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U.S. Crude Oil and Natural Gas Proved Reserves, Year-end 2017

With Data for 2017   |  Release Date:  November 29, 2018   |   Next Release Date: November 2019   |   full report

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Stronger oil and natural gas prices combined with continuing development of shales and low permeability formations drove producers of crude oil and natural gas in the United States to report new all-time record levels of proved reserves for both fuels in 2017. Total U.S. oil reserves in 2017 exceeded a brief, one-year, 47-year-old record, highlighting the importance of crude oil development in shales and low permeability plays, mainly in the Southwest. The new record for natural gas extends a longer-term trend of development, mainly in shale plays in the Northeast. Both U.S. proved reserves of crude oil and natural gas are approximately double their levels from a decade ago. These new proved reserves records were established in 2017 despite production of crude oil at levels not seen since 1972, and record natural gas production.

Highlights are listed below.

Oil highlights

  • Proved reserves of crude oil in the United States increased 19.5% (6.4 billion barrels) to 39.2 billion barrels at Year-End 2017, setting a new U.S. record for crude oil proved reserves. The previous record was 39.0 billion barrels set in 1970.
  • Proved reserves of lease condensate in the United States increased 16% (0.4 billion barrels) to 2.8 billion barrels at Year-End 2017. Since 2009, to provide a clearer picture of U.S. liquid fuel resources, EIA features combined proved reserves of U.S. crude oil and lease condensate in its reporting.
  • U.S. production of crude oil and lease condensate increased by 6% from 2016 to year-end 2017. Crude oil production in 2017 reached its highest level since 1972.
  • The annual average spot price for a barrel of West Texas Intermediate (WTI) crude oil at Cushing, Oklahoma increased 20% in 2017, from $42.59 in 2016 to $51.03. At the end of 2017, the WTI spot price exceeded $60 per barrel for the first time since June 2015.
  • Producers in Texas added 3.3 billion barrels of crude oil and lease condensate proved reserves, the largest net increase of all states in 2017. The increase was a result of increased prices and development in the Permian Basin of the Spraberry Trend and the Wolfcamp/Bone Spring shale play.
  • The Wolfcamp/Bone Spring shale play in the Permian Basin surpassed the Bakken/Three Forks play in the Williston Basin to become the largest oil-producing tight play in the United States in 2017.
  • The next largest net gains in crude oil and lease condensate proved reserves in 2017 were in New Mexico (1.0 billion barrels) and in the Federal Offshore Gulf of Mexico (729 million barrels).

Natural gas highlights

  • Proved reserves of natural gas increased by 123.2 trillion cubic feet (Tcf) (36.1%) to 464.3 Tcf at year-end 2017—a new U.S. record for total natural gas proved reserves. The previous U.S. record was 388.8 Tcf, set in 2014.
  • U.S. production of total natural gas increased by 4% from 2016 to 2017, reaching a new record level.
  • The share of natural gas from shale compared with total U.S. natural gas proved reserves increased from 62% in 2016 to 66% at year-end 2017.
  • The annual average spot price for natural gas at the Louisiana Henry Hub increased by 21% from $2.47 per million British thermal units (MMBtu) in 2016 to $2.99 per MMBtu in 2017.
  • Producers in Pennsylvania added 28.1 Tcf of natural gas proved reserves, the largest net increase of all states in 2017, as a result of increased prices and development of the Marcellus and Utica shale plays.
  • The next largest net gains in natural gas proved reserves by volume in 2017 were in Texas (26.9 Tcf) and Louisiana (18.4 Tcf) as a result of development of the Wolfcamp/Bone Spring shale play in the Permian Basin and the Haynesville/Bossier shale play in eastern Texas and northern Louisiana.

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 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 from its survey Form EIA-23L, and then estimates the non-reported portion of proved reserves. Responses were recerived from 412 of 418 sampled operators. Estimates are developed for the United States, each state, and state subdivisions. Within this report, EIA publishes proved reserves for state subdivisions within California, Louisiana, New Mexico, Texas, and the Federal Offshore Gulf of Mexico.

National summary

Table 1. U.S. proved reserves, and reserves changes, 2016–17
  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, 2016 32.8 35.2 341.1
Extensions and discoveries 5.1 5.7 70.8
Net revisions 2.6 2.7 41.3
Net adjustments, sales, acquisitions 1.8 1.8 41.4
Estimated production -3.1 -3.4 -30.4
Net additions to U.S. proved reserves 6.4 6.8 123.2
U.S. proved reserves as of December 31, 2017 39.2 42.0 464.3
Percent change in U.S. proved reserves 19.5% 19.2% 36.1%
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

Both U.S. proved reserves of crude oil and natural gas are approximately double their levels from a decade ago. Prior to 1997, natural gas and crude oil reserves had been declining since the 1970s (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 have continued, and both crude oil and natural gas proved reserves reached new U.S. record levels at Year-End 2017.

Figure 1. U.S. oil and natural gas proved reserves, 1966-2016
figure data

Proved reserves of combined crude oil and lease condensate increased in all of the top seven U.S. oil reserves states in 2017 (Figure 2). In 2017, Texas held the largest proved reserves of any state and saw the largest volumetric increase—a net increase of 3.3 billion barrels of crude oil and lease condensate proved reserves from 2016 to 2017. Most reserves additions, largely due to additional drilling and exploration in previously discovered reservoirs, were made in the Spraberry Trend Area and Wolfcamp shale play in west Texas (Texas Railroad Commission Districts 8, 8A, and 7C). EOG Resources, Inc.—the largest oil producer in Texas[2]—attributed its success in the Wolfcamp shale play (Delaware Basin) in 2017 to lateral length extensions, precision targeting, high-density stimulations, and cost reductions. The average lateral length of completed wells in the play increased from approximately 5,200 feet in 2016 to approximately 6,100 feet in 2017. Precision targeting refers to advances in logging while drilling technology (both sensors and software) that have improved the real-time geosteering process of horizontal drilling,[3] allowing operators to identify the best rock and achieve precise wellbore placement within it. High-density stimulations (hydraulic fracturing) refers to an increase in the amount of perforation clusters per hydraulic fracturing stage and also the proppant load per lateral foot (more fractures, more proppant per fracture). EOG Resources cites in its 2017 Annual Report that ownership of a sand mine and two sand processing centers in Hood County, Texas, was significant in reducing operating costs in 2017.

New Mexico had the second-largest proved reserves increase—a net addition of 1.0 billion barrels of crude oil and lease condensate proved reserves. Success in the Permian Basin (see above) also applied to Wolfcamp/Bone Springs shale play wells in eastern New Mexico. The third-largest net increase in proved reserves of crude oil and lease condensate was in the Federal Offshore Gulf of Mexico (GOM) at 729 million barrels. Producers brought seven new projects and expansions online in 2016 in the GOM and ramped up production in 2017. Another two projects came online in 2017[4].

Figure 2. Proved reserves of the top five U.S. oil reserve states, 2012-16
figure data

Proved natural gas reserves increased in each of the top eight U.S. natural gas reserves states in 2017 (Figure 3). Pennsylvania had the largest net increase in proved natural gas reserves of any state, adding 28.1 Tcf of proved natural gas reserves in the Marcellus and Utica shale plays. EQT Corporation announced on December 13, 2017, that it had successfully completed the longest lateral by any operator in the Marcellus shale play—the Haywood H18 well in Washington County, Pennsylvania, has a completed lateral length of 17,400 feet (more than three miles)[5]—and that the company plans to drill 27 Marcellus wells at 17,000 feet or longer in 2018.

Texas had the second-largest net increase, adding 26.9 Tcf of proved natural gas reserves—the largest portion of the increase came from associated-dissolved natural gas proved reserves that accompanied the gains in crude oil proved reserves in the Permian Basin. The third-largest net increase in proved natural gas reserves was in Louisiana, where operators added 18.4 Tcf of proved reserves developing the Haynesville/Bossier shale play.

Figure 3. Proved reserves of the top seven U.S. natural gas reserves states, 2012-16
figure data

Official EIA Oil and Gas Production Data

EIA’s official production volumes are published by EIA in the Petroleum Supply Annual 2017, DOE/EIA-0340(17) and the Natural Gas Annual 2017, DOE/EIA-0131(17) 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 2017, U.S. crude oil and lease condensate production increased 178 million barrels (6%) from 2016 production, and imports of crude oil increased 35 million barrels (1%) from the 2016 level (Figure 4).

Figure 4. U.S. crude oil and lease condensate proved reserves, production, and imports, 1983-2016
figure data

U.S. natural gas production increased 4% (1.2 Tcf) in 2017, and natural gas imports increased 36 Bcf (1%) from the 2016 level (Figure 5).

Figure 5. U.S. total natural gas reserves, production, and imports, 1983-2016
figure data

 

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 2017. Changes for 2017 are measured as the difference between Year-End 2016 and Year-End 2017 estimates. EIA starts with the data filed on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, which was submitted by 412 of the 418 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 the economically producible base diminishes.

The 2017 reporting period is the ninth year companies reporting to the U.S. Securities and Exchange Commission (SEC) followed revised rules for determining the prices underpinning their proved reserves estimates. Designed to make estimates less sensitive to price fluctuations, the 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 2017 was $51.03 per barrel, up 20% from 2016 (Figure 6).

Figure 6. WTI crude oil spot prices first day of the month, 2010-17
figure data

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 2017 was $2.99 per MMBtu, a 21% increase from the previous year’s average spot price of $2.47 per MMBtu (Figure 7). In January 2018, a price spike of $6.24 per MMBtu was observed, but prices declined the following month.

Figure 7. Henry Hub natural gas spot prices, 2010-17
figure data

Proved Reserves Outlook for EIA’s next report (2018). At the start of 2018, the spot price of WTI crude oil was at $60 per barrel. The price level stayed in the $60-$70 range throughout most of 2018 but periodically rose higher than $70 per barrel after May 2018. EIA forecasts in its most recent Short-Term Energy Outlook[6] that the price will remain above $72 per barrel for the remainder of the year (November and December, 2018).

Compared with the 12-month, first-of-the-month 2017 average of $51.03 per barrel, EIA’s October Short-Term Energy Outlook projects that the 12-month, first-of-the-month 2018 average WTI spot oil price will increase 33% to $68.03 per barrel. Consequently, upward revisions in U.S. crude oil proved reserves in 2018 are likely, even as production increases draw down proved reserves. The 12-month, first-of-the-month average natural gas spot price at the Henry Hub in Louisiana in 2017 was $2.99 per MMBtu. EIA expects the average 12-month, first-of-the-month spot natural gas price at the Henry Hub to increase about 8% in 2018, to $3.22 per MMBtu. Some net upward revisions in U.S. natural gas proved reserves can be expected in the 2018 reserves report, but record-setting levels like those in 2017 are not likely.

Throughout 2017, the number of U.S. rotary rigs in operation increased from 683 to 930[7]. Throughout most of 2018, this upward trend continued and the number of rotary rigs in operation now exceeds 1,000. This trend is expected to increase both crude oil and natural gas reserves in the 2018 reserves report because of more extensions and discoveries.

Crude oil and lease condensate proved reserves

EIA estimates that the United States had 41,990 million barrels of crude oil and lease condensate proved reserves as of December 31, 2017—an increase of 19.2% from year-end 2016. Proved reserves rose 19% (5.6 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 28% in Alaska and 18% in the Federal Offshore (both Pacific and the Gulf of Mexico)(Figure 8).

Figure 8. U.S. crude oil and lease condensate proved reserves, 1986-2016
figure data

U.S. crude oil and lease condensate proved reserves increased by 6.8 billion barrels (19.2%) in 2017, as the combination of total discoveries of 5.7 billion barrels and net revisions, net acquisitions, and adjustments totaling 4.5 billion barrels exceeded 2017 annual production of 3.4 billion barrels (Figure 9a).

Figure 9a. U.S. crude oil and lease condensate proved reserves changes, 2015-16

Texas saw the largest net increase in crude oil and lease condensate proved reserves (3.3 billion barrels) of all states in 2017—an increase of 24% from 2016. In 2017, the largest proved reserves gains were in the Permian Basin of West Texas (Texas Railroad Commission Districts 8, 8A, and 7C) 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 were in New Mexico (1.0 billion barrels) in 2017—an increase of 62% from 2016. In eastern New Mexico (portions of which are within the Permian Basin) operators developed the Wolfcamp shale play and the Bone Spring formation.

The Federal Offshore Gulf of Mexico (GOM) had the third-largest increase in crude oil and lease condensate proved reserves (729 million barrels) in 2017—an increase of 18% from 2016. This is the first increase in the proved reserves of the GOM since 2012.

Alaska saw the fourth-largest net increase of crude oil and lease condensate proved reserves of all states in 2017—442 million barrels (28% increase). The states of Utah and Kansas experienced the largest net declines in proved reserves in 2017, ( drops of 79 million barrels and 65 million barrels, respectively).

The increase in oil price in 2017 and increased development activity resulted in net increases to all other components of proved reserves, despite production levels not seen since 1972 (Figure 9b).

Figure 9b. Components of U.S. crude oil and lease condensate reserves changes, 2006-16
figure data

As of December 31, 2017, tight plays[8] accounted for 48% of all U.S. crude oil and lease condensate proved reserves. Most of these proved reserves (98%) came from seven tight plays (Table 2). The Wolfcamp/Bone Spring shale play in the Permian Basin surpassed the Bakken/Three Forks play in the Williston Basin to become the largest oil-producing tight play in the United States in 2017. EIA publishes a series of maps and animations showing U.S. shale and other tight plays where oil and natural gas are produced.

Table 2. Crude oil production and proved reserves from selected U.S. tight plays, 2016–17
million barrels
Basin Play State(s) 2016
production
2016
reserves
2017
production
2016
reserves
Change
2016-17 Reserves
Permian Bone Spring, Wolfcamp NM, TX 426 4,960 592 8,319 3,359
Williston Bakken/Three Forks ND, MT, SD 375 5,226 387 5,447 221
Western Gulf Eagle Ford TX 438 4,163 411 4,815 652
Anadarko, S. OK Woodford OK 27 389 36 412 23
Appalachian Marcellus* PA, WV 13 139 17 279 140
Denver Niobrara CO, NE, WY 16 225 11 232 7
Fort Worth Barnett TX 3 22 2 20 -2
Sub-total     1,298 15,124 1,456 19,524 4,400
Other tight     42 431 35 449 18
U.S. tight plays     1,340 15,555 1,491 19,973 4,418
Notes: Includes lease condensate. Bakken/Three Forks oil includes proved reserves from shale or low-permeability formations reported on Form EIA-23L. Bone Spring and Wolfcamp 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.
Other tight includes proved reserves reported from shale formations reported on Form EIA-23L not assigned by EIA to the Bakken/Three Forks, Barnett, Bone Spring, Eagle Ford, Marcellus, Niobrara, Wolfcamp, or Woodford tight plays.
* 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, 2016 and 2017.

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 5.7 billion barrels to U.S. crude oil and lease condensate reserves in 2017. The largest extensions and discoveries of crude oil and lease condensate proved reserves in 2017 were in Texas, North Dakota, and New Mexico. Texas had 3.1 billion barrels, North Dakota had 0.7 billion barrels, and New Mexico had 0.5 billion barrels of extensions and discoveries in 2017.

Net revisions and other changes. Revisions to reserves occur primarily when operators change their estimates of what they are able to economically produce from the properties they operate 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 as various adjustments are made to reconcile estimated volumes.

Net upward revisions increased U.S. crude oil and lease condensate proved reserves by 2.7 billion barrels in 2017. The largest net upward revisions of crude oil and lease condensate proved reserves were in Texas, the GOM, and Alaska. Operators in Texas revised their reserves estimates upward by 1.0 billion barrels, in the GOM by 0.8 billion, and in Alaska by 0.6 billion barrels.

The U.S. crude oil and lease condensate proved reserves associated with buying and selling properties[9] had a net increase of 1.0 billion barrels in 2017. Adjustments (positive and negative reserves changes that EIA cannot attribute to any other category) increased U.S. proved oil reserves by 0.8 billion barrels.

Production. EIA’s official published estimate of U.S. crude oil production is 3,413 million barrels in 2017, an increase of 6% from 2016. As estimated using EIA-23L responses[10], the United States produced 3,401 million barrels of crude oil and lease condensate in 2017, an increase of 6% from 2016. Production onshore in the Lower 48 states was 6% higher than the 2016 level, and Federal Offshore (both Pacific and Gulf of Mexico) production experienced a 5% increase based on the EIA-23L data.

Natural gas proved reserves

The United States had 464.3 Tcf of proved natural gas reserves as of December 31, 2017. U.S. proved reserves of total natural gas (including natural gas plant liquids) increased by 123.2 Tcf (36.1%) (Figure 10).

Figure 10. U.S. total natural gas proved reserves, 1986-2016
figure data

The spot price of U.S. natural gas at the Louisiana Henry Hub began at $3.71 per MMBtu in January 2017; however, the price hovered at or near the $3 per MMBtu mark throughout the year. The 12-month, first-of-the-month average natural gas spot price at the Henry Hub in Louisiana in 2017 was $2.99 per MMBtu. Unlike in 2015, when operators revised their natural gas proved reserves downward by more than 80 Tcf, net revisions in 2017 resulted in a large net increase of 41 Tcf to natural gas proved reserves and those were outweighed by extensions and discoveries of 71 Tcf (Figure 11a).

Figure 11a. U.S. total natural gas proved reserves changes, 2014-15

Operators in Pennsylvania and Texas reported the largest net increases in natural gas proved reserves in 2017. Pennsylvania natural gas proved reserves increased by 45% (28.1 Tcf) because of higher prices and the continued development of the Marcellus and Utica shale plays. Texas natural gas proved reserves increased by 31% (26.9 Tcf) because of higher prices and the development of the Wolfcamp/Bone Spring shale play in the west and the Haynesville/Bossier shale play in the east. The third-largest net increase in natural gas proved reserves occurred in Louisiana, where natural gas reserves increased by 18.4 Tcf (Haynesville shale play). The fourth- and fifth-largest net increases in natural gas proved reserves occurred in West Virginia and Ohio (11.1 Tcf, each), respectively, as a result of development of the Marcellus and Utica shale plays.

Extensions and discoveries.The U.S. total of natural gas extensions and discoveries were 70.8 Tcf in 2017 (Table 3), with 86% of those discoveries were from shale plays. Extensions and discoveries accounted for 46% of all proved reserves additions in 2017.

Table 3. Changes to proved reserves of U.S. natural gas by source, 2016–17
trillion cubic feet
Source
of natural gas
Year-end 2016
proved reserves
2017
Eextensions & discoveries
2017
Revisions & other changes

2017
Production

Year-end 2017
Proved reserves

Coalbed methane 10.6 0.0 2.2 -1.0 11.9
Shale 209.8 60.8 55.9 -18.6 307.9
Other U.S. natural gas
Lower 48 onshore 110.3 9.7 20.5 -9.4 131.1
Lower 48 offshore 7.1 0.2 0.6 -1.1 6.8
Alaska 3.3 0.1 3.5 -0.3 6.6
U.S. total 341.1 70.8 82.8 -30.4 464.3
Note: The Lower 48 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, 2016 and 2017

Extensions and discoveries of natural gas reserves were highest in Pennsylvania and West Virginia at 21.6 Tcf and 13.7 Tcf, respectively. Texas saw the third-largest volume of extensions and discoveries in 2017 (12 Tcf). Extensions and discoveries in Pennsylvania and West Virginia were from extensions in the Marcellus shale play, the largest natural gas shale play in the United States by volume of reserves. Natural gas discoveries in Texas were from extensions to oil fields with associated-dissolved natural gas in the Permian Basin (TX RRC Districts 8, 8A, 7C), associated-dissolved and nonassociated natural gas in the Eagle Ford shale play (TX RRC Districts 1-5) and nonassociated natural gas in the Haynesville/Bossier shale play (TX RRC District 6).

Net revisions and other changes. Net revisions increased U.S. total natural gas proved reserves by 41.3 Tcf in 2017. This increase is significantly larger than net revisions reported in the previous 10 years, which were typically less than 10 Tcf per year. The following states had the largest net upward revisions in 2017:

  • Texas had the largest net revision increase of natural gas proved reserves of all states in 2017, with an increase of 13.4 Tcf.
  • Pennsylvania had the second-largest net revision increase of natural gas proved reserves (10.3 Tcf).
  • Ohio had the third-largest net revision increase of natural gas proved reserves (5.6 Tcf).
  • Louisiana had the fourth-largest net revision increase of natural gas proved reserves (4.5 Tcf).

The net change to natural gas proved reserves from the purchase and sale of properties resulted in an additional gain of 22.1 Tcf in 2017. Adjustments (annual reserves changes that EIA cannot attribute to any other category) added 19.3 Tcf to U.S. total natural gas proved reserves in 2017.

Production. EIA’s official published estimate of marketed natural gas production is 29.2 Tcf in 2017, an increase of 3% from 2016. As estimated using EIA-23L responses and used in the reserves calculations in this report,[11] U.S. production of total natural gas, wet after lease separation, in 2017 is estimated to be 30.4 Tcf—an increase of 4% from 2016.

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

Figure 11b. Components of U.S. total natural gas proved reserves changes, 2005-15
figure data

Nonassociated natural gas

Nonassociated natural gas, also called gas well gas, is defined as natural gas not in contact with significant quantities of crude oil in a reservoir. EIA considers most shale natural gas and all coalbed natural gas to be nonassociated natural gas. Nonassociated natural gas made up almost three-quarters of production in the United States in 2017. Proved reserves of U.S. nonassociated natural gas increased by 95.9 Tcf in 2017, a 36% increase from 2016. Estimated production of U.S. nonassociated natural gas increased 2%—from 22.7 Tcf in 2016 to 23.2 Tcf in 2017. The largest increase in 2017 nonassociated natural gas proved reserves (28.3 Tcf) was in Pennsylvania (Marcellus Shale). The largest decrease in 2017 nonassociated natural gas proved reserves (0.4 Tcf) was in Oklahoma (Oklahoma total natural gas proved reserves increased by 4.2 Tcf in 2017).

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 made up more than a fifth of production in the United States in 2017. Proved reserves of associated-dissolved natural gas increased from 72.2 Tcf in 2016 to 99.4 Tcf in 2017—an increase of 38% (27.2 Tcf). Estimated production of associated-dissolved natural gas increased 12%—from 6.4 Tcf in 2016 to 7.2 Tcf in 2017. The largest increase in 2017 associated-dissolved natural gas proved reserves (10.3 Tcf) was in Texas (86% of this increase was in the Permian Basin).

Coalbed natural gas

Coalbed natural gas, also called coalbed methane, is a type of natural gas contained in and produced from coal seams. Extraction requires drilling wells into the coal seams and removing water contained in the seams to reduce hydrostatic pressure and to release adsorbed (and free) natural gas from the coal. Coalbed natural gas made up only 3% of production in the United States in 2017. Proved reserves of U.S. coalbed natural gas increased from 10.6 Tcf in 2016 to 11.9 Tcf in 2017, a 12% increase. Estimated production of coalbed natural gas decreased 4%—from 1.02 Tcf in 2016 to 0.98 Tcf in 2017. In 2017, New Mexico experienced the largest increase (0.97 Tcf) in proved reserves of coalbed methane, and Alabama had the largest decrease (0.2 Tcf) in coalbed methane proved reserves.

As of Year-End 2017, coalbed methane proved reserves represent only 2.6% of the U.S. total natural gas proved reserves. EIA will not include coalbed methane proved reserves as a separate data category in its U.S. Crude Oil and Natural Gas Proved Reserves, Year-End 2018 report.

Natural gas from shale

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 209.8 Tcf in 2016 to 307.9 Tcf in 2017.

The share of natural gas from shale compared with total U.S. natural gas proved reserves increased from 62% in 2016 to 66% in 2017 (Figure 12). Estimated production of natural gas from shale increased 9%—from 17.0 Tcf in 2016 to 18.6 Tcf in 2017.

Figure 12. U.S. total natural gas proved reserves (shale and other sources), 2008-15
figure data

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

  • Pennsylvania had the most natural gas proved reserves from shale in 2017 (89.5 Tcf)
  • Texas had the second-most (78.7 Tcf)
  • West Virginia (34.3 Tcf) remained the third-largest
  • Louisiana (26.5 Tcf) was the fourth-largest
  • Ohio (26.5 Tcf) was the fifth-largest
  • Oklahoma (22.7 Tcf) was the sixth-largest
  • North Dakota (10.0 Tcf) was the seventh-largest
  • New Mexico (9.5 Tcf) was the eighth-largest shale gas proved reserves state

Figure 13.Proved shale gas reserve of the top six U.S. shale gas reserves states, 2010-15
figure data

Eight shale plays contained 95% of U.S. shale gas proved reserves at the end of 2017 (Table 4). The Marcellus remained the play with the largest amount of natural gas proved reserves from shale in 2017. Its proved reserves increased in 2017 by 47%. The second-largest shale gas play in 2017 was the Haynesville/Bossier shale play, where proved reserves almost tripled.

Table 4. U.S. shale plays: natural gas production and proved reserves, 2016–17
trillion cubic feet
          Change 2017–2016
Basin Shale play State(s) 2016 production reserves 2016 production reserves Production Reserves
Appalachian Marcellus* PA,WV 6.3 84.1 6.9 123.8 0.6 39.7
Texas-Louisiana Salt Haynesville/Bossier TX,LA 1.5 13.0 1.8 35.9 0.3 22.9
Permian Basin Wolfcamp, Bone Spring NM, TX 1.7 19.1 2.2 31.9 0.5 12.8
Western Gulf Eagle Ford TX 2.1 22.7 1.9 27.4 -0.2 4.7
Appalachian Utica/Pt. Pleasant OH 1.4 15.5 1.7 26.5 0.3 11.0
Anadarko, S. OK Woodford OK 1.1 20.2 1.3 22.5 0.2 2.3
Fort Worth Barnett TX 1.4 16.8 1.2 19.2 -0.2 2.4
Arkoma Fayetteville AR 0.7 6.3 0.6 7.1 -0.1 0.8
Sub-total 16.2 197.7 17.6 294.3 1.4 96.6
Other shale gas 0.8 12.1 1.0 13.6 0.2 1.5
All U.S. shale gas 17.0 209.8 18.6 307.9 1.6 98.1
Note: Table values are based on natural gas proved reserves and production volumes from shale reported and imputed from data on Form EIA-23L. 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. * 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 not assigned by EIA to the Marcellus, Barnett, Haynesville/Bossier, Eagle Ford, Woodford, Utica/Pt. Pleasant, Wolfcamp, Bone Spring, or Fayetteville shale plays.
Columns may not add to subtotals due to independent rounding.
Sources: U.S. Energy Information Administration, Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, 2016 and 2017.

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, 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 322.2 Tcf in 2016 to 438.5 Tcf in 2017, an increase of 36%.

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 using estimates of total natural gas reserves and a recovery factor determined for each area of origin based on the 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, 2017, the United States had 2,830 million barrels of lease condensate proved reserves, an increase of 390 million barrels from 2016 (16%). U.S. lease condensate production decreased 9%—from 270 million barrels in 2016 to 246 million barrels in 2017.

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 14.7 billion barrels in 2016 to 19.2 billion barrels in 2017 (a 30% increase).

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 are directly offset to wells that have commercial production in the objective formation
  • Such locations are reasonably certain to be within the known proved productive limits of the objective formation
  • The locations conform to existing well spacing regulations where applicable
  • The locations are 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 18 shows the estimated volumes of nonproducing proved reserves of crude oil, lease condensate, nonassociated natural gas, associated-dissolved natural gas, and total natural gas for 2017. As of December 31, 2017 the United States had 16.0 billion barrels of crude oil proved reserves and 167.5 Tcf of natural gas proved reserves in nonproducing reservoirs. This is a 20% increase for crude oil and a 52% increase for total natural gas in nonproducing reservoirs from the 2016 level published in EIA’s previous report.

Maps and additional data tables

Maps
Figure 14. Crude oil and lease condensate proved reserves by state/area, 2017
Figure 15. Changes in crude oil and lease condensate proved reserves by state/area, 2016–17
Figure 16. Natural gas proved reserves by state/area, 2017
Figure 17. Changes in natural gas proved reserves by state/area, 2016–17

Oil tables
Table 5. U.S. proved reserves of crude oil and lease condensate, crude oil, and lease condensate, 2007–17
Table 6. Crude oil and lease condensate proved reserves, reserves changes, and production, 2017
Table 7. Crude oil proved reserves, reserves changes, and production, 2017
Table 8. Lease condensate proved reserves, reserves changes, and production, 2017

Natural gas tables
Table 9. U.S. proved reserves of total natural gas, wet after lease separation, 2001–17
Table 10. Total natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017
Table 11. Nonassociated natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017
Table 12. Associated-dissolved natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017
Table 13. Shale natural gas proved reserves and production, 2014–17
Table 14. Shale natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017
Table 15. Coalbed methane proved reserves and production, 2014–17
Table 16. Coalbed methane proved reserves, reserves changes, and production, 2017
Table 17. Estimated natural gas plant liquids and dry natural gas proved reserves, 2017

Miscellaneous/other tables
Table 18. Reported proved nonproducing reserves of crude oil, lease condensate, nonassociated gas, associated-dissolved gas, and total gas (wet after lease separation), 2017

Figure 14. Crude oil and lease condensate proved reserves by state/area, 2017

Figure 15. Changes in crude oil and lease condensate proved reserves by state/area, 2016 to 2017

Figure 16. Natural gas proved reserves by state/area, 2017

Figure 17. Changes in natural gas proved reserves by state/area, 2016 to 2017

 

Footnotes:

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

2. As ranked by the Railroad Commission of Texas in its 2017 compilation of the top 32 oil and natural gas producers in Texas, February 15, 2018.

3. Halliburton, “Targeting the Sweet Spot: Positioning the horizontal wellbore in the target zone for optimal production.”

4.“U.S. Gulf of Mexico crude oil production to continue at record highs through 2019”, U.S. Energy Information Administration, Today in Energy, April 11, 2018.

5. “EQT Announces 2018 Operational Forecast”, EQT Investor Relations, Pittsburgh, Pennsylvania, December 13, 2017.

6. EIA Short Term Energy Outlook, published October 10, 2018.

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

8. Tight plays (sometimes called resource plays) produce oil from petroleum-bearing formations with low permeability such as the Eagle Ford, the Bakken, and other formations that must be hydraulically fractured to produce oil at commercial rates. A kerogen-bearing, thermally mature shale is the source rock that typically lends its name to the play.

9. 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.

10. 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 may differ slightly from the official U.S. EIA production data for crude oil and lease condensate for 2017 contained in the Petroleum Supply Annual 2017, DOE/EIA-0340(17).

11. 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 2017, DOE/EIA-0131(17).


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


Data tables

1. U.S. proved reserves, and reserves changes, 2016–17 PDF XLS
2. Crude oil production and proved reserves from selected U.S. tight plays, 2016–17 PDF XLS
3. Changes to proved reserves of U.S. natural gas by source, 2016–-17 PDF XLS
4. U.S.shale gas plays: natural gas production and proved reserves, 2016–17 PDF XLS
5. U.S. proved reserves of crude oil and lease condensate, crude oil, and lease condensate, 2007–17 PDF XLS
6. Crude oil and lease condensate proved reserves, reserves changes, and production, 2017 PDF XLS
7. Crude oil proved reserves, reserves changes, and production, 2017 PDF XLS
8. Lease condensate proved reserves, reserves changes, and production, 2017 PDF XLS
9. U.S. proved reserves of total natural gas, wet after lease separation, 2001–17 PDF XLS
10. Total natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017 PDF XLS
11. Nonassociated natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017 PDF XLS
12. Associated-dissolved natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017 PDF XLS
13. Shale natural gas proved reserves and production, 2014–17 PDF XLS
14. Shale natural gas proved reserves, reserves changes, and production, wet after lease separation, 2017 PDF XLS
15. Coalbed methane proved reserves and production, 2014–17 PDF XLS
16. Coalbed methane proved reserves, reserves changes, and production, 2017 PDF XLS
17. Estimated natural gas plant liquids and dry natural gas content of total natural gas proved reserves, 2017 PDF XLS
18. Reported proved nonproducing reserves of crude oil, lease condensate, nonassociated gas, associated dissolved gas, and total gas (wet after lease separation), 2017 PDF XLS