In 2016, total natural gas1 proved reserves in the United States increased by 5% from 324.3 trillion cubic feet (Tcf) to 341.1 Tcf—an increase of 16.8 Tcf. Over the same period, while proved reserves of U.S. crude oil and lease condensate rose 3% onshore in the Lower 48 states, declines in oil reserves in Alaska and the Federal Offshore led to virtually the same total U.S. crude oil and lease condensate at year-end 2016, at 35.2 billion barrels. Despite increasing prices later in 2016, the average first-of-the-month prices used to calculate reserves dropped for both natural gas (down 6%) and for crude oil (down 15%) compared to 2015.

Oil highlights
U.S. proved reserves remained at 35.2 billion barrels at year-end 2016 (net decline of 17 million barrels)
Proved reserves for crude oil and lease condensate increased 3% (846 million barrels) onshore in the Lower 48 states (U.S. total not including Alaska, Federal Offshore, and State Offshore reserves)
Gains in proved reserves onshore in the Lower 48 states were offset by declines of 865 million barrels in proved reserves in Alaska and the Federal Offshore. (Development costs in these areas are typically higher and can be prohibitive in a lower oil price environment)
Texas and Oklahoma experienced the largest net increases in proved reserves of crude oil and lease condensate of all states in 2016, mostly from development of liquids-rich shale plays in the Permian Basin (Wolfcamp/Bone Spring formations) and SCOOP and STACK plays in the Anadarko Basin
U.S. production of crude oil and lease condensate decreased by 6% from 2015
U.S. oil reserve additions from new fields, identification of new reservoirs in previously discovered fields, and extensions of existing fields effectively offset production to keep total reserves constant

Natural gas highlights
Proved reserves of natural gas increased 5% (16.8 Tcf) to 341.1 Tcf at year-end 2016
Pennsylvania added 6.1 Tcf of natural gas proved reserves, the largest net increase of all states in 2016 as a result of development of the Marcellus shale in the Appalachian Basin
The next largest net gains in natural gas proved reserves by volume in 2016 were in Oklahoma (3.7 Tcf) and Ohio (3.1 Tcf), as a result of development of the SCOOP and STACK plays and the Utica shale play
U.S. production of total natural gas decreased by 1% from 2015
The share of natural gas from shale compared with total U.S. natural gas proved reserves increased from 54% in 2015 to 62% in 2016
U.S. natural gas reserve additions from new fields, identification of new reservoirs in previously discovered fields, and extensions of existing fields exceeded production by more than 30%

Proved reserves are estimated volumes of hydrocarbon resources that analysis of geologic and engineering data demonstrates with reasonable certainty2 are recoverable under existing economic and operating conditions. Reserves estimates change from year to year as new discoveries are made, as existing fields are thoroughly appraised, as existing reserves are produced, as prices and costs change, and technologies evolve.

National summary
In 2016, total U.S. crude oil and lease condensate proved reserves remained at 35.2 billion barrels. Proved reserves of U.S. total natural gas increased 16.8 trillion cubic feet (Tcf) to 341.1 Tcf in 2016 (Table 1). Net revisions in 2016 were significantly below what EIA reported in 20153, while extensions and discoveries remained at about the same level.

Table 1. U.S. proved reserves, and reserves changes, 2015–16

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

U.S. proved reserves of crude oil and lease condensate and total natural gas have increased by more than 50% in the last decade. Prior to the 1993 discovery of natural gas within the Barnett Shale, reserves had generally been declining since the 1970's (Figure 1).

Proved reserves of crude oil and lease condensate increased in four of the top seven U.S. oil reserves states in 2016 (Figure 2). In 2016, Texas held the largest proved reserves of any state and saw the largest volumetric increase—a net increase of 941 million barrels of crude oil and lease condensate proved reserves from 2015 to 2016. Most reserves additions (in the form of field extensions) were made in the Spraberry Trend Area and Wolfcamp shale play in west Texas (Texas Railroad Commission Districts 8 and 7C). Oklahoma had the second-largest proved reserves increase—a net addition of 386 million barrels of crude oil and lease condensate proved reserves. The largest net declines in proved reserves in 2016 were in Alaska, California, the Federal Offshore Pacific, and the Federal Offshore Gulf of Mexico—combined, the declines in these four areas (a net decline of 1.27 billion barrels) almost offset the gains in Texas and Oklahoma.

Proved natural gas reserves increased in each of the top seven U.S. natural gas reserves states in 2016 (Figure 3). Pennsylvania had the largest net increase in proved natural gas reserves of any state, adding 6.1 Tcf of proved natural gas reserves in the Marcellus shale play. Oklahoma had the second-largest net increase, adding 3.7 Tcf of proved natural gas reserves in the Woodford shale play. The third-largest net increase in proved natural gas reserves was in Ohio, where operators added 3.1 Tcf of proved reserves developing the Utica shale play and Point Pleasant formation using drilling and completion techniques applied in the Marcellus shale play.

In 2016, U.S. crude oil and lease condensate production decreased 204 million barrels (6%) from 2015 production, and imports of crude oil increased 186 million barrels (7%) from the 2015 level (Figure 4).

U.S. natural gas production decreased 176 billion cubic feet (Bcf) (1%) in 2016, and natural gas imports increased 288 Bcf (10%) from the 2015 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 2016. Changes for 2016 are measured as the difference between year-end 2015 and year-end 2016 values. The U.S. Energy Information Administration (EIA) starts with the data filed on Form EIA-23L, Annual Report of Domestic Oil and Gas Reserves, which was submitted by 461 of the 481 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 this 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 (positive revisions) as operators consider a broader portion of the resource base economically producible, or proved. Lower prices, on the other hand, generally reduce estimates (negative revisions) as the economically producible base diminishes.

The 2016 reporting period represents the eighth 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 while EIA requires companies to report their operated reserves.)

Because actual prices received by operators depend on their particular contractual arrangements, location, hydrocarbon quality, and other factors, spot market prices are not necessarily the prices used by operators in their reserve estimates for EIA. 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 2016 was $42.59 per barrel, 15% lower than for 2015 (Figure 6). The 2016 price was also lower than the 2017 price.

The 12-month, first-day-of-the-month average natural gas spot price at the Louisiana Henry Hub for 2016 was $2.47 per MMBtu, a 6% decrease from the previous year's average spot price of $2.62 per MMBtu (Figure 7). The 2016 price was also lower than the 2017 price.

Proved Reserves Outlook for EIA's next report (2017). At the start of 2017, the spot price of WTI crude oil was slightly lower than $50 per barrel. This price level continued through most of 2017 but increased during the last months of 2017 to slightly more than $60 per barrel at the end of the year.

Compared with the 12-month, first-of-the-month 2016 average of $42.59 per barrel, the 12-month, first-of-the-month 2017 average WTI spot oil price increased 20% to $51.03 per barrel. Consequently, upward revisions in U.S. crude oil proved reserves in 2017 are likely, but production increases will also affect proved reserves. The 12-month, first-of-the-month average natural gas spot price at the Henry Hub in Louisiana in 2016 was $2.47 per MMBtu. In December 2016, the monthly average natural gas spot price exceeded $3.00 per MMBtu for the first time since 2014. The average 12-month, first-of-the-month spot natural gas price at the Henry Hub increased 21% in 2017, to $2.99 per MMBtu. As with oil, some net upward revisions in U.S. natural gas proved reserves are expected in the 2017 reserves report.

.In the second half of 2016, the number of U.S. rotary rigs in operation began to increase. Throughout most of 2017, this trend continued. This increase is expected to positively affect both crude oil and natural gas reserves through increased extensions and discoveries in the 2017 reserves report

Crude oil and lease condensate proved reserves
The United States had 35,213 million barrels of crude oil and lease condensate proved reserves as of December 31, 2016, which is almost the same level as at the end of 2015. Proved reserves rose 3% (846 million barrels) onshore in the Lower 48 states (U.S. total not including Alaska, Federal Offshore, and State Offshore reserves), but those gains were offset by declines of 865 million barrels in crude oil and lease condensate proved reserves in Alaska and in the Federal Offshore (both Pacific and the Gulf of Mexico)(Figure 8).

U.S. crude oil and lease condensate proved reserves decreased by 17 million barrels (0.0%) in 2016, as net reserves additions (mostly extensions and discoveries) were virtually the same as annual production (Figure 9a).

Texas had the largest net increase in crude oil and lease condensate proved reserves (941 million barrels) of all states in 2016—an increase of 7% from 2015. In 2016, the largest proved reserves gains were in the Permian Basin of West Texas (Texas Railroad Commission Districts 8 and 7C) where operators developed the Wolfcamp shale play and drilled horizontal wells in the Spraberry Trend Area. In 2015, Texas proved reserves had declined more than in any other state (1,001 million barrels) after operators revised their proved reserves downward in response to the dramatic drop in oil prices at the end of 2014 from an average of about $95 per barrel to $50 per barrel.

Oklahoma had the second-largest net increase in crude oil and lease condensate proved reserves (386 million barrels) in 2016—an increase of 23% from 2015. Development in 2016 centered on two Oklahoma oil plays—the South Central Oklahoma Oil Province (SCOOP) and the Sooner Trend, Anadarko [basin], Canadian & Kingfisher [counties] (STACK). These plays feature several stacked oil-bearing reservoirs in addition to the Woodford Shale, such as the Caney Shale (above the Woodford) and the Hunton Limestone (a carbonate below the Woodford Shale.) One formation within the STACK play, the Meramec formation, is notable because wells have been drilled that produce crude oil with no associated water production (therefore, no produced water disposal costs)4.

New Mexico had the third-largest increase in crude oil and lease condensate proved reserves (74 million barrels) in 2016—an increase of 5% from 2015. In eastern New Mexico (portions of which are within the Permian Basin) operators developed the Wolfcamp shale play and the Bone Spring formation.

Alaska had the largest net decline of crude oil and lease condensate proved reserves of all states in 2016—a 25% drop of 530 million barrels. California and the Federal Offshore Pacific had the next largest net declines in proved reserves, (402 million barrels and 203 million barrels, respectively). In Alaska and California, net downward revisions of proved reserves exceeded discoveries. The Federal Offshore Pacific had no discoveries.

The smaller decrease in oil prices in 2016 (after a much larger drop in 2015) resulted in much smaller negative net revisions to proved reserves than in 2015 (Figure 9b).

As of December 31, 2016, tight plays5 accounted for 44% of all U.S. crude oil and lease condensate proved reserves. Most of these proved reserves (97%) came from seven tight plays (Table 2). The Bakken/Three Forks play in the Williston Basin remained the largest oil-producing tight play in the United States in 2016. EIA has 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, 2015–16
million barrels

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 8, TX RRC 7C, and NME.
Other tight includes proved reserves 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 Niobrara estimate in 2016 was modified to include only proved reserves identified from shale reservoirs in the Denver Julesburg basin in Colorado. 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, 2015 and 2016

Extensions and discoveries. Reserves additions including discoveries of new fields, identification of new reservoirs in fields discovered in prior years, and reserve additions that result from the additional drilling and exploration in previously discovered reservoirs (extensions) added 3.2 billion barrels to U.S. crude oil and lease condensate reserves in 2016. The largest extensions and discoveries of crude oil and lease condensate proved reserves in 2016 were in Texas, North Dakota, Oklahoma, and New Mexico. Texas had 1.8 billion barrels, North Dakota had 0.4 billion barrels, Oklahoma had 0.3 billion barrels, and New Mexico had 0.2 billion barrels of extensions and discoveries in 2016.

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 downward revisions decreased U.S. crude oil and lease condensate proved reserves by 0.5 billion barrels in 2016. The largest net downward revisions of crude oil and lease condensate proved reserves were in Alaska, Texas, and Colorado. Alaska revised reserves downward by 0.4 billion barrels, Texas by 0.3 billion, and Colorado by 0.2 billion barrels. In Texas, extensions and discoveries far outweighed negative net revisions, increasing Texas proved reserves in 2016 (see Extensions and discoveries above).

The net change to U.S. crude oil and lease condensate proved reserves associated with buying and selling properties was an increase of 264 million barrels in 2016. Adjustments (positive and negative reserves changes that EIA cannot attribute to any other category) increased U.S. proved oil reserves by 206 million barrels.

Production. EIA's official published estimate of U.S. crude oil production is 3,242 million barrels in 2016, a decrease of 6% from 2015. As estimated using EIA-23L responses6 the United States produced 3,223 million barrels of crude oil and lease condensate in 2016, also having a decrease of 6% from 2015. This is the first decline for both of these production estimate series after seven consecutive years of production increases. Production onshore in the Lower 48 states was 9% lower than the 2015 level, but Alaska production experienced a 2% increase, and Federal Offshore production experienced a 3% increase based on the EIA-23L data.

Natural gas proved reserves
The United States had 341.1 trillion cubic feet (Tcf) of proved natural gas reserves as of December 31, 2016. U.S. proved reserves of total natural gas (including natural gas plant liquids) increased by 16.8 Tcf (5%) (Figure 10).

The spot price of U.S. natural gas at the Louisiana Henry Hub dropped below $2 per million British thermal units (MMBtu) at times in the first half of 2016, but that price had risen higher than $3 per MMBtu by December 2016. Unlike in 2015, where operators revised their natural gas proved reserves downward by more than 80 Tcf, net revisions resulted in a small increase to natural gas proved reserves in 2016 and were far outweighed by extensions and discoveries (Figure 11a).

Pennsylvania and Oklahoma reported the largest net increases in natural gas proved reserves in 2016. Pennsylvania natural gas proved reserves increased by 11% (6.1 Tcf) and Oklahoma natural gas proved reserves increased by 12% (3.7 Tcf). Net increases greater than 1 Tcf also occurred in Ohio, Texas, West Virginia, Louisiana, and North Dakota. The states with the largest net decreases in natural gas proved reserves in 2016 were Alaska and New Mexico.

Extensions and discoveries. The U.S. total of natural gas extensions and discoveries were 38.4 Tcf in 2016 (Table 3) and 84% of those discoveries were from shale plays. Extensions and discoveries accounted for most (83%) of all proved reserves additions in 2016.

Table 3. Changes to proved reserves of U.S. natural gas by source, 2015–16
trillion cubic feet

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 Survey of Domestic Oil and Gas Reserves, 2015 and 2016

Extensions and discoveries of natural gas reserves were highest in Pennsylvania and West Virginia, at 10.7 Tcf and 7.1 Tcf, respectively. Texas had the third-largest volume of extensions and discoveries in 2016 (6.5 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. Total discoveries in Texas were mostly from extensions to oil fields with associated-dissolved natural gas in the Permian Basin (TX RRC District 8) and to fields within the Eagle Ford shale play (TX RRC Districts 2 and 4).
Net revisions and other changes. Net revisions increased U.S. total natural gas proved reserves by 0.1 Tcf in 2016. This is a notable change from the prior year, when net revisions reduced proved reserves by 80 Tcf. The following states had the largest changes (positive and negative) in 2016 because of net revisions:

• Pennsylvania had the largest net revision increase of natural gas proved reserves of all states in 2016, with an increase of 2.2 Tcf.
• West Virginia had the largest net revision decrease of natural gas proved reserves (2.9 Tcf). Despite a negative net revision in 2016, total West Virginia proved reserves increased by almost 3 Tcf.
• Texas had an overall net revision increase in its natural gas proved reserves of 2 Tcf. Natural gas proved reserves in west and southwest Texas (Wolfcamp and the Eagle Ford shale plays) increased in 2016, while natural gas proved reserves in north central Texas (Barnett shale play) declined.

The net change to natural gas proved reserves from the purchase and sale of properties resulted in an additional gain of 0.4 Tcf in 2016. Adjustments (annual reserves changes that EIA cannot attribute to any other category) added 7.1 Tcf to U.S. total natural gas proved reserves in 2016.

Production. EIA's official published estimate of marketed natural gas production is 28.5 Tcf in 2016, a decrease of 1% from 2015. As estimated using EIA-23L responses , U.S. production of total natural gas, wet after lease separation, in 2016 is estimated to be 29.2 Tcf, also having a decrease of 1% from 2015. This is the first decline for both of these production estimate series after 10 consecutive years of increases.

Figure 11b summarizes 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. EIA considers most shale natural gas and all coalbed natural gas to be nonassociated natural gas. Proved reserves of U.S. nonassociated natural gas increased by 10.1 Tcf in 2016, a 4% increase from 2015. Estimated production of U.S. nonassociated natural gas decreased 2%—from 23.1 Tcf in 2015 to 22.7 Tcf in 2016. The largest increases in 2016 nonassociated natural gas production were in Ohio (Utica shale) and Pennsylvania (Marcellus Shale). The largest decrease in 2016 nonassociated natural gas production (0.6 Tcf) was in Texas.

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 gas in solution with crude oil (dissolved). Proved reserves of associated-dissolved natural gas increased from 65.5 Tcf in 2015 to 72.2 Tcf in 2015—an increase of 10%. Estimated production of associated-dissolved natural gas increased 4%—from 6.2 Tcf in 2015 to 6.4 Tcf in 2016. The largest increase in 2016 associated-dissolved natural gas production (0.2 Tcf) was in Colorado..

Coalbed natural gas
Coalbed natural gas, also called coalbed methane, is a type of natural gas contained in and removed 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. Proved reserves of U.S. coalbed natural gas decreased from 12.5 Tcf in 2015 to 10.6 Tcf in 2016, a 15% drop. Estimated production of coalbed natural gas decreased 20%—from 1.27 Tcf in 2015 to 1.02 Tcf in 2016. In 2016, New Mexico experienced the largest decrease (0.98 Tcf) in proved reserves of coalbed methane, and Wyoming had the largest increase (0.12 Tcf) in coalbed methane proved reserves.

Natural gas from shale
Shale formations can be the source rock and the production zone. 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 175.6 Tcf in 2015 to 209.8 Tcf in 2016.

The share of natural gas from shale compared with total U.S. natural gas proved reserves increased from 54% in 2015 to 62% in 2016 (Figure 12). Estimated production of natural gas from shale increased 12%—from 15.2 Tcf in 2015 to 17.0 Tcf in 2016.

Pennsylvania had the most natural gas proved reserves from shale in 2016 (61.0 Tcf), Texas had the second-most (56.6 Tcf), and West Virginia (23.1 Tcf) remained the third largest (Figure 13). Oklahoma (20.3 Tcf) was the fourth-largest shale gas proved reserves state. Ohio remained the fifth-largest shale gas proved reserves state in 2016 (15.4 Tcf), and Louisiana and North Dakota were the sixth- and seventh-largest shale gas proved reserves states, respectively.

Eight shale plays contained 94% of U.S. shale gas proved reserves at the end of 2016 (Table 4). The Marcellus Shale play remained the play with the largest amount of natural gas proved reserves from shale in 2016. Its proved reserves increased in 2016 by 16%. The second-largest shale gas play was the Eagle Ford, where proved reserves also increased by 16% in 2016.

Table 4. U.S. shale gas plays: natural gas production and proved reserves, 2015–16
trillion cubic feet

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 nonshale 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 fields reported as 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, 2015 and 2016

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 deducting the corresponding volume of natural gas that make up that plant liquids estimated volume from total natural gas proved reserves.

U.S. dry natural gas proved reserves increased from an estimated 307.7 Tcf in 2015 to 322.2 Tcf in 2016, an increase of 5%.

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 (NGPL) 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 butane and propane, which are recovered at downstream natural gas processing plants or facilities. Lease condensate usually enters the crude oil stream.

Before 2015, U.S. lease condensate proved reserves had increased for six consecutive years. As of December 31, 2016, the United States had 2,440 million barrels of lease condensate proved reserves, a decline of 472 million barrels from 2015 (16%). U.S. lease condensate production also decreased 16%—from 323 million barrels in 2015 to 270 million barrels in 2016.

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. Components may be further fractionated or mixed. 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 12.7 billion barrels in 2015 to 14.7 billion barrels in 2016 (a 16% 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; and Proved, Undeveloped Reserves.

Examples of Proved, Developed, Nonproducing reserves 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 Proved, Undeveloped Reserves is an undrilled offset well location (acreage adjacent to an existing producing well that is scheduled to have a well drilled upon it). However, additional conditions must be met to satisfy the definition of proved reserves:

1. the locations are directly offset to wells that have commercial production in the objective formation,
2. it is reasonably certain such locations are within the known proved productive limits of the objective formation,
3. the locations conform to existing well spacing regulations where applicable, and
4. it is reasonably certain the locations will be developed. SEC rules currently require development within a 5-year time 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 2016. As of December 31, 2016, the United States had 13.3 billion barrels of crude oil proved reserves and 110.5 Tcf of natural gas proved reserves in nonproducing reservoirs. This is a 6% increase for both fuels from the 2015 level published in EIA's last report.
Source: EIA