcellus shale play. The fourth- and fifth-largest net increases in natural gas proved reserves in 2018 occurred in West Virginia (+2.6 Tcf, 7%) and Alaska (+2.3 Tcf, 35%).

Extensions and discoveries. The U.S. total of natural gas extensions and discoveries was 79.5 Tcf in 2018 (Table 3), and 81% of those discoveries were from shale plays.

Operators in Pennsylvania reported the largest amount of extensions and discoveries of natural gas proved reserves in the United States in 2018, totaling 22.3 Tcf. Texas saw the next-largest volume of extensions and discoveries in 2018 (21 Tcf). The largest natural gas discoveries in Texas were from extensions to oil fields with associated-dissolved natural gas in the Permian Basin (TX RRC District 8), nonassociated natural gas in the Haynesville/Bossier shale play (TX RRC District 6), and associated-dissolved and nonassociated natural gas in the Eagle Ford shale play (TX RRC District 4).

Table 3. Changes to proved reserves of U.S. natural gas by source, 2017–18

trillion cubic feet Source

of natural gas Year-end 2017

Proved reserves 2018

Eextensions & discoveries 2018

Revisions & other changes 2018

Production Year-end 2018

Proved reserves Shale 307.9 64.7 -8.4 -22.1 342.1 Other U.S. natural gas Lower 48 states onshore 143 14.2 -0.3 -10.6 146.3 Lower 48 states offshore 6.8 0.3 1.1 -1 7.2 Alaska 6.6 0.3 2.4 -0.3 8.9 U.S. total 464.3 79.5 -5.2 -34.1 504.5 Note: The Lower 48 states offshore subtotal in this table includes state offshore and Federal Offshore. Components may not add to total because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, 2017 and 2018

Net revisions and other changes. Net revisions decreased U.S. total natural gas proved reserves by 27.7 Tcf in 2018. In 2017, the U.S. total natural gas reserves were revised upwards by a significant amount (41.3 Tcf), and the net revision decreases in 2018 are likely a result of re-evaluation of planned development in the face of declining prices in 2019 combined with the natural decline of existing producing wells. The following states had the largest positive and negative net revisions in 2018:

Texas had the largest net revision increase of natural gas proved reserves (2.6 Tcf).

Pennsylvania had the largest net revision decrease of natural gas proved reserves of all states in 2018 (10.4 Tcf).

Ohio had the second-largest net revision decrease of natural gas proved reserves (6.5 Tcf).

Oklahoma had the third-largest net revision decrease of natural gas proved reserves (5.8 Tcf).

Despite the large net revision decreases in 2018, the volume of natural gas proved reserves increased in Pennsylvania and Oklahoma but declined in Ohio.

The net change to natural gas proved reserves from the purchase and sale of properties resulted in an additional gain of 13.7 Tcf in 2018.

Adjustments. Adjustments (yearly changes in the published reserve estimates that cannot be attributed to the estimates for other reserve change category) added 8.8 Tcf to U.S. total natural gas proved reserves in 2018.

Production. EIA’s official published estimate of marketed natural gas production is 32.8 Tcf in 2018, an increase of 12% from 2017. As EIA estimated using Form EIA-23L responses and as EIA used in the reserves calculations in this report, U.S. production of total natural gas, wet after lease separation, in 2018 was 34.1 Tcf—an increase of 12% from 2017 (Table 10).[7]

Figure 11b illustrates the components of U.S. natural gas annual reserves changes over time.





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. Most shale natural gas is nonassociated natural gas. Nonassociated natural gas accounted for almost three-quarters of gas production in the United States in 2018. The U.S. total of nonassociated natural gas proved reserves increased from 364.8 Tcf in 2017 to 384.9 Tcf in 2018—an increase of 5%. Estimated production of U.S. nonassociated natural gas increased 9%—from 23.2 Tcf in 2017 to 25.4 Tcf in 2018. The largest increase in 2018 nonassociated natural gas proved reserves (14.1 Tcf) was in Pennsylvania from the Marcellus shale play. The largest decrease in 2018 nonassociated natural gas proved reserves (-2.9 Tcf) was in Louisiana (Table 11).

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 natural gas in solution with crude oil (dissolved). Associated-dissolved natural gas accounted for 25% of production in the United States in 2018. The U.S. total of associated-dissolved natural gas proved reserves increased from 99.4 Tcf in 2017 to 119.6 Tcf in 2018—an increase of 20%. Estimated production of associated-dissolved natural gas increased 20%—from 7.2 Tcf in 2017 to 8.6 Tcf in 2018. The largest increase in 2018 associated-dissolved natural gas proved reserves (11.7 Tcf) was in Texas (76% of this increase was in the Permian Basin)(Table 12).

Coalbed natural gas (discontinued)

At year-end 2017, coalbed methane proved reserves represented only 2.6% of the U.S. total natural gas proved reserves.[8] EIA did not include coalbed methane proved reserves as a separate data category in this 2018 report. It is included as conventional natural gas.

Natural gas from U.S. shale plays

Shale formations can be both the source rock (where the oil and gas is generated from organic matter in the rock) and the producing formation (the rock from which the oil and gas is produced). Shale reservoirs must typically be hydraulically fractured to produce natural gas at economic rates. Horizontally-drilled wells perform substantially better than vertical wells (but they are more expensive to drill and complete at the same depth). Proved reserves of U.S. natural gas from shale increased from 307.9 Tcf in 2017 to 342.1 Tcf in 2018 (Table 13).

The share of natural gas from shale compared with total U.S. natural gas proved reserves increased from 66% in 2017 to 68% in 2018 (Figure 12). Estimated production of natural gas from shale increased 19%—from 18.6 Tcf in 2017 to 22.0 Tcf in 2018 (Table 14).





The following eight states reported the most proved reserves of shale natural gas (Figure 13).

Rankings for natural gas proved reserves from shale in 2018

Pennsylvania (103.4 Tcf) Texas (100.8 Tcf) West Virginia (31.7 Tcf) Louisiana (25.6 Tcf) Ohio (24.0 Tcf) Oklahoma (21.4 Tcf) New Mexico (13.1 Tcf) North Dakota (11.7 Tcf)

EIA collected production and proved reserves data for nine major U.S. shale plays in 2018 (Table 4). The Marcellus shale play remained the play with the largest amount of natural gas proved reserves from shale in 2018. Its proved reserves increased in 2018 by 9%. The second-largest shale gas play in 2018 was the Wolfcamp/Bone Spring shale play of the Permian Basin, which surpassed the Bossier/Haynesville shale play in 2018. Proved shale gas reserves in the Wolfcamp/Bone Spring shale play increased by 14.8 Tcf (46%) in 2018. Table 4. U.S. shale plays: natural gas production and proved reserves, 2017–18

trillion cubic feet Basin Shale play State(s) 2017 Production 2017 Proved Reserves 2018 Production 2018 Proved Reserves Change in Production Change in Proved Reserves Appalachian Marcellus* PA, WV 6.9 123.8 7.6 135.1 0.7 11.3 Permian Basin Wolfcamp/Bone Spring NM,TX 2.2 31.9 3.3 46.7 1.1 14.8 TX-LA Salt Haynesville/Bossier LA, TX 1.8 35.9 2.6 44.7 0.8 8.8 Western Gulf Eagle Ford TX 1.9 27.4 2 30.8 0.1 3.4 Appalachian Utica/Pt. Pleasant OH 1.7 26.5 2.3 23.9 0.6 -2.6 Anadarko, S. OK Woodford OK 1.3 22.5 1.3 21.4 0 -1.1 Fort Worth Barnett TX 1.2 19.2 1.2 17.2 0 -2 Williston Bakken/Three Forks MT, ND 0.7 10.2 0.9 12 0.2 1.8 Arkoma Fayetteville AR 0.6 7.1 0.5 6 -0.1 -1.1 Sub-total 18.3 304.5 21.7 337.8 3.4 33.3 Other shale gas 0.3 3.4 0.4 4.3 0.1 0.9 All U.S. shale gas 18.6 307.9 22.1 342.1 3.5 34.2 Note: Table values are based on natural gas proved reserves and production volumes from shale reported and imputed from data on Form EIA-23L. * In this table, the Marcellus shale play refers only to portions within Pennsylvania and West Virginia. Other shale includes proved reserves and production reported from shale on Form EIA-23L assigned by EIA to the Niobrara, Antrim, and Monterey shale plays.

Columns may not add to subtotals because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, 2017 and 2018 EIA publishes a series of maps showing the nation’s shale gas resources for both shale plays and geologic basins. Dry natural gas proved reserves 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, usually downstream at a natural gas processing plant. Not all produced gas has to be processed at a natural gas processing plant. Some produced gas is sufficiently dry and satisfies pipeline transportation standards without processing.

EIA calculates its estimate of dry natural gas proved reserves by first estimating the expected yield of natural gas plant liquids from total natural gas proved reserves and by then subtracting the gas equivalent volume of the natural gas plant liquids from total natural gas proved reserves. U.S. dry natural gas proved reserves increased from an estimated 438.5 Tcf in 2017 to 474.8 Tcf in 2018, an increase of 8.3%.[9] 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 Report of Domestic Oil and Gas Reserves. Natural gas plant liquids are determined from data reported on Form EIA-64A, Annual Report of the Origin of Natural Gas Liquids Production. EIA calculates the expected yield of natural gas plant liquids by using estimates of total natural gas reserves and a recovery factor determined for each area of origin based on Form EIA-64A data. Lease condensate 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 propane, butane, and natural gasoline, which are recovered at downstream natural gas processing plants or facilities. Lease condensate usually enters the crude oil stream. As of December 31, 2018, the United States had 3.2 billion barrels of lease condensate proved reserves, an increase of 0.4 billion barrels from 2017 (14%). U.S. lease condensate production increased 18%—from 246 million barrels in 2017 to 288 million barrels in 2018 (Table 8). Natural gas plant liquids Natural gas plant liquids (unlike lease condensate) remain within the natural gas after it passes through lease separation equipment. These liquids are normally separated from the natural gas at processing plants, fractionators, and cycling plants. Natural gas plant liquids that are extracted include ethane, propane, butane, isobutane, and natural gasoline. Lease condensate is not a natural gas plant liquid and is not a component of the natural gas plant liquids total. The estimated volume of natural gas plant liquids contained in proved reserves of total natural gas increased from 19.2 billion barrels in 2017 to 21.8 billion barrels in 2018 (a 13.5% decrease)(Table 15).[10] Reserves in nonproducing reservoirs Not all proved reserves are contained in actively producing reservoirs. Reserves within actively producing reservoirs are known as proved, developed, producing reserves. Two additional categories for proved reserves exist: proved, developed, nonproducing reserves (PDNPs), and proved, undeveloped reserves (PUDs). Examples of PDNPs include: existing producing wells that are shut in awaiting well workovers; drilled wells that await completion; drilled well sites that require installation of production equipment or pipeline facilities; or behind-the-pipe reserves that require the depletion of other zones or reservoirs before they can be placed on production (by recompleting the well). An example of PUDs are undrilled offset well locations (acreage adjacent to an existing producing well that is scheduled to have wells drilled upon it). However, additional conditions must be met to satisfy the definition of proved reserves:

The locations must be directly offset to wells that have commercial production in the objective formation

Such locations must be reasonably certain to be within the known proved productive limits of the objective formation

The locations must conform to existing well spacing regulations where applicable

The locations must be reasonably certain to be developed. SEC rules currently require development within a five-year period

Reserves from other locations beyond direct offset wells are categorized as proved, undeveloped reserves only where interpretations of geological and engineering data from wells indicate with reasonable certainty that the objective formation is laterally continuous and contains commercially recoverable petroleum at that location.

Table 16 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 2018. As of December 31, 2018, the United States had 17.3 billion barrels of crude oil proved reserves and 192.1 Tcf of natural gas proved reserves in nonproducing reservoirs. These volumes are an 8% increase for crude oil and a 15% increase for total natural gas in nonproducing reservoirs from the 2017 levels published in EIA’s previous report.[11]

Maps and additional data tables

Maps

Figure 14. Crude oil and lease condensate proved reserves by state/area, 2018

Figure 15. Changes in crude oil and lease condensate proved reserves by state/area, 2017–18

Figure 16. Natural gas proved reserves by state/area, 2018

Figure 17. Changes in natural gas proved reserves by state/area, 2017–18

Oil tables

Table 5. U.S. proved reserves of crude oil and lease condensate, crude oil, and lease condensate, 2008–18

Table 6. Crude oil and lease condensate proved reserves, reserves changes, and production, 2018

Table 7. Crude oil proved reserves, reserves changes, and production, 2018

Table 8. Lease condensate proved reserves, reserves changes, and production, 2018

Natural gas tables

Table 9. U.S. proved reserves of total natural gas, wet after lease separation, 2001–18

Table 10. Total natural gas proved reserves, reserves changes, and production, wet after lease separation, 2018

Table 11. Nonassociated natural gas proved reserves, reserves changes, and production, wet after lease separation, 2018

Table 12. Associated-dissolved natural gas proved reserves, reserves changes, and production, wet after lease separation, 2018

Table 13. Shale natural gas proved reserves and production, 2015–18

Table 14. Shale natural gas proved reserves, reserves changes, and production, wet after lease separation, 2018

Table 15. Estimated natural gas plant liquids and dry natural gas proved reserves, 2018

Miscellaneous/other tables

Table 16. Reported proved nonproducing reserves of crude oil, lease condensate, nonassociated gas, associated-dissolved gas, and total gas (wet after lease separation), 2018









Footnotes:

1. Reasonable certainty assumes a probability of recovery of 90% or greater.

2. EIA Crude Oil and Natural Gas Drilling Activity, EIA and Baker Hughes, Inc., Houston, Texas.

3. EIA’s Short Term Energy Outlook, November 13, 2019.

4. How can acquisitions in a given year exceed sales? When it comes to proved reserves, an exchange of properties is not a zero-sum game. Operators often have differing development plans for oil- and natural gas-bearing properties they purchase from or exchange with other operators. For example, when an operator purchases acreage that is adjacent to its producing wells, the operator can drill longer horizontal laterals and add more proved reserves..

5. The oil production estimates in this report are based on data reported on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves. They are used to weight estimates used in developing total proved reserves, and may differ slightly from the official U.S. EIA production data for crude oil and lease condensate for 2018 contained in the Petroleum Supply Annual 2018, DOE/EIA-0340(18).

6. Shale plays produce oil from petroleum-bearing formations with low permeability, such as the Eagle Ford and the Bakken, which must be hydraulically fractured to produce oil at commercial rates. A kerogen-bearing, thermally mature shale is the source rock that typically lends its name to the play. Often, several oil-producing layers are stacked in these plays, but the source rock is the shale.

7. The natural gas production estimates in this report are based on data reported on Form EIA-23L, Annual Report 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 2018, DOE/EIA-0131(18).

8. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017, November 2018, pg. 18.

9. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017, November 2018, Table 17.

10. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017, November 2018, Table 17.

11. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2017, November 2018, Table 18.

Contact: Steven G. Grape or 202-586-1868