Natural Gas

The decline in oil and natural gas prices in 2019 interrupted a 2-year trend of rising proved reserves of oil and natural gas in the United States. Proved reserves of crude oil and lease condensate remained effectively the same in 2019 as in 2018 (a very slight increase of 0.1%), and proved reserves of natural gas declined by 2% (Table 1). Although the U.S. had enough extensions and discoveries of proved reserves of crude oil and natural gas to replace annual production in 2019, reserves were revised downwards due to lower prices. Highlights are listed below.

Oil highlights

• The annual average spot price for a barrel of West Texas Intermediate (WTI) crude oil at Cushing, Oklahoma decreased 15.1% in 2019, from $65.66 in 2018 to $55.77 (Figure 6).
• Proved reserves of crude oil increased 367 million barrels in 2019 while proved reserves of lease condensate (produced from gas wells) dropped 313 million barrels yielding a net gain of 54 million barrels of proved reserves of crude oil and lease condensate (0.1%) to 47.1 billion barrels at year-end 2019 (Table 5).
• At 47.1 billion barrels, U.S. proved reserves of oil in 2019 remain at the record level set in 2018.
• U.S. production of crude oil and lease condensate increased 12.7% from 2018 to 2019 (Table 5).
• Producers in Alaska added 259 million barrels (MMBbl) of proved reserves of crude oil and lease condensate in 2019, the largest net increase in all states (Table 6).
• Producers in New Mexico saw the second-largest net increase in proved reserves of crude oil and lease condensate in 2019 (+226 MMBbl) and in Texas had the third largest (+179 MMBbl). Extensions and discoveries in the Permian Basin of eastern New Mexico and west Texas contributed the most to these annual gains. (Table 6)
• The largest net decrease in proved reserves of crude oil and lease condensate of all states in 2019 was in Colorado (-154 MMBbl). (Table 6)

Natural gas highlights

• The annual average spot price for natural gas at the Louisiana Henry Hub decreased by 21.5% from $3.35 per million British thermal units (MMBtu) in 2018 to $2.63 per MMBtu in 2019 (Figure 7).
• Proved reserves of natural gas decreased 1.9%, from 504.5 trillion cubic feet (Tcf) at year-end 2018 to 494.9 Tcf at year-end 2019 (Table 10).
• This is the first annual decrease in proved reserves of natural gas in the United States since 2015, but reserves remain at their 2nd highest level ever.
• Total U.S. production of natural gas increased 9.8% from 2018 to 2019 (Table 9).
• Proved reserves of natural gas from shale increased from 68% of the U.S. total in 2018 to 71% at year-end 2019 (Figure 12).
• The largest net gain in proved reserves of U.S. natural gas by volume in 2019 was in Ohio (+10.4 Tcf) as a result of continuing development of the Utica/Pt. Pleasant shale play in the Appalachian Basin (Table 10).
• The largest net decrease in proved reserves of natural gas in all states in 2019 was in Texas (-12 Tcf) (Table 10). Net downward revisions of reserves in the Eagle Ford, Barnett, and Bossier shale plays contributed the most to the annual drop (Table 4).

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 prepare 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 Form EIA-23L. EIA uses this sample to further estimate the portion of proved reserves from operators who do not report. Responses were received from 372 of 412 sampled operators, which provided coverage of about 90% of proved reserves of oil and natural gas at the national level. EIA develops estimates for the United States, each state individually, and some 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, 2018–19

	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, 2018	43.8	47.1	504.5
Extensions and discoveries	6.1	6.7	56.7
Net revisions	-1.9	-2.4	-35.3
Net adjustments, sales, acquisitions	0.3	0.3	6.4
Estimated production	-4.2	-4.5	-37.4
Net additions to U.S. proved reserves	0.4	0.1	-9.6
U.S. proved reserves as of December 31, 2019	44.2	47.1	494.9
Percent change in U.S. proved reserves	0.80%	0.10%	-1.90%
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, U.S. reserves of natural gas and crude oil experienced a steady decline (Figure 1). In 1997, the downward trend for natural gas reversed as producers introduced innovations in directional drilling and hydraulic fracturing techniques that successfully increased proved reserves and production of natural gas from shale formations. In 2008, the downward trend for crude oil reversed when innovations in directional 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 proved reserves were revised downward because these lower prices did not support operators’ projections of resource development. From 2016 to 2018, U.S. oil and natural gas prices and reserves trended upwards by at least 9% annually. In 2019, prices declined to levels only slightly higher than those of 2015 and that trend of rising reserves was interrupted— proved reserves of U.S. crude oil and lease condensate remained at the 2018 level, while natural gas reserves declined slightly.

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Proved reserves of combined crude oil and lease condensate increased in five the top seven U.S. oil reserves states in 2019 (Figure 2). In 2019, operators in the state of Alaska reported the largest volumetric increase in its proved reserves of crude oil and lease condensate—a net increase of 259 MMBbl. Most reserves additions were made on the north slope of Alaska.

Operators in New Mexico had the second-largest increase of proved crude oil and lease condensate reserves—a net addition of 226 MMBbl. The third-largest net increase in proved reserves of crude oil and lease condensate was in Texas, at 179 MMBbl. The New Mexico reserves additions and most of the Texas reserves additions were made in the Permian Basin, the center of the Wolfcamp/Bone Spring shale play.

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Proved natural gas reserves decreased in four of the top eight U.S. natural gas reserves states in 2019 (Figure 3). Texas saw the largest net decrease in proved natural gas reserves of any state, a net decrease of 12.1 Tcf. Oklahoma saw the second-largest net decrease in 2019, declining by 4.7 Tcf of proved natural gas reserves. Decreases were a result of net downward revisions to proved reserves of natural gas in 2019. The average U.S. natural gas price declined 21.5% in 2019, curtailing development plans and reducing the economically recoverable volume of existing proved reserves.

In spite of the significant natural gas price reduction during 2019, operators in the northeastern U.S. reported significant additions of proved reserves. Operators in the state of Ohio reported the largest net increase in proved natural gas reserves of all States in 2019, adding a net 10.4 Tcf in the Utica/Pt. Pleasant shale play. Pennsylvania had the second-largest natural gas proved reserves increase—a net addition of 2.4 Tcf, where extensions in the Marcellus shale play exceeded net downward revisions of proved natural gas reserves.

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In 2019, production of crude oil and lease condensate increased in the United States by 506 MMBbl (12.7%) from 2018’s production level. Crude oil imports decreased 353 MMBbl (-12.4%) from 2018 (Figure 4).

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U.S. natural gas production increased 9.8% (3.3 Tcf) in 2019, and natural gas imports decreased 5.1% (0.1 Tcf) from the 2018 level (Figure 5).

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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 2019. Changes for 2019 are measured as the difference between year-end 2018 and year-end 2019 estimates. EIA processes data filed on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, which was submitted by 372 of the 412 sampled operators of U.S. oil and natural gas fields. EIA then estimates the portion of proved reserves that is not reported for the United States, each state, and some federal offshore 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 typically make up the largest share of total discoveries. New fields and reservoirs generally account for only a small share 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 net 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 2019 was $55.77 per barrel—a price drop of -15.1% from 2018 (Figure 6).

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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 2019 was $2.63 per MMBtu—a 21.5% decrease from the previous year’s average spot price of $3.35 per MMBtu (Figure 7). Although the natural gas spot price began at $3.25 per MMBtu on January 1, 2019, after March, the first-day-of-the-month spot price remained below $3 throughout the year.

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Proved Reserves Outlook for EIA’s next report (2020). The World Health Organization announced on March 11, 2020 that the COVID-19 outbreak was characterized as a pandemic and on March 13, a National Emergency was declared in the United States. In addition to travel restrictions, many states imposed mandatory lockdowns and issued stay-at-home orders, and people avoiding exposure chose not to travel as well. Consequently, demand fell for transportation fuels, fuel prices fell, and a critical shortage of available storage for liquids production was created. On April 20, 2020, for the first time since WTI began trading on the New York Mercantile Exchange (NYMEX) in 1983, the price of West Texas Intermediate oil futures fell below zero dollars per barrel[2].

The 12-month, first-of-the-month average crude oil spot price for West Texas Intermediate at Cushing, Oklahoma and the natural gas spot price at the Henry Hub in Louisiana in 2020 declined from the 2019 level—the 2020 oil price declined 29.8% and natural gas price declined 22.4%. Consequently, EIA expects that oil and gas well operators will revise down their proved reserves in 2020.

During the last week of 2019, 805 rotary rigs were operating in the United States.[3] By November 20, 2020, the number of rigs operating in the United States had declined to 310 (-61%). As a result, EIA expects operators to report significantly fewer additions of proved reserves from extensions and discoveries in the 2020 reserves report.

According to EIA’s Short-Term Energy Outlook forecast, U.S. production in 2020 will decline an estimated 7% for crude oil and 2% for natural gas.[4] When combined with lower prices, reduced rig counts, and decreased annual production, EIA anticipates that total U.S. proved reserves will decline in 2020 for both crude oil and natural gas.

Proved reserves of crude oil and lease condensate

EIA estimates that the United States had 47,107 MMBbl of proved reserves of crude oil and lease condensate as of December 31, 2019—an increase of 0.1% from year-end 2018. Proved reserves rose 10% (259 MMBbl) in Alaska, but declined 0.4% onshore in the Lower 48 states (excluding Federal Offshore [both Pacific and the Gulf of Mexico], and State Offshore reserves), and declined 1.1% in the Federal Offshore (both Pacific and the Gulf of Mexico)(Figure 8).

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U.S. proved reserves of crude oil and lease condensate increased only slightly by 54 MMBbl (0.1%) in 2019, as the combination of downward net revisions and production almost completely offset the 6.67 billion barrels of total discoveries for the year (Figure 9a).

Alaska saw the largest net increase in proved crude oil and lease condensate reserves (259 MMBbl) of all states in 2019—an increase of 10.7% from 2018.

Operators in New Mexico had the second-largest net increase in 2019—226 MMBbl of proved crude oil and lease condensate reserves—an increase of 6.6% from 2018. Texas added a net increase of 179 MMBbl of proved reserves (0.9%). Operators in the west Texas state subdivision of TX Railroad Commission District 8 had the mathematically largest net increase (+652 MMBbl) of all state subdivisions for the year in 2019, but the state total for Texas was reduced when combined with all other Texas subdivisions.

Operators in Ohio had the fourth-largest increase in proved crude oil and lease condensate reserves (106 MMBbl) in 2019—an increase of 50.5% from 2018. Operators acquired and reassessed proved lease condensate reserves for their operations in the Utica shale play in the Appalachian Basin.

Colorado experienced the largest net decline in proved reserves in 2019, -154 MMBbl (-9.0%) of proved crude oil and lease condensate reserves.

Extensions and discoveries in 2019 outweighed the net increases of all other components of proved reserves (Figure 9b), but the gains from this component were countered by a combination of increased production and net revisions to proved reserves that were negative. Figure 9b summarizes the components of U.S. crude oil and lease condensate annual reserves changes over time:

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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 6.67 billion barrels to U.S. crude oil and lease condensate reserves in 2019.

The largest extensions and discoveries of proved reserves of crude oil and lease condensate in 2019 were in Texas, New Mexico, and North Dakota. Texas had 3.5 billion barrels, New Mexico had 1.1 billion barrels, and North Dakota had 0.7 billion barrels of extensions and discoveries in 2019.

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 downward revisions decreased proved reserves of U.S. crude oil and lease condensate by -2.38 billion barrels in 2019. The largest net downward revisions of proved reserves of crude oil and lease condensate were in Texas (net revisions of proved reserves of crude oil and lease condensate accounted for -1.6 billion barrels in 2019).

The proved reserves of U.S. crude oil and lease condensate associated with buying and selling properties[5] resulted in a net increase of 884 MMBbl in 2019.

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. For example, should 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. Other examples that contribute to adjustments include changes in the selected reporting companies from the previous year, and imputations for missing or unreported reserve changes.

In 2019, the sum of all of EIA’s adjustments for U.S. proved oil reserves was -630 MMBbl.

Production. EIA’s official published estimate of total U.S. crude oil production (including lease condensate) is 4,470 MMBbl in 2019, an increase of 11.7% from 2018. As estimated using Form EIA-23L responses, the United States produced 4,490 MMBbl of crude oil and lease condensate in 2019, an increase of 12.7% from 2018 (Tables 5 and 6).[6] Production onshore in the Lower 48 states (3,591 MMBbl) was 14.3% higher than the 2018 level (3,141 MMBbl), and Federal Offshore (both Pacific and Gulf of Mexico) production experienced a 9.6% increase based on the Form EIA-23L data (rising from 649 MMBbl in 2018 to 711 MMBbl in 2019).

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

As of December 31, 2019, seven major shale plays[7] accounted for 49.3% of all proved reserves of U.S. crude oil and lease condensate (Table 2). The Wolfcamp/Bone Spring shale play in the Permian Basin remains the largest oil-producing shale play in the United States. Of the seven selected major U.S. shale plays with proved reserves of crude oil listed in Table 2, the Wolfcamp/Bone Spring shale play is the only one that had a net gain in proved reserves in 2019. EIA publishes a series of maps 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, 2018–19
million barrels

Basin	Play	State(s)	2018 Production	2018 Proved reserves	2019 Production	2019 Proved reserves	2018–19 Reserves change
Permian	Bone Spring, Wolfcamp	NM, TX	922	11,096	1,209	11,096	898
Williston	Bakken/Three Forks	ND, MT, SD	458	5,862	517	5,845	-17
Western Gulf	Eagle Ford	TX	449	4,734	451	4,297	-437
Anadarko, South Oklahoma	Woodford	OK	34	560	53	524	-36
Appalachian	Marcellus*	PA, WV	17	345	21	326	-19
Denver-Julesburg	Niobrara	CO, KS,NE, WY	25	317	25	235	-82
Fort Worth	Barnett	TX	2	20	2	19	-1
Sub-total			1,907	22,934	2,278	23,240	306
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, 2018 and 2019

Proved reserves of natural gas

The United States had 494.9 Tcf of proved natural gas reserves as of December 31, 2019. U.S. proved reserves of total natural gas (including natural gas plant liquids) decreased by 9.6 Tcf (1.9%) (Figure 10).

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In 2018, extensions and discoveries exceeded net revisions and production, however in 2019 the opposite was true. Net downward revisions of 35.3 Tcf when combined with annual production of 37.4 Tcf were larger than the 56.7 Tcf of extensions and discoveries of natural gas proved reserves in 2019 (Figure 11a), and the National total has declined as a result.

Texas, Oklahoma, and Wyoming reported the largest net decreases in proved reserves of natural gas of all states in 2019. Proved reserves of natural gas in Texas decreased by 8.7% overall as downward revisions of natural gas reserves in the Eagle Ford and Barnett Shale plays exceeded gains from the proved reserves of associated-dissolved natural gas that accompanied crude oil development in the Permian Basin. Oklahoma’s natural gas reserves (which includes the Woodford shale play) declined 11.6%. Wyoming’s proved natural gas reserves declined 17.8%—unlike Texas or Oklahoma, which had extensions of 15 Tcf and 5 Tcf from the Wolfcamp and Woodford shale plays to alleviate a portion of their State’s downward revisions and production, Wyoming had only 0.4 Tcf of extensions and discoveries during 2019.

Ohio, Pennsylvania, and Louisiana reported the largest net increases in proved natural gas reserves in 2019. Ohio reported a 42.4% (10.4 Tcf) increase, as operators in the Utica/Pt. Pleasant shale play reported record-level acquisitions of reserves from their competitors and applied new valuation to that volume. Pennsylvania reported a 2.3% (2.4 Tcf) increase in proved natural gas reserves from the Marcellus shale play. Louisiana reported a 6.9% (2.4 Tcf) increase in proved natural gas reserves in 2019 from the Haynesville shale play in northern Louisiana.

Extensions and discoveries. The U.S. total of natural gas extensions and discoveries in 2019 was 56.7 Tcf (Table 3), and 82.0% of those discoveries were from shale plays.

Operators in Texas reported the largest extensions and discoveries of proved natural gas reserves in the United States in 2019, totaling 15.7 Tcf (Table 10). 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 nonassociated natural gas in the Eagle Ford shale play (TX RRC District 4).

Pennsylvania saw the next-largest volume of extensions and discoveries in 2019 (13.8 Tcf). These discoveries were in the Marcellus shale play of southwestern Pennsylvania.

Table 3. Changes to proved reserves of U.S. natural gas by source, 2018–19
trillion cubic feet

Source of natural gas	Year-end 2018 Proved reserves	2019 Eextensions & discoveries	2019 Revisions & other changes	2019 Production	Year-end 2019 Proved reserves
Shale	342.1	46.5	-9.9	-25.6	353.1
Other U.S. natural gas
Lower 48 states onshore	146.3	9.7	-19.6	-10.4	125.9
Lower 48 states offshore	7.2	0.3	0.1	-1.1	6.5
Alaska	8.9	0.3	0.5	-0.3	9.4
U.S. total	504.5	56.7	-28.9	-37.4	494.9
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, 2018 and 2019

Net revisions and other changes. Net revisions decreased U.S. total proved natural gas reserves by 35.3 Tcf in 2019 (Table 9). In 2018, the U.S. total natural gas reserves were revised downwards by 27.7 Tcf, and the net revision decreases in 2019 are both a continuation of that trend throughout 2019 and a recognition of demand destruction caused by the COVID-19 pandemic in 2020. The following states had the largest positive and negative net revisions in 2019 (Table 10):

• Texas had the largest net revision decrease of proved natural gas reserves of all states in 2019 (-16.3 Tcf).
• Oklahoma had the second-largest net revision decrease of proved natural gas reserves (-6.7 Tcf).
• West Virginia had the third-largest net revision decrease of proved natural gas reserves (-5.2 Tcf).
• Despite the large net revision decrease in 2019, the volume of proved natural gas reserves increased in West Virginia by 4.4%.
• Ohio had the largest net revision increase of proved natural gas reserves of all states in 2019 (3.9 Tcf).

The net change to proved natural gas reserves from the purchase and sale of properties resulted in an additional gain of 16.2 Tcf in 2019.

Adjustments. Adjustments are yearly changes in the published reserve estimates that EIA cannot attribute to other reserve change categories. In 2019, the sum of all of EIA’s adjustments for proved natural gas reserves was 9.8 Tcf.

Production. EIA’s official published estimate of marketed natural gas production is 36.5 Tcf in 2019, an increase of 10.6% from 2018. EIA estimates (using Form EIA-23L responses) that U.S. production of total natural gas, wet after lease separation, in 2019 was 37.4 Tcf—an increase of 9.8% from the 2018 estimate (34.1 Tcf) published in last year’s report (Tables 9 and 10).[8]

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

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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. Nonassociated natural gas accounted for three-quarters (75.4%) of proved natural gas reserves in the United States in 2019. The U.S. total of proved reserves of nonassociated natural gas decreased from 384.9 Tcf in 2018 to 373.1 Tcf in 2019—a decrease of 3.1% (Table 11). Estimated production of U.S. nonassociated natural gas increased 7.1%—from 25.4 Tcf in 2018 to 27.3 Tcf in 2019. The largest decrease in 2019 proved nonassociated natural gas reserves (-14.6 Tcf) was in Texas. The largest increase in 2019 proved nonassociated natural gas reserves (+10.3 Tcf) was in Ohio from the Utica/Pt. Pleasant shale play.

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 24.6% of proved natural gas reserves in the United States in 2019. The U.S. total proved reserves of associated-dissolved natural gas increased from 119.6 Tcf in 2018 to 121.9 Tcf in 2019—an increase of 1.9% (Table 12). Estimated production of associated-dissolved natural gas increased 18%—from 8.6 Tcf in 2018 to 10.2 Tcf in 2019. The largest increase proved reserves of associated-dissolved natural gas in 2019 was in Texas (2.5 Tcf), caused by the oil reserves additions in the Permian Basin).

Coalbed natural gas (discontinued since the 2018 report)

At year-end 2017, coalbed methane proved reserves represented only 2.6% of the U.S. total natural gas proved reserves.[9] 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). When a sandstone or carbonate formation produces oil and gas, these rock layers are typically permeable enough to allow oil and gas to easily flow to a nearby wellbore. Shale formations have very low permeability and must typically be hydraulically fractured to produce natural gas at economic rates. Horizontally-drilled wells perform substantially better than vertical wells, though they are more expensive to drill and complete at the same depth because they are longer and the drilling process is more complex.[10] Proved reserves of U.S. natural gas from shale increased 3.2%, from 342.1 Tcf in 2018 to 353.1 Tcf in 2019 (Table 13).

The share of total U.S. natural gas made up by natural gas from shale increased from 67.8% in 2018 to 71.3% of proved natural gas reserves in 2019 (Figure 12). Estimated production of natural gas from shale increased 15.9%—from 22.1 Tcf in 2018 to 25.6 Tcf in 2019 (Table 13).

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The eight states that reported the most shale natural gas proved reserves in 2019 are shown in Figure 13. Operators in Pennsylvania reported the most proved reserves of shale natural gas in 2019 with 105.4 Tcf, and Texas reported the second-largest reserves with 93.5 Tcf. Proved shale natural gas reserves in Ohio were 34.4 Tcf, making it the third-largest in 2019, now larger than the proved shale gas reserves reported in West Virginia (34.0 Tcf) and those in Louisiana (29.6 Tcf). Oklahoma reported 20.9 Tcf, New Mexico reported 13.8 Tcf, and North Dakota reported 12.5 Tcf of proved shale natural gas reserves in 2019.

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EIA collected production and proved reserves data for nine major U.S. shale plays in 2019 (Table 4). The Marcellus shale play remained the play with the largest amount of proved reserves of natural gas from shale in 2019. Proved reserves in the Marcellus increased by 4.3 Tcf (3.2%) in 2019. The second-largest shale gas play in 2019 was the Wolfcamp/Bone Spring shale play of the Permian Basin. Proved shale gas reserves in the Wolfcamp/Bone Spring shale play increased by 2.6 Tcf (5.6%) in 2019.

Table 4. U.S. shale plays: natural gas production and proved reserves, 2018–19
trillion cubic feet

Basin	Shale play	State(s)	2018 Production	2018 Proved Reserves	2019 Production	2019 Proved Reserves	Change in Production	Change in Proved Reserves
Appalachian	Marcellus*	PA, WV	7.6	135.1	8.7	139.4	1.1	4.3
Permian Basin	Wolfcamp/Bone Spring	NM,TX	3.3	46.7	4.5	49.3	1.2	2.6
TX-LA Salt	Haynesville/Bossier	LA, TX	2.6	44.7	3.4	46.7	0.8	2.0
Western Gulf	Eagle Ford	TX	2.0	30.8	2.1	26.6	0.1	-4.2
Appalachian	Utica/Pt. Pleasant	OH	2.3	23.9	2.6	34.4	0.3	10.5
Anadarko, S. OK	Woodford	OK	1.3	21.4	1.5	20.9	0.2	-0.5
Fort Worth	Barnett	TX	1.2	17.2	1.1	14.1	-0.1	-3.1
Williston	Bakken/Three Forks	MT, ND	0.9	12.0	1.0	12.2	0.1	0.2
Arkoma	Fayetteville	AR	0.5	6.0	0.5	5.1	0.0	-0.9
Sub-total			21.7	337.8	25.4	348.7	3.7	10.9
Other shale gas			0.4	4.3	0.1	4.4	-0.3	0.1
All U.S. shale gas			22.1	342.1	25.5	353.1	3.4	11.0
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, 2018 and 2019

EIA publishes a series of maps showing the nation’s shale gas resources for both shale plays and geologic basins.

Proved U.S. reserves of dry natural gas

Dry natural gas is the volume of natural gas 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 the proved reserves of dry natural gas in the United States 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.

Proved reserves of dry natural gas in the United States decreased from an estimated 474.8 Tcf in 2018 to 465.4 Tcf in 2019, a decrease of 2.0%.[11]

Proved reserves of lease condensate and natural gas plant liquids

Operators of natural gas fields report their estimates of lease condensate reserves and production 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, 2019, the United States had proved reserves of 2.9 billion barrels of lease condensate, a decrease of 0.3 billion barrels from 2018 (-9.7%) (Table 8). U.S. lease condensate production increased 11.5%—from 288 MMBbl in 2018 to 321 MMBbl in 2019.

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, natural gasoline, and plant condensate. Plant condensate is similar to lease condensate in that it usually enters the crude oil stream, but is recovered at a gas processing plant rather than lease separation facilities.

The estimated volume of natural gas plant liquids contained in proved reserves of total natural gas decreased from 21.8 billion barrels in 2018 to 21.7 billion barrels in 2019 (a 0.9% decrease)(Table 15).[12]

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 conform to existing well spacing regulations where applicable

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 2019. As of December 31, 2019, the United States had 16.3 billion barrels of crude oil proved reserves and 184.0 Tcf of natural gas proved reserves in nonproducing reservoirs. These volumes are a 5.8% decrease for crude oil and a 4.2% decrease for total natural gas in nonproducing reservoirs from the 2018 levels published in EIA’s previous report.[13]

Maps and additional data tables

Maps
Figure 14. Proved reserves of U.S. crude oil and lease condensate by state/area, 2019
Figure 15. Changes in proved reserves of crude oil and lease condensate by state/area, 2018–19
Figure 16. Proved reserves of U.S. natural gas by state/area, 2019
Figure 17. Changes in proved reserves of natural gas by state/area, 2018–19

Oil tables
Table 5. U.S. proved reserves of crude oil and lease condensate, crude oil, and lease condensate, 2009–19
Table 6. Proved reserves, reserves changes, and production of crude oil and lease condensate, 2019
Table 7. Proved reserves, reserves changes, and production of crude oil, 2019
Table 8. Proved reserves, reserves changes, and production of lease condensate, 2019

Natural gas tables
Table 9. U.S. proved reserves of total natural gas, wet after lease separation, 2001–19
Table 10. Proved reserves, reserves changes, and production of natural gas, wet after lease separation, 2019
Table 11. Proved reserves, reserves changes, and production of nonassociated natural gas, wet after lease separation, 2019
Table 12. Proved reserves, reserves changes, and production of associated-dissolved natural gas, wet after lease separation, 2019
Table 13. Proved reserves and production of shale natural gas, 2016–19
Table 14. Proved reserves, reserves changes, and production of shale natural gas, 2019
Table 15. Estimated proved reserves of natural gas plant liquids and dry natural gas, 2019

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, 2019

 

Footnotes:

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

2. EIA Today in Energy, Low liquidity and limited available storage pushed WTI crude oil futures price below zero, April 27, 2020.

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

4.EIA’s Short-Term Energy Outlook, November 10, 2020.

5. 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.

6.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 2019 contained in the Petroleum Supply Annual 2019, DOE/EIA-0340(19).

7. 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.

8. 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 2019, DOE/EIA-0131(19).

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

10. EIA Today in Energy, Hydraulically fractured horizontal wells account for most new oil and natural gas wells, January 30, 2018.

11. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2018, December 2019, Table 15.

12. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2018, December 2019, Table 15.

13. U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2018, December 2019, Table 16.

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