February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 1

Date February 18, 2015

To Karen Milam

From Lisa Tarquinio and Michael Fisher

Subject Profile of the Oil and Gas Extraction (OGE) Sector, with Focus on Unconventional Oil 

and Gas (UOG) Extraction 

1 Background

Recent advances in horizontal drilling and hydraulic fracturing along with rising oil and natural gas prices

through the middle of the last decade have made the extraction of natural oil and gas from shale and tightsand formations – unconventional oil and gas (UOG) – technically and economically feasible. 

Applications of these advanced (or unconventional) drilling and production techniques, coupled with 

large oil and gas reserves in shale and other unconventional petroleum-bearing formations around the 

country, have resulted in dramatic increases in the number of wells drilled and hydraulically fractured in 

the United States.

According to the 2013 Annual Energy Outlook (AEO2013) published by the Energy Information 

Administration of the Department of Energy, natural gas production is expected to increase by 44 percent

by 2040, compared to 2011 production levels.

1 EIA expects shale gas production to be the largest 

contributor to overall natural gas production by 2040, with its production more than doubling, and its 

share of total U.S. natural gas production increasing from 34 percent in 2011 to 50 percent. While tight 

gas production is expected to increase by 25 percent, EIA expects its share of total natural gas production 

to decline slightly (U.S. DOE, 2013a).

2

According to EIA, compared to 2011 production, total U.S. production of petroleum and other liquids3

will grow by 26 percent in million barrels per day by 2019, mostly due to growth in onshore production 

of crude oil and natural gas liquids (NGLs) from tight oil formations (including shale formations).4,5

Between 2019 and 2040, EIA projects that total U.S. production of petroleum and other liquids will 

 

1 All AEO2013 projections referred to in this document are for the Reference Case scenario.

2 Throughout this document, the term “tight gas” refers to all gas produced from tight gas formations except for gas produced 

from shale formations, which is separately referred to as “shale gas.”

3 EIA’s AEO2013 projections of future oil supply include two broad categories: petroleum liquids and other liquid fuels. The 

term petroleum liquids refers to crude oil and lease condensate – which includes tight oil, shale oil, extra-heavy crude oil, 

and bitumen (i.e., oil sands, either diluted or upgraded), plant condensate, natural gas plant liquids (NGPL), and refinery 

gain. The term other liquids refers to oil shale (i.e., kerogen-to-liquids), gas-to-liquids (GTL), coal-to-liquids (CTL), and 

biofuels (including biomass-to-liquids) (U.S. DOE, 2013a).

4 NGLs include a wide range of components produced during natural gas processing and petroleum refining. NGLs include 

ethane, propane, normal butane (n-butane), isobutane, and pentanes plus.

5 Throughout this document, the term “tight oil” refers to all oil produced from tight oil formations, including shale 

formations.

Memorandum

Environment and Resources
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 2

decline by 8 percent, as crude oil production from tight oil formations levels off due to depletion of the 

more productive tight oil resources, and shift of tight oil production to less-productive areas. Because 

many wells drilled in tight oil and shale oil formations have limited production history, the impact of 

recent technology advances on future resource recovery is highly uncertain. EIA projects that in 2040, 

conventionally and unconventionally produced crude oil will account for 51 percent of total U.S. liquids 

production, dropping from its peak of 59 percent in 2016. EIA expects that in 2040, tight oil – i.e., oil 

produced from very-low-permeability shale, sandstone, and carbonate formations – will account for 33 

percent of total U.S. oil production (U.S. DOE, 2013a). 

According to EIA, in 2012, tight oil and shale gas accounted for 29 percent of total U.S. crude oil 

production and 40 percent of total U.S. natural gas production, respectively (U.S. DOE, 2013g). As the 

number of unconventional oil and gas wells in the United States increases, so too will the volume of 

wastewater that requires management.

The analysis and information in this report was completed in 2013 (much of it based on EIA’s 2013 

Annual Energy Outlook report). EPA will update the profile with the latest information, including the 

latest annual energy report, for the final rulemaking.

1.1 Industry Focus of this Profile

The OGE industry is identified in the North American Industry Classification System (NAICS) as NAICS 

211111: Crude Petroleum and Natural Gas Extraction, and NAICS 211112: Natural Gas Liquid 

Extraction. These two 6-digit NAICS industry segments make up the OGE industry (NAICS 21111: Oil 

and Gas Extraction). Table 1-1 describes the two segments of the OGE industry.

To the extent possible, this profile reports data for the two OGE industry segments separately. However, 

as described below, much of the economic, financial and general business information used in this profile 

is available only at a higher level of industry definition, for example, at the level of the overall Oil and 

Gas Extraction industry. The UOG industry subsector lies mostly within Crude Petroleum and Natural 

Gas Extraction. The Natural Gas Liquid Extraction segment, however, does capture natural gas liquids 

that may be recovered from shale or other unconventional formations. 

Table 1-1: OGE Industry Segments and Number of Facilities

NAICS NAICS Description Facilities Included

Number of 

Facilities

211111 Crude Petroleum and 

Natural Gas Extraction

(1) exploration, development and/or production of petroleum or

natural gas from wells in which the hydrocarbons will initially 

flow or can be produced using normal pumping techniques or (2) 

the production of crude petroleum from surface shale or tar 

sands or from reservoirs in which the hydrocarbons are 

semisolids.

5,956

211112 Natural Gas Liquid 

Extraction

(1) recovery of liquid hydrocarbons from oil and gas field gases 

and also included (2) sulfur recovery from natural gas.

291

Total Oil and Gas Extraction (NAICS 21111) 6,247

Sources: U.S. DOC, 2007

2 Overview of Oil and Gas and the U.S. Economy 

This section provides a background review of the overall OGE industry and its products, including a 

review of the demand for, and role of, oil and gas in the U.S. economy, oil and gas production levels, and 

prices. The overall picture depicted by the data presented in this section is that between 2000 and 2012, 

U.S. consumption of natural gas increased, with most of that increase occurring after 2005. This increase 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 3

in demand for natural gas has been largely met through an increase in domestic production, mostly from 

shale and tight-sand formations, as opposed to imports. On the other hand, compared to 2000, 2012 

consumption of oil and petroleum products remained essentially unchanged, although it increased in the 

middle of the analysis period. Unlike in the case of natural gas, imports play a significant role in meeting 

U.S. demand for oil and petroleum products, despite the fact that in recent years this role diminished.

The decline in import dependence in recent years for both natural gas and oil and petroleum products is 

largely due to increased domestic production, which resulted in lower U.S. prices for these commodities.6

In turn, these lower prices lead to growth in exports of both natural gas, and oil and petroleum products. 

Compared to natural gas prices, however, oil prices remain high. 

2.1 Oil and Gas Demand and Consumption 

The major products of the OGE industry are petroleum, natural gas, and natural gas liquids.7Since 1990, 

the transportation sector has accounted for the largest share of U.S. consumption of liquid fuels, which 

include both petroleum and other liquids. As discussed above, in AEO2013 projections, other liquids 

include oil shale (i.e., kerogen-to-liquids), gas-to-liquids (GTL), coal-to-liquids (CTL), and biofuels 

(including biomass-to-liquids) (U.S. DOE, 2013a). The industrial sector accounts for the second largest 

share, followed by residential and commercial consumers and electricity generators.

In the United States, consumption of OGE products – oil, natural gas, and natural gas liquids – is closely 

linked to the nation’s overall economy. Specifically, as GDP grows and the economy develops, demand 

for these products as inputs for energy production, transportation, and certain manufacturing processes 

increases. However, improvements in energy efficiency over the last several decades have weakened this 

link: consumption of OGE products increases, in aggregate, with GDP, but generally at a lower rate than 

GDP. 

Figure 2-1 shows real U.S. GDP ($2013) for 2000 through 2012, graphed against total U.S. consumption 

of crude oil and petroleum products, and of natural gas (Quadrillion Btu). As shown in Figure 2-1, 

increasing economic output (or total economic activity) over the 13-year period of 2000 through 2012 is 

accompanied by increased consumption of either oil and petroleum products (between 2000 and 2006) or

natural gas (between 2007 and 2012). Specifically, between 2000 and 2006, the 16-percent growth in real 

GDP was accompanied by the 9-percent growth in consumption of oil and petroleum products, and a 7-

percent decline in consumption of natural gas. Between 2006 and 2012, 6-percent growth in real GDP 

was accompanied by the 18-percent increase in consumption of natural gas and the 9-percent increase in 

consumption of petroleum products. During 2009, all three metrics declined, with real GDP falling by 3 

percent, and consumption of oil and petroleum products, and natural gas declining 5 percent and 2 

percent, respectively, reflecting significant recessionary pressures. Overall, between 2000 and 2012, real 

GDP grew by 23 percent, while consumption of natural gas increased by 9 percent and consumption of oil 

and petroleum products decreased by 1 percent.

While changes in consumption of OGE products may not match the changes in real GDP in magnitude, it 

is clear that consumption is closely linked to GDP. Regardless of the direction of effect – does economic 

 

6 As discussed later in this profile, U.S. crude oil prices have been lower than international crude oil prices in recent years. 

This divergence has led to increased export of refined petroleum products, and recently to increased pressure for relaxation 

of the 40-year ban on exports of crude oil exports.

7 Natural gas liquids include ethane, propane, normal butane, isobutene, and pentanes plus, which are all longer carbon chain 

hydrocarbons than methane, which is the intended constituent of natural gas.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 4

growth drive oil and gas consumption? or does oil and gas consumption drive economic growth? – the 

importance of oil and gas consumption in the U.S. economy is clear. 

Figure 2-1: Real Gross Domestic Product (Billions; $2013) with Total Consumption of Crude Oil 

and Petroleum Products and Natural Gas (Quadrillion Btu)

Sources: U.S. BEA, 2014 and 2013; U.S. DOE, 2014g, 2013d, 2013e and 2013h

2.1.1 Consumption of Crude Oil and Petroleum Products

Domestic consumption of crude oil and petroleum products is met by a combination of domestic 

production and imports. As shown in Figure 2-1, compared to 2000, 2012 consumption of oil and 

petroleum products remained essentially unchanged, although it increased in the middle of the analysis 

period. Total consumption of crude oil and petroleum products peaked at 40 quadrillion Btu in 2005 and 

2006; this increase in demand was met through imports, which also peaked during that time at 73 percent 

of total consumption.

8 One reason for decline in the U.S. net dependence on imported liquid fuels since 

2005 is the reduction in demand in some uses, such as personal transportation and home heating, coupled 

with slow growth in other applications (U.S. DOE, 2013a). 

Between 2000 and 2012, the role of imports in meeting U.S. demand for crude oil and petroleum products 

decreased slightly from 67 percent of total U.S. consumption to 62 percent of total U.S. consumption. The 

role of domestically produced crude oil and petroleum products, on the other hand, increased steadily 

 

8 Figure 2-1 assumes that domestic crude oil production, less crude oil exports, plus net imports of crude oil and petroleum 

products, equals total domestic consumption of crude oil and petroleum products. The calculation does not account for 

changes in inventories.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 5

since 2009, possibly due to increasing prices for oil, relative to those for natural gas (Section 2.5), which 

made domestic oil production more attractive (Section 2.2.1).

Future domestic demand for liquid fuels will depend on the future level of activities dependent on liquid 

fuels, such as transportation. Demand will also be affected by the fuel efficiency of the consumption 

technology, and the potential for fuel switching, where liquid fuels are replaced with other fuel types, 

such as LNG, biofuels, or electricity. In 2012, the transportation sector accounted for 71 percent of 

petroleum and other liquids consumption, while the industrial sector and residential and commercial 

sector made up 23 percent and 5 percent of consumption, respectively. Power generation accounted for 

less than 1 percent of consumption (U.S. DOE, 2013c). According to EIA, as currently anticipated, 

consumption of petroleum and other liquids will grow through 2019, with the number of barrels per day 

falling by 5 percent between 2019 and 2040. The transportation sector will continue to account for the 

largest share of total consumption, despite its share of total consumption falling by 4 percentage points 

from 72 percent in 2012 to 68 percent in 2040, due to improvements in vehicle efficiency. The industrial 

sector is the only end-use sector likely to see an increase in consumption of petroleum and other liquids 

(U.S. DOE, 2013a).

Going forward, as currently anticipated, as the result of weak growth in demand for petroleum and other 

liquids due to tightening fuel efficiency standards in the United States coupled with faster growth in 

domestic production of petroleum, mostly from tight oil formations, the import share of total supply of 

petroleum and other liquids will decline. Further, with increasing domestic production and slow growth in 

consumption, the United States will likely become a net exporter of petroleum products, with net exports 

more than doubling (on a million barrels per day basis) by 2040, compared to 2011 (U.S. DOE, 2013a).
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 6

Figure 2-2: Total Domestic Consumption of Crude Oil and Petroleum Products (Quadrillion Btu)a

a. Abt Associates analysis to combine exports, imports and field production on a Btu-energy-consumed basis.

Sources: U.S. DOE 2013d, 2013e and 2013h

Figure 2-3 presents total consumption of crude oil and petroleum products by Petroleum Administration 

Defense District (PADD)9from 2000 to 2012. Over this period, consumption of crude oil and petroleum 

products increased in only one PADD, PADD 4: Rocky Mountain, where it rose by 5 percent. PADD 1: 

East Coast saw the largest decline (11 percent) followed by PADD 5: West Coast (6 percent), PADD 3: 

Gulf Coast (5 percent) and PADD 2: Midwest (3 percent). In 2012, PADD 1: East Coast accounted for 

the largest share of U.S. consumption of crude oil and petroleum products at 28 percent, followed by 

PADD 3: Gulf Coast (27 percent) and PADD 2: Midwest (26 percent), PADD 5: West Coast (15 

percent), and PADD 4: Rocky Mountain (4 percent).

 

9

Petroleum Administration Defense Districts (PADDs), a regional reporting concept developed during World War II, 

continue to be used by the EIA and other organizations to report information on petroleum (oil). PADDs were similarly used 

in this document to aggregate data on oil as well as natural gas, for consistency. For a breakdown of Petroleum 

Administration for Defense Districts by state please visit: http://www.eia.gov/oog/info/twip/padddef.html
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 7

Figure 2-3: Crude Oil and Petroleum Products Total Consumption in the United States by 

Petroleum Administration Defense District (Quadrillion Btu)

Sources: U.S. DOE, 2013f

2.1.2 Consumption of Natural Gas

U.S. consumption of natural gas rose throughout the 1980s and 1990s due to low prices relative to prices 

for oil products. This led to investments in infrastructure for natural gas, especially electric generation 

facilities (Augustine et al, 2006). Figure 2-4 shows total domestic consumption of natural gas for the 13-

year analysis period of 2000 through 2012. Total consumption of natural gas continuously declined until 

2005, at which point it began to steadily increase. Overall, between 2000 and 2012, total consumption of

natural gas increased by 13 percent. According to 2012 EIA data, a non-trivial share (8 percent) of the 

gross domestic supply of natural gas (from domestic production and imports) was consumed in the natural 

gas production and delivery process, itself, as lease and plant fuel (5 percent of total) and fuel for pipeline 

and distribution services (3 percent of total). The remaining 92 percent of gross supply is available to 

natural gas consumers, and was delivered to the following sectors: electrical power (36 percent of total), 

industrial (28 percent of total), residential (16 percent of total), commercial (11 percent of total), and 

vehicle fuel (0.1 percent of total) (U.S. DOE, 2014f).

Like oil consumption, natural gas consumption is met through both domestic production and imports of 

natural gas. Compared to oil consumption, however, natural gas imports make up a much smaller share of 

total domestic consumption of natural gas. While between 2000 and 2012 natural gas imports fluctuated, 

their share of domestic consumption overall grew through 2007, at which point it began to decline. 

Between 2007 and 2012, the share of natural gas imports decreased from 19 percent to 12 percent. 

Therefore, the overall increase in demand for natural gas was met through domestic production of natural 

gas, largely due to growth in production of natural gas from shale formations, rather than imports. While 

the decline in natural gas prices, resulting from growth in domestic natural gas production, mostly due to 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 8

shale gas, made the United States a less attractive export market for other countries, thereby reducing U.S. 

natural gas imports; they also made purchases of U.S. natural gas for foreign customers more attractive, 

increasing exports (U.S. DOE, 2013a). As shown in Figure 2-9, later in this report, exports of natural gas 

increased by more than six times during the period of analysis.

Future domestic consumption of natural gas and natural gas exports is subject to uncertainties, including, 

but not limited to domestic and international economic growth, natural gas prices, prices of alternative 

fuels, and development of new production capacity in foreign countries, particularly from deep-water 

reservoirs, shale gas deposits, and the Arctic. Within natural gas consumption, the largest changes are 

likely to occur in natural gas converted into liquid fuels, which is then directly consumed in transportation 

as compressed natural gas (CNG) or liquefied natural gas (LNG), or exported as LNG. A number of 

factors affect whether LNG is used as a transportation fuel or exported as LNG (U.S. DOE, 2013a). These 

factors include:

 The price differential between crude oil and natural gas. The higher is the oil-to-gas price ratio, 

the greater is the incentive to use natural gas, both in U.S. and foreign markets.

 The availability of LNG export terminals in the United States and import terminals in receiving 

countries. Currently, LNG exports are constrained by LNG export capability – i.e., the equipment 

for compressing and liquefying natural gas, for storing LNG, and for transferring the liquefied gas 

to LNG tankers. As of January 2013, the Department of Energy had received 31 applications for 

LNG export permits. Eight applications involve conversion of existing LNG import terminals to 

export capability, while the remaining 23 applications involve construction of new LNG export 

terminal capacity. These applications indicate significant interest of U.S. business to increase 

natural gas exports in light of natural gas’ significant discount to oil prices in U.S. markets, and 

increasing worldwide demand for natural gas. In addition to the need for export infrastructure in 

the United States, receiving countries must have capacity for receiving the LNG imports. 

Constraints exist here as well (Ratner et al, 2013). 

 Trade restrictions of export of natural gas. Under 1992 amendments to the Natural Gas Act, 

approval from the Department of Energy is required for exporting natural gas. Countries with 

which the United States has entered a Free Trade Agreement (FTA) qualify for natural gas export 

on the basis of “national interest.” However, export to non-FTA countries requires significantly 

more process and time to gain necessary export approval. Over 95 percent of the export volume 

in the recent applications for LNG export, as described above, involves exports to non-FTA 

countries (Ratner el al, 2013; U.S. DOE, undated). 

As the U.S. economy continues to recover, so will primary energy consumption. U.S. total natural gas 

consumption, as currently anticipated, will grow by 21 percent by 2040, compared to 2011. The 

residential sector is the only end-use sector where consumption is expected to decline; this likely decline 

is due to improvements in appliance efficiency and falling demand for space heating, attributable in part 

to people relocating to warmer regions of the country. Nevertheless, the residential sector will remain the 

third largest consumer of natural gas. Natural gas consumption in the electric power sector will grow at a 

faster average annual rate compared to the industrial sector through 2040, and is expected to account for 

30 percent of total electricity generation by 2040. The expected growth in natural gas usage by the electric 

power sector is due to a combination of factors that make natural gas generating units an attractive choice 

for new generation capacity: the relatively low cost of natural gas, relative to coal; relatively low capital 

costs for new capacity and/or combined cycle conversion of existing non-natural gas capacity; and 

increasingly stringent environmental limitations on coal-based generation (including greenhouse gas 

limitations) compared to natural gas generation. Nevertheless, the industrial sector, which has led natural 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 9

gas consumption since the 1990s despite a major overall decline in consumption during the last decade, 

will continue to account for the largest share of natural gas consumption through 2040, as the recovering 

energy-intensive industries enjoy relatively low natural gas prices. The electric power sector has seen the 

largest rise in natural gas consumption since 1990 and is projected to achieve a much closer second 

position to the industrial sector over the next several decades. The transportation and commercial sectors 

will continue to account for relatively small shares of total natural gas consumption (U.S. DOE, 2013a).

Figure 2-4: Total Domestic Consumption of Natural Gas (Quadrillion Btu)a

a. Abt Associates analysis to combine exports, imports and field production on a Btu-energy-consumed basis.

Sources: U.S. DOE 2014h, 2014j, and 2014k

Figure 2-5 reports total consumption of natural gas in the United States by PADD for 2000 through 2012.

During this time, consumption of natural gas increased in PADD 1: East Coast, PADD 4: Rocky 

Mountain, and PADD 2: Midwest by 37 percent, 27 percent, and 1 percent, respectively, while remaining

relatively flat in PADD 5: West Coast and in PADD 3: Gulf Coast. In 2012, natural gas consumption in 

PADD 1: East Coast, PADD 2: Midwest, and PADD 3: Gulf Coast each constituted approximately a 

quarter of total U.S. natural gas consumption. PADD 4: Rocky Mountain and PADD 5: West Coast madeup 4 percent and 15 percent of total natural gas consumption, respectively. Of note, the Central Atlantic 

and New England sub-districts of PADD 1: East Coast, which accounted for approximately 16 percent of 

total domestic consumption in 2012, have had little local natural gas production until the advent of shale 

gas production and have relied on imports from outside their regions to meet natural gas demand. The 

Marcellus Shale provides a closer supply source and may affect market prices for natural gas in these 

parts of PADD 1, in part because natural gas will not need to be shipped as long a distance to reach these 

markets.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 10

Figure 2-5: Natural Gas Total Consumption in the United States by Petroleum Administration 

Defense District (Quadrillion Btu)a

a. Data were taken from EIA, as reported by state, and aggregated to the PADD level by Abt Associates.

Sources: U.S. DOE, 2014g

2.2 Domestic Production

As stated previously, the main products of the OGE industry are petroleum, natural gas, and natural gas 

liquids. In 2012, the Gulf Coast area (PADD 3) accounted for the largest share of total U.S. natural gas

and crude oil production (58 percent each). The West Coast area (PADD 5) contributed the smallest share 

of total U.S. natural gas production (9 percent), while the East Coast area (PADD 1) accounted for the 

smallest share of total U.S. crude oil production (less than 1 percent). 

2.2.1 Domestic Production of Crude Oil

Beginning in 2005, the disparity between oil and natural gas prices started to grow as oil prices continued 

to rise while natural gas prices declined (see Figure 2-10). This gap in prices, largely due to the sharp rise 

in production of shale gas, made oil a relatively more attractive option for producers. Many firms that 

produce both gas and oil began to focus on acquisition of, and production from, liquids-rich plays over 

natural gas production (CHK, 2013; DVN, 2013). This shift towards liquids production is evident in the 

sharp rise in production from tight oil plays, including shale, beginning in 2008. From 2007 to 2013, EIA 

estimated that tight oil production increased 10-fold, from 0.34 to 3.48 million barrels per day (U.S. EPA, 

2014b). 

Figure 2-6 shows U.S. crude oil production by PADD for 2000 through 2012. Overall, domestic crude oil 

production steadily declined between 2000 and 2008, while steadily increasing after that. This rise in 

crude domestic oil production during the last decade coincides with an increase in domestic production of 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 11

tight oil after 2008 (U.S. DOE, 2013a). Overall, between 2000 and 2012, domestic crude oil production 

increased by 11 percent.

At the regional level, PADD 2: Midwest, where production more than doubled since 2000, saw the largest 

increase. PADD 4: Rocky Mountains also saw a substantial increase of 49 percent, followed by PADD 1: 

East Coast (22 percent) and PADD 3: Gulf Coast (18 percent). PADD 5: West Coast experienced a 

relatively large decrease of 39 percent. In 2012, PADD 3: Gulf Coast accounted for more than half of 

total U.S. crude oil production, while PADD 2: Midwest and PADD 5: West Coast accounted for nearly 

one fifth each. PADD 4: Rocky Mountains and PADD 1: East Coast accounted for the smallest shares of 

total U.S. crude oil production, at 7 percent and less than 1 percent, respectively.

Domestic production of light crude oil from tight formations (and consequent reduction in imports of light 

crude oil) has increased substantially over the last few years at the same time that imports of heavier 

crude oils have increased. As a result, U.S. petroleum and energy transportation firms have made 

significant investments in crude midstream infrastructure, including pipelines that will bring higher 

quantities of light sweet crudes to petroleum refineries along the U.S. Gulf Coast. Substantial investments 

are also being made in rail infrastructure for shipping oil from areas with limited pipeline capacity. 

However, recent accidents in rail transportation of crude oil are creating pressure to shift away from this 

transportation mode, and to accelerate construction of pipeline capacity. Going forward, more 

investments may have to be made to ensure sufficient transportation infrastructure. 

Future production of crude oil in the United States is highly uncertain and will depend on many factors, 

including the production profiles of individual wells over time, the costs of drilling and operating those 

wells, the generated revenues, and advancement of production technologies. These factors are especially 

important in the case of tight oil, as its production moves into less-explored areas. In addition, as noted 

above, less is known about the depletion profiles and longevity of tight oil formations because of the 

relatively short period that substantial production from these formations has been underway. The 

currently expected future growth in lower 48 onshore crude oil production will result primarily from 

continued development of tight oil resources, mostly in the Bakken (PADD 2: Midwest and PADD 4: 

Rocky Mountain), Eagle Ford Formation (PADD 3: Gulf Coast), and Permian Basin (PADD 3: Gulf 

Coast) (U.S. DOE, 2013a). 

According to EIA, as currently anticipated, total U.S. production of petroleum and other liquids will grow 

by 26 percent (in terms of barrels per day) by 2019, mostly due to increased production of tight oil, 

compared to 2011 levels. However, between 2019 and 2040, domestic production of petroleum and other 

liquids will decline by 8 percent due to depletion of resources in higher productivity fields, and extension 

of activity into lower productivity fields. Because oil production from tight formations is a relatively 

recent phenomenon, the ongoing exploration, appraisal, and development programs will expand 

operators’ knowledge about producing reservoirs, and could result in development of methods for 

increased production from existing production fields and/or discovery and development of additional tight 

oil resources. Therefore, whether and when tight oil production may start tapering off is highly uncertain. 

As currently anticipated, by 2040, tight oil production will account for 33 percent of total U.S. daily oil 

production (U.S. DOE, 2013a).

According to EIA, the Bakken and Three Forks formations (PADD 2: Midwest and PADD 4: Rocky 

Mountains) will account for 32 percent of cumulative tight oil production between 2012 and 2040, with

the Eagle Ford Formation and Permian Basin (PADD 3: Gulf Coast) accounting for 24 and 22 percent, 

respectively. The Austin Chalk (PADD 3: Gulf Coast), Niobrara (PADD 4: Rocky Mountain), Monterey

(PADD 5: West Coast), Woodford (PADD 2: Midwest), and other formations will account for the 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 12

remaining 22 percent of cumulative tight oil production. NGL production will also increase, mostly due to 

expected strong growth in shale gas production (U.S. DOE, 2013a).

Figure 2-6: Crude Oil Production in the United States by Petroleum Administration for Defense 

Districts (Quadrillion Btu)

Sources: U.S. DOE, 2013d

2.2.2 Domestic Production of Natural Gas

Natural gas, and especially unconventional natural gas, has become increasingly significant to the U.S. 

energy economy. This rising importance largely results from its lower air pollution characteristics 

compared to coal, its substantial, and increasing, domestic supply, and the presence of a well-developed 

processing and transmission/distribution infrastructure in the United States (GWPC and ALL, 2009). The 

energy sector has become progressively more reliant on natural gas with the electric power sector’s

consumption of natural gas increasing by more than 50 percent between 1996 and 2005 (Augustine et al, 

2006). In 2009, natural gas accounted for just under a quarter (23 percent) of total U.S. energy supply and 

the majority of natural gas was from domestic resources, unlike the case for petroleum products (McRae 

and Ruppel, 2011). As discussed above, the dependence of the electric power sector on natural gas is 

likely to increase going forward. Furthermore, the increase in supplies of domestic natural gas, largely 

from shale gas development, coupled with reduced industrial demand due to economic weakness, has 

reduced natural gas prices to levels below those forecasted earlier in the decade (McRae and Ruppel, 

2011). Increased natural gas production from shale and tight-sands formations also has the potential to 

further reduce U.S. dependence on energy-related imports.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 13

Figure 2-7 reports natural gas marketed production by PADD.10 Between 2000 and 2005, natural gas 

production declined by 6 percent and increased steadily after that resulting in an increase of 34 percent 

between 2006 and 2012. Between 2000 and 2012, total marketed production of natural gas in the United 

States as a whole grew by 25 percent over the analysis period, with an average annual growth rate of 0.8 

percent. 

The greatest increase in marketed production of natural gas occurred in PADD 1: East Coast, where 

production increased by more than five times during the 13-year analysis period. Marketed production of 

natural gas increased in other districts as well, nearly doubling in PADD 4: Rocky Mountain, followed by 

PADD 5: West Coast (45 percent), PADD 2: Midwest (6 percent), and PADD 3: Gulf Coast (4 percent). 

In 2012, approximately 60 percent of total U.S. marketed production of natural gas occurred in PADD 3: 

Gulf Coast, followed by PADD 1: East Coast (12 percent), PADD 2: Midwest (11 percent), PADD 4: 

Rocky Mountain (10 percent), and PADD 5: West Coast (9 percent). 

The U.S. OGE industry depends on the availability of oil and gas resources in the United States, so 

growth in the industry depends on current levels of production as well as available oil, natural gas, and 

natural gas liquids resources for future production. Future growth of natural gas production, including that 

of unconventional gas, will also depend on whether or not natural gas prices rebound going forward. Low 

natural gas prices will likely have an adverse effect on all natural gas extraction activity, including shale 

and tight gas, as natural gas producers find they are receiving diminishing returns on their investments in 

natural gas wells. Many OGE companies have investments in both oil and natural gas/natural gas liquids 

extraction and as the price of oil continues to rise while natural gas prices stay low, companies may 

switch investment from natural gas to oil. Chesapeake Energy, one of the major UOG companies, made 

such a transition in 2010 (Phillips, 2010). However, multiple sources have continued to project output 

growth based on increasing production of shale gas and tight oil. For instance, according to the Bureau of 

Labor Statistics (BLS), OGE output will increase by 28 percent, by 2022, compared to 2012 (U.S. DOL, 

2013b). According to EIA, natural gas production will likely increase by 44 percent by 2040, compared to 

the 2011 production levels, mostly due to growing development of shale gas, tight gas, and coalbed 

methane resources. EIA expects shale gas production to contribute the largest share to overall natural gas 

production growth, with its production more than doubling and its share of total U.S. natural gas 

production increasing from 34 percent in 2011 to 50 percent in 2040. While tight gas production is 

expected to increase by 25 percent, EIA expects its share of total natural gas production to decline 

slightly. The growth in CBM is not realized until 2035 when natural gas prices and demand levels are 

high enough to spur more drilling (U.S. DOE, 2013a).

 

10 Marketed production is defined by the EIA as “gross withdrawals less gas used for repressuring, quantities vented and 

flared, and non-hydrocarbon gases removed in treating or processing operations (includes all quantities of gas used in field 

and processing plant operations).”
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 14

Figure 2-7: Natural Gas Marketed Production in the United States by Petroleum Administration 

for Defense Districts (Quadrillion Btu)a

a. Data were taken from the EIA, reported by state, and then aggregated by PADD. EIA data for federal offshore natural gas marketed 

production in the Gulf of Mexico was added to PADD 3: Gulf Coast.

Sources: U.S. DOE, 2014h

2.3 Net Imports

Net imports of oil and natural gas, which reflect the balance between U.S. imports and exports, are an 

important measure of the country’s dependence on non-U.S. sources of these energy products, which are 

vital to our economy. Over the last several decades, the United States has been a net importer of both oil

and natural gas, despite being a source of production for both resources. While in 2012, the U.S. was still 

a net importer for oil and natural gas, the rise in domestic production from unconventional oil and gas is 

leading to major changes in U.S. dependence on foreign oil and natural gas as exports rise rapidly and 

imports decline. The decline in U.S. demand for foreign oil has already affected international oil prices, as 

witnessed by the decline in Brent Crude oil prices in 2013 (U.S. DOE, 2014i). Furthermore, according to 

EIA’s AEO2013 Reference Case, the United States is projected to become a net exporter of natural gas by 

2018 (U.S. DOE, 2014a).

The United States’ substantial dependence on oil imports has exposed the U.S. economy to substantial 

risk from rapidly increasing oil prices and supply disruption, with serious market disturbances in the early 

and late 1970s presenting significant challenges in terms of simultaneous occurrence of recession and 

input-based price inflation. The substantial improvements in energy efficiency achieved since the 1970s 

coupled with increased domestic petroleum and natural gas production in recent years, largely due to 

production of oil and gas from unconventional formations and by unconventional production techniques, 

puts the United States at the verge of energy independence, a stated policy objective for more than four 

decades.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 15

2.3.1 Net Imports of Crude Oil and Petroleum Products

Figure 2-8 presents U.S. net imports of crude oil and petroleum products against imports and exports for

2000 through 2012. Especially evident in the beginning of the period, changes in net imports are largely 

driven by changes in imports, with exports of crude oil facing significant limitations due to U.S. 

regulations.11 Net imports of crude oil and petroleum products increased through 2005, but have declined 

steadily after that. These changes in net imports are consistent with the overall changes in consumption of 

crude oil and petroleum products coupled with the overall changes in the domestic production of crude oil

during the period. This decline in imports during the last few years coincides with the rapid rise in 

production of tight oil, which began in 2008. The trend in net imports over this period generally reflects 

that of imports; however, while both net imports and imports declined since 2006, the higher decline in 

net imports, compared to that of imports, reflects the fast and steady increase in exports of crude oil and 

petroleum products beginning in 2006. Overall, between 2000 and 2012, U.S. imports of crude oil and 

petroleum products fell by about 8 percent, while exports increased by 208 percent, leadings to an overall 

29-percent drop in net imports. The continuing increase in domestic crude oil production will lead to 

continued decline in net imports of crude oil and petroleum production for the foreseeable future. Some 

analysts expect the United States to surpass Russia and Saudi Arabia as the world’s top oil producer by 

2015, and be close to energy self-sufficiency in the next two decades (Smith, 2013). However, if domestic 

production of tight oils slows down due to faster depletion of resources in current production than 

currently anticipated, net imports of crude oil and petroleum products may begin to decline at a lower 

rate.

 

11 U.S. regulations on the export of crude oil set aside only a few, specific types of oil, such as crude oil produced in the Cook 

Inlet, that qualify automatically for a U.S. oil export license. For all other types of crude oil, would-be-exporters must apply 

for an export license, which has had the effect of limiting U.S. crude oil exports (Clayton, 2013). 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 16

Figure 2-8: Net Imports of Crude Oil and Petroleum Products in the United States (Quadrillion 

Btu)a

a. Data from EIA is reported in thousands of barrels and was converted to quadrillion Btu.

Sources: U.S. DOE 2013e and 2013h

2.3.2 Net Imports of Natural Gas

Figure 2-9 presents net imports, imports, and exports of natural gas in the United States for 2000 through

2012. As is the case with crude oil and petroleum production, for natural gas, the trend in net imports over 

this period generally reflects that of imports; however, this relationship becomes weaker as exports of 

natural gas increase significantly and steadily. Overall, between 2000 and 2012, while natural gas imports 

decreased by 17 percent, natural gas exports increased by more than six times, resulting in a 57-percent 

decrease in net imports. Between 2000 and 2007, imports and net imports of natural gas increased by 22

percent and 7 percent, respectively, while exports more than tripled. However, increasing domestic 

production of natural gas, mostly from shale formations, resulted in lower natural gas prices, making the 

United States a less attractive market to sell in, which reduced U.S. natural gas imports, but a more 

attractive market to buy from, which increased U.S. natural gas exports. Consequently, between 2007 and 

2012, while imports declined by 32 percent, exports increased by 97 percent, leading to a 60-percent 

decline in net imports.

According to EIA, going forward, total domestic natural gas consumption is likely to be outpaced by 

natural gas production, led by growing development of shale gas resources. Consequently, assuming U.S. 

natural gas prices remain relatively low, exports are expected to grow as imports continue to decline, 

making the United States a net exporter of natural gas. In 2020, net exports will likely account for less 

than 1 percent of total U.S. natural gas consumption and by 2040 will account for 12 percent (U.S. DOE, 

2013a; U.S. DOE, 2014c). 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 17

Figure 2-9: Net Imports of Natural Gas in the United States (Quadrillion Btu)a

a. Data from EIA is reported in million cubic feet and was converted to quadrillion Btu.

Sources: U.S. DOE 2014j and 2014k

2.4 Economic Output

The OGE sector’s contribution to the U.S. economy may also be understood in terms of economic output, 

which is the value of goods and services produced by the economy, as a whole, or by a particular sector. 

Often, economic output is expressed in real terms – i.e., removing the effects of inflation – so that output 

can be measured over time on a basis that does not include the effect of inflation-based price increases. 

Increases in value that result from inflation-based price increases don’t reflect actual increases in the 

quantity of goods and services that are produced and are available for consumption. The Industrial 

Production Index (IPI) is a measure of real output in a given year, expressed as a percentage of real 

output in the base year, in this case 2007; therefore, this index shows how much production occurred in a 

given year relative to the production that occurred in 2007. Real output in this case represents quantity, 

not the actual value of the dollar, and of goods and services made. Table 2-1 provides the Federal Reserve 

System’s IPI for the OGE industry sector for 2000 to 2012. Between 2002 and 2005, real output in the 

overall OGE industry (NAICS 21111) fell every year, but increased steadily after that, with the largest 

increase of 15 percent occurring in 2012. Overall, during the 13-year period of 2000 through 2012, real 

output increased by 19 percent, at an average annual growth rate exceeding 1 percent. Real output in the 

NAICS 211111: Crude Petroleum and Natural Gas Extraction segment underwent approximately the 

same changes. Real output in the NAICS 211112: Natural Gas Liquid Extraction segment fluctuated 

throughout the analysis period, but overall increased by 24 percent; again, the largest growth of 14 

percent occurred in 2012.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 18

Table 2-1: Industrial Production Index for the OGE Sector, by Year and Segmenta

Oil and Gas Extraction

(NAICS 21111)

Crude Petroleum and Natural 

Gas Extraction

(NAICS 211111)

Natural Gas Liquid Extraction

(NAICS 211112)

Year Index 2007=100 % Change Index 2007=100 % Change Index 2007=100 % Change

2000 106.90 N/A 106.79 N/A 107.50 N/A

2001 107.69 0.7% 107.89 1.0% 104.37 -2.9%

2002 105.40 -2.1% 105.40 -2.3% 104.61 0.2%

2003 104.17 -1.2% 104.84 -0.5% 95.44 -8.8%

2004 101.56 -2.5% 101.58 -3.1% 100.76 5.6%

2005 97.72 -3.8% 97.83 -3.7% 95.68 -5.0%

2006 98.12 0.4% 98.17 0.4% 97.09 1.5%

2007 100.00 1.9% 100.00 1.9% 100.00 3.0%

2008 101.22 1.2% 101.29 1.3% 99.77 -0.2%

2009 106.34 5.1% 106.32 5.0% 106.92 7.2%

2010 109.69 3.1% 109.36 2.9% 116.60 9.1%

2011 115.57 5.4% 115.16 5.3% 124.19 6.5%

2012 126.68 15.5% 126.37 15.6% 132.97 14.0%

2000-2012 Comparison

Total Percent Change 18.5% 18.3% 23.7%

Average Annual 

Growth Rate 1.4% 1.4% 1.8%

a. IPI in a given year is a measure of real output in that year, expressed as a percentage of real output in the base year, in this case 

2007; therefore, this index shows how much production occurred in a given year relative to the production that occurred in 2007. 

Real output in this case represents quantity, not the actual value of the dollar, and of goods and services made.

Sources: FRS, 2013b

2.5 Prices in the OGE Industry Sector

While oil and natural gas are often considered together, the way in which prices are set for each 

commodity differs. While the price of oil is influenced more by global supply and demand, and 

international market conditions, U.S. natural gas prices are determined largely on a regional basis, in 

response to supply and demand conditions in North America. U.S. natural gas prices vary regionally 

across the United States mostly due to regional limitations on transportation and storage coupled with 

differences in supply/demand characteristics across regional markets. 

While these two products have some commonalities in their uses, they are not perfect substitutes as they 

require different transportation, processing, and consumption infrastructure. In instances where oil and 

natural gas can be used as substitutes, the price of one affects the demand for the other. In recent years, 

the oil-to-gas price ratio has reached historically high levels (McRae and Ruppel, 2011).

Natural gas is priced and traded at different locations, or market hubs at the intersection of major pipeline 

systems. Generally, the trading price of natural gas differs across the major hubs, depending on the supply 

and demand for natural gas at a specific location. There are over 30 major market hubs in the United 

States, with the Henry Hub, located in Erath, Louisiana, being the most important natural gas hub in 

North America. The settlement prices at the Henry Hub are used as benchmarks for the natural gas market 

in North America. Other major pricing locations include wellhead, where natural gas is produced, and 

citygate, where distribution companies receive gas from a pipeline. The wellhead price, hub price, and 

citygate price are all directly linked, with differences reflecting the cost of transporting natural gas by 

pipeline from wellhead to the hub, and then to the citygate.

Natural gas trades in two distinct markets: the spot market, and the futures market. Essentially, the spot 

market is the daily market, where natural gas is bought and sold for immediate delivery. For 

understanding the price of natural gas on a specific day, the spot market price is most informative. The 

futures market consists of buying and selling natural gas for future delivery under contracts; these 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 19

transactions may be carried out at spot prices or forward prices, i.e., prices expected to exist at the time of 

physical delivery. Futures transactions are often used to shield market participants – e.g., a local natural 

gas distribution company, or an industrial consumer – from volatility in spot prices. Natural gas futures 

are traded on the New York Mercantile Exchange (NYMEX); these are Henry Hub contracts in that they 

reflect the price of natural gas for physical delivery at this hub (NGSA, undated).

For oil prices, the Brent crude oil price is an international benchmark for light sweet crude oil and is used 

to price approximately two thirds of the world’s internationally traded crude oil. Brent crude oil is 

sourced from the North Sea and trades on the London-based Intercontinental Exchange (ICE) and the 

NYMEX. Another benchmark for crude oil, which is lighter and sweeter than Brent, is the West Texas 

Intermediate (WTI) price. WTI oil is a very high quality crude oil and is refined mostly in the Midwest 

and Gulf Coast regions in the United States and trades on the Chicago Mercantile Exchange (CME) and 

NYMEX. Cushing, Oklahoma is the largest U.S. oil-storage hub for WTI oil. While Brent crude recently 

has been regarded as a better indicator of global oil prices, WTI prices are generally regarded as a better 

reflection of the U.S. oil market. Historically, WTI has traded closely to Brent; however, during the last 

few years, WTI crude has traded at a discount to Brent crude. The chief reason behind this price spread

for otherwise near-perfect substitute commodities is the rapid inflow of oil into Cushing from areas like 

North Dakota and Canada, which has strained the transportation infrastructure needed to move crude oil 

from Cushing, Oklahoma, where WTI is quoted, to the Gulf Coast for refining. The resulting excess of 

supply at this market transaction node has depressed the WTI price compared to global prices, as better 

reflected in the Brent crude price. Like natural gas, both WTI and Brent oil trades in spot and future 

markets.

Figure 2-10 reports prices for natural gas and crude petroleum for 2000 through 2012, measured in 

dollars per million Btu (MMBtu) as the U.S. average wellhead price for natural gas, and as spot prices for 

WTI and Brent for crude oil. Overall, between 2000 and 2012, the price of WTI oil more than tripled, 

increasing from $5.24 per MMBtu to $16.22 per MMBtu. During the same time, the price of natural gas 

fell by 28 percent, from $3.58 per MMBtu to $2.59 per MMBtu. Throughout this period, oil prices 

increased substantially and steadily except during the recession period of 2008-2009. In contrast, natural 

gas prices increased to a much lower degree, and continued largely in a downtrend since 2008. The 

decline in natural gas prices during recent years results from abundant U.S. production of natural gas 

made possible largely through growth in shale and tight gas production, while oil prices increased in 

response to global demand. Markets are beginning to arbitrage this spread on both the demand and supply 

sides as consumers shift from oil to natural gas use where possible, and oil and gas developers shift their 

focus from natural gas to petroleum liquids production. The chart also shows the disparity between Brent 

and WTI prices (described above), which began in 2010. By 2013 (not shown), this gap had already 

begun to narrow as (1) infrastructure was put in place to transport tight oil from the Bakken, Permian and 

Eagle Ford to refineries and (2) the increase in U.S. light sweet crude oil production, mostly due to the

rise in production from tight oil formations, led to a decline in U.S. need for foreign crude oil and exerted 

downward pressure on Brent crude prices (U.S. 2014i). 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 20

Figure 2-10: Prices in the OGE Industry (Dollars per MMBtu)a

a. Wellhead price is reported by EIA in dollars per thousand cubic feet and both oil prices are reported in dollars per barrel. These values were 

converted to dollars per million Btu.

Sources: U.S. DOE, 2014d, 2014e, and 2014l

Pending further resolution of transportation system constraints in the United States, the spread between 

WTI and Brent oil prices will likely continue to narrow. According to EIA, by 2025, the spread will likely 

be as small as $2 per barrel. Overall, future oil prices are uncertain and will likely depend on: (1) the 

economics of petroleum liquids supply from non-OPEC countries, (2) OPEC investment and production 

decisions, (3) the economics of other nonpetroleum liquids supply, and (4) world demand for petroleum 

and other liquids. Demand in the OECD countries depends primarily on price, while demand in nonOECD regions, where larger growth in world demand is occurring, is driven primarily by rates of 

economic growth that are particularly uncertain. Overall, going forward, the combination of increasing oil 

production and lower demand for liquid fuels may put downward pressure on oil prices, all else equal. On 

the other hand, continuing economic recovery and resulting increase in energy demand may push oil 

prices upwards. The high uncertainty regarding future oil prices is reflected in the fact that EIA’s 

AEO2013, three main projections show markedly different changes in oil prices. All three projections 

show a price of just below $100 dollars per barrel in 2013 but while the reference case and high oil price 

case show increases to over $150 per barrel and over $225 dollars per barrel, respectively, the low oil 

price case shows a decline to about $75 per barrel. According to EIA, if crude oil prices are to increase

going forward, they are likely to do so more slowly than natural gas prices, bringing the oil-to-gas price 

ratio down from its 2012 level (U.S. DOE, 2013a).

Future U.S. natural gas prices are also uncertain and will depend on many factors, including, but not 

limited to, rates of resource recovery and decline from producing natural gas fields, especially shale gas 

wells, LNG exports and imports, and domestic and international economic growth. Higher economic 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 21

growth will result in higher natural gas consumption through higher levels of housing starts, growing 

commercial-floor space, and increasing industrial output. Increasing natural gas production will result in 

faster depletion of existing natural gas resources, leading to a more rapid increase in the cost of new 

production as newer, less productive resources are brought into production, pushing natural gas prices 

higher. As previously described, currently low natural gas prices are likely to make natural gas production 

less attractive to existing and potential OGE firms, reducing natural gas production, at least in a relative 

sense in the near-term. At the same time lower natural gas prices may result in greater natural gas exports, 

depending on economic conditions outside the United States, setting the stage for upward pressure on 

natural gas prices. EIA projects Henry Hub prices to grow in all of its AEO2013 resource recovery and 

economic cases, with the Reference Case predicting a doubling in prices from just under $4 per MMBtu

in 2011 to nearly $8 per MMBtu (2011 dollars) in 2040 (U.S. DOE, 2013a). In a study by Deloitte, the 

reference case Henry Hub spot prices increase by more than $3 per MMBtu between 2011 and 2030 while 

in an alternative case prices decline by about $2 per MMBtu, just between 2016 and 2030 (Choi and 

Robertson, 2011).

3 OGE Industry Structure and Economic Performance

This section reviews industry structure and recent economic/financial performance for the overall Oil and 

Gas Extraction industry (NAICS 21111) and its two segments: Crude Petroleum and Gas Extraction

(NAICS 211111) and Natural Gas Liquid Extraction (NAICS 211112). The review includes:

 Industry structure by number of firms/establishments and business size

 Revenue, employment, and payroll

 Pricing and market power

The OGE industry has grown over the past decade: (1) the number of firms and number of establishments 

in the United States have risen by approximately 2 percent and 5 percent, respectively, (2) the number of 

OGE industry employees has increased by 43 percent, (3) revenue has nearly doubled, and (4) annual 

payroll has increased substantially. On the other hand, the character of the industry, with regards to firm 

size, has seen little change as the ratio of small firms (those with less than 500 employees) to large firms 

remained relatively constant.

3.1 Number of Firms and Establishments

Table 3-1 reports the number of firms in the NAICS 21111: Oil and Gas Extraction sector by segment

using data from the Statistics of U.S. Businesses (SUSB) for the period 2000-2008. Census defines firms 

as: “a business organization consisting of one or more domestic establishments in the same state and 

industry that were specified under common ownership or control. The firm and the establishment are the

same for single-establishment firms. For each multi-establishment firm, establishments in the same 

industry within a state will be counted as one firm- the firm employment and annual payroll are summed 

from the associated establishments” (U.S. DOC, undated). The number of firms in the overall Oil and Gas 

Extraction sector fluctuated during this period but increased by more than 2 percent overall, with the 

greatest increase in the number of firms occurring in 2006 (less than 5 percent). The Crude Petroleum and 

Gas Extraction segment saw similar changes during that time period, with the number of firms increasing

modestly by less than 2 percent overall. The number of firms in the Natural Gas Liquid Extraction

segment, on the other hand, increased substantially, by 62 percent. The greatest increase in the number of 

firms in the Natural Gas Liquid Extraction segment took place in 2002 (35 percent).

Census defines establishment as: “a single physical location where business is conducted or where 

services or industrial operations are performed” (U.S. DOC, undated). Between 2000 and 2011, the 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 22

number of establishments in the overall Oil and Gas Extraction sector, reported in Table 3-2, saw a larger 

increase of 5 percent, with largest the increases of 6 to 7 percent occurring in 2006, 2008, and 2011. As is 

the case with the number of firms, the Crude Petroleum and Gas Extraction segment saw similar changes 

in the number of establishments during that time period, with an overall increase of 7 percent. Between 

2000 and 2012, the number of establishments in the Natural Gas Liquid Extraction segment, on the other 

hand, fell by 28 percent, at an average annual rate of 3 percent.

As both tables – Table 3-1 and Table 3-2 – show, the Crude Petroleum and Gas Extraction segment 

makes up nearly the entire Oil and Gas Extraction sector in terms of the number of firms and 

establishments. Specifically, in 2011, the Crude Petroleum and Gas Extraction segment accounted for 98

percent of all firms and 96 percent of all establishments in the overall Oil and Gas Extraction sector.

Table 3-1: Number of Firms in the OGE Industry Sector, by Year and Segment

Year

Oil and Gas Extraction

(NAICS 21111)

Crude Petroleum and Natural 

Gas Extraction

(NAICS 211111)

Natural Gas Liquid Extraction 

(NAICS 211112)

Number % Change Number % Change Number % Change

2000 6,472 N/A 6,417 N/A 84 N/A

2001 6,435 -0.6% 6,377 -0.6% 84 0.0%

2002 6,317 -1.8% 6,238 -2.2% 113 34.5%

2003 6,273 -0.7% 6,170 -1.1% 135 19.5%

2004 6,288 0.2% 6,187 0.3% 136 0.7%

2005 6,317 0.5% 6,215 0.5% 137 0.7%

2006 6,606 4.6% 6,498 4.6% 144 5.1%

2007 6,528 -1.2% 6,424 -1.1% 139 -3.5%

2008 6,641 1.7% 6,550 2.0% 124 -10.8%

2009 6,500 -2.1% 6,411 -2.1% 120 -3.2%

2010 6,513 0.2% 6,415 0.1% 130 8.3%

2011 6,628 1.8% 6,523 1.7% 136 4.6%

2000-2011 Comparison

Total Percent Change 2.4% 1.7% 61.9%

Average Annual 

Growth Rate 0.2% 0.1% 4.5%

Sources: SUSB, 2000-2011

Table 3-2: Number of Establishments in the OGE Industry Sector, by Year and Segment

Oil and Gas Extraction

(NAICS 21111)

Crude Petroleum and Natural 

Gas Extraction

(NAICS 211111

Natural Gas Liquid Extraction 

(NAICS 211112)

Year Number % Change Number % Change Number % Change

2000 7,740 N/A 7,273 N/A 467 N/A

2001 7,691 -0.6% 7,254 -0.3% 437 -6.4%

2002 7,629 -0.8% 7,135 -1.6% 494 13.0%

2003 7,493 -1.8% 6,968 -2.3% 525 6.3%

2004 7,372 -1.6% 6,883 -1.2% 489 -6.9%

2005 7,390 0.2% 6,948 0.9% 442 -9.6%

2006 7,803 5.6% 7,276 4.7% 527 19.2%

2007 7,542 -3.3% 7,221 -0.8% 321 -39.1%

2008 7,993 6.0% 7,643 5.8% 350 9.0%

2009 7,891 -1.3% 7,568 -1.0% 323 -7.7%

2010 7,859 -0.4% 7,521 -0.6% 338 4.6%

2011 8,095 7.3% 7,757 7.4% 338 5.3%

2000-2011 Comparison

Total Percent Change 4.6% 6.7% -27.6%

Average Annual 

Growth Rate 0.4% 0.6% -2.9%

Sources: SUSB, 2000-2011
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 23

3.2 Number of Small Firms

As discussed earlier, the overall Oil and Gas Extraction sector is subdivided into the Crude Petroleum 

and Natural Gas Extraction and Natural Gas Liquid Extraction segments. Small Business Administration 

(SBA) criteria define a small firm as having 500 or fewer employees, in both segments. Table 3-3 reports 

the distribution of firms by firm size for 2000 through 2011. The percentage of small firms in the overall 

Oil and Gas Extraction sector remained relatively constant during this period at approximately 99

percent. The Crude Petroleum and Natural Gas Extraction segment similarly maintained a high 

percentage of small firms, about 99 percent, throughout the period. On the other hand, the number of 

small firms in the Natural Gas Liquid Extraction segment increased substantially; as a result, the 

percentage of small firms in this segment began at 60 percent in 2000 and rose to 73 percent in 2011. 

Table 3-3: Number of Firms in the OGE Industry Sector by Year, Segment, and

Firm Size 

Oil and Gas Extraction

(NAICS 21111)

Crude Petroleum and 

Natural Gas Extraction 

(NAICS 211111)

Natural Gas and Liquid 

Extraction 

(NAICS 211112)

Year

Employment 

Group

Number of 

Firms % of Total

Number of 

Firms % of Total

Number of 

Firms % of Total

2000 <500 6,373 98.5% 6,327 98.6% 50 59.5%

>500 99 1.5% 90 1.4% 34 40.5%

2001 <500 6,343 98.6% 6,292 98.7% 55 65.5%

>500 92 1.4% 85 1.3% 29 34.5%

2002 <500 6,224 98.5% 6,154 98.7% 77 68.1%

>500 93 1.5% 84 1.3% 36 31.9%

2003 <500 6,183 98.6% 6,092 98.7% 99 73.3%

>500 90 1.4% 78 1.3% 36 26.7%

2004 <500 6,195 98.5% 6,103 98.6% 98 72.1%

>500 93 1.5% 84 1.4% 38 27.9%

2005 <500 6,230 98.6% 6,137 98.7% 100 73.0%

>500 87 1.4% 78 1.3% 37 27.0%

2006 <500 6,513 98.6% 6,416 98.7% 104 72.2%

>500 93 1.4% 82 1.3% 40 27.8%

2007 <500 6,423 98.4% 6,329 98.5% 98 70.5%

>500 105 1.6% 95 1.5% 41 29.5%

2008 <500 6,546 98.6% 6,462 98.7% 89 71.8%

>500 95 1.4% 88 1.3% 35 28.2%

2009 <500 6,407 98.6% 6,328 98.7% 84 70.0%

>500 93 1.4% 83 1.3% 36 30.0%

2010 <500 6,420 98.6% 6,334 98.7% 92 70.8%

>500 93 1.4% 81 1.3% 38 29.2%

2011 <500 6,530 98.5% 6,436 98.7% 99 72.8%

>500 98 1.5% 87 1.3% 37 27.2%

2000-2011 Comparison

Total Percent Change <500 2.5% 1.7% 98.0%

>500 -1.0% -3.3% 8.8%

Average Annual 

Growth Rate

<500 0.2% 0.2% 6.4%

>500 -0.1% -0.3% 0.8%

Sources: SUSB, 2000-2011

3.3 Employment 

Table 3-4 presents the number of employees for the overall Oil and Gas Extraction sector and by segment 

for 2000 through 2011. Over this period, total industry employment increased substantially, by 43

percent, with the largest increase of 53 percent and the largest drop of 24 percent occurring in 2007 and 

2008, respectively. Employment in the Crude Petroleum and Natural Gas Extraction segment saw similar 

changes, increasing by 48 percent during the analysis period. While employment in the Natural Gas 

Liquids Extraction segment also increased during that time, this increase was much smaller, at 7 percent.
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 24

While in 2007, the Crude Petroleum and Natural Gas Extraction segment saw the largest increase in 

employment of 70 percent, the Natural Gas Liquids Extraction segment saw the largest decline of 40 

percent. The employment contraction in 2008, and also in 2007 in case of the Natural Gas Liquids 

Extraction segment, is likely due to the economic downturn during that time. 

According to BLS, employment in the overall Oil and Gas Extraction sector will continue to increase; by 

2022, total sector-wide employment is projected to increase by 33.9 percent, compared to 2012 (U.S. 

DOL, 2013b). Employment in all but a few occupations within the overall Oil and Gas Extraction sector 

(file clerks, data entry and information processing workers, and machine tool cutting setters, operators, 

and tenders, metal and plastic) will grow by 2.9 percent to 39.1 percent. The occupations with the highest

expected growth include petroleum engineers, industrial machinery mechanics, logisticians and market 

research analysts and marketing specialists (U.S. DOL, 2013a).

Table 3-4: Number of Employees in the OGE Industry Sector by Year and Segment

Year

Oil and Gas Extraction 

(NAICS 21111)

Crude Petroleum and Natural Gas 

Extraction 

(NAICS 211111)

Natural Gas Liquid Extraction 

(NAICS 211112)

Number % Change Number % Change Number % Change

2000 83,012 N/A 73,704 N/A 9,308 N/A

2001 87,980 6.0% 78,394 6.4% 9,586 3.0%

2002 88,280 0.3% 76,794 -2.0% 11,486 19.8%

2003 83,447 -5.5% 70,534 -8.2% 12,913 12.4%

2004 82,879 -0.7% 69,723 -1.1% 13,156 1.9%

2005 85,562 3.2% 72,350 3.8% 13,212 0.4%

2006 92,683 8.3% 78,367 8.3% 14,316 8.4%

2007 141,809 53.0% 133,286 70.1% 8,523 -40.5%

2008 107,100 -24.5% 98,880 -25.8% 8,220 -3.6%

2009 107,394 0.3% 98,516 -0.4% 8,878 8.0%

2010 109,199 1.7% 99,502 1.0% 9,697 9.2%

2011 118,959 8.9% 108,954 9.5% 10,005 3.2%

2000 – 2011 Comparison

Total Percent Change 43.3% 47.8% 7.5%

Annual Average 

Growth Rate 3.3% 3.6% 0.7%

Sources: SUSB, 2000-2011

Combining the data shown in Table 3-4 on employment with the number of firms reported in Table 3-1

provides estimates of average employment per firm. In 2011, Oil and Gas Extraction sector firms 

employed, on average, 18 employees while the average number of employees per firm in the Crude 

Petroleum and Natural Gas Extraction segment and Natural Gas Liquid Extraction segment was 17 and 

74, respectively. 

3.4 Revenue and Payroll in the OGE Industry Segments

Revenue and payroll data from the Economic Census for years 1997, 2002, and 2007 also can provide 

insight into the effects of changing business conditions on the overall Oil and Gas Extraction sector and 

its two segments throughout the period of analysis. As reported in Table 3-5, between 1997 and 2007, the

overall Oil and Gas Extraction sector grew in revenue, annual payroll, and revenue less payroll. 

Likewise, the Crude Petroleum and Natural Gas Extraction segment experienced increases in all three 

metrics during that time, despite declines in 2002. While between 1997 and 2007 revenue and revenue 

less payroll in the Natural Gas Liquid Extraction segment increased, annual payroll fell. 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 25

Table 3-5 also displays average revenue per company (calculated as total revenues for the industry 

divided by the number of companies). For both the overall Oil and Gas Extraction sector and the Crude 

Petroleum and Natural Gas Extraction segment, average revenue rose between 1997 and 2007 with the 

majority of the increase occurring between 2002 and 2007. Average revenue in the Natural Gas Liquid 

Extraction segment also rose throughout the time period, but declined between 1997 and 2002.

Comparing the two segments, average revenue values for the Natural Gas Liquid Extraction segment are 

significantly higher than those in the Oil and Gas Extraction sector; one explanation of this difference is

that while total revenues for the Oil and Gas Extraction sector are higher, this segment also has a higher 

number of companies (see Section 3.1 above).

Table 3-5: Key Economic Performance Statistics for OGE Industry Sector, by Year and 

Segment, 1997-2007

Year

Revenue 

(Millions; 

$2013)

Average Revenue 

per Company 

(Millions, $2013)

Annual Payroll 

(Millions; 

$2013)

Revenue Less 

Payroll (Millions; 

$2013)

Oil and Gas Extraction (NAICS 21111)

1997 $140,327 $20 $7,520 $132,808 

2002 $141,625 $22 $6,713 $134,912 

2007 $279,309 $54 $10,504 $268,805 

Total Percent Change 

1997-2007 99.00% 167.10% 39.70% 102.40%

Average Annual Growth 

Rate 1997-2007 7.10% 10.32% 3.40% 7.30%

Crude Petroleum and Natural Gas Extraction (NAICS 211111)

1997 $106,447 $16 $6,781 $99,666 

2002 $105,217 $17 $6,110 $99,107 

2007 $232,972 $46 $9,953 $223,019 

Total Percent Change 

1997-2007 118.90% 196.37% 46.80% 123.80%

Average Annual Growth 

Rate 1997-2007 8.10% 11.48% 3.90% 8.40%

Natural Gas Liquid Extraction (NAICS 211112)

1997 $33,881 $381 $739 $33,142 

2002 $36,408 $294 $603 $35,805 

2007 $46,337 $414 $551 $45,786 

Total Percent Change 

1997-2007 36.80% 8.68% -25.50% 38.20%

Average Annual Growth 

Rate 1997-2007 3.20% 0.84% -2.90% 3.30%

Sources: U.S. DOC, 1997, 2002, and 2007

3.5 Capacity Utilization

Capacity utilization measures output as a percentage of total potential output based on available capacity. 

The Federal Reserve Bank reports capacity utilization for the overall Oil and Gas Extraction sector. As 

depicted in Figure 3-1, capacity utilization declined between 2000 and 2005 from almost 95 percent to 

just below 90 percent. As discussed earlier, during this period, the number of firms and establishments in 

the OGE sector and its two segments declined (Section 3.1), along with domestic production (Section 2.2

and Section 2.3). This may have been partly caused by the recession of early 2000s. Between 2005 and 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 26

2012, capacity utilization overall increased steadily, except for a mild decline in 2008, again, likely due to 

weakening of the overall economy. The larger increases in capacity utilization occurred between 2005 

and 2007, in 2009, and in 2012. The overall increase in capacity utilization since 2005 coincides with the 

increase in natural gas production during that period and with production of domestic crude oil since 

2008. Compared to 2000, capacity utilization in the Oil and Gas Extraction sector increased slightly by 3 

percent to 98 percent; such high capacity utilization leaves only modest room for production growth 

without capacity/infrastructure investments.

Figure 3-1: Capacity Utilization for OGE Industry (NAICS 21111)

Sources: FRS, 2013a

3.6 Market Structure, Pricing, and Concentration in the OGE Industry Sector

The oil and gas industry has been traditionally viewed as a tiered industry, with companies ranging from 

independent oil and gas exploration and production companies, to mid-tier oil and gas companies that 

usually have some level of vertical integration (e.g., to include transportation, refining, and/or wholesale 

and retail distribution) in their operations, to major international companies, which have fully integrated 

operations and are among some of the largest companies in the world (APA, 2013; APC, 2013; CHK, 

2013). U.S. OGE firms operate in competitive markets, comprised of a large number of firms both 

nationally and in given production regions, and produce commodities with uniform characteristics. 

Consequently, natural gas and crude oil prices at the point of production – the wellhead – are largely 

beyond the influence of the individual U.S. producer. The market power of U.S. OGE firms is further 

limited by the potential for imports to enter domestic supply channels and displace domestic production if 

and as U.S. producers attempt to increase prices. This last point is of greater importance for crude oil, 

compared to natural gas, due to the relative ease of crude oil transportation and storage, and the resulting 

potential for imports to enter U.S. markets. However, domestically produced natural gas also faces price 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 27

competition from imports through pipeline shipments from Canada and Mexico or import shipments of 

LNG.

3.6.1 Market Structure and Pricing in the OGE Industry Sector

Within the OGE industry, the markets for oil and natural gas differ substantially. The main differences are 

discussed below.

Oil

The oil market is a globally integrated market with multiple supply sources that are connected to multiple 

markets. This is in a large part due to the physical characteristics of oil, which allow it to be easily 

transported in a number of ways and at a moderate cost (McRae and Ruppel, 2011). The largest producers 

of oil are Saudi Arabia, Russia, and the United States. However, the largest eight oil companies, as of 

2005, were all national oil companies of the OPEC states, with Russian companies coming in at 10 and 11 

and Exxon Mobil at 12. While OPEC’s influence over oil prices has varied over time, in 2005 OPEC 

accounted for 65 percent of global oil reserves. As an international cartel, OPEC places producer quotas 

on members in an effort to manage world oil prices. Other oil companies, even major producers like 

Exxon Mobil, have relatively smaller reserves and have no influence over price (Grant et al, 2006). 

Therefore, crude oil producers tend to be price takers – meaning that they do not exert control over the 

price they receive at the point of production, the wellhead price. On the other hand, prices are greatly 

influenced by global demand for oil, with the largest source of demand being the U.S. and China (Grant et 

al, 2006). While the United States is also one of the largest crude oil producers, it remains a major 

importer of oil; as a result the level of U.S. imports can significantly influence oil prices. The recent 

upsurge in U.S. oil production, largely from tight oil plays, with a consequent decline in U.S. imports, has 

exerted downward pressure on international oil prices, as seen in recent Brent crude prices (Figure 2-10) 

(U.S. DOE, 2014i).

Natural Gas

Unlike the oil market, natural gas markets divide roughly into three broad regionalized markets: North 

America, Europe (including North Africa and Russia), and Asia (with links to the Persian Gulf). In North 

America, specifically within the United States, there is a relatively mature, integrated natural gas market 

with a robust spot market for the natural gas commodity. In U.S. natural gas markets, natural gas spot 

prices are determined by overall supply and demand (McRae and Ruppel, 2011). There is potential for 

market and pricing power along the natural gas supply chain – particularly at the natural gas 

transportation stage because of the limited pipeline network and general monopoly tendencies of a 

company controlling access to a major pipeline. However, this market power potential does not extend to 

the natural gas producer since like crude oil producers, natural gas producers have relatively small 

reserves with no influence over price.12 Therefore, natural gas producers also tend to be price takers. 

Natural gas prices are determined by a combination of national and regional market factors. A “general”

national price for natural gas is determined by broad supply and demand conditions in the overall 

 

12 The potential for market power does exist at the level of natural gas transportation and distribution because of the ability for 

pipelines and/or distribution companies to provide transportation and distribution services in a monopoly or oligopoly 

market structure. The pricing power from the transportation and distribution ‘bottlenecks’ can work both in the direction of 

the consumer, who may face limited supply choices for receiving natural gas, and in the direction of the natural gas 

producer, who may face limited choices for shipping gas from the point of production to market. For these reasons, shipment 

rates for interstate natural gas pipelines require approval from the U.S. Federal Energy Regulatory Commission (FERC), and 

natural gas sales prices for natural gas distribution companies, which distribute gas to local consumers, remain regulated by 

state regulatory commissions. 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 28

domestic market. Because supply is relatively fixed in the short run, prices can fluctuate substantially 

with changes in demand – e.g., due to changing economic conditions, or weather conditions. On the 

supply side, differences in natural gas production, storage levels, and transportation costs will also affect 

price. Gas prices can be further affected, differentially, at the regional level, based on supply/demand 

characteristics in specific regional markets. Limitations on transportation and storage infrastructure, 

which could effectively limit the flow of gas into a specific region despite rising demand, can lead to 

increased prices in that region than observed in other regions. Similarly, increased production in a region, 

such as is now occurring in the Mid-Atlantic region as a result of increased gas production from shale 

formations, can lead to relative price declines. 

Over a longer period, natural gas prices can exhibit structural cyclicality. To illustrate, low production of 

natural gas means low supply and high prices which leads to an increased incentive for drilling. As 

drilling and production increase so does supply leading to falling prices, which may again lead to lower 

production. 

Large-volume consumers of natural gas, mainly industrial consumers and electricity generators, generally 

have the ability to switch between oil and natural gas. When the price of gas is low relative to oil, these 

consumers could switch to gas, increasing demand for natural gas and increasing gas prices. 

Alternatively, when gas prices are high, demand could shift in the opposite direction causing a relative 

decrease in natural gas prices (U.S. DOE, 2011b).

3.6.2 Concentration in the OGE Industry

As previously discussed, the degree of concentration in national and regional markets can indicate 

potential for market power, which may provide potential for firms to affect prices – but subject overall to 

the broad market factors described above. Within the overall OGE sector, merger and acquisition (M&A) 

activity in the Exploration & Production (E&P) segment increased since the first quarter of 2009,

reaching a peak in the fourth quarter of 2012 (Deloitte, 2013). During this period, low prices for natural 

gas created a financial strain on small and midsized producers, resulting in increased consolidations in 

this industry segment. Increased acquisition and consolidation also occurred as larger oil OGE companies 

acquired the companies and/or production assets of smaller shale oil and gas producers, as the business 

potential of shale oil and gas has become increasingly obvious. Major acquisitions by some of the larger 

companies occurred in the Eagle Ford and Marcellus Shale during 2011 due to increasing confidence in 

the long-term potential for production of natural gas and oil from shale formations. Financial buyers also 

were making deals involving shale oil and gas plays. Deals by midstream businesses remained relatively 

constant with most transactions involving gas gathering and processing plays in North America (Deloitte, 

2011). However, during the first half of 2013, M&A activity in the E&P segment dropped, declining 43 

percent from the previous year. Analysts assess this decline in M&A as indicative of a transition from 

acquisitions to development of North American UOG plays. In 2013, despite a drop in overall M&A 

activity, international buyers continued to purchase U.S. properties, showing interest especially in Gulf of 

Mexico assets (Deloitte, 2013). 

4 Financial Performance and Condition of the OGE Industry Sector 

and UOG Activity

As part of this profile of the OGE sector, EPA reviewed the financial performance and condition of the 

sector over the past few years; the Agency also reviewed information on the financial outlook for the 

sector. In performing this review, EPA looked at both the general OGE sector and a component that is 

more specifically focused on UOG activities. These reviews show that both the overall OGE sector and 
February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 29

the component more specifically involved in UOG activity have experienced substantial growth and 

generally strong financial performance over the past few years, and that their financial outlook is strong 

going forward. As described in earlier sections, domestic OGE activity and its contribution to the U.S. 

economy accelerated significantly in the latter part of the last 10 years, with much of this growth 

occurring in UOG activity. To an important degree, the financial strength of the OGE sector and its 

generally positive outlook result from the opportunities in UOG exploration, development, and 

production. 

Overall economic conditions affect demand for OGE products and consequently, financial performance of 

OGE firms. Financial performance of OGE firms is also affected by prices for OGE products; therefore, 

the volatility of oil and natural gas prices tends to create a higher level of risk for OGE firms compared to 

firms in many other industries. Low oil or natural gas prices can decrease revenue, operating results and 

profitability, which in turn can reduce cash flow and ability to obtain financial capital. Declining product 

prices can also reduce the quantity and value of a firm’s oil and gas reserves, thus requiring asset writedowns, which can weaken a firm’s balance sheet and increase the cost of financial capital. 

The business model of an oil and gas producer requires that it produce from – i.e., deplete – its principal 

business asset, its oil and gas reserves. Accordingly, to remain a viable enterprise, the firm must 

continually replenish these reserves either by exploring for and developing new resources or by acquiring 

production resources from other firms. Weakness of financial performance and condition, whether due to 

falling cash flow, a deteriorating balance sheet, or other factors, can increase the difficulty and cost of 

obtaining capital for developing or acquiring new reserves. 

The following metrics were selected for assessing the financial performance of UOG firms and the overall 

OGE industry:

 Revenue

 Operating margin

 Net profit margin

 Return on total capital

 Total capital spending.

Data from the Value Line Investment Analyzer® (Value Line) and firms’ 10k SEC filings and annual 

reports was used to compile data and calculate these selected performance metrics over the past 10 years 

(2003-2012) for selected public reporting firms in the OGE industry.

These metrics were developed for two broad sets of firms: 

1. UOG Firms. These are firms reported by Value Line as operating in the Natural Gas Diversified

and Petroleum Production OGE industry sub-sectors and that were confirmed to have U.S. 

exploration and production operations in U.S. shale gas, tight gas, and/or tight oil plays. EPA

based this determination on research of Value Line profiles, company websites and SEC filings, 

Oil and Gas Journal articles, Reuters, newspaper articles and http://oilshalegas.com/.

13

2. Other OGE Firms. Firms reported by Value Line as operating in the Petroleum Integrated OGE

industry sub-sector with U.S. exploration and production operations, regardless of whether they 

have any operations or interests in UOG plays, and firms in the Natural Gas Diversified and 

Petroleum Production sub-sectors for which UOG operations could not be confirmed.

14

 

13 If a company was found to have production in an unconventional play, they were added to the UOG firms set. If no 

information could be found indicating that a firm had unconventional production, then it was considered an Other OGE firm. 

The results of this search may not be definitive.

14 Petroleum integrated companies were not included in the UOG Firms set – even though a number of these large firms are 

known to have UOG operations – because their business model differs from that of other OGE firms. These firms, such as 
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 30

The objective in developing the UOG firm dataset was to identify firms for which UOG activity is likely 

to be a substantial part of their business compared to the broader industry. Looking at this subset of firms, 

compared to firms in the broader OGE industry, would thus give better insight into levels of, and trends 

in, financial performance and condition metrics for UOG E&P firms. In fact, the rise in development of 

unconventional plays, in particular shale plays, was spearheaded by smaller companies, from independent 

start-ups to established independent and mid-size companies, like Devon Energy and Chesapeake Energy 

(Crooks, 2013). These smaller companies acquired drilling rights in the “sweet spots” of the shale gas and 

oil plays before the industry’s larger firms made a serious entrance into the market. On the other hand, 

larger companies, such as the international, integrated majors like Royal Dutch Shell and ExxonMobil, 

entered the market later and, in some cases, appear to have paid higher prices and bought less productive 

assets (“US: Failing in Shale,” 2013). In addition, smaller companies are likely leading innovation in 

shale production, giving them another competitive edge over the larger firms (“US: Failing in Shale,”

2013). These relatively smaller firms have a clear difference in overall business structure and operations 

from other conventional E&P firms as well as the larger firms whose entrance into unconventional 

production is markedly different. Therefore, the Other OGE firms dataset is intended to capture firms 

with U.S. exploration and production operations, which in many cases are known to include UOG 

operations, but for which UOG exploration and production is likely to be a less important element of their 

overall business in terms of contribution to production and revenue, and allocation of capital. As 

described below, for some of the metrics – for example, total capital spending – the financial profile over 

time is strikingly different for the two firm sets, particularly during the mid to late 2000s. This 

difference can be attributed – if not largely, at least in part – to the substantial increase in activity that 

occurred in UOG exploration and production in the latter part of the decade, compared to general oil and 

gas exploration and production activity in the country.

To develop the financial-indicator metrics reported below, EPA assembled data for the firms for the 10-

year period of 2003 through 2012 from the sources listed above. In developing data for this analysis, EPA

first sorted firms according to their business activities, as described above: UOG firms and Other OGE 

firms. Second, because EPA wanted this analysis to cover a period of 10 years, the Agency excluded 

firms that did not have 10 years of data for at least one of the metrics. Overall, 47 firms are in the final 

UOG firms set and 19 firms are in the final Other OGE firms set; however, the number of firms used in 

the calculation for a given metric may be less than these totals because 10 years of data were sometimes 

not available for all of the metrics for a given firm. Three of the five metrics – operating margin, net profit 

margin, and return on total capital – are reported as percentage values and were used directly for this 

analysis. The revenue and total capital spending metrics are reported in Value Line and financial reports 

as absolute values and thus display a wide range of values across firms of varying sizes. For these metrics,

EPA developed an index for each firm, using 2003 values as the base year, and used these scalenormalized index values for the analyses presented below. 

The following sections present charts and summary discussions for each financial performance/condition 

metric. EPA included two charts for each metric. The first chart presents the median values of each metric 

for the UOG firms and Other OGE firms. This chart provides insight into whether and how the profile of 

performance and change over time differs between the UOG firms and Other OGE firms. This 

understanding is important for assessing the momentum and financial performance/condition in UOG 

extraction and production compared to the overall OGE industry. The second chart, which is for the UOG 

firms only, presents the median, 10th percentile and 90th percentile values, and the revenue-weighted 

 

Exxon Mobil, tend to be relatively larger firms that have business in all stages of oil and gas extraction process from 

exploration and production to retail operations. In addition, the contribution of UOG activity to these firms’ overall business 

tends not to be as great as that for some of the smaller E&P firms, some of which have focused substantially on UOG 

activity in recent years. 
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 31

average of values. This information provides the basis for examining the profile of change over time and 

year-to-year values across firms within the UOG firm set.

4.1 Revenue Index

The revenue index provides a direct indicator of the overall scale of activity and, on a year-to-year basis, 

the change in activity level for each firm. As described above, because revenue is a dollar-valued metric 

compared to the percentage values for margin and return on assets metrics, EPA converted the revenue 

metric to an index for each firm, by dividing the data series for each firm by the first year revenue value. 

This yields a revenue index over time for each firm with the 2003 value equal to one. As described above, 

to form the index series for each group of firms - UOG firms and Other OGE firms - EPA then weighted 

each firm’s index value by revenue and summed the revenue-weighted values to yield the multi-firm 

index series.

As shown in Figure 4-1, OGE-industry revenue (as represented by the indexes for both UOG firms and 

Other OGE firms) rose significantly between 2000 and 2008 before declining in 2009 at the time of recent 

recession. Beginning in 2010, revenue rebounded for both firm sets, though not enough to reach the index 

level of 2008. The steep increases in revenue before and after the recession coincide with the shale gas 

boom. Reflecting the effect of the shale gas boom, revenue for UOG firms rose more steeply than revenue 

for Other OGE firms, both before and after the recession-induced decline in 2009. In addition, while 

revenue for Other OGE firms declined in 2012, revenue continued to rise for the UOG firms. As shown in

Figure 4-2, within UOG firms, the 90th percentile revenue index grew at a much higher rate, especially 

between 2007 and 2008, compared to Other OGE firms. The 10th percentile value experienced much 

slower growth, with a slight decrease in 2006. 

Figure 4-1: Revenue Index (Median) for UOG Firms and Other OGE Firms (2003=1)

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 32

Figure 4-2: Revenue Index for UOG Firms (2003=1)

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

4.2 Operating Margin

For this analysis, and as reported by Value Line, operating margin is defined as earnings before 

depreciation, depletion, amortization, interest and income tax divided by revenue. This metric indicates a 

firm’s profitability on a ‘pure’ operations basis before accounting for non-cash charges such as 

depreciation, depletion, and amortization, or tax and financial structure factors. 

As shown in Figure 4-3, the operating margin for UOG firms was higher than that of Other OGE firms

for the entire period of analysis, likely due to structural differences in the business models of the typically 

smaller, non-integrated E&P firms comprising the UOG firms set, and the typically larger, vertically 

integrated firms in the Other OGE firms set. Accordingly, what is more significant in this comparison are 

the differences in the profile of change over time in the margin values for the two groups of firms. The 

UOG firms’ operating margin declined slightly over the reporting period, while operating margin for the 

Other OGE firms increased substantially. The higher rate of increase in operating margin for Other OGE

firms may reflect increasing prices for oil and refined products, relative to natural gas during much of the 

decade. Overall, the operating margin performance of the UOG firms set does not appear to have declined 

or changed in an unfavorable way in comparison to the Other OGE firms set. In Figure 4-4, both the 

average and 10th percentile operating margins show an overall increase throughout the period of analysis, 

while the median and 90th percentile show a decline.
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Figure 4-3: Operating Margin (Median) for UOG Firms and Other OGE Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

Figure 4-4: Operating Margin for UOG Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

4.3 Net Profit Margin

Net Profit Margin differs from operating margin by including non-cash charges, and interest and taxes. 

As defined in Value Line, net profit margin excludes nonrecurring gains and losses, and is calculated as 

net profit divided by revenue. This metric thus provides an alternative profit measure that reflects the tax 

circumstances and financial structure of the firm, as well as including an ongoing charge based on 

previous outlays for E&P activity (depletion) and other property, plant, and equipment (depreciation). 

As shown in Figure 4-5, the UOG firms had a higher net profit margin than Other OGE firms throughout 

the analysis period, except in 2009. Again, this difference in net income margin is due to differences in 

the business models of the two firm sets: what is more important in this information are the profiles of 

change in net profit margin over time. Net profit margin for UOG firms increased until 2008 before 

declining steeply in 2009. Net profit margin for Other OGE firms followed a similar path but the net 

profit decline began earlier for these firms, in 2008, and was, overall, less severe. This difference likely 
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 34

results from UOG firms’ business areas being more affected by price swings, while the largely integrated 

Other OGE firms have a business presence in all three major segments of OGE – production, refining, 

and distribution and sales – allowing for greater stability.

Figure 4-6 provides the median, 10th percentile and 90th percentile, and revenue-weighted average for net 

profit margin of UOG firms. Over the period of analysis, median and average net profit margin decreased

by about 5 percent, largely due to a decline following the economic downturn in 2009. The net profit 

margin for the 90th percentile declined overall during the analysis period as well but fared better with a 

much less severe decline in 2009. On the other hand, the net profit margin for the 10th percentile exhibited 

the greatest amount of volatility, experiencing declining and negative net profit margins for most of the 

latter half of the decade, indicating a lack of profitability for those firms.

Figure 4-5: Net Profit Margin (Median) for UOG Firms and Other OGE Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

Figure 4-6: Net Profit Margin for UOG Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 35

4.4 Return on Total Capital

For this analysis, return on total capital is defined as the ratio of operating income (i.e., income on a pretax and pre-interest basis) to capital invested, and indicates the fundamental financial performance of a 

firm in generating income from its business assets. Like the operating margin metric (Section 0), return 

on total capital provides a relatively ‘pure’ look at business performance without considering the effects 

of financial structure or tax conditions. If individual firms are unable to maintain a return on total capital 

that equals/exceeds the cost of capital needed by lenders and equity investors for providing financial 

capital to the firms, then they will be constrained in their ability to invest in new assets, which for the 

OGE industry is new oil and gas producing assets, and to maintain or grow their business. Such 

considerations are particularly important because of the required depletion of the primary business 

asset (i.e., oil and gas reserves) in the ordinary course of business. 

UOG firms and Other OGE firms had similar trends in returns on total capital throughout the period 

(Figure 4-7). However, the return on total capital for Other OGE firms was higher than that for the UOG 

firms throughout the period and year-to-year fluctuations were more pronounced for UOG firms. Both 

UOG firms and Other OGE firms experienced modest declines in return on total capital over the analysis 

period. Overall, there is no evidence that the UOG firms are operating in some way that is impaired or 

disadvantaged from a business performance standpoint relative to the Other OGE firms and, accordingly, 

the overall OGE industry. 

As shown in Figure 4-8, UOG firms experienced a modest decline in return on total capital between 2003

and 2012. While all firms experienced fluctuations in return on total capital, once again, firms in the 10th

percentile were more adversely affected by the recent recession, experiencing a much larger decline. 

Figure 4-7: Return on Total Capital (Median) for UOG Firms and Other OGE Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 36

Figure 4-8: Return on Total Capital for UOG Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

4.5 Long-Term Debt to Total Assets

Long-term debt to total assets describes the overall financial structure of a firm in terms of relative 

reliance on debt and equity in financing the firm’s total assets. A high ratio of long-term debt to total 

assets can expose a firm to a greater degree of operating financial risk as fluctuations in financial 

performance (e.g., operating income) will be magnified in their impact on net income due to the income 

leverage effect associated with higher debt levels. A high ratio can also indicate that a firm is more likely 

to experience difficulty in meeting its fixed payment obligations in the face of fluctuating operating 

financial performance. All else equal, firms with a higher ratio may experience more difficulty or incur 

higher costs in acquiring new, or renewing existing, financial capital, whether as debt or equity. As 

reported by Value Line, long-term debt to total assets is all repayment liabilities extending for at least one 

year divided by the balance sheet value for all current and long-term assets.

As shown in Figure 4-10, overall, while the median value of the debt to total assets ratio for UOG firms

increased by 5.2 percentage points, the ratio for Other OGE firms declined by 9.1 percentage points. The 

debt to total assets ratio is consistently higher for UOG firms than Other OGE firms, but is not unusually 

high for firms in the natural resource industries. In general, there is no evidence of systematic 

deterioration in the debt to total assets measure for UOG firms or Other OGE firms. Figure 4-10 shows an 

overall increase in the long term debt to total assets measure for UOG firms from 2003 to 2012. While the 

average and median values remained within about 10 percent, the 90th percentile values saw major 

fluctuations, with a steep rise in 2008 and again in 2012.
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 37

Figure 4-9: Long-Term Debt to Total Assets (Median) for UOG Firms and Other OGE Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

Figure 4-10: Long-Term Debt to Total Assets for UOG Firms

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

4.6 Total Capital Spending Index

The total capital spending index represents annual outlays for plant and equipment, including, for the oil 

and gas E&P segments, outlays for exploration, development, and production. This metric is important 

for the UOG firms set as it may indicate the extent to which firms are investing in UOG exploration and 

production. EPA developed the total capital spending index by multiplying capital spending per share by 

average shares outstanding for each reporting year, indexing the year-by-year dollar-valued series to the 

first year’s spending value, weighting the resulting index values by revenue, and aggregating over the 

firms in each analysis set. An increasing level of outlays indicates a favorable assessment by individual 

firms/industry of the opportunities to which capital resources are being assigned. Increasing outlays also 

indicate that the relevant firms have access to the financial capital for undertaking these outlays. 
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 38

Figure 4-11 reports the median index values of the total capital spending index for UOG firms and Other 

OGE firms. Both sets of firms had almost identical patterns of change through 2005. However, from 2006 

to 2008, the rate of growth in the total capital spending index for UOG firms is much higher than that for

Other OGE firms. Outlays for both sets of firms declined in 2009, though more so for UOG firms than for 

Other OGE firms. The divergence and substantial increase in UOG firms’ outlays beginning in 2006 

coincides with the period in which shale gas development began strong growth. At least in part, the 

divergence in the outlay patterns for the two sets of firms reflects this substantial increase in exploration 

and production activity for shale gas. After the decline in 2009, both sets of firms rebounded in 2010, but 

by 2011, UOG firms were again showing a much higher rate of growth. This strong growth in total capital 

outlays for the UOG firms set confirms the assessment by these firms of the favorable outlook for 

unconventional oil and gas exploration and production, and the likelihood that unconventional oil and 

gas-related activity will continue vigorously for the foreseeable future. 

Figure 4-12 provides the median, 10th percentile and 90th percentile, and average for total capital spending 

index for UOG firms. From 2003 to 2012, total capital outlays increased by a substantial multiple for the 

median and average index values, and even more so for the 90th percentile index value. All of these index 

lines show a similar pattern of increase, which suggests that UOG firms are investing heavily, almost 

assuredly, in exploration and production assets. The 10th percentile index value showed a much smaller 

increase in the index value for the period, ending in 2012 with a value of 1.50.

Figure 4-11: Total Capital Spending Index (Median) for UOG Firms and Other OGE firms 

(2003=1)

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 39

Figure 4-12: Total Capital Spending Index for UOG Firms (2003=1)

Sources: Value Line 2003-2012; Company 10k SEC Filings and Annual Reports

4.7 Summary

The preceding reviews of financial performance and condition metrics for UOG firms and Other OGE 

firms indicate no deterioration in financial performance and condition for UOG firms over the previous 

decade and suggest that UOG firms are well-positioned for continued investment in UOG exploration and 

development. The strong growth in revenue and total capital outlays by the UOG firms during the latter 

part of the last decade – which coincides with the growth in UOG exploration and production activity –

underscores the economic opportunity provided by the emerging UOG resource and the industry’s 

commitment to investing in and producing UOG for the foreseeable future.

5 Outlook for UOG Exploration and Production Activity

OGE is a relatively volatile industry that is substantially affected by overall economic growth and OGE 

product prices. Over the past decade, metrics of economic/financial performance for the OGE industry, 

and in particular, for firms specifically associated with UOG exploration and production, have fluctuated 

with general economic conditions. However, overall the industry shows considerable financial vitality and 

appears in sufficient financial condition to support continued UOG exploration and production. 

The achievements in UOG exploration and production during the past decade have led to the emergence 

of shale and tight oil and gas as important contributors to the nation’s energy supply portfolio. Beginning 

from only a few percentage points of total supply share in 2000, by 2009, tight gas was already the 

leading source of natural gas production in the United States, representing 14 percent of total domestic 

gas production. In that same year, shale gas became the third largest source for natural gas production and 
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 40

by 2011 outpaced tight gas to become the number one source of U.S. production (U.S. DOE, 2013b). 

Likewise, between 2000 and 2012, tight oil production, in terms of barrels per day, grew by more than 

seven times (U.S. DOE, 2014b). According to EIA, in 2012, tight oil and shale gas accounted for 29 

percent of total U.S. crude oil production and 40 percent of total U.S. natural gas production, respectively 

(U.S. DOE, 2013g).While many factors will affect further UOG development, and forecasts inevitably 

involve considerable uncertainty, these trends are expected to continue, with EIA forecasting that by 

2040, shale gas will account for 50 percent of U.S. natural gas production, with tight gas as the second 

leading source at 22 percent. Production of tight oil is also expected to grow for the foreseeable future, 

though potentially tapering off as higher productivity fields are depleted and replaced by lower 

productivity resources. According to EIA, by 2040, tight oil will account for 33 percent of total U.S. oil 

production (U.S. DOE, 2013b; U.S. DOE, 2013a).

Other factors considered in this profile support the expectation of continued growth of UOG exploration 

and production. In particular, the overall increase in OGE capacity and production coupled with the 

substantial increase in revenue and capital outlays over the last few years by firms identified as being 

substantially involved in UOG exploration and production are important factors indicating continued 

development of UOG resources. These increases in revenue and capital outlays coincide with the growth 

in shale and tight oil and gas exploration and production activity. They indicate the industry’s favorable 

assessment of the economic potential of the UOG resources, and support an expectation of continued 

growth in development and production. Other financial measures considered in this profile also 

underscore the economic opportunity provided by the emerging UOG resource, and the industry’s 

commitment to investing in and producing shale and tight oil and gas for the foreseeable future.

Growth in UOG activities will likely be regionalized as OGE firms continue to develop current UOG

basins (see Table 5-1 for shale formations and Table 5-2 for other tight oil/gas formations). In the near 

future, UOG activities will likely continue to emphasize tight oil, as companies focus on liquids-rich 

plays because of the continued gap between natural gas and oil prices (CHK, 2013; APC, 2013). As 

advances in UOG E&P technology continue, depending on growth in demand, OGE firms may begin to 

develop other parts of basins as UOG extraction outside of the current plays becomes economically 

viable. This may expand the areas in which UOG activities occur, but UOG will still be concentrated in 

those areas with substantial resource potential. For shale gas and tight gas, this will include Texas, the 

Gulf Coast, central South (e.g., Oklahoma and Arkansas), upper Midwest (Michigan, Indiana), the MidAtlantic (New York, Pennsylvania), and parts of Appalachia (West Virginia, Kentucky). For tight oil,

production will likely continue to be predominate in regions like Texas, the Mid-Atlantic, parts of 

Appalachia, the Midwest (Ohio), the Rocky Mountains (e.g., Colorado and Utah), central South (e.g., 

Oklahoma), and possibly California.

Further UOG development will likely strain the capacity of current infrastructure and require construction 

of additional pipelines, gathering lines and processing plants to support the increased production. 

Resolving these infrastructure issues is a key to future production of oil and natural gas from shale and 

tight sands formations, as lack of transportation capacity may constrain production from certain fields.

Therefore, going forward, OGE firms will likely increase their infrastructure investments. According to 

IHS, while in 2012, total upstream capital expenditures for UOG were over $87 billion, with nearly $6 

billion dedicated to gathering systems, these expenditures will exceed $5 trillion between 2012 and 2035 

as UOG extraction and production continues to grow and mature (IHS, 2012).
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 41

Table 5-1: Shale Formation Potential as of January 1, 2012

EIA Basin UOG Formation 

Name

Resource 

Type

Oil EUR 

(MMbls 

per well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(MMbls)

Gas 

TRR 

(Bcf)

New Well 

Potential

Appalachian

Devonian Shale gas 0.000 0.058 0 20,800 358,600

Marcellus Shale gas 0.000 1.317 0 118,900 90,300

Utica

Shale gas 0.000 0.330 0 37,400 113,500

Shale oil 0.063 0.057 1,000 900 15,900

Illinois New Albany Shale gas 0.000 1.721 0 41,700 24,200

Michigan Antrim Shale gas 0.000 0.157 0 15,300 97,500

Black 

Warrior

FloydNeal/Conasauga Shale gas 0.000 1.520 0 4,300 2,800

TX-LA-MS 

Salt

HaynesvilleBossier Shale gas 0.000 3.455 0 70,900 20,500

Western 

Gulf

Eagle Ford

Shale gas 0.177 1.549 6,100 53,400 34,500

Shale oil 0.101 0.212 3,300 6,900 32,500

Pearsall Shale gas 0.000 1.090 0 7,800 7,200

Tuscaloosa Shale oil 0.092 0.019 2,900 600 31,600

Woodbine Shale oil 0.108 0.054 600 300 5,600

Anadarko Cana Woodford

Shale gas 0.014 1.232 100 8,900 7,200

Shale oil 0.038 0.415 100 1,100 2,700

Arkoma

Caney Shale gas 0.000 0.330 0 1,100 3,300

Fayetteville Shale gas 0.000 1.284 0 29,800 23,200

Woodford Shale gas 0.000 1.422 0 6,700 4,700

Black 

Warrior Chattanooga Shale gas 0.000 0.970 0 1,600 1,600

Barnett Shale Gas Shale gas 0.000 0.377 0 20,300 53,900

Permian

Wolfcamp Shale oil 0.068 0.217 3,400 10,900 50,200

Barnett-Woodford Shale gas 0.000 1.513 0 15,800 10,400

Avalon/Bone 

Spring Shale oil 0.080 0.000 2,000 0 25,000

Denver Niobrara Shale oil 0.011 0.073 400 2,700 37,000

Greater 

Green River

Hilliard-BaxterMancos Shale gas 0.000 0.293 0 10,500 35,800

Montana 

Thrust Belt All tight oil plays Shale oil 0.113 0.075 600 400 5,300

Powder 

River All tight oil plays Shale oil 0.035 0.040 2,100 2,400 60,000

San Juan Lewis Shale gas 0.000 2.200 0 9,800 4,500

UintaPiceance Mancos Shale gas 0.000 0.880 0 10,900 12,400

Williston

Gammon Shale gas 0.000 0.440 0 3,400 7,700

Bakken Shale oil 0.142 0.096 9,300 6,300 65,500

Columbia Basin Centered Shale gas 0.000 1.400 0 12,200 8,700

San 

Joaquin/Los 

Angeles

Monterey/Santos Shale oil 0.502 0.502 600 600 1,200

Source: U.S. EPA, 2015
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 42

Table 5-2: Other Tight Formation Potential as of January 1, 2012

EIA Basin UOG Formation 

Name

Resource 

Type

Oil EUR 

(MMbls 

per well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(MMbls)

Gas 

TRR 

(Bcf)

New Well 

Potential

Appalachian

Clinton-Medina Tight gas 0.003 0.060 500 11,700 195,000

Tuscarora Tight gas 0.000 2.172 0 4,400 2,000

Michigan Berea Sand Tight gas 0.000 0.143 0 8,100 56,600

TX-LA-MS 

Salt Cotton Valley Tight gas 0.009 1.472 900 152,700 103,700

Western 

Gulf

Olmos Tight gas 0.005 1.093 100 23,600 21,600

Vicksburg Tight gas 0.000 1.473 0 3,900 2,600

Wilcox Lobo Tight gas 0.000 1.404 0 10,100 7,200

Austin Chalk Tight oil 0.086 0.048 7,600 4,300 88,800

Buda Tight oil 0.108 0.070 3,700 2,400 34,300

Anadarko

Cleveland Tight gas 0.036 0.394 100 1,100 2,800

Granite Wash Tight gas 0.046 0.948 600 12,300 13,000

Red Fork Tight gas 0.000 0.593 0 1,000 1,700

Permian

Abo Tight gas 0.101 0.182 1,000 1,800 9,900

Canyon Tight gas 0.002 0.209 100 10,900 52,200

Spraberry Tight oil 0.108 0.113 8,100 8,500 75,200

Denver Muddy Tight gas 0.000 0.182 0 11,500 63,200

Greater 

Green River All Tight Oil Plays Tight oil 0.135 0.015 900 100 6,700

North 

Central 

Montana

BowdoinGreenhorn Tight gas 0.000 0.151 0 300 2,000

Paradox Fractured Interbed Tight oil 0.543 0.434 1,000 800 1,800

San Juan

Dakota Tight gas 0.000 0.416 0 6,100 14,700

Mesaverde Tight gas 0.000 0.464 0 5,800 12,500

Pictured Cliffs Tight gas 0.000 0.397 0 200 500

SW 

Wyoming

Fort Union-Fox 

Hills Tight gas 0.000 1.047 0 15,800 15,100

Frontier Tight gas 0.009 0.273 200 6,200 22,700

Lance Tight gas 0.016 1.012 300 18,700 18,500

Lewis Tight gas 0.000 0.248 0 7,700 31,000

All Tight Oil Plays Tight oil 0.165 0.015 1,100 100 6,700

UintaPiceance

Iles-Mesaverde Tight gas 0.000 0.502 0 17,100 34,100

WasatchMesaverde Tight gas 0.023 0.463 400 8,200 17,700

Williams Fork Tight gas 0.000 0.456 0 7,600 16,700

All Tight Oil Plays Tight oil 0.056 0.111 100 200 1,800

Williston Judith River-Eagle Tight gas 0.000 0.158 0 1,000 6,300

Wind River Mesaverde/Frontier 

Shallow Tight gas 0.000 0.768 0 4,400 5,700

Source: U.S. EPA, 2015
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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 43

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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 49

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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 50

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February 18, 2015 Abt Associates | Profile of the Oil and Gas Extraction Sector | pg 51

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