Economics and the 1995 National Assessment of 

United States Oil and Gas Resources 

By Emil D. Attanasi

A summary of the economic component of the 1995 National Assessment

of United States Oil and Gas Resources for onshore and State offshore

areas of the United States 

U.S. GEOLOGICAL SURVEY CIRCULAR 1145

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1998
Free on application to U.S. Geological Survey, Information Services

Box 25286, Federal Center

Denver, CO 80225

Any use of trade, product, or firm names in this publication is for descriptive purposes only and

does not imply endorsement by the U.S. Government

Library of Congress Cataloging-in-Publication Data

U.S. DEPARTMENT OF THE INTERIOR

BRUCE BABBITT, Secretary

U.S. GEOLOGICAL SURVEY

Mark Shaefer, Acting Director

Attanasi, E.D.

MMEconomics and the 1995 national assessment of United States oil and 

Mgas resources / by Emil D. Attanasi

MMMMp.Mcm.—(U.S. Geological Survey circularM ;M1145)

MM”A summary of the economic component of the 1995 National

MAssessement of of United States Oil and Gas Resources for onshore

Mand State offshore areas of the United States.”

MMMIncludes bibliographical references.

MMM1. Petroleum reserves—United States. 2. Natural gas reserves—

MUnited States. 3. Petroleum engineering—United States—Costs.

M4. Petroleum industry and trade—United States. I. Title. 

MII. Series.

MTN872.A5A86 1997

338.2’78’0973—dc21 97–37291

 CIP

 

 
III

CONTENTS

Summary......................................................................................................................... 1

Introduction .................................................................................................................... 1

Resources Assessed ........................................................................................................ 2

Methodology................................................................................................................... 3

Undiscovered Conventional Oil and Gas Fields..................................................... 4

Unconventional Resources ..................................................................................... 6

Inferred Reserves.................................................................................................... 7

Assumptions ................................................................................................................... 7

General Assumptions.............................................................................................. 7

Specific Assumptions: Undiscovered Conventional Oil and Gas Plays................. 8

Specific Assumptions Continuous-Type and Coal-Bed Gas Plays ........................ 8

Incremental Costs ........................................................................................................... 8

Overview: Undiscovered Conventional Fields and 

Continuous-Type Accumulations........................................................................... 8

Undiscovered Conventional Oil and Gas ............................................................... 13

Characteristics of Technically Recoverable Resources.................................. 13

Incremental Costs of Oil and Gas from Undiscovered Conventional

Oil and Gas Fields .......................................................................................... 14

Continuous-Type Accumulations and Coal-Bed Gas............................................. 15

Characteristics of Technically Recoverable Resources.................................. 15

Incremental Costs of Oil and Gas from Continuous-Type and

Coal-Bed Gas Accumulations ........................................................................ 15

Inferred Reserve Estimates............................................................................................. 17

Field Growth: Origins and Qualifications .............................................................. 17

Field Growth Through 2015: A Comparative Analysis ......................................... 18

Implications and Limitations.......................................................................................... 19

References Cited............................................................................................................. 21

Glossary of Selected Terms............................................................................................ 22

Appendix A—Tables of Province-Level Conventional Undiscovered 

Resource Estimates......................................................................................................... 24

Appendix B—Tables Showing Regions, Provinces, Province Numbers, and 

Play Numbers for Continuous-Type Plays and Coal-Bed Gas Plays ............................. 30

Appendix C—Methodology ........................................................................................... 33

Undiscovered Conventional Oil and Gas Resources.............................................. 33

Continuous-Type Accumulations in Sandstone, Shales, Chalks, and Coal............ 34

Appendix D—Assessed Technically Recoverable Resources, Proved Reserves, and 

Past Production ............................................................................................................... 35

FIGURES

[Figure number preceded by letter indicates figure is in Appendix with same letter designation]

1. Graphs showing incremental costs of finding, developing, and producing crude oil from undiscovered 

conventional oil fields and continuous-type oil accumulations and incremental costs of finding, 

developing, and producing undiscovered conventional non-associated gas in gas fields and

unconventional non-associated gas (in continuous-type accumulations and coal-bed gas) 

in onshore and State offshore areas of the United States ................................................................................. 2

2. Charts showing estimated shares, as of January 1994, of crude oil and non-associated gas that could be

available for production during the next 2 decades (through 2015)................................................................. 3
IV CONTENTS

3–5. Maps showing:

3. Petroleum regions and provinces in onshore and State offshore areas in the

 conterminous United States and Alaska ................................................................................................. 4

4. Assessed continuous-type gas plays and oil plays from the USGS 1995 National Assessment for

which the predominant reservoir rock is sandstone, siltstone, shale, or chalk........................................ 5

5. Assessed coal-bed gas plays from the USGS 1995 National Assessment .............................................. 6

6. Schematic drawing of geologic setting of a continuous-type accumulation and discrete conventional 

accumulations in a structural trap and a stratigraphic trap................................................................................ 6

7–13. Graphs showing:

7. Estimates of quantities of crude oil, by petroleum region, from undiscovered conventional oil fields

and from assessed continuous-type oil accumulations having incremental costs of

$18 and $30 per barrel............................................................................................................................. 10

8. Estimates of quantities of non-associated gas, by petroleum region, from undiscovered conventional

gas fields and from assessed continuous-type gas accumulations having incremental costs of

$2 and $3.34 per thousand cubic feet ...................................................................................................... 10

9. Incremental cost of finding, developing, and producing crude oil from undiscovered conventional

oil fields and crude oil from continuous-type oil accumulations in U.S. petroleum regions .................. 11

10. Incremental cost of finding, developing, and producing non-associated gas from undiscovered

conventional gas fields and unconventional gas from assessed continuous-type 

gas accumulations and coal-bed gas in U.S. petroleum regions.............................................................. 12

11. Field-size distribution of ultimate (discovered plus undiscovered) and undiscovered conventional

oil and gas fields in onshore and State offshore areas of the conterminous United States...................... 14

12. Estimates, as of January 1994, of proved crude oil reserves, projected crude oil reserve additions 

through 2015 for oil fields discovered before 1992, and the combined estimates of crude oil in 

undiscovered conventional oil fields and from continuous-type oil accumulations having 

incremental costs of $30 per barrel ......................................................................................................... 19

13. Estimates, as of January 1994, of proved non-associated gas reserves, projected non-associated gas 

reserve additions through 2015 for gas fields discovered before 1992, and the combined estimates of

non-associated gas in undiscovered conventional gas fields and from continuous-type

gas accumulations having incremental costs of $3.34 per thousand cubic feet ...................................... 19

D-1–D-2. Graphs showing:

D-1. Estimates, as of January 1994, by petroleum region, of discovered crude oil (i.e., cumulative production 

and proved reserves), inferred reserves, and the combined mean estimates of assessed technically

recoverable undeveloped crude oil in undiscovered conventional oil fields and crude oil in

continuous-type oil accumulations.......................................................................................................... 35

D-2. Estimates, as of January 1994, by petroleum region, of discovered gas (i.e., cumulative production

and proved reserves), inferred reserves, and the combined mean estimates of assessed technically

recoverable undeveloped gas in undiscovered conventional oil and gas fields, gas in

continuous-type oil and gas accumulations, and coal-bed gas................................................................ 35

TABLES

[Table number preceded by letter indicates table is in Appendix with same letter designation]

1. Estimated economic oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields and in 

unconventional oil and gas accumulations in onshore and State offshore areas of the United States as of

January 1994...................................................................................................................................................... 9

2. Estimates of technically recoverable and economic oil, gas, and natural gas liquids in continuous-type

oil and gas accumulations in onshore areas of the conterminous United States as of January 1994................ 16

3. Estimates of technically recoverable and economic gas in assessed coal beds in onshore areas of the

conterminous United States as of January 1994................................................................................................ 17

A-1. Mean values of undiscovered technically recoverable conventional oil, gas, and natural gas liquids in

onshore and State offshore areas of U.S. oil and gas fields as of January 1994 ............................................... 24
V CONTENTS

A-2. Oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields in onshore and State 

offshore areas of the United States with incremental costs of $18 per barrel oil and 

$2 per thousand cubic feet gas as of January 1994........................................................................................... 25

A-3. Oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields in onshore and State

offshore areas of the United States with incremental costs of $30 per barrel oil and 

$3.34 per thousand cubic feet gas as of January 1994...................................................................................... 27

A-4. Conventional field-size class definitions .......................................................................................................... 29

B-1. List of petroleum provinces of onshore and State offshore areas in the conterminous United States.............. 30

B-2. Provinces, play numbers, and play names for continuous-type gas plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 31

B-3. Provinces, play numbers, and play names for continuous-type oil plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 31

B-4. Provinces, play numbers, and play names for coal-bed gas plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 32
1

Economics and the 1995 National Assessment of 

United States Oil and Gas Resources

By Emil D. Attanasi

SUMMARY

This report summarizes the economic component of the

U.S. Geological Survey’s 1995 National Assessment of Oil

and Gas Resources for U.S. onshore areas and State waters.

This area accounts for 80 percent of U.S. hydrocarbon

production and 85 percent of U.S. proved reserves. The Minerals Management Service (1996) has released a parallel

study for Federal offshore areas. Estimates are as of January

1994. The economic evaluation uses mean values of the

technically recoverable resources assessed by geologists. 

Figures 1A and 1B summarize for all U.S. onshore and

State offshore areas aggregate incremental costs of finding,

developing, and producing oil and non-associated gas from

undiscovered conventional oil and gas fields and from

selected unconventional sources. In the figures, unconventional economic resources are depicted as the difference

between the conventional undiscovered curve and the curve

designated as total. At $18 per barrel and $2 per thousand

cubic feet (mcf), 9.2 billion barrels oil (BBO), 15.8 trillion

cubic feet associated gas, and 1.1 billion barrels (BBL) natural gas liquids (NGL) from undiscovered conventional oil

fields, and 61.7 trillion cubic feet of gas (TCFG) and 2.0

BBL NGL from undiscovered conventional gas fields can be

found, developed, and produced. At $30 per barrel and $3.34

per mcf, estimates of economic oil increase by 85 percent

and total conventional economic gas increases by 57 percent.

In both cases, associated gas accounts for about one-fifth of

total economic undiscovered conventional gas. Similarly,

NGL from associated and non-associated gas accounts for 20

to 25 percent of total liquid hydrocarbons (crude oil plus

NGL). Regionally, Alaska and the Gulf Coast account for 40

percent of the economic oil in future discoveries, and the

Gulf Coast accounts for 60 percent of the economic gas in

future gas discoveries.

Crude oil in unconventional (continuous-type) accumulations add less than 6 percent to economic crude oil, even at

$30 per barrel. Unconventional gas accumulations add 35.6

TCFG to economic gas resources at $2 per mcf, and, at $3.34

per mcf, 72.1 TCFG is added. Total economic gas resources

(undiscovered conventional and unconventional) available

at $2 per mcf are 113.4 TCFG and at $3.34 are 196.3 TCFG.

Provinces of the Colorado Plateau Region and the Eastern

Region have the highest concentrations of economic unconventional gas and are in strategic locations to supply West

Coast markets and the industrial Northeast.

Figures 2A and 2B show sources and amounts of oil and

non-associated gas that could be available for production

during the next 2 decades through 2015. Figure 2A represents 69 BBO, and figure 2B represents 381 TCFG. Amounts

include economic quantities of undiscovered conventional

and unconventional oil and non-associated gas evaluated at

$30 per barrel and $3.34 per mcf, proved reserves as of January 1994, and projections of field growth (inferred

reserves) from 1994 through 2015 for pre-1992 discoveries.

In figure 2A, projected quantities of oil from field growth

account for 44 percent, proved reserves 29 percent, and

undiscovered conventional and unconventional oil account

for 27 percent. For non-associated gas (figure 2B), field

growth accounts for 26 percent, proved reserves 30 percent,

undiscovered conventional gas 25 percent, and unconventional gas accumulations (continuous-type and coal-bed gas)

19 percent. Even with these projected amounts from inferred

reserves and real price increases to $30 per barrel ($3.34 per

mcf) that yield additional oil and gas from undiscovered conventional and unconventional accumulations, it will be possible but very difficult to sustain production at levels

comparable to the 1994 level over this period without

improvements in exploration and production technology.

INTRODUCTION

The 1995 National Assessment of United States Oil and

Gas Resources by the U.S. Geological Survey (USGS) (U.S.

Geological Survey National Oil and Gas Resource Assessment Team, 1995) posits a set of scientifically based estimates of recoverable quantities of oil and gas that could be

added to the measured (proved) reserves of the United

States. The geologic component of the 1995 National

Assessment (U.S. Geological Survey National Oil and Gas

Resource Assessment Team, 1995) developed estimates of

hydrocarbons that are producible using current technology

but without reference to economic profitability, whereas the

economic component (this report) presents costs of finding,

developing, and producing the assessed resources. In partic-
2 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

0 

10 

20 

30 

40 

50 

DOLLARS PER BARREL

0 5 10 15 20 25 

A BILLIONS OF BARRELS OF OIL

0 

1 

2 

3 

4 

5 

6 

DOLLARS PER THOUSAND CUBIC FEET

0 50 100 150 200 250 

B TRILLIONS OF CUBIC FEET OF GAS

ular, this report presents estimates of costs of transforming

technically recoverable resources assessed in undiscovered

conventional fields and unconventional oil and gas accumulations into producible proved reserves. The incremental

cost functions show costs as a function of the cumulative

quantity of resources transformed. Costs include finding,

development, production, and also a return on investment.

The computation of the incremental cost functions requires

that the “full cost” of the marginal unit of resources added to

producible reserves equal well-head price.1

Incremental cost functions show the quantity of

resources that the industry is capable of adding to proved

reserves or cumulative production rather than predicting

what the industry will actually supply. Actual additions and

market supply are the outcome of optimizations of numerous

supplier decisions over geographically diverse regions and

hydrocarbon sources that assure market supply at lowest

costs. This report provides a base line to compare costs when

examining alternative supply regions, alternative sources for

oil and gas, and alternative technologies. Coal-bed gas and

conventional gas, for example, have different production

technologies that characterize discovery, development, and

production costs. These differences are taken into account

when economic quantities of the resources are put on a common basis by incremental cost functions.

The economic analysis ties costs to the volumes of

hydrocarbons that are fully identified and where wells and

production facilities are installed with the anticipation that

actual production will repay all operating costs, including

taxes, all investment expenditures, and provide an after-tax

rate of return of at least 12 percent on the investment. This

specification, which is equivalent to proved reserves, narrows the volume of hydrocarbons to a well-defined producibility standard. Individual wells are physically limited by the

amount of hydrocarbons that can be accessed at any given

time, and no more than 10 to 15 percent of the proved reserves

of individual fields can be extracted annually without risking

reservoir damage and reducing ultimate field recovery. The

“proven reserves” standard limits annual production to an

amount well below absolute resource levels.

RESOURCES ASSESSED

Geologists assessed the numbers and size distribution of

undiscovered conventional oil and gas plays. They also

assessed technically recoverable unconventional resources in

continuous-type oil and gas plays and coal-bed gas plays.

Projections of future additions to proved reserves of discovered conventional fields (inferred reserves) were prepared

using statistical extrapolations of historical trends. Commodities assessed were crude oil, natural gas (associated and nonassociated), and natural gas liquids from associated and nonassociated gas. All gas quantities are expressed as dry gas,

that is, gas that has been stripped of natural gas liquids. Gas

dissolved in geopressured brines, oil in tar deposits, and oil

shales are excluded from the analysis. Gas from low-permeability “tight” sandstone reservoirs, oil and gas from shale

reservoirs, and coal-bed gas were specifically assessed.

The commercial value of a new conventional discovery

or a continuous-type accumulation depends on whether it is

 1These functions are often referred to in the popular literature as marginal cost or price-supply functions. However, they differ from the economist’s marginal cost or supply functions in that resource quantities are not

expressed in terms of rate of resource supply, that is, the number of barrels

per year, but rather in terms of cumulative barrels added to reserves or

production.

Figure 1. A, Incremental costs, in dollars per barrel, of finding, developing, and producing crude oil from undiscovered conventional

oil fields and continuous-type oil accumulations in onshore and

State offshore areas of the United States. Solid line represents undiscovered conventional oil, and dashed line represents total of undiscovered conventional oil and oil in continuous-type accumulations. B, Incremental costs, in dollars per thousand cubic feet, of

finding, developing, and producing undiscovered conventional nonassociated gas in gas fields and unconventional non-associated gas

(in continuous-type accumulations and coal-bed gas) in onshore and

State offshore areas of the United States. Solid line represents undiscovered conventional non-associated gas, and dashed line represents total of undiscovered conventional and unconventional gas.
METHODOLOGY 3

oil or gas, its depth, location, well production profiles, and

by-products. Technology and costs associated with oil fields

differ from gas fields so it was important to classify the source

of hydrocarbons by type. Fields and accumulations having at

least 20,000 cubic feet of gas per barrel of crude oil were classified as gas fields and accumulations; otherwise, they were

classified as oil fields.

For the 1995 National Assessment, undiscovered technically recoverable resources are defined as estimated quantities of resources hypothesized to exist on the basis of

geologic knowledge, data on past discoveries, or theory—these resources are contained in undiscovered accumulations outside of known fields. Estimated resource quantities

are producible using current recovery technology but without

reference to economic viability. Posited undiscovered accumulation sizes include all components of field growth that

might occur during field development and production. Conventional accumulations are oil and gas accumulations that

are typically bounded by a downdip water contact and from

which oil, gas, and natural gas liquids (NGL) can be extracted

using traditional development and production practices.

Accumulations assessed by geologists as occurring outside of

existing fields were considered for the purposes of the economic analysis as separate and discrete new fields. Onshore

and State offshore areas of the United States were divided

into eight regions and further subdivided onto a total of 71

provinces (fig. 3). For the 71 provinces, about 460 conventional plays were assessed. The economic analysis evaluated

undiscovered conventional resources at the province level.

Inferred reserves, more commonly called field growth,

include resources expected to be added to reserves of discovered fields as a consequence of their extension, periodic

revisions of their reserve estimates, improvements in recovery technology, and additions of new pools. Forecasts of

reserve growth apply only to conventional fields discovered

before 1992 .

Continuous-type accumulations are hydrocarbon accumulations that are pervasive throughout a large area or region

and that do not owe their existence to the buoyancy of hydrocarbons in water as conventional accumulations do. Coal-bed

gas was assessed separately, although it is also a form of continuous-type accumulation. Figures 4A, 4B and 5 show locations of assessed continuous-type gas and oil accumulations

and coal-bed gas accumulations, respectively. The figures

show the areal extent of these accumulations to be regional

in nature and cover hundreds of square miles. Continuoustype accumulations have no downdip hydrocarbon-water

contact, whereas conventional accumulations have welldefined hydrocarbon-water contacts and seals that hold the

hydrocarbons. Figure 6 shows conventional structural and

stratigraphic deposits in relation to a “basin center” continuous-type accumulation. A dominant characteristic of the reservoir rock of a continuous-type accumulation is that it is

everywhere oil or gas charged. Other geologic characteristics

include positioning of the accumulation downdip from watersaturated rocks, low reservoir permeability, abnormal (high

or low) pressures, and close association of the reservoir with

source rocks from which hydrocarbons were generated.

These accumulations are contained in sandstone, siltstone,

shale, chalk, or coal, but their areal extent and heterogeneity

remain uncertain. Large portions remain undrilled. Conventional play assessment methods that typically rely on historical discovery size distributions are not applicable. New

geologic and economic assessment methods were devised for

assessing technically and commercially recoverable oil and

gas from continuous-type plays. Economic evaluations were

prepared at the play level. 

METHODOLOGY

More detailed descriptions of methodologies applied to

assessing the technically recoverable and economic undiscovered conventional resources and unconventional

Proved reserves (29.40 %)

Continuous accumulations (1.59 %)

Undiscovered (25.35 %) 

Mconventional

Growth through 2015 (43.66 %)

A

Proved reserves (29.63 %)

Coal-bed gas (7.06 %)

Continuous (11.87 %)

Maccumulations

Undiscovered (25.17 %)

Mconventional

Growth through 2015 (26.27 %)

 

B

Figure 2. A, Estimated shares, as of January 1994, of crude oil that

could be available for production during the next 2 decades

(through 2015). Sources consist of proved crude oil reserves, projected crude oil reserve additions through 2015 for fields discovered before 1992, estimates of economic crude oil in undiscovered

conventional oil fields, and economic crude oil from continuoustype oil accumulations. Estimates of economic oil assumed incremental costs of $30 per barrel. Total crude oil represented is 69 billion barrels. B, Estimated shares, as of January 1994, of nonassociated gas that could be available for production during the next

2 decades (through 2015). Sources consist of proved non-associated

gas reserves, projected non-associated gas reserve additions

through 2015 for fields discovered before 1992, estimates of economic non-associated gas in undiscovered conventional gas fields,

economic gas in continuous-type gas accumulations, and economic

coal-bed gas. Estimates of economic gas assumed incremental costs

of $3.34 per thousand cubic feet. Total quantity of non-associated

gas represented is 381 trillion cubic feet.
4 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

PACIFIC 

COAST

COLORADO PLATEAU 

AND BASIN AND RANGE

ROCKY MOUNTAINS 

AND 

NORTHERN GREAT PLAINS

MIDCONTINENT

GULF COAST

WEST TEXAS

AND 

EASTERN 

NEW MEXICO

EASTERN

50

70

4

5

18 6

7

10

9

8

11

12

13

14

15

16

17

19

27 28

24

21

25

37

29

34

35

20

36

22

26

44 45

47

48

58

43

41

39

33

31

53

32

38

40

23 42

59

61

55

46

54

51

52

56

57

60

62

49

64

63

66 67

68

71 72

69

65

0 500 MILES

A 0 500 KILOMETERS

Trans-Alaska

Pipeline

Prudhoe

Bay

Valdez

Northern Alaska

Central Alaska

Southern Alaska

0 200 MI

0 300 KM

B

resources are provided in Appendix C. Complete explanations are provided in a series of USGS Open-File Reports

referenced in those sections. Estimation of inferred reserves

(field growth) is described in detail in Root and others (1996).

UNDISCOVERED CONVENTIONAL OIL 

AND GAS FIELDS

The geologic assessment posited undiscovered conventional oil and gas field size-frequency distributions from

which quantities of oil, associated gas, associated gas liquids, non-associated gas, and non-associated gas liquids

were computed. The incremental cost functions were prepared at the province level using the expected or mean value

of the assessed size-frequency distributions of undiscovered

accumulations grouped by 5,000-ft depth interval. The size

frequency distributions of new discoveries (by field type and

depth) were projected for successive increments of wildcat

wells using a set of finding-rate functions and the geologic

assessment. A standard application of discounted cash flow

(DCF) analysis determined commercial developability of

newly discovered fields. The net after-tax cash flow consisted of revenues from the production of oil and (or) gas less

the operating costs, investment costs in the year incurred,

and all taxes. All new discoveries of a particular size and

Figure 3. A, Petroleum regions and provinces in onshore and State

offshore areas in the conterminous United States. Heavy lines are

region boundaries; lighter lines are province boundaries. B, Petroleum provinces of onshore and State offshore areas of Alaska. Regions and provinces are listed by name and number in table B-1,

Appendix B.
METHODOLOGY 5

503

3740, 3741, 

3742,3743,

3744

2812

2812

2810, 2811

2007, 2010

3906

2020

2018

2016

2015

2205,

2209,

2211

4923

6733, 

6734,

6735

3113

6407

6604

6728,6729,

6730

6741

6740

6320

6319

6742

Play and number

4923

0 500 MILES

0 500 KILOMETERS

A

Figure 4. Assessed continuous-type plays from the USGS 1995 National Assessment for which the predominant reservoir rock is sandstone,

siltstone, shale, or chalk. A, gas plays; B, oil plays. Tables B-2 and B-3, Appendix B, list provinces and play names associated with play numbers.

3904

3920,3921

2804

2103

4748

4749

4747

2009

2208

3110

3112

3111

Play and number

3904

0 500 MILES

0 500 KILOMETERS

B
6 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

depth class are assumed to be developed and added to producible reserves if the representative field is found to be

commercially developable, that is, if it has an after-tax net

present value greater than zero. The discount rate included

the cost of capital and the industry’s required return.

Finding-rate functions predicted, for each increment of

wildcat drilling, a distribution of oil and gas discoveries.

For successive discovery distributions, average discoveries

became smaller and (or) were found in deeper horizons,

resulting in increasing finding costs. Increments of 50

wildcat wells (or 20 wildcat wells for State offshore areas)

are assumed to be drilled until the exploration cost associated with the wildcat well increment is equal to or greater

than the after-tax net present value of the commercially

developed fields discovered by that increment of wildcat

wells. For each increment of wildcat drilling, the allocation

or targeting of wildcat wells to specific depth intervals maximized the after-tax net present value of the oil and gas discovered. As prices/incremental costs are allowed to

increase, additional increments of wildcat wells are economic to drill and the marginal economic field size

declines—this adds more commercially developable fields.

Both effects add to producible reserves. The basis for the

estimates of recoverable undiscovered petroleum as a function of well-head price is that incremental units of exploration, development, and production effort will not take place

unless the revenues expected to be received from the eventual production will cover the incremental costs, including a

normal return on the incremental investment.

UNCONVENTIONAL RESOURCES

Geologic assessment of continuous-type plays and

coal-bed gas plays started with partitioning the postulated

play area into equal-area cells. For continuous-type plays,

cell spacing corresponded to the median drainage area of

6750

6751

6752

6553

6552

6550

6553

5650

6050

6450

2252

2253

2250 4150

4152

3350

3351

3755 3350

2052

2050

2051

2053

2056

2055

2057 2054

Stacked plays

3750, 3751,

3752,3753,

3754,3755

450

451

452

6250

6251

4151

6551

EXPLANATION

Play and number 450

6250

0 500 MILES

0 500 KILOMETERS

Tens of miles (kilometers)

Discrete-type

Land surface

Continuous-type

accumulation

Stratigraphic

accumulation

Structural

accumulation

Figure 5. Assessed coal-bed gas plays from the USGS 1995 National Assessment. Table B-4, Appendix B, lists province and play names

and numbers.

Figure 6. Geologic setting of a continuous-type accumulation and

discrete conventional accumulations in a structural trap and a stratigraphic trap (U.S. Geological Survey National Oil and Gas Resource Assessment Team, 1995)
ASSUMPTIONS 7

production wells in the play, and, for coal-bed gas plays, it

corresponded to well spacing set by the State regulatory

commission. Geologists interpreted past drilling results and

production records to assess technically recoverable

resources in remaining untested cells. The assessment

results are expressed in terms of a size-frequency distribution of productive untested cells, where “cell size” here

means quantity of hydrocarbons recovered. For calculating

incremental costs, the geologic play assessment results were

transformed into the expected size-frequency distribution of

untested (productive) cells computed in 5,000-ft depth intervals. To determine the part of the cell frequency-size distribution of each 5,000-ft depth interval within a play that is

commercially developable, a cash-flow analysis was applied

to each cell-size category. After evaluation of all the cellsize classes within a specific depth interval, if the computed

after-tax net present value of the aggregate developable cells

is sufficient to cover the costs of drilling all cells, that is, the

cost of exploration, then the aggregate resources in the commercially developable wells are added to reserves. Otherwise, drilling is not justified and resources are not added to

reserves. Calculations were repeated assuming progressively higher well-head prices, and results were aggregated

from depth intervals to the play level and then to the province level to arrive at incremental cost functions.

INFERRED RESERVES

Inferred reserves (or field growth) are those resources

in identified fields over and above current proved (measured) reserves. They are expected to be added to discovered

conventional fields through extensions, revisions, improved

efficiency, and the addition of new pools or reservoirs. In the

discussion of field growth, estimates of field size (or known

field recovery) are computed as the sum of past cumulative

field production and the field’s proved reserves. When fields

are grouped by their year of discovery, the sum of the estimates of known recovery for each group tends to increase

systematically over time or years of observations. This

observed systematic nature of the “field-growth phenomenon” suggested a modeling approach that was statistical

rather than geologic in nature. To model this process, cumulative growth functions were specified and calibrated.

Cumulative field-growth functions show the estimated

field size at age n, that is, n years after discovery, as a multiple

of the field’s initially estimated size. Cumulative growth

functions were calibrated using yearly field-size estimates

from 1977 through 1991 of conventional fields (grouped by

discovery year from 1901 to 1991) in the lower 48 States.2

The cumulative growth function was then applied to the 1991

field-size estimates to project future annual reserve additions

for pre-1992 discoveries for the next 80 years. Alaska’s oil

field growth was calculated using the lower-48-States growth

function (U.S. Geological Survey National Oil and Gas

Resource Assessment Team, 1995). The form of the cumulative growth function assumed that the annual rate of growth

of older fields will not exceed that of younger fields and that

fields continued to grow for as long as 90 years after their discovery. Also implicit in the application of the calibrated

cumulative growth function is the assumption that the rate of

technological improvement and economic conditions occurring during the observation period will prevail in the future.

Studies designed to tie estimated costs of drilling activity to historical field growth for a sample of fields failed to

yield a credible costing scheme that could be applied to estimate costs of future reserve additions from inferred reserves.

The 60 BBO and 322 TCFG (U.S. Geological Survey

National Oil and Gas Resource Assessment Team, 1995) of

estimated future reserve additions are expected to occur over

an 80-year period to 2071. Only a small fraction of these

resources can be added to reserves annually (Root and others,

1996). For purposes of comparison with the economic undiscovered conventional and unconventional resources,

regional field-growth projections prepared for the period

from 1994 to 2015 are presented and discussed.

ASSUMPTIONS

GENERAL ASSUMPTIONS

1. The economic analysis uses the mean or expected

value of the assessed hydrocarbons. 

2. Industry exhibits rational behavior, so that investment will not be undertaken unless the full operating

costs, investment costs, and the cost of capital can be

recovered. 

3. Industry was assumed to use a 12 percent after-tax

rate of return as a hurdle rate or required rate of return

to undertake new investment. The cash-flow analysis

was specific to individual projects and ignored minimum income taxes and tax preference items that

might be important from a corporate accounting

stance. Cost levels prevailing in 1993 were assumed.

4. Federal taxes are based on the 1986 Tax Reform Act

and the 1993 revision. State tax rates are as of 1993.

5. Royalty payment to the resource owner is 12.5 percent of gross revenues for onshore areas and 16.67

percent of State offshore areas.

 2Data used for calibrating cumulative growth functions typically consist of short time-series (6 to 15 years) of estimates of ultimate field recoveries for sets of fields grouped by discovery year. For example, with such a

series, the expected percent field growth for a field going from age 19 to 20

is computed using estimates of known recovery for all those fields that

passed from age 19 to 20 during the sample period. An entirely different set

of fields may be used in calculating expected field growth from age 4 to age

5. Field-size estimates were from the Energy Information Administration’s

proprietary Oil and Gas Integrated Field File (OGIFF), issued in 1993.
8 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

6. Dry gas (gas without natural gas liquids) prices were

assumed to be two-thirds the price of oil when

expressed on an equivalent energy basis. For example, if oil prices are $18 per barrel, the implied price

of gas would be $2 per mcf. This relationship

between oil and gas prices corresponds roughly to the

historical average. The analysis also focused on

prices between $18 per barrel ($2 per mcf) and $30

per barrel ($3.34 per mcf). Also, the well-head price

of natural gas liquids is assumed to be three-fourths

the per-barrel price of crude oil.

7. By-product revenues from associated gas and natural

gas liquids are credited in the economic evaluation to

the primary products of either crude oil or non-associated natural gas in the calculation of the incremental cost functions.

SPECIFIC ASSUMPTIONS: 

UNDISCOVERED CONVENTIONAL 

OIL AND GAS PLAYS

1. Economic evaluation of undiscovered conventional

oil and gas fields were generally prepared at the province level and based on the assessed field-size distribution of undiscovered fields within 5,000-ft depth

intervals.

2. Exploration continues until the expected net present

value of the commercially developable resources discovered by the last increment of wildcat drilling is

insufficient to pay for that increment of wildcat

drilling. 

3. Except in the Northern Alaska province, oil and gas

prices used in the economic evaluation were wellhead prices. For the Northern Alaska province, the

oil price used in the economic evaluation was the

lower-48-States-West-Coast price, rather than the

well-head price, so incremental costs include transportation from the field to the lower 48 States West

Coast. Oil produced in Northern Alaska is transported through the Trans-Alaska Pipeline System

(TAPS).

4. Because of the absence of a market for the gas

resources of Northern Alaska, non-associated gas

fields were not evaluated and a zero price was

attached to the extracted associated gas from oil

fields. 

5. The oil and gas resources of the Central Alaska province and of the Southern Alaska province outside the

Cook Inlet were not evaluated by the economic analysis because these areas have very limited potential

and expected discovery sizes are insufficient to offset

cost barriers imposed by the hostile climate, primitive infrastructure, and remoteness from markets.

6. Technically recoverable resources assigned to Lake

Michigan and Lake Erie were not evaluated. These

resources amounted to 0.67 BBO and 3.0 TCFG.

SPECIFIC ASSUMPTIONS:

CONTINUOUS-TYPE AND

COAL-BED GAS PLAYS

1. Economic evaluations of continuous-type accumulations and coal-bed gas were prepared at the play level

and based on the expected cell-size frequency distribution of untested cells for each 5,000-ft depth interval over which the play extends.

2. Each untested cell requires a new well; recompletions

to the target plays of producing wells were not considered. 

3. Within continuous-type or coal-bed gas plays, it is

assumed there is no trend in the discovery rate or well

productivities as drilling progresses. In particular, it

is assumed that within a play, operators cannot highgrade areas except by restricting drilling to specific

depth intervals. To the extent possible, so-called

sweet spots should be separate plays.

INCREMENTAL COSTS

OVERVIEW: 

UNDISCOVERED CONVENTIONAL FIELDS 

AND CONTINUOUS-TYPE ACCUMULATIONS

Table 1 shows regional estimates of economic quantities of oil, gas, and natural gas liquids in conventional undiscovered oil and gas fields, continuous-type accumulations

and coal-bed gas accumulations having incremental costs of

$18 per barrel or $2 per mcf and $30 per barrel or $3.34 per

mcf. Figures 7 and 8 depict estimates of oil in oil fields and

accumulations and gas in gas fields and accumulations.

Figures 9 and 10 show regional incremental cost functions

for of oil and non-associated gas, respectively. 

At $18 per barrel and $2 per mcf, 9.2 BBO, 15.8 TCF

associated gas, and 1.1 BBL NGL from undiscovered oil

fields and 61.7 TCFG and 2.0 BBL NGL from undiscovered

gas fields can be found, developed, and produced. Similarly,

at $30 per barrel and $3.34 mcf, 17.4 BBO, 25.9 TCF associated gas, and 1.6 BBL NGL in undiscovered oil fields and

95.9 TCFG and 2.9 BBL NGL in undiscovered gas fields is

economic. Associated gas represents 20 percent of the total

gas estimated at both cost levels. Additionally, NGL from

associated and non-associated gas accounts for one-fifth to

one-fourth of total economic hydrocarbon liquids (crude oil

plus natural gas liquids).

Crude oil in continuous-type oil accumulations, even at

the high cost level, adds less than 6 percent to economic

crude oil. At $2 per mcf, continuous-type gas accumulations
INCREMENTAL COSTS 9
10 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

add 35.9 TCFG to economic resources, and, at $3.34 per mcf,

72 TCFG is added. Assessed NGL resources in unconventional gas were very small. Quantities of economic

unconventional gas are significant, even at low incremental

costs. Total economic gas resources at $2 per mcf are 113.4

TCFG and, at $3.34, are 196.3 TCFG.

The economic analysis treated the Northern Alaska

province (Alaska, Region 1) at the play level (see Attanasi

and Bird, 1996) because it is still a frontier area with little

infrastructure and is remote from markets. Incremental costs

for this province included product transport costs from the

field to the lower 48 States West Coast. These costs ranged

from $5.41 to $9.38 per barrel. Assessed non-associated gas

fields in the Northern Alaska province were not evaluated by

the economic analysis because markets and a product transportation system for new gas appear at least 2 decades away

(see Attanasi, 1994). There is at least 30 TCF associated gas

already discovered that can be produced cheaply if a market

should develop. Although no commercial value was imputed

to the associated gas in oil fields in the Northern Alaska province, by-product revenues for natural gas liquids were credited. The Cook Inlet area has local oil and gas markets, so

that, for the marginal unit of resources added to reserves,

incremental costs equaled well-head price. For the Alaska

Region, at $18 per barrel, 11 percent of the technically recoverable oil is economic. Similarly at $30 per barrel, 45 percent

of the assessed oil is economic.

Nearly all the economic oil shown in table 1 is in conventional undiscovered oil fields. For the lower 48 States,

about 36 percent of the geologically assessed oil in undiscovered conventional fields and continuous-type oil accumulations can be found, developed, and produced at $18 per

barrel. As costs increase to $30 per barrel, 62 percent of the

technically recoverable oil is economic.

Assessed coal-bed gas and gas in continuous-type

accumulations (unconventional gas) amounted to more than

three-fifths of the 507 TCF of technically recoverable nonassociated gas assessed in conterminous U.S. onshore and

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 1 2 3 4 

BILLIONS OF BARRELS OF CRUDE OIL

$18/bbl conventional

$30/bbl conventional

$18/bbl unconventional

$30/bbl unconventional

EXPLANATION

Figure 7. Estimates of quantities of crude oil, by petroleum region,

from undiscovered conventional oil fields and from assessed continuous-type oil accumulations having incremental costs of $18 and

$30 per barrel, respectively.

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 10 20 30 40 50 60 

TRILLIONS OF CUBIC FEET OF GAS

$2.00/mcf conventional

$2.00/mcf unconventional

$3.34/mcf conventional

$3.34/mcf unconventional

EXPLANATION

Figure 8. Estimates of quantities of non-associated gas, by petroleum region, from undiscovered conventional gas fields and from

assessed continuous-type gas accumulations having incremental

costs of $2 and $3.34 per thousand cubic feet, respectively.

Figure 9 (facing page). Incremental cost of finding, developing,

and producing crude oil from undiscovered conventional oil fields

and crude oil from continuous-type oil accumulations in U.S. petroleum regions: A, Region 1 (Alaska); B, Region 2 (Pacific Coast); C,

Region 3 (Colorado Plateau and Basin and Range); D, Region 4

(Rocky Mountains and Northern Great Plains); E, Region 5 (West

Texas and Eastern New Mexico); F, Region 6 (Gulf Coast); G, Region 7 (Midcontinent); H, Region 8 (Eastern). Solid line represents

undiscovered conventional oil, and dashed line represents the total

of undiscovered conventional oil and oil in continuous-type

accumulations.
INCREMENTAL COSTS 11

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

D

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

H

BILLIONS OF BARRELS OF CRUDE OIL

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

B F

0 1 2 3 4 5 6 

0 

10 

20 

30 

40 

50 

0

10

20

30

40

50

A

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

E

0 1 2 3 4 5 6

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

C

0 

10 

20 

30 

40 

50 

0 1 2 3 4 5 6 

G

DOLLARS PER BARREL
12 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

0

1

2

3

4

5

 6

A

0 

1 

2 

3 

4 

5 

6 

0 10 20 30 40 50 60 70 80 

D

0 

1 

2 

3 

4 

5 

6 

0 2 4 6 8 10 12 14 16 18 20 

E

0 0.2 0.4 0.6 0.8 1

0 

1 

2 

3 

4 

5 

6 

0 2 4 6 8 10 12 14 16 18 20 

G

0 

1 

2 

3 

4 

5 

6 

0 10 20 30 40 50 60 70 80 

F

0 

1 

2 

3 

4 

5 

6 

0 10 20 30 40 50 60 70 80 

H

0 

1 

2 

3 

4 

5 

6 

0 10 20 30 40 50 60 70 80 

C

0 

1 

2 

3 

4 

5 

6 

0 2 4 6 8 10 12 14 16 18 20 

B

TRILLIONS OF CUBIC FEET OF GAS

DOLLARS PER THOUSAND CUBIC FEET
INCREMENTAL COSTS 13

State offshore areas. Table 1 shows that, even at a cost of $2

per mcf, the unconventional gas accounts for 36 percent of

the economic non-associated gas. As prices increase, the

proportion of economic gas coming from these accumulations increases because of the much larger quantity of technically recoverable gas in unconventional accumulations.

Regions where unconventional gas is expected to dominate,

that is, Colorado Plateau (Region 3) and Rocky Mountain

(Region 4), are strategically located to contribute to West

Coast gas supplies. Eastern Region (Region 8) gas from

Antrim Shales of the Michigan Basin and coal-bed gas in

Central Appalachia will also find a ready market in the

industrial Northeast. Moreover, locational advantages of

Eastern Region gas permit higher well-head prices to

partially offset typically higher costs of unconventional gas.

By source, economic non-associated gas at $2 per mcf

amounted to 39 percent of the assessed technically recoverable undiscovered conventional gas and 10 percent of the

assessed technically recoverable unconventional gas.

Similarly, at $3.34 per mcf, 61 percent of undiscovered

conventional and 20 percent of unconventional gas is

economic.

UNDISCOVERED CONVENTIONAL

OIL AND GAS

CHARACTERISTICS OF TECHNICALLY 

RECOVERABLE RESOURCES

Characteristics of the geologic assessment important

for understanding the economic analysis are highlighted

here. Table A-1, Appendix A, shows the combined mean

values of assessed conventional undiscovered recoverable

resources for U.S. onshore and State offshore areas. Federal

offshore areas are not included. Oil and gas estimates shown

in the table are small revisions to the estimates presented in

U.S. Geological Survey Circular 1118 (U.S. Geological

Survey National Oil and Gas Resource Assessment Team,

1995). The technically recoverable natural gas liquids

estimates shown here, however, correct estimates presented

in Circular 1118. The estimates are presented by field-type

because cost and technology for oil and gas field

development are different. Non-associated gas, that is gas in

gas fields, accounts for more than four-fifths of total

undiscovered gas.

Region 1.—The Northern Alaska province was

assigned mean values of 7.40 BBO and 63.5 TCFG, the

Central Alaska province 0.06 BBO and 2.7 TCFG, and the

Southern Alaska province 1.0 BBO and 2.1 TCFG. To place

these estimates in perspective, through-1990 cumulative discoveries in the Northern Alaska province amount to more

than 14 BBO and 32 TCFG, and, in the Southern Alaska

province, discoveries amount to about 1.2 BBO and 6.8

TCFG (NRG Associates, 1993, 1994). Alaska accounts for

about 30 percent of the assessed technically recoverable

undiscovered oil and 26 percent of the undiscovered gas

resources in the 1995 National Assessment. Plays in the

Central Alaska province and in the Southern Alaska

province (outside of the Cook Inlet area) have very limited

potential, and expected discovery sizes are unlikely to be

large enough to offset cost barriers imposed by the hostile

climate, primitive infrastructure, and remoteness from markets. Consequently, these plays were not further evaluated

by economic analysis.

At the mean value, the 1995 Northern Alaska province

assessment of undiscovered oil of 7.40 BBO is a 41 percent

reduction from the 12.6 BBO estimated in the 1989 assessment (see Mast and others, 1989). Assessed undiscovered

gas increased by about 10 percent over the 1989 analysis.

This revision resulted from new drilling information and an

alternative interpretation of the thermal history of the

province (U.S. Geological Survey National Oil and Gas

Resource Assessment Team, 1995) that reduced the perceived maximum depths where oil was thought to occur. For

the 1995 Assessment, more than three-fourths of the estimated undiscovered oil was assigned to depths shallower

than 10,000 ft and only 2 percent was assigned to depths

greater than 15,000 ft. A high degree of uncertainty was

attached to geologic estimates for both oil and gas in the

Northern Alaska province.

Regions 2, 3, 4, 5, 6, 7, and 8.—Table A-1, Appendix

A, shows more than 21 billion barrels of oil and 190 trillion

cubic feet of gas remain to be discovered in the onshore and

State offshore areas in the conterminous United States. For

this area, undiscovered resources amount to only 13 percent

of the oil and 23 percent of the gas already discovered.

Nearly all of these areas have been rather thoroughly

explored for conventional resources. State offshore areas

account for about 10 percent of the undiscovered resources

in the lower 48 States. Of the 55 provinces listed for the

lower 48 States, 45 percent of the oil is contained in just four

provinces (Permian Basin (044), Western Gulf (047),

Louisiana-Mississippi Salt Basins (049), and Powder River

(033)) and more than half the non-associated gas is

contained in the Western Gulf (047) province and the

Louisiana-Mississippi Salt Basins (049).

Figure 10 (facing page). Incremental cost of finding, developing,

and producing non-associated gas from undiscovered conventional

gas fields and unconventional gas from assessed continuous-type

gas accumulations and coal-bed gas in U.S. petroleum regions: A,

Region 1 (Alaska); B, Region 2 (Pacific Coast); C, Region 3 (Colorado Plateau and Basin and Range); D, Region 4 (Rocky Mountains and Northern Great Plains); E, Region 5 (West Texas and

Eastern New Mexico); F, Region 6 (Gulf Coast); G, Region 7 (Midcontinent); H, Region 8 (Eastern). Solid line represents undiscovered conventional non-associated gas, and dashed line represents

the total of undiscovered conventional non-associated gas, gas in

continuous-type gas accumulations, and coal-bed gas.
14 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

Figure 11A shows the mean field-size frequency distribution of the ultimate (discovered plus undiscovered) and

undiscovered numbers of fields containing at least 1 million

barrels of oil equivalent (1 MMBOE). Similarly, figure 11B

shows the frequencies for all field-size classes. Table A-4,

Appendix A, provides size class definitions. Data in the figures show future discoveries to be dominated by smaller

fields. Though only 10 percent of hydrocarbons discovered in

the past were in fields of less than 8 MMBOE, half the undiscovered hydrocarbons were assigned to these size classes.

Field-size classes smaller than 1 MMBOE (classes 1-5) contain less than 3 percent of discovered hydrocarbons but

account for 23 percent of the undiscovered hydrocarbons.

Because finding, development, and production costs typically vary inversely with field size, data behind the figures

imply increases in costs are associated with future discoveres. 

INCREMENTAL COSTS OF OIL AND GAS FROM 

UNDISCOVERED CONVENTIONAL

OIL AND GAS FIELDS

Computation of incremental cost functions started with

the economic evaluation of the assessed distribution of

undiscovered oil and gas fields: the economic target for

exploration. Province-level finding-rate functions were used

to predict the ordering and arrival rate of discoveries. For

each increment of wildcat wells, the finding-rate function

generates a distribution of discoveries by size and depth,

some of which will be commercially developable and some

not. The computational algorithm assumes exploration continues until the expected economic value of the resources discovered by the last increment of wildcat wells is insufficient

to pay for that exploration increment. The targeting of wildcat wells by depth interval for each well increment maximized the expected after-tax net present value of oil and gas

discovered. Successive increments of wildcat wells generate

smaller discoveries and (or) discoveries in deeper horizons

that typically lead to increasing finding costs. All this implies

that it is not valid to simply add a flat finding cost to development cost to arrive at the full incremental costs.

Tables A-2 and A-3, Appendix A, show province-level

estimates of economic resources by commodity. Table A-2

shows that, at $18 per barrel ($2 per mcf), it will be economic

to find, develop, and produce 9.2 BBO, 15.8 TCF associated

gas, and 1 BBL NGL from undiscovered conventional oil

fields and 61.7 TCFG and 2 BBL NGL from undiscovered

conventional gas fields. Table A-3 shows estimates of economic oil increase by 85 percent and total economic gas

increases by 57 percent as incremental costs are allowed to

increase to $30 per barrel ($3.34 per mcf). Associated gas

accounts for about one-fifth of total economic undiscovered

conventional gas, and NGL from associated and non-associated gas contributes 20 to 25 percent to total conventional

liquid hydrocarbons (crude oil plus NGL). 

For the Northern Alaska province, at a lower-48-StatesWest-Coast price of $18 per barrel, only 8 percent of the technically recoverable undiscovered oil is economic; at $30 per

barrel, about 43 percent is economic. For the lower 48 States,

38 percent of the technically recoverable undiscovered oil

and 39 percent of the technically recoverable undiscovered

non-associated gas can be found, developed, and produced at

incremental costs of $18 per barrel ($2 per mcf). At an incremental cost of $30 per barrel ($3.34 per mcf), two-thirds of

the technically recoverable oil and gas is economic.

The Alaska and Gulf Coast Regions have the largest

quantities of economic undiscovered oil at $30 per barrel,

followed by (1) the Rocky Mountain Region and (2) the West

Texas and Eastern New Mexico Region. Tables A-2 and A3, Appendix A, show that, within most regions, one or two

provinces dominate potential reserve additions. Based on the

0 

1 

2 

3 

4 

5 

6 7 8 9 10 11 12 13 14 15 16 17 18 19

A

0 

10 

20 

30 

40 

50 

NUMBER OF FIELDS, IN THOUSANDS

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

FIELD-SIZE CLASS

Undiscovered plus discovered Undiscovered

EXPLANATION

B

Figure 11. Field-size distribution of ultimate (discovered plus

undiscovered) and undiscovered conventional oil and gas fields in

onshore and State offshore areas of the conterminous United States.

A, part of distribution for fields containing at least 1 million barrels

of oil equivalent. B, entire distribution. Size classes, in terms of

millions of barrels of oil equivalent, are defined in table A-4,

Appendix A.
INCREMENTAL COSTS 15

incremental cost functions and the fraction of technically

recoverable oil that is economic to find, develop, and produce at an incremental cost of $18 per barrel, the Permian

Basin province (044) in the West Texas and Eastern New

Mexico Region has the lowest cost oil, followed by the

Western Gulf province (047) in the Gulf Coast Region. The

Northern Alaska province was assigned the largest quantity

of oil of any U.S. province; however, transport of the product

to market increases costs substantially.

For economic undiscovered non-associated gas, the

Gulf Coast Region is the dominant region, followed by the

Rocky Mountain, Midcontinent, and West Texas and

Eastern New Mexico Regions. The Western Gulf province

of the Gulf Coast Region has lowest costs. Half of the

technically recoverable gas in the Gulf Coast Region is economic to find, develop, and produce for $2 per mcf. That

quantity of gas is more than all the other regions combined

at that cost level.

Even at low well-head prices, improvements in

exploration technology are likely to occur during the next 2

decades. Though undiscovered resources are unchanged,

improvements in exploration efficiencies can increase the

quantity of resources found and developed at nearly every

cost level. If the analysis for the conterminous United States

is repeated assuming exploration efficiency is doubled, the

quantity of crude oil and non-associated gas that is economic

at $18 per barrel ($2 per mcf) increases by more than onethird, so 54 percent of the technically recoverable resources

are economic. At the $30 per barrel ($3.34 per mcf), almost

three-fourths of the assessed resources are economic.

CONTINUOUS-TYPE ACCUMULATIONS 

AND COAL-BED GAS

CHARACTERISTICS OF TECHNICALLY 

RECOVERABLE RESOURCES

Tables 2 and 3 show the expected values of the assessed

technically recoverable oil and gas in continuous-type plays

and in coal-bed gas plays, respectively. The 302 TCF

assessed in sandstone/siltstone, shale, and chalk continuoustype plays and the 50 TCF in coal-bed gas together represent

more than twice the estimated technically recoverable undiscovered conventional gas assessed in the lower 48 States.

The 2 BBO assessed in continuous-type oil plays is small

compared to oil in undiscovered conventional fields. More

than half this oil was in the Austin Chalk plays of the Western Gulf province (047).

The geographical concentration of the resources

assessed in continuous-type gas and in coal-bed gas plays is

very uneven. Three of the twelve provinces with assessed

continuous-type gas accumulations accounted for two-thirds

of the gas. These dominant provinces include Southwestern

Wyoming (037), Appalachian Basin (067), and Central

Montana (028). Similarly, of the 13 provinces with assessed

coal-bed gas plays, the Uinta-Piceance (020), the San Juan

(022), and the Appalachian (067) Basins accounted twothirds of the total gas.

With few exceptions the coal-bed gas assessed by geologists was restricted to depths of 6,000 ft or less. One-third

of the 302 TCF of technically recoverable gas assessed in

continuous-type plays is shallower than 5,000 ft and onefifth is deeper than 15,000 ft. Coal-bed gas and shallow gas

in continuous-type gas plays together account more than 150

TCFG. The in-place volumes of hydrocarbons in unconventional plays are overwhelming. Some unconventional plays

were not assessed because the geologic and production data

were simply not sufficient or because the inferior quality of

the resources, in the assessor’s judgment, was outside the

practical limits of recovery technology.

INCREMENTAL COSTS OF OIL AND GAS FROM 

CONTINUOUS-TYPE AND COAL-BED GAS 

ACCUMULATIONS

For unconventional resources, incremental costs represent the full costs of exploring, developing, and producing

the commercially developable cells in a specific 5,000-ft

depth interval of a continuous-type or coal-bed gas play.

Individual depth intervals of continuous-type or coal-bed gas

plays will not be explored unless the aggregate expected

after-tax net present value of the commercially developable

cells is sufficient to cover costs of testing all cells in the

depth interval.

Gas resources in continuous-type gas accumulations are

massive, but are also dilute, as evidenced by typically low

well productivities. Only 7 percent of the assessed technically recoverable gas is economic to find, develop, and produce at $2 per mcf. At $3.34 per mcf, 15 percent of the

assessed gas is economic (see table 2). At $2 per mcf, plays

in the San Juan Basin (022), the Louisiana-Mississippi Salt

Basins (049), the Uinta-Piceance Basin (020), and the Central Montana (028) provinces account for 85 percent of the

economic resources in continuous-type gas accumulations

(see table 2). These provinces continue to dominate as costs

increase to $3.34 per mcf and plays from the Michigan (063),

Appalachian (067), and Southwestern Wyoming (037) provinces are added. The lowest cost continuous-type gas plays

evaluated were in the San Juan and Louisiana-Mississippi

Salt Basins, having costs of $1.10 per mcf.

The quantity of oil assessed in continuous-type oil

accumulations is small. For continuous-type oil accumulations at $18 per barrel and $30 per barrel, about 7 percent and

50 percent, respectively, of the assessed technically recoverable oil is economic (see table 2).

Table 3 shows, at $2 per mcf, 30 percent of the assessed

coal-bed gas is economic. The San Juan (022), UintaPiceance (020), and Appalachian (067) Basins account for

86 percent of the economic resources. As incremental costs
16 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES
INFERRED RESERVE ESTIMATES 17

increase to $3.34 per mcf, more than half of all the assessed

coal-bed gas becomes economic. The lowest cost plays (with

costs of $1 per mcf) were located in the San Juan Basin. 

The regional distribution of economic gas in continuous-type gas accumulations and coal-bed gas is notable. The

San Juan and the Uinta-Piceance Basins can supply West

Coast markets. Gas from the Michigan Basin Antrim Shale

and Central Appalachian coal-bed gas plays have ready

markets in the industrial Northeast. Economic undiscovered

conventional gas in these provinces is very modest.

Locational advantages, particularly in the Eastern Region,

permit higher well-head prices to offset the generally higher

costs of developing these unconventional gas resources.

Assumptions applied in the economic evaluation

assured conservative estimates of economic resources. For

example, it was assumed that the industry could not selectively drill a continuous-type play. However, an individual

firm may have site-specific or specialized knowledge that

allows it to high-grade a play by identifying “sweet spots.”

At the time of the 1995 National Assessment, the occurrence

and extent of these local sweet spots were not known with

sufficient detail to incorporate them. Selective drilling

reduces costs by siting wells in high-productivity areas and

avoiding noncommercial wells. For some plays, industry

production experience gained since the 1995 National

Assessment suggests more efficient well spacing (cell size)

than assumed. Although it was assumed that new wells are

required to test and produce each cell in a continuous-type

accumulation, in practice, the industry has recompleted

existing wells to produce these resources. 

INFERRED RESERVE ESTIMATES

FIELD GROWTH: ORIGINS AND 

QUALIFICATIONS

Field-growth projections are applied only to conventional pre-1992 discoveries. Inferred reserves (field growth)

are recoverable resources in discovered fields beyond current proved reserves that are expected to be added in the

future as proved reserves. Because proved reserves are
18 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

reported in financial statements, commercial transactions,

legal contracts, and in response to regulatory mandates by

governmental entities, traditionally its definition reflects the

highest degree of certainty about economically recoverable

volumes of the resource in identified fields. Although worded

slightly differently, standards of reporting proved reserves

published by the Securities and Exchange Commission

(1981), the Society of Petroleum Engineers (1987), and

Energy Information Administration (1994) convey essentially the same narrow definition. The Energy Information

Administration (1994) defines proved reserves as estimated

volumes of the resource which geologic and engineering data

demonstrate with reasonable certainty to be recoverable in

future years from known reservoirs under existing economic,

operating and, regulatory conditions. Reservoirs are proved

if commercial producibility is supported by actual production or conclusive formation tests (drill stem or wire line),

core analysis, and (or) electric or other log interpretations.

Proved reserves increase with normal field development

as boundaries of proved areas are extended by drilling; as

new pay zones, pools, or reservoirs are found and confirmed

by drilling; as new infill wells (vertical and horizontal) or

well-stimulation procedures contact previously inaccessible

hydrocarbons; and with the introduction of water-flood or

other fluid-injection programs. Data used in calibrating

cumulative growth functions (see earlier discussion) and estimating field growth, however, do not allow identification of

the source of reserve additions with level of effort expended

to increase reserves. Hence, costs were not definitively tied

to either past or projected field growth.

Field-growth projections are also not very robust to

changes in assumptions implicit in the calibration and application of the cumulative field growth function. The 1995

National Assessment, for example, assigned three times as

much oil and gas to inferred reserves than the 1989 USGS

Assessment (Mast and others, 1989). Part of the reason for

this increase is that newly available data from the 1977-1991

period show some fields continuing to grow 90 years after

discovery—well beyond the 60-year cutoff used in 1989 (see

footnote 2). In fact, if a 60-year field-growth cutoff is

imposed on these data, the inferred oil estimate is about onethird of 1995 estimate and the gas estimate is one-half of the

1995 estimate. The shape of the cumulative growth function

is also sensitive to the sample period used in calibration

(National Petroleum Council, 1992, p. 45–46).

Fields are not well-defined entities and, as a fundamental unit of observation, are frequently defined in an ad hoc

manner for the convenience of regulatory agencies or of

operators, or they are simply artifacts of the historical

discovery process. If the unit of observation is narrowed to

the level of the pool, as it is in Canada, reserve growth is

limited to extensions, infill drilling, well stimulation, and

efforts to enhance recovery. On average, pools reach full

development earlier than fields. Cumulative growth functions calibrated with Canadian data on pools show gas pools

reached 85 percent of full size 7 years after discovery and oil

pools reached 85 percent of full size 27 years after discovery

(K. Drummond, National Energy Board of Canada, written

commun., 1996). In contrast, U.S. gas fields did not attain 85

percent of their 90-year size until 61 years, and oil fields did

not attain 85 percent of their 90-year size until 66 years after

discovery. Growth is sustained over a longer time period in

oil accumulations than in gas accumulations. The low initial

recovery of oil, typically less than 35 percent of in situ

hydrocarbons rather than the 70 to 80 percent for gas fields,

makes the remaining oil an attractive target for progressively

more intensive development efforts, particularly for very

large fields. 

The unknown effects of model specification and errors

in the data have not been sufficiently formalized to quantify

the uncertainty in projected field-growth estimates. Costs

were not estimated because past or projected future field

growth could not be related to specific development efforts.3

However, within a province, continuing simultaneous new

field exploration, field development, and investment in pre1992 discoveries indicates costs associated with the marginal

quantities of oil and gas produced in each project are

comparable. In order to study potential reserves that might be

available for production during the next 2 decades, inferred

reserve projections from 1994 through 2015 were calculated.

Projected field-growth reserve additions through 2015

amount to about one-half the total oil and gas projected

through 2071 (see U.S. Geological Survey National Oil and

Gas Resource Assessment Team, 1995).

FIELD GROWTH THROUGH 2015:

A COMPARATIVE ANALYSIS

Figure 12 shows regional estimates of proved reserves,

projected oil growth though 2015, and estimated oil from

undiscovered conventional oil fields and continuous-type

accumulations with incremental costs of $30 per barrel

($3.34 per mcf). Figure 13 is similar but shows amounts of

non-associated gas. Only the non-associated gas growth in

the Cook Inlet area was projected for Alaska because gas is

not under development in the Northern Alaska province.

Proved reserve estimates, prepared by the Energy Information Administration (1994), are as of January 1994 and

include proved reserves of oil and gas from conventional

fields, continuous-type accumulations, and coal-bed gas.

Field-growth projections from pre-1992 discoveries started

 3Investments in field development and enhanced recovery are site specific, so the technical characteristics of the discovered pools or fields must

be known in some detail to choose among alternative technologies. One approach is to develop a series of sceening criteria and engineering cost models

to apply to candidate fields to a priori estimate costs of future growth in reserves. Such an approach was used by Bowers and Drummond (1994) and

the National Petroleum Council (1984).
IMPLICATIONS AND LIMITATIONS 19

in 1994. Figures 12 and 13 are useful because they show

quantities and sources of oil and gas that could be available

for production during the next 2 decades through 2015.

Overall, projected growth (of pre-1992 oil discoveries)

through 2015 accounts for about 44 percent of the 69 BB of

the crude oil represented by regions and sources shown in

figure 12. Proved reserves account for 29 percent, and economic oil discoveries and continuous-type accumulations

accounted for the rest. Regional shares of oil growth in the

lower 48 States mimic the pattern observed during the 1977

to 1991 data period. The Alaska, Pacific Coast, and West

Texas and Eastern New Mexico Regions account for almost

three-fourths of projected oil growth. The Gulf Coast Region

has almost 30 percent of the oil discovered to date but

accounts for only 5 percent of the projected growth (see fig.

D-1, Appendix D). Its disproportionately low oil growth may

result because the region has higher initial recovery of the inplace oil, leaving less oil for enhanced recovery. 

Projected field growth (of pre-1992 gas discoveries)

through 2015 accounts for about a quarter of the 381 TCF of

non-associated gas represented in figure 13. Proved reserves

account for 30 percent, and economic gas from new gas

discoveries, continuous-type accumulations, and coal-bed

gas account for 44 percent. In the lower 48 States, projected

regional shares of growth almost duplicates the pattern

observed for growth of non-associated gas during the 1977

to 1991 period. The Gulf Coast and Midcontinent Regions

account for 80 percent of non-associated gas growth

through 2015. In summary, quantities of oil and gas from field growth

could account for 44 percent of the oil and a quarter of the

non-associated gas available for production during the next

2 decades. Estimated quantities of oil are large but the deliverability or flow rates of the resource from enhanced recovery projects are typically inferior to flow rates that can be

achieved in newly discovered conventional fields of comparable size. In comparison to assessed quantities of economic

undiscovered oil resources, break-throughs in improvements

in recovery efficiency of oil-in-place would make old fields

into even more important sources of future domestic supplies

than suggested above.

IMPLICATIONS AND LIMITATIONS

Several findings are worth further elaboration. The 1994

proved reserves of oil, non-associated gas, and total gas

amount to roughly 10 times their 1994 production, respectively. Assuming this reserves-to-production ratio is sustained in the future, then, in order to maintain 1994 production

through 2015 (that is, 22 years), additions to oil and gas

reserves from field growth and economic undiscovered conventional and unconventional resources must amount to 42.8

BBO and 259.5 TCF non-associated gas (or 298.2 TCF total

non-associated and associated gas). Even if the quantities projected from field growth are added to reserves during this

Figure 12. Estimates, as of January 1994, of proved crude oil reserves, projected crude oil reserve additions through 2015 for oil

fields discovered before 1992, and the combined estimates of crude

oil in undiscovered conventional oil fields and from continuoustype oil accumulations having incremental costs of $30 per barrel.

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 10 20 30 40 50 60 70 

GAS, IN TRILLIONS OF CUBIC FEET

Proved reserves Growth through 2015

Conventional undiscovered and 

MMunconventional at $3.34/mcf

EXPLANATION

Figure 13. Estimates, as of January 1994, of proved non-associated

gas reserves, projected non-associated gas reserve additions

through 2015 for gas fields discovered before 1992, and the combined estimates of non-associated gas in undiscovered conventional

gas fields and from continuous-type gas accumulations having incremental costs of $3.34 per thousand cubic feet.

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 2 4 6 8 10 12 

OIL, IN BILLIONS OF BARRELS

Proved reserves Growth through 2015 

Conventional undiscovered and 

MMunconventional at $30/bbl

EXPLANATION
20 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

time, expected total additions from economic undiscovered

conventional and unconventional oil and gas at $18 per barrel

($2 per mcf) would not be enough to maintain 1994 production. When prices are $30 per barrel ($3.34 per mcf), projected

growth and total reserve additions from economic oil and gas

barely meet these requirements. Moreover, the development

of newly discovered conventional fields would not likely add

their entire ultimate recovery to proved reserves during this

time period without greatly accelerated development. Projected reserve additions from pre-1992 discoveries (field

growth) may also be optimistic—half of the hydrocarbons

from field growth expected during the next 80 years were projected in the period to 2015. In summary, even though it

appears possible with increases in real prices to $30 per barrel

($3.34 per mcf) to maintain production at levels comparable

to that of 1994 production, this production level will be very

difficult to achieve without significant improvements in

exploration and production technology.

Analysis shows that gas from continuous-type accumulations and coal-bed gas can make significant contributions to

supply and identifies provinces where this gas is currently

produced at competitive costs. By virtue of the large quantity

of technically recoverable unconventional gas assessed, its

share of total gas supplies is expected to increase as prices

increase. These accumulations are generally large, disperse,

hydrocarbon resources. Extraction costs for unconventional

gas are typically higher than costs for conventional accumulations; however, improvements in well-stimulation technology and practices could significantly increase the volume of

resources that can be accessed by an individual well, and thus

reduce unit costs. 

The abundance of oil and gas produced from conventional fields at high flow rates in the early years of the twentieth century permitted the U.S. economy to move from coal

to petroleum fuels as its basic energy source. However, the

1995 National Assessment showed that oil field growth and

unconventional gas account for the largest quantities of estimated technically recoverable crude oil and gas resources.

While there are some exceptions, reserve additions from

these sources are not characterized by high deliverability. The

characteristic of deliverability bridges the gap between economic reserves and actual production. Generally, lower quality resources require much larger amounts of capital to

produce at the same level as high-flow-rate conventional

resources. In particular, because their production characteristics are typically inferior to conventional accumulations of

similar size, they require larger amounts of proved reserves

per unit of daily production. Consequently, even though these

resources meet the standards of economic reserves, they

probably will not be produced rapidly. 

Estimates of economic oil and gas from conventional

undiscovered fields and unconventional plays were based on

the mean or expected value reported in the geologic assessment. It is appropriate to use this point estimate in the computations and for ease of communicating results; however, it

tends to convey a mistaken sense of precision in the results.

The economic analysis could also have been prepared using

distributions associated with the 5th or 95th fractiles of the

assessment. Indeed, there is also uncertainty in the costs and

technical relationships used in the economic analysis, as well

as the field-growth analysis that is yet to be quantified.

Economic models are also limited in that they are

abstractions designed to characterize a real economic system,

but they are typically detailed enough to only roughly approximate the outcomes of interactions between economic agents.

Only the general direction and the approximate magnitude of

the reaction of the system to change can be modeled. Incremental cost functions are time independent and should not be

confused with the firm supply functions that relate marginal

cost to production per unit time period. Because of the timeindependent nature of the incremental cost functions and the

absence of market-demand conditions in the analysis, user

costs or the opportunity costs of future resource use are not

computed. However, the incremental cost functions and the

data that underlie the functions can provide the basis for market-supply models.

For a national perspective, the resources estimated by

the Minerals Management Service (1996) in undiscovered

conventional oil and gas for the Federal Outer Continental

Shelf (OCS) should be added to the estimates presented here.

At $18 per barrel ($2 per mcf dry gas) the Minerals Management Service assessed a total of 14.4 BBO and 72.5 TCFG for

the U.S. OCS. At $30 per barrel ($3.34 per mcf dry gas), economic resources were estimated at about 21 BBO and 100

TCFG. Alaska’s OCS was assigned 3.8 BBO at $18 per barrel

and about 6.6 BBO at $30 per barrel. Amounts of economic

gas assigned to Alaska were very small. Based on the analysis

presented here, for onshore and State water areas at the $18

per barrel ($2 per mcf) level, total economic oil and gas

assessed in undiscovered conventional and unconventional

accumulations was 9.3 BBO and 113 TCFG, respectively. At

the higher price level, economic oil is estimated at 18.5 BBO

and total gas is 196.3 TCFG.

Acknowledgments.—The report represents a revision of

results, summary, synthesis, and interpretation of the economic analysis cited in the four earlier Open-File Reports on

the economics of various components of the 1995 USGS

National Assessment of Oil and Gas Resources listed in the

reference list. The geologic assessment project was under the

direction of D. Gautier. Province geologists responsible for

assessing the conventional undiscovered resources were M.

Ball, C. Barker, K. Bird. L. Beyer, T. Bruns, W. Butler, R.

Charpentier, G. Dolton, T. Dyman, T. Fouch, J. Fox, J. Grow,

J. Hatch, T. Hester, D. Higley, M. Henry, A.C. Huffman, Jr.,

S. Johnson, C.W. Keighin, M. Keller, B. Law, D. Macke, L.

Magoon, R. Milici, C. Molenaar, J. Palacas, W. Perry, Jr., J.

Peterson, R. Pollastro, R. Powers, R. Ryder, C. Schenk, C.

Spencer, R. Stanley, M. Tennyson, and C. Wandrey. D.H.

Root was responsible for aggregation of play-level geologic

assessments and prepared computations of province-level
REFERENCES CITED 21

expected frequency-size distributions of undiscovered conventional fields by depth intervals. Province geologists who

assessed the continuous-type accumulations were G. Dolton,

T. Dyman, T. Fouch, J. Hatch, D. Higley, A.C. Huffman, Jr.,

B. Law, R. Milici, W. Perry, R. Pollastro, R. Ryder, C.

Schenk, J. Schmoker, and C. Spencer. R. Crovelli and R.

Balay prepared the original computations of the expected values of the technically recoverable resources. J. Quinn was

responsible for development of empirical EUR distributions

and well-production characteristics of continuous-type

accumulations. D. Rice prepared the geologic assessment of

coal-bed gas. Advance Resources, Inc., prepared coal-bed

gas well-production characteristics. Field-growth projections

for the original assessment and subsequent regional projections were prepared by D.H. Root. I am also grateful to G.L.

Dolton and R.F. Mast for manuscript review.

REFERENCES CITED

Attanasi, E.D., 1994, U.S. North Slope gas and Asian LNG markets: Resources Policy, v. 20, no. 4, p. 247–255.

Attanasi, E.D., and Bird, K.J., 1996, Economics and undiscovered

conventional oil and gas accumulations in the 1995 National

Assessment of U.S. oil and gas resources: Alaska: U.S. Geological Survey Open-File Report 95-75J, 48 p.

Attanasi, E.D., Gautier, D.L., and Root D.H., 1996, Economics and

undiscovered conventional oil and gas accumulations in the

1995 National Assessment of oil and gas resources: Conterminous United States: U.S. Geological Survey Open-File Report

95-75H, 50 p.

Attanasi, E.D., and Rice, D.D., 1995, Economics and coalbed gas

in the 1995 National Assessment of oil and gas resources: U.S.

Geological Survey Open-File Report 95-75A, 22 p.

Attanasi, E.D., Schmoker, J.W., and Quinn, J.C., 1995, Economics

and continuous-type oil and gas accumulations in the 1995

National Assessment of U.S. oil and gas resources: U.S. Geological Survey Open-File Report 95-75F, 33 p.

Bowers, B., and Drummond, K., 1994, Conventional crude oil

resources of the Western Canadian Sedimentary Basin:

Petroleum Society of CIM & AOSTRA Paper No. 94-71,

June, 1994.

Energy Information Administration, 1994, U.S. crude oil, natural

gas, and natural gas liquids reserves: Washington, D.C., 1993

Annual Report, 155 p.

———1995, U.S. crude oil, natural gas, and natural gas liquids

reserves: Washington, D.C., 1994 Annual Report, 153 p.

Gautier, D.L., and Dolton, G.L., 1995, Methodology for assessment of undiscovered conventional accumulations in, Gautier,

D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds.,

1995 National Assessment of United States Oil and Gas

Resources—Results, Methodology, and Supporting Data:

U.S. Geological Survey Digital Data Series DDS-30, release

2, 1 CD-ROM.

Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L.,

eds., 1995, 1995 National Assessment of United States Oil

and Gas Resources—Results, Methodology, and Supporting

Data: U.S. Geological Survey Digital Data Series DDS-30,

release 2, 1 CD-ROM.

Houghton, J.C., Dolton, G.L., Mast, R.F., Masters, C.D., and Root,

D.H., 1993, U.S. Geological Survey estimation procedure for

accumulation size distribution by play: Bulletin of the

American Association of Petroleum Geologists, v. 77., no. 3,

p. 454–466.

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., Attanasi,

E.D., Martin, P.E., Cook, L.W., Carpenter, G.B., Pecora, W.C.,

and Rose, M.B., 1989, Estimates of undiscovered conventional

oil and gas resources in the United States; A summary: U.S.

Geological Survey/Minerals Management Service Special

Publication, 56 p.

Minerals Management Service, 1996, An Assessment of the undiscovered hydrocarbon potential of the Nation’s outer continental shelf: Washington D.C., 50 p.

National Petroleum Council, 1984, Enhanced oil recovery: Washington, D.C., 289 p.

———1992, The potential for natural gas in the U.S.—Source and

supply: Washington, D.C., v. 2, 400 p.

NRG Associates, 1993 and 1994, The significant oil and gas fields

of the United States: Colorado Springs, Colo., NRG

Associates, Inc. [includes data current as of December 31,

1992, and December 31, 1993, respectively—database available from NRG Associates, Inc., P.O. Box 1655, Colorado

Springs, CO 80901].

Rice, D.D., Young, G.B., and Paul, G.W., 1995, Methodology for

assessment of technically recoverable resources of coalbed

gas, in Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds., 1995 National Assessment of United States Oil

and Gas Resources—Results, Methodology, and Supporting

Data: U.S. Geological Survey Digital Data Series 30, release 2,

1 CD-ROM.

Root, D.H., and Attanasi, E.D., 1993, Small fields in the National

Oil and Gas Assessment: Bulletin of the American Association

of Petroleum Geologists, v. 77, no. 3, p. 485–490.

Root, D.H., Attanasi, E.D., Mast, R.F., and Gautier, D.L., 1996,

Estimates of inferred reserves for the 1995 USGS National Oil

and Gas Resource Assessment, U.S. Geological Survey OpenFile Report 95-75-L, 29 p.

Schmoker, J.W., 1995, Method for assessing continuous-type

(unconventional) hydrocarbon accumulations, in Gautier,

D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds.,

1995 National Assessment of United States Oil and Gas

Resources—Results, Methodology, and Supporting Data:

U.S. Geological Survey Digital Data Series 30, release 2, 1

CD-ROM.

Securities and Exchange Commission, 1981, Securities and

Exchange Commission reserves definitions: Regulation S-X,

Rule 40-10; Financial accounting and reporting oil and gas

producing activities: New York, Brown and Co.

Society of Petroleum Engineers, 1987, Reserves definitions

approved: Journal of Petroleum Technology, no. 576, p. 576.

U.S. Geological Survey National Oil and Gas Resource Assessment Team, 1995, 1995 National Assessment of United States

Oil and Gas Resources: U.S. Geological Survey Circular

1118, 20 p.
22 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

GLOSSARY OF SELECTED TERMS

barrels of oil equivalent (BOE).—gas volume and NGL volume that is expressed in terms of its energy equivalent in barrels of crude oil. For this assessment, 6,000

cubic feet of gas equals 1 barrel of crude oil, and 1

barrel of NGL equal 0.667 barrels of crude oil. 

cell.—a subdivision of a continuous-type oil or gas play, the

area of which is equivalent to the median drainage

area of wells producing from the play. A productive

cell has at least one well with reported production. A

nonproductive cell is a cell that was evaluated with

drilling but where none of the wells have reported

production. An untested cell is one that has not been

evaluated by a well. The number of cells in a play is

equal to the area of the play divided by the cell area.

conditional estimates.—sizes, numbers, or volumes of oil or

natural gas that are estimated to exist in an area,

assuming that at least some oil and gas is present.

Conditional estimates do not incorporate the risk that

the area may be devoid of oil or natural gas.

continuous-type accumulation.—a hydrocarbon accumulation that is pervasive throughout a large area, that is

not significantly affected by hydrodynamic influences, and for which the standard methodology for

assessment of sizes and numbers of discrete accumulations is not appropriate.

conventional accumulations.—discrete deposits having a

well-defined downdip oil or gas water contact, from

which oil, gas, or NGL can be extracted using traditional development practices.

crude oil.—a mixture of hydrocarbons that exist in the liquid

phase in underground reservoirs and remain liquid at

atmospheric pressure after passing through surface

separating facilities.

estimated ultimate recovery (EUR) probability distribution.—a probability distribution of ultimate recoveries of oil or gas that characterizes the distribution of

gas recoveries in productive cells within a play. An

empirical EUR distribution is based on the estimated

ultimate recoveries of wells thought to be representative of the play’s range of recoveries. The reported

EUR distribution for untested cells is assigned by the

geologist to represent the distribution of recoveries

from potentially productive, but as of yet untested,

cells within the play.

field.—an individual producing unit consisting of a single

pool or multiple pools of hydrocarbons grouped on, or

related to, a single structural or stratigraphic feature.

crude oil fields.—fields where the ratio of natural gas to

crude oil is less than 20 thousand cubic feet of gas

per barrel of crude oil.

non-associated gas fields.—fields where the ratio of natural gas to crude oil is at least 20 thousand cubic

feet of gas per barrel of crude oil.

field growth (inferred reserves).–that part of identified conventional resources over and above proved (measured) reserves, expected to be added to existing

conventional fields through extension, revision,

improved efficiency, and addition of new pools or

reservoirs.

gas-oil ratio (GOR).—average ratio of associated-dissolved

gas to oil.

growth function.—cumulative growth function relates a multiple of a field’s initially estimated size to the number

of years after discovery. A field age of zero is

assigned to the year of discovery. If the cumulative

growth function has the property that older fields

experience a smaller percentage of growth than

younger fields, then the cumulative growth function

is monotonic. An “annual growth function” expresses

annual percentage field growth as a function of the

estimated field size at the end of the previous year.

NGL to non-associated gas ratio.—volume of natural gas

liquids (NGL), in barrels, contained in 1 million

cubic feet of wet gas in a known or postulated gas

accumulation.

NGL to associated-dissolved gas ratio.—volume of natural

gas liquids, in barrels, in 1 million cubic feet of

associated-dissolved wet gas in a known or postulated oil accumulation.

natural gas.—a mixture of hydrocarbon compounds and

small quantities of non-hydrocarbons existing in gaseous phase or in solution with crude oil in natural

underground reservoirs at reservoir conditions. The

principal hydrocarbons normally contained in the

mixture are methane, ethane, propane, butane, and

pentanes.

natural gas liquids (NGL).—those hydrocarbons in natural

gas that are separated from the gas through the

processes of absorption, condensation, adsorption, or

other methods in gas processing or cycling plants.

Generally, such liquids consist of propane and

heavier hydrocarbons and are commonly referred to

as natural gasoline or liquefied petroleum gases.

After separation of natural gas liquids from the gas,

the gas is called “dry.”

play.—set of known or postulated oil and (or) gas accumulations sharing similar geologic, geographic, and

temporal properties, such as source rock, migration

patterns, timing, trapping mechanism, and hydrocarbon type. 

confirmed plays.—plays where one or more accumulations of minimum size (1 million barrels of oil or

6 billion cubic feet of gas) have been discovered

in the play.

hypothetical plays.—plays identified and defined based

on geologic information but for which no accumulations at minimum size (1 MMBO or 6

BCFG) have, as yet, been discovered.
GLOSSARY OF SELECTED TERMS 23

play attributes.—geologic characteristics thought to characterize the principal elements necessary for occurrence of oil and (or) gas accumulations of some

minimum size. Attributes used in this assessment

(charge, reservoir, and trap) are defined as:

charge.—occurrence of conditions of hydrocarbon generation and migration adequate to cause an accumulation of the minimum size. Subsidiary

elements of charge are source rocks with sufficient organic matter, temperature, and duration of

heating for expulsion of sufficient quantities of

oil and (or) gas and timing of expulsion of hydrocarbons to available traps. 

reservoir.—occurrence of reservoir rocks of sufficient

quantity and quality to permit containment of oil

and (or) gas in volumes sufficient for an accumulation of the minimum size.

trap.—occurrence of those structures, pinch-outs, permeability changes, and similar features necessary

for the entrapment and sealing of hydrocarbons

in at least one accumulation of the minimum size.

play probability.—for recoverable resources, represents the

likelihood that technically recoverable quantities of

oil or natural gas exist in at least one undiscovered

accumulation of the minimum size (1 MMBO or 6

BCFG) in the play being assessed.

proved (measured) reserves.—estimated quantities of crude

oil, natural gas, or natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from

known reservoirs under existing economic and operating conditions. Reserves are proved if economic

productivity is supported by actual production or

conclusive formation tests (drill stem or wireline), or

if economic producibility is supported by core analyses and (or) electric or other log interpretations. 

reservoir.—a porous and permeable underground formation

containing an individual and separate accumulation

of producible hydrocarbons that is confined by

impermeable rock or water barriers and is characterized by a single natural pressure system.

risked (unconditional) estimates.—resources estimated to

exist, including the possibility that the area of the

play may be devoid of oil or natural gas. For example, the risked mean may be determined by multiplication of the mean of a conditional distribution by the

related probability of occurrence. Resource estimates

presented in this report are risked estimates.

technically recoverable.—estimated to be producible using

current technology but without reference to

economic profitability.

ultimate field size (known recovery).—the sum of cumulative past production and estimated current reserves.

unconventional oil and gas accumulations.—a broad class of

hydrocarbon deposits of a type that traditionally have

not been produced using standard development practices. Unconventional deposits include continuoustype oil and gas accumulations and coal-bed gas.

Standard definitions of unconventional oil and gas

accumulations often hinge on gravity of oil or the

permeability of the oil and gas reservoir rock. Even

though most continuous-type accumulations are

characterized by poor reservoir permeability, not all

low-permeability deposits are continuous-type

accumulations. 

undiscovered resources.—resources postulated from geologic information and theory to exist outside of

known oil and (or) gas fields.

Published in the Central Region, Denver Colorado

Manuscript approved for publication August 11, 1997

Edited by Richard W. Scott, Jr.

Graphics preparation and photocomposition by

William E. Sowers; use made of 

author-drafted material
24 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

APPENDIX A—TABLES OF PROVINCE-LEVEL CONVENTIONAL

UNDISCOVERED RESOURCE ESTIMATES

Table A-1 (1/2)

6a(1/2)
appendix a—tables of province-level conventional undiscovered resource estimates APPENDIX A 25
26 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES
appendix a—tables of province-level conventional undiscovered resource estimates APPENDIX A 27
28 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES
appendix a—tables of province-level conventional undiscovered resource estimates APPENDIX A 29
30 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

APPENDIX B—TABLES SHOWING REGIONS, PROVINCES, PROVINCE

NUMBERS, AND PLAY NUMBERS FOR CONTINUOUS-TYPE PLAYS AND

COAL-BED GAS PLAYS
Appendix b—Tables showing regions, provinces, province numbers, and play numbers for continuous-type plays and coal- APPENDIX B 31
32 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES
APPENDIX C—METHODOLOGY 33

Geologists assessed conventional undiscovered accumulations having technically recoverable hydrocarbons of at

least 1 million barrels of oil (MMBO) or 6 billion cubic feet

of gas (BCFG) at the play level (see Gautier and Dolton,

1995, for more detail). Initial play definitions were based on

the assessor’s interpretations of the geology and hydrocarbon generation, past discovery information, and past drilling

information. Each play definition included a description of

the geographic location and geologic characteristics of the

play (see Gautier and others, 1995, for play descriptions). In

the case of confirmed plays, that is plays already having discoveries of at least 1 MMBO or 6 BCFG, the geologist

reviewed drilling penetration maps and historical discovery

data. For confirmed plays, a play probability of 1.0 was

assigned. In cases where the geologist posited a hypothetical

play, the play probability was computed as the product of the

occurrence probabilities of the three play attributes of

charge, reservoir, and trap. The play probability is multiplied by conditional resource estimates, which assumed the

occurrence of the threshold quantity of oil or gas remained.

The size distribution of undiscovered accumulations for

each play was modeled with a Truncated Shifted Pareto

(TSP) distribution (Houghton and others, 1993). The geologist chose a median and shape class for the TSP distribution

along with the minimum (95 percent), median (50 percent),

and largest (5 percent) numbers of undiscovered accumulations. The assessor also chose a minimum, median, and maximum depth for remaining resources in the play. Simulations

were used to combine distributions of size and numbers of

undiscovered accumulations to generate field size-frequency

distributions and to estimate the fractiles of the quantities of

oil, associated gas, associated gas liquids, non-associated

gas, and non-associated gas liquids. For an individual province, dependencies among plays were characterized by pairwise correlations. Simulations were used to aggregate plays

to the province level.

At the province level, the size-frequency distribution of

undiscovered “small fields,” that is fields smaller than 1

MMBO (or 6 BCFG), was derived with a statistical extrapolation procedure described by Root and Attanasi (1993). The

underlying assumption is the province size-frequency distribution of small fields can be described with a log-geometric

size distribution. The minimum estimated field size of the

smallest field-size class for which numbers of fields were

estimated was 32,000 barrels oil or 192,000 cubic feet gas.

The economic analysis of province assessments used

the discrete size-frequency distributions of expected (mean)

numbers of undiscovered oil and gas fields classified by

5,000-ft depth intervals. Table A-4, Appendix A, shows field

size classification for undiscovered conventional oil and gas

fields. Province-specific data, such as gas-to-oil ratios and

natural-gas-liquids-to-natural-gas ratios and expected sulfur

levels, were derived from data provided by the geologic play

assessments. Field size, depth, regional costs, and co-product ratios as well as well-head prices and hurdle rate of return

determine whether a new discovery will be commercially

developable.

The incremental cost algorithm used a finding-rate

model to predict, for successive increments of wildcat wells,

the size distribution and depths of new oil and gas field discoveries at the province level. Economic analysis of the

newly discovered fields of specific size and depth categories

is a standard application of discounted cash flow (DCF)

analysis. The net after-tax cash flow consists of revenues

from the production of oil and (or) gas less the operating

costs, capital costs in the year incurred, and all taxes. All new

discoveries of a particular size and depth class are assumed

to be developed if the representative field is found to be commercially developable, that is, if it has an after-tax net

present value greater than zero, where the discount rate

includes a hurdle rate representing the cost of capital and the

industry’s required return. When field-production decline

causes operator income to decline to the sum of direct operating costs and the operator’s production-related taxes, the

economic limit rate is reached and field production stops.

Newly discovered commercially developable fields are

aggregated to provide an estimate of potential reserves from

undiscovered fields at a given price and required rate of

return. Additional increments of, for example, 100 wildcat

wells are assumed to be drilled until the costs of drilling

wildcat wells are equal to or greater than the after-tax net

present value of the commercially developed fields discovered by that increment of wildcat wells.

The basis for the estimates of recoverable undiscovered

petroleum as a function of price is that incremental units of

exploration, development, and production effort will not

take place unless the revenues expected to be received from

the eventual production will cover the incremental costs,

including a normal return on the incremental investment.

Also, for the last increment of oil and gas produced from a

field, operating costs (including production-related taxes)

per barrel of oil equivalent are equal to price. These two

assumptions together imply that, for the commercially developable resources discovered by the last economic increment

of wildcat wells, the sum of finding costs and development

and production costs per barrel (that is, the “incremental cost

of the barrel”) is equal to the well-head price. Alternatively,

these costs are sometimes called the marginal finding costs

and the marginal development and production costs. Marginal finding costs are calculated by dividing the cost of the

APPENDIX C—METHODOLOGY

UNDISCOVERED CONVENTIONAL OIL AND GAS RESOURCES

APPENDIX C
34 ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES

last increment of wildcat wells (which is approximately

equal to the sum of the after-tax net present value of all commercially developable fields discovered in that last increment of exploration) by the amount of economic resources

discovered by the last increment of exploration. Marginal

development and production cost per barrel (for the economic resources discovered in that last increment of exploration) are calculated by subtracting the incremental finding

costs from the well-head price.

Finding-rate functions were calibrated for each province (see Attanasi, Gautier, and Root, 1996, for details of

these models). Because the size, depth, and number of undiscovered fields were calculated from the geologic assessment

data, the finding-rate functions determined the ordering of

new discoveries as well as the rate at which these fields

would be found as a function of cumulative wildcats drilled

in a particular depth interval. The allocations of wildcat wells

by depth interval was made in such a way that, for each increment of wildcat wells evaluated, the after-tax net present

value of the oil and gas fields discovered was maximized.

CONTINUOUS-TYPE ACCUMULATIONS IN 

SANDSTONE, SHALES, CHALKS, AND COAL

Geologic assessment of technically recoverable

resources required partitioning the continuous-type play into

equal-area cells equivalent either to the median drainage area

of productive wells in the play or the well spacing imposed

by the State regulatory authority. Data on results of past drilling and estimated recoveries of wells producing from the

play were assembled, interpreted, and used to calculate the

empirical drilling success ratio and the fractiles of the empirical distribution of estimated ultimate recoveries (EUR) of

productive cells. With these data as a guide, the geologist

subjectively estimated a drilling success ratio for undrilled

cells and assigned values to fractiles of distributions representing numbers of undrilled cells, the EUR distribution of

undrilled cells expected to be productive, and depths of

undrilled cells. Estimates and distributions describing the

undrilled cells were used to generate an expected discrete frequency-size (where size is hydrocarbon recovery) distribution of productive undrilled cells for the play at 5,000-ft

depth intervals. For each play, production flow rates of wells

having recoveries corresponding to the fractiles of the EUR

distribution were modeled using historical production data,

or the results of a reservoir-simulation model were calibrated

by matching well histories.

The procedure for calculating incremental costs relied

on results of a discounted cash flow analysis applied to wells

corresponding to the expected or mean cell frequency-size

distribution of undrilled cells. For a specific well-head oil

and gas price and required rate of return, the after-tax net

present value of commercially developable cells was calculated. Exploration of a play at a particular depth interval is

assumed to be economic if the expected aggregate after-tax

net present value of the developable cells would at least pay

for the cost of exploration, that is, the cost of drilling noncommercial cells in that depth interval. If the aggregate aftertax net present value of the commercially developable cells

was sufficient to cover such costs, the aggregate resources in

the commercially developable cells would be added to the

incremental cost function. Calculations were repeated

assuming progressively higher prices and aggregated by

depth intervals across plays to arrive at province incremental

cost functions. Industry, as a whole, has not generally been

successful in drilling the more productive cells in preference

to the less productive cells within an individual play, so, with

the exception of target depth, no high-grading or selective

drilling of cells within plays was assumed. The computational algorithm assumed that, for the last increment of

hydrocarbons added to reserves, the sum of marginal finding,

development, and production costs were approximately

equal to the assumed well-head price. For details of the geologic and economic assessment methods for coal-bed gas see

Rice and others (1995) and Attanasi and Rice (1995); for

other continuous-type plays see Schmoker (1995) and

Attanasi, Schmoker, and Quinn (1995).
APPENDIX D—ASSESSED TECHNICALLY RECOVERABLE RESOURCES, PROVED RESERVES, AND PAST 35

Figures D-1 and D-2 place the quantities of assessed

technically recoverable resources in perspective by comparing them to past cumulative production by USGS petroleum

region. From the bottom to the top of each bar, the figures

show cumulative production, proved reserves, inferred

reserves, and assessed technically recoverable oil and total

gas (associated and non-associated). Cumulative production

and proved reserves include conventional and assessed

unconventional sources of oil and gas. Inferred reserves represent the amounts of oil and gas expected to be added to

reserves in pre-1992 conventional discoveries during the 80

years following 1991. Items below the “zero” horizontal line

are identified technically recoverable oil and gas resources.

The assessed mean value of technically recoverable resources

in conventional undiscovered fields and in continuous-type

accumulations are represented by bars above the “zero” horizontal line.

For all regions combined, cumulative past oil production accounts for 58 percent of the total oil depicted in figure

D-1 (62 pecent in regions in the lower 48 States). The area

above the “zero” horizontal line accounts for only 12 percent

of the oil, leaving 30 percent in proved reserves and projected

field growth. For all regions combined, cumulative past gas

production accounts for 40 percent of the gas shown in figure

D-2. The area above the “zero” horizontal line accounts for

35 percent of the total gas, leaving 25 percent assigned to

proved reserves and field growth.

APPENDIX D—ASSESSED TECHNICALLY RECOVERABLE RESOURCES, 

PROVED RESERVES, AND PAST PRODUCTION



–60

–50

–40

–30

–20

–10

0

10

OIL, IN BILLIONS OF BARRELS

1 2 3 4 5 6 7 8

PETROLEUM REGION

Cumulative production

Proved reserves

Inferred reserves

EXPLANATION

Assessed technically recoverable

undiscovered conventional and 

assessed unconventional oil

Figure D-1. Estimates, as of January 1994, by petroleum region,

of discovered crude oil (i.e., cumulative production and proved

reserves), inferred reserves, and the combined mean estimates of

assessed technically recoverable undeveloped crude oil in undiscovered conventional oil fields and crude oil in continuous-type

oil accumulations. Bars representing discovered crude oil and

inferred reserves are below the “zero” horizontal line; bars representing assessed technically recoverable undeveloped crude oil in

undiscovered conventional oil fields and crude oil in continuoustype oil accumulations are above the “zero” horizontal line.

Petroleum regions are identified by number and name in table B-1,

Appendix B.

Figure D-2. Estimates, as of January 1994, by petroleum region,

of discovered gas (i.e., cumulative production and proved reserves),

inferred reserves, and the combined mean estimates of assessed

technically recoverable undeveloped gas in undiscovered conventional oil and gas fields, gas in continuous-type oil and gas accumulations, and coal-bed gas. Bars representing discovered gas and

inferred reserves are below the “zero” horizontal line; bars representing assessed technically recoverable undeveloped gas in undiscovered conventional oil and gas fields, gas in continuous-type oil

and gas accumulations, and coal-bed gas are above the “zero” horizontal line. Gas does not include natural gas liquids. Petroleum regions are identified by number and name in table B-1, Appendix B.

Inferred reserves of Region 1 include some gas discovered in the

Northern Alaska province not counted as proved reserves.













–500

–400

–300

–200

–100

0

100

200

1

PETROLEUM REGION

GAS, IN TRILLIONS OF CUBIC FEET 

Cumulative production

Proved reserves

Inferred reserves

EXPLANATION

Assessed technically recoverable 

undiscovered conventional and 

assessed unconventional gas

2 3 4 5 6 7 8

APPENDIX D