United States Office of Water EPA-821-R-16-003

Environmental Protection Washington, DC 20460 June 2016

Agency

Profile of the 

Unconventional Oil and Gas 

Industry
Profile of the Unconventional Oil and Gas 

Industry

EPA-821-R-16-003

June 2016

U.S. Environmental Protection Agency

Office of Water (4303T)

Engineering and Analysis Division

1200 Pennsylvania Avenue, NW

Washington, DC 20460
Profile of the Unconventional Oil and Gas Industry Acknowledgements and Disclaimer

This report was prepared by the U.S. Environmental Protection Agency. Neither the United States 

Government nor any of its employees, contractors, subcontractors, or their employees make any warrant, 

expressed or implied, or assume any legal liability or responsibility for any third party’s use of or the 

results of such use of any information, apparatus, product, or process discussed in this report, or 

represents that its use by such party would not infringe on privately owned rights.
Profile of the Unconventional Oil and Gas Industry Table of Contents

June 2016 i

Table of Contents

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

2 Background....................................................................................................................................... 1

3 Overview of Crude Oil and Natural Gas and the U.S. Economy................................................. 5

3.1 Crude Oil ............................................................................................................................................ 5

3.1.1 Recent Trends in Crude Oil Production, Prices, Imports, and Consumption........................... 5

3.1.2 Short Term Projections .......................................................................................................... 10

3.1.3 Long Term Projections........................................................................................................... 11

3.2 Natural Gas....................................................................................................................................... 12

3.2.1 Recent Trends in Natural Gas Production, Prices, Imports, and Consumption ..................... 12

3.2.2 Short Term Projections .......................................................................................................... 17

3.2.3 Long Term Projections........................................................................................................... 18

3.3 Economic Output.............................................................................................................................. 18

3.4 Financial Outlook ............................................................................................................................. 19

4 OGE Industry Structure and Economic Performance................................................................ 21

4.1 Number of Firms and Establishments .............................................................................................. 21

4.2 Number of Small Firms.................................................................................................................... 22

4.3 Employment ..................................................................................................................................... 23

4.4 Revenue and Payroll in the OGE Industry Segments....................................................................... 24

4.5 Capacity Utilization.......................................................................................................................... 25

4.6 Market Structure, Pricing, and Concentration in the OGE Industry Sector ..................................... 26

4.6.1 Market Structure and Pricing in the OGE Industry Sector..................................................... 26

4.6.2 Concentration in the OGE Industry........................................................................................ 28

5 Financial Performance and Condition ......................................................................................... 29

5.1 Revenue ............................................................................................................................................ 31

5.2 Operating Margin ............................................................................................................................. 32

5.3 Net Profit Margin ............................................................................................................................. 34

5.4 Return on Total Capital .................................................................................................................... 35

5.5 Long-Term Debt to Total Assets...................................................................................................... 36

5.6 Total Capital Spending..................................................................................................................... 38

5.7 Summary........................................................................................................................................... 40

6 Outlook for UOG Exploration and Production Activity............................................................. 43

7 References ....................................................................................................................................... 46
Profile of the Unconventional Oil and Gas Industry Table of Contents

June 2016 ii

List of Tables

Table 2-1: OGE Industry Segments and Number of Establishments............................................................4

Table 3-1: Industrial Production Index for the OGE Sector, by Year and Segmenta

..................................19

Table 4-1: Number of Firms in the OGE Industry Sector, by Year and Segment ......................................22

Table 4-2: Number of Establishments in the OGE Industry Sector, by Year and Segment .......................22

Table 4-3: Number of Firms in the OGE Industry Sector by Year, Segment, and Firm Size.....................23

Table 4-4: Number of Employees in the OGE Industry Sector by Year and Segment...............................24

Table 4-5: Key Economic Performance Statistics for OGE Industry Sector, by Year and Segment, 1997-

2012.....................................................................................................................................................25

Table 6-1: UOG Formation Potential as of January 1, 2013.......................................................................44
Profile of the Unconventional Oil and Gas Industry Table of Contents

June 2016 iii

List of Figures

Figure 3-1: Crude Oil Production in the United States by Petroleum Administration for Defense Districts 

(Quadrillion Btu)...................................................................................................................................6

Figure 3-2: Tight and Shale Oil Production in the United States by Formation (MMbpd)..........................7

Figure 3-3: Crude Oil Prices (Dollars per barrel) .........................................................................................8

Figure 3-4: Net Imports of Crude Oil in the United States (Quadrillion Btu)a

.............................................9

Figure 3-5: Total Domestic Consumption of Crude Oil (Quadrillion Btu)a ...............................................10

Figure 3-6: Natural Gas Marketed Production in the United States by Petroleum Administration for 

Defense Districts (Quadrillion Btu)a

...................................................................................................13

Figure 3-7: Dry Shale Gas Production in the United States by Formation (Bcfd)......................................14

Figure 3-8: Total Domestic Consumption of Natural Gas (Quadrillion Btu)a

............................................15

Figure 3-9: Net Imports of Natural Gas in the United States (Quadrillion Btu)a

........................................16

Figure 3-10: Henry Hub Natural Gas Price (Dollars per million Btu)........................................................17

Figure 4-1: Capacity Utilization for OGE Industry (NAICS 21111)..........................................................26

Figure 5-1: Revenue, Year-to-Year Percent Change (Median) for UOG, Integrated, and Other OGE Firms

............................................................................................................................................................31

Figure 5-2: Revenue, UOG Firms, Year-to-Year % Change ......................................................................32

Figure 5-3: Operating Margin (Median) for UOG, Integrated, and Other OGE Firms ..............................33

Figure 5-4: Operating Margin for UOG Firms ...........................................................................................33

Figure 5-5: Net Profit Margin (Median) for UOG, Integrated, and Other OGE Firms ..............................34

Figure 5-6: Net Profit Margin for UOG Firms ...........................................................................................35

Figure 5-7: Return on Total Capital (Median) for UOG, Integrated and Other OGE Firms ......................36

Figure 5-8: Return on Total Capital for UOG Firms ..................................................................................36

Figure 5-9: Long-Term Debt to Total Assets (Median) for UOG, Integrated, and Other OGE Firms.......37

Figure 5-10: Long-Term Debt to Total Assets for UOG Firms..................................................................38

Figure 5-11: Total Capital Spending, Year-to-Year Percent Change (Median) for UOG, Integrated, and 

Other OGE firms.................................................................................................................................39

Figure 5-12: Total Capital Spending, Year-to-Year Percent Change for UOG Firms................................40
Profile of the Unconventional Oil and Gas Industry List of Abbreviations

June 2016 iv

List of Abbreviations

AEO Annual Energy Outlook

Bcfd Billion cubic feet per day

BLS U.S. Bureau of Labor Statistics

CME Chicago Mercantile Exchange

DOE U.S. Department of Energy

DUC Drilled but uncompleted

E&P Exploration and production

EIA Energy Information Administration

EPA U.S. Environmental Protection Agency

EUR Estimated ultimate recovery

FERC Federal Energy Regulatory Commission

ICE Intercontinental Exchange

IEA International Energy Agency

IPI Industrial Production Index

M&A Merger and acquisition

MMbpd Million barrels per day

mmBtu Million British Thermal Units

NAICS North American Industry Classification System

NGL Natural gas liquid

NYMEX New York Mercantile Exchange

OGE Oil and gas extraction

OPEC Organization of Petroleum Exporting Countries

PADD Petroleum Administration for Defense District

SBA Small Business Administration

SUSB Statistics of U.S. Businesses

Tcf Trillion cubic feet

TRR Technically recoverable resources

UOG Unconventional oil and gas

WTI West Texas Intermediate

XOP Standard and Poor’s Exploration and Production Index
Profile of the Unconventional Oil and Gas Industry 1: Introduction

June 2016 1

1 Introduction

This report profiles the Oil and Gas Extraction (OGE) industry, with focus on the unconventional oil and 

gas (UOG) subsector. The profile contains background on UOG exploration and production activity; an 

overview of crude oil and natural gas and the U.S. economy, including recent trends and projections for 

crude oil and natural gas production, prices, imports, and consumption; a review of the industry and 

market structure for crude oil and natural gas; a discussion of the financial performance and condition of 

OGE firms in general, and UOG firms specifically; and a summary outlook for UOG exploration and 

production activity. 

Key findings of the profile are:

 Natural gas production has increased substantially since 2005 due to shale gas; crude oil 

production has increased substantially since 2008 due to tight and shale oil.

 Increased production has led to reduced crude oil and natural gas prices, increased exports, and 

lower imports.

 The greater than 50 percent fall in crude oil prices since June 2014, along with declining natural 

gas prices, has had significant adverse effects on OGE firms in general, and UOG firms in 

particular.

 Prices for crude oil and natural gas are expected to increase slowly from the current (May 2016)

price of approximately $44/bbl for WTI, $44/bbl for Brent, and $2/mmBtu for Henry Hub. May 

2016 EIA projections have WTI and Brent prices at approximately $44/bbl in the fourth quarter 

of 2016 and Henry Hub prices at $2.65/mmBtu.

 After five years of increasing crude oil prices (2009-2014) and a two-year increase in Henry Hub 

natural gas prices (2012-2014), along with increasing crude oil and natural gas production, cash 

flows at OGE firms, generally, and UOG firms, specifically, are falling in line with the declining 

prices since 2014. As a result, lenders are pressuring firms to raise cash and reduce debt. This is 

expected to lead to asset sales, perhaps at depressed prices, and mergers and acquisitions (M&A)

activity is likely to increase going into 2016.

 While integrated firms and larger, more strongly financed firms, generally, are in a better position 

to weather this period of low prices, they also have not been immune to the adverse effects of the 

fall in crude oil prices.

 The nature of UOG production and the financial structure of UOG firms, along with the slow 

price recovery that is predicted, make it possible that the financial performance and condition of 

UOG firms will not improve substantially, and may deteriorate further, in the short term.

 The long term outlook is more favorable for the general OGE industry. Though price volatility is 

expected to remain high going into 2016, crude oil and natural gas prices are forecast to increase 

through 2040. Shale gas production is expected to increase through 2040; tight and shale oil 

production is expected to increase through 2020. The United States is expected to be energy 

independent by 2029.

For purposes of this rulemaking, these key findings are not expected to change the economic achievability 

of the industry to meet a zero discharge standard. EPA has no data of a facility that does not use the zero 

discharge technology. Therefore, EPA determined that facilities can afford a technology to meet the zero 

discharge standard. Since facilities are already meeting a zero discharge standard, EPA’s regulation will 

impose no additional cost. EPA also has no data to suggest that the zero discharge technology will be a 
Profile of the Unconventional Oil and Gas Industry 1: Introduction

June 2016 2

barrier to entry because all facilities already meet the zero discharge standard and new facilities would 

likewise be able to meet this standard at no cost disadvantage to existing facilities.
Profile of the Unconventional Oil and Gas Industry 2: Background

June 2016 3

2 Background

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

prices through the middle of the last decade have made the extraction of crude oil and natural gas from 

shale and tight-sand formations – unconventional oil and gas (UOG) – technically and economically 

feasible. Applications of these advanced drilling and production techniques, coupled with large crude oil 

and natural 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 2015 Annual Energy Outlook (AEO2015) published by the Energy Information 

Administration of the Department of Energy, natural gas production is expected to increase by 45 percent

by 2040, compared to 2013 production levels.

1 EIA expects lower-48 shale gas production to increase 73 

percent by 2040. Tight gas production, offshore production, and onshore Alaskan production are also 

projected to increase (U.S. DOE, 2015a).

2

According to EIA, compared to 2013 production, total U.S. production of crude oil will grow by 42 

percent in million barrels per day by 2020, mostly due to growth in onshore production of crude oil and 

natural gas liquids (NGLs) from tight and shale oil formations.

3 Between 2020 and 2040, EIA projects 

that total U.S. production of crude oil will decline by 11 percent, as crude oil production from tight and 

shale oil formations levels off due to depletion of the more productive tight and shale oil resources, and 

shift of tight and shale oil production to less-productive areas. Because many wells drilled in tight and 

shale oil formations have limited production history, the impact of recent technology advances on future 

resource recovery is highly uncertain. EIA expects that in 2040, lower-48 onshore tight and shale 

oil formations will account for 45 percent of total U.S. crude oil production (EPA calculated this number 

from Appendix A) (U.S. DOE, 2015a).

According to EIA, in 2013, tight and shale oil and shale gas accounted for 42 percent of total U.S. crude 

oil production and 46 percent of total U.S. natural gas production, respectively (U.S. DOE, 2015a).

The analysis and information in this report was completed in 2015, with much of it based on EIA’s 2015 

Annual Energy Outlook report. 

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 2-1 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 (NAICS 21111). The UOG industry subsector lies mostly within Crude 

Petroleum and Natural Gas Extraction (NAICS 211111). However, the Natural Gas Liquid Extraction

 1 All AEO2015 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 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.
Profile of the Unconventional Oil and Gas Industry 2: Background

June 2016 4

(NAICS 211112) segment does capture natural gas liquids that may be recovered from shale or other 

unconventional formations. Therefore, they are described below as well.

Table 2-1: OGE Industry Segments and Number of Establishments

NAICS NAICS Description Facilities Included

Number of 

Establishments

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.

6,470

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. 

320

Total Oil and Gas Extraction (NAICS 21111) 6,790

Sources: U.S. DOC 2012
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 5

3 Overview of Crude Oil and Natural 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, crude oil and natural gas in the U.S. economy, crude oil and natural 

gas production levels, and prices. Overall, domestic crude oil and natural gas production has increased 

substantially over the last decade, with production of unconventional oil and gas since 2008 accounting 

for the bulk of this increase. Tight and shale oil and shale gas now represent a large fraction of overall 

production of crude oil and natural gas. This increased production has led to reduced crude oil and natural 

gas prices, lower imports, and higher exports. U.S. consumption of crude oil and natural gas has 

increasingly been met with domestic production as opposed to imports. As a result, the United States is 

expected to no longer be dependent on foreign energy by 2029, as net energy imports reach zero (U.S. 

DOE, 2015a). Crude oil and natural gas prices have fallen in recent years, and recovery is expected to be 

slow. This will increasingly affect OGE firms, as improved drilling efficiencies and hedging contracts 

will eventually become less able to protect firms against falling cash flows.

3.1 Crude Oil

Since 2008, U.S. production of crude oil has increased, coinciding with increased production from tight 

and shale oil formations. Due to this increased production, U.S. West Texas Intermediate (WTI) prices 

began to fall in July 2014. Domestic production began to replace imports, which have fallen as well. 

International production has also increased, which, in combination with falling U.S. demand for foreign 

crude oil, has led to excess supply in international markets and falling international (Brent) prices. In 

November 2014, OPEC announced it was not changing its production goals, despite increased U.S. 

supply, and WTI prices immediately fell 10 percent. Increased production of unconventional oil in the 

United States and Canada is changing the import/export dynamics in the region and further reducing 

Western reliance on OPEC crude oil (Deloitte, 2015b).

3.1.1 Recent Trends in Crude Oil Production, Prices, Imports, and Consumption

Figure 3-1 shows U.S. crude oil production by Petroleum Administration for Defense District (PADD)

for 2000 through the second quarter of 2015. Overall, domestic crude oil production declined between 

2000 and 2008. Since 2008, domestic crude oil production has increased except for a small period of 

decline in the first quarter of 2015. Between 2000 and second quarter 2015, domestic crude oil production 

increased 61 percent.

PADD 2: Midwest saw the largest increase, where production has more than tripled since 2000. PADD 1: 

East Cost and PADD 4: Rocky Mountain also saw large increases but remain small fractions of total 

domestic production (1 percent and 8 percent of total, respectively). PADD 5: West Coast production has 

declined since 2000 but remains 11 percent of total domestic production. The biggest fraction of 

production comes from PADD 3: Gulf Coast, which accounted for 60 percent of domestic crude oil 

production by second quarter 2015.

The increase since 2008 coincides with increased production of unconventional oil from tight and shale 

oil formations. Figure 3-2 shows U.S. tight and shale oil production from selected formations. As can be 

seen in the figure, tight and shale oil production has significantly increased since 2008. Tight and shale oil 

production in August 2015 was almost ten times higher than in January 2008, due mostly to increased 

production in the Eagle Ford and Bakken formations. These formations are located in PADD 3: Gulf 

Coast and PADD 2: Midwest, respectively, which together accounted for 80 percent of total domestic 

crude oil in August 2015.
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 6

This increased domestic production of crude oil has led to a fall in both U.S. and international crude 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 New York 

Mercantile Exchange (NYMEX). The West Texas Intermediate (WTI) crude oil price is a benchmark for 

prices in the U.S. oil market; WTI oil trades on the Chicago Mercantile Exchange (CME) and NYMEX. 

WTI oil is a very high quality crude oil, lighter and sweeter than Brent, and is refined mostly in the 

Midwest and Gulf Coast regions of the United States. Cushing, Oklahoma is the largest U.S. oil-storage 

hub for WTI oil.

Figure 3-1: Crude Oil Production in the United States by Petroleum Administration for Defense

Districts (Quadrillion Btu)

Sources: U.S. DOE 2015m

0

5

10

15

20

25

200020012002200320042005200620072008200920102011201220132014

PADD 5: West Coast

PADD 4: Rocky Mountain

PADD 3: Gulf Coast

PADD 2: Midwest

PADD 1: East Coast
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 7

Figure 3-2: Tight and Shale Oil Production in the United States by Formation (MMbpd)

Sources: U.S. DOE 2015x

Both WTI and Brent oil trade in two distinct markets: the spot market and the futures market. Essentially, 

the spot market is the daily market, where crude oil is bought and sold for immediate delivery. For 

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

futures market consists of buying and selling crude oil for future delivery under contracts; these 

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

physical delivery. Futures transactions are often used to shield market participants from volatility in spot 

prices.

Figure 3-3 shows WTI and Brent prices from 2000 to second quarter 2015. WTI and Brent prices peaked 

in June 2014 but have since fallen. WTI prices peaked at $105.79/bbl before falling to $42.87/bbl in 

August 2015. WTI prices increased slightly in September 2015, to $45.48/bbl, due to falling U.S. crude 

oil output and five weeks of inventory draws at the Cushing, OK hub (U.S. DOE, 2015k). October 2015 

saw another small increase in WTI prices, to $46.22/bbl, as inventories remained about the same in 

Cushing (U.S. DOE, 2015j). Brent prices have been slightly higher than WTI prices, though they have 

followed the same trend, peaking at $111.80/bbl in June 2014. Brent prices fell to $46.58/bbl in August 

2015 before increasing slightly to $47.62/bbl in September 2015 and $48.43/bbl in October 2015. For 

several years beginning in 2011, WTI crude oil traded at a discount to Brent despite the two prices 

historically trading very close to each other. The chief reason behind this price spread for otherwise nearperfect substitute commodities was the rapid inflow of crude oil into Cushing from areas like North 

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

Cushing to the Gulf Coast for refining. The resulting excess of supply at this market transaction node 

depressed the WTI price relative to Brent. The Brent-WTI spread decreased in 2014 as new transportation 

infrastructure was built, lowering the cost of moving crude oil from Cushing to the Gulf Coast to be 

processed (U.S. DOE, 2015y).

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5 Utica (OH, PA & WV)

Delaware (TX & NM Permian)

Yeso & Glorieta (TX & NM Permian)

Eagle Ford (TX)

Bakken (MT & ND)

Spraberry (TX & NM Permian)

Bonespring (TX & NM Permian)

Wolfcamp (TX & NM Permian)

Niobrara-Codell (CO, WY)

Haynesville

Marcellus (PA,WV,OH &NY)

Woodford (OK)

Granite Wash (OK & TX)

Austin Chalk (LA & TX)

Monterey (CA)
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 8

Figure 3-3: Crude Oil Prices (Dollars per barrel)

Sources: U.S. DOE 2015d, 2015e

Increased domestic production has also led to decreased imports of crude oil, as domestic tight and shale 

oil displaced imported foreign light crude. Figure 3-4 shows U.S. net imports, imports, and exports of 

crude oil from 2000 through second quarter 2015. The low level of crude oil exports reflects the U.S. 

crude oil export ban, which made it illegal to export domestically produced crude oil without a license.

4

Exports have increased almost eight times since 2012 due almost entirely to exports to Canada, which 

were made legal in 1985. Because of the crude oil export ban, net imports have historically reflected only 

imports. Between 2008 and second quarter 2015 crude oil imports declined 26 percent, corresponding to 

the increase in domestic tight and shale oil production.

Consumption of crude oil is not directly reported because only a small amount of crude oil is directly 

consumed in the United States; most crude oil is refined into petroleum products. However, crude oil 

consumption can be estimated as domestic crude oil production plus crude oil imports less crude oil 

exports less changes in crude oil stocks. Consumption in this context represents the total amount of crude 

oil either directly consumed or used as an input in refining. Figure 3-5 shows domestic consumption of 

crude oil, broken into two parts. The lower part of the chart shows consumption from domestically 

produced crude oil (i.e., domestic production less exports, plus inventory decreases); the upper part of the 

chart shows crude oil imports. The sum of these two components represents total domestic consumption.

From 2000 to second quarter 2015, crude oil consumption increased a modest 4.5 percent. More 

importantly, though, the role of imports in meeting U.S. demand for crude oil declined substantially. In 

2008, total domestic consumption of crude oil was 31.1 quadrillion Btu, with imports accounting for 67 

 4 Congress acted to relax the ban in December 2015. See discussion at page 11.

$0

$20

$40

$60

$80

$100

$120 Dollars per barrel

Europe Brent Spot Price FOB

WTI Spot Price FOB
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 9

percent (20.8 quadrillion Btu) of the total. This declined to 45 percent of total consumption in second 

quarter 2015. Again, this reflects the increase in domestic tight and shale oil production since 2008.

Figure 3-4: Net Imports of Crude Oil in the United States (Quadrillion Btu)a

a. Data from EIA are reported in thousands of barrels and were converted to quadrillion Btu.

Sources: U.S. DOE 2015q, 2015r, 2015s

 -

 5

 10

 15

 20

 25

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Quadrillion Btu

Net Imports of Crude Oil Imports of Crude Oil Exports of Crude Oil
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 10

Figure 3-5: Total Domestic Consumption of Crude Oil (Quadrillion Btu)a

a. EPA analysis to combine production, imports, exports, and stock changes on a Btu-energy-consumed basis.

Sources: U.S. DOE 2015m, 2015n, 2015o, 2015q, 2015r, 2015s

3.1.2 Short Term Projections

Total domestic crude oil production began to decline in second quarter 2015 and is expected to continue 

declining through September 2016 before increasing again. This production decline can be attributed to 

poor economic performance from some onshore production regions and anticipated seasonal disruptions 

(such as hurricane-related disruptions in the Gulf of Mexico). As new projects in the Gulf of Mexico 

come online in late 2015 and 2016, production should increase by fourth quarter 2016. The poor 

economic performance seen in onshore regions, characterized by reduced cash flows and capital 

expenditures, has led producers to focus on major tight and shale oil formations and direct investment 

away from marginal exploration. This has resulted in lower numbers of oil-directed rigs, which as of 

March 2016 have declined 60 percent since October 2014. In addition, well completions are below 2014 

levels, as companies have chosen to defer completion of drilled wells until crude oil prices stabilize or 

increase (U.S. DOE, 2015j).

Improved productivity and reduced production costs have allowed producers to continue producing in the 

major oil formations within the Bakken, Eagle Ford, Permian, and Niobrara formations through the first 

half of 2015. However, WTI prices are expected to remain below 60 $/bbl throughout 2016, which is 

expected to limit drilling and well completions despite changing economics. Actual production activity 

will depend on wellhead prices and region- and formation-specific economics (U.S. DOE, 2015j).

Demand should begin to grow faster than supply in 2016 (Deloitte, 2015b). Low prices have already 

begun to deter investment and increase demand. In addition, many factors keeping 2015 production high 

will disappear. Current hedging contracts, which protect producers from low market prices and improve 

revenue, will expire, and the fraction of total production hedged is expected to decline in 2016 (IHS, 

0

5

10

15

20

25

30

35

40

20002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015

Quadrillion Btu

Imports of Crude Oil Production of Crude Oil Less Exports of Crude Oil Less Crude Oil Stock Change
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 11

2015). Existing crude oil projects considered “too late to turn back” will be completed, while new projects 

are not being developed at the same rate given the low rig count.

EIA, in its November Short Term Energy Outlook, forecasts WTI prices to end 2016 at $52/bbl after 

peaking at $54/bbl in the summer of 2016 (U.S. DOE, 2015j). Brent prices are forecast to be slightly 

higher, closing out 2016 at $57/bbl. Standard and Poor’s 2016 price assumptions are $50/bbl for WTI and 

$55/bbl for Brent oil (“S&P Revised its Crude Oil and Natural Gas Price Assumptions,” 2015). Deloitte’s 

projections are in the same range, averaging $53.55/bbl for WTI oil in 2016 (Deloitte, 2015c). Crude oil 

price volatility remains high, especially in the international market, due to uncertainty about economic 

growth and associated crude oil demand in emerging market countries. Volatility is expected to remain 

high going into 2016 due to uncertainties regarding: (1) the pace and volume at which Iranian crude oil 

reenters the market; (2) the strength of crude oil consumption growth; and (3) the responsiveness of nonOPEC production to low prices (U.S. DOE, 2015j).

In August 2015, the United States relaxed its crude oil export ban to allow up to 100,000 bpd of crude oil 

to be traded5 with Mexico (U.S. DOE, 2015c). Under this relaxation, the U.S. will send light crude oil 

(which is being produced in larger quantities due to tight and shale oil production) to Mexico and receive 

heavier crude oil from Mexico. This exchange is expected to benefit both countries. Mexico has 

historically produced light crude oil, and its refineries were built to process light crude oil. However, 

recent Mexican production has tended toward heavy crude oil, which its refineries are not as wellequipped to handle. The opposite has occurred in the United States. Before the rise in tight and shale oil 

production beginning in 2008, domestic production was mostly heavier crudes, and U.S. refineries are 

better equipped to process heavy crude oil. Import and export data are only available through July 2015, 

but this change in crude oil trade terms is expected to increase imports and exports of crude oil by up to 

100,000 bpd (resulting in no change in net imports).

More recently, in December 2015, Congress acted to relax the crude oil export ban with limited 

exceptions. Relaxation of the export ban is an additional factor affecting the outlook for domestic oil 

production, domestic refining activity, and potentially market prices. 

3.1.3 Long Term Projections

According to EIA, as currently anticipated, total U.S. production of crude oil is projected to increase to

10.6 million bpd in 2020 as crude oil prices recover, a 42 percent increase over 2013 levels. Increased 

domestic production through 2020 is expected to have two results: (1) decreased imports of crude oil; and 

(2) increased refinery throughput, which should increase exports of petroleum products (U.S. DOE, 

2015h). Between 2020 and 2040, domestic crude oil production is expected to decline by 11 percent, 

causing net imports to rise again. Domestic tight and shale oil production is also expected to increase

through 2020, when it will reach 5.60 million bpd, and then decrease from 2020 to 2040. In 2013, tight 

and shale oil production accounted for 42 percent of total domestic crude oil production. This share is 

expected to increase to 53 percent of total domestic crude oil production in 2020 before falling to 45 

percent in 2040. The United States is projected to remain a net importer of crude oil and a net exporter of 

petroleum products through 2040 (U.S. DOE, 2015a).

As previously stated, crude oil price volatility remains high in the short term. Longer term, though, prices 

are expected to resume an upward trend. In its 2015 Annual Energy Outlook, EIA projects the Brent price 

to be $79.13/bbl in 2020 and to continue to increase to $141.28/bbl in 2040. WTI prices are projected to 

follow the same trend – $72.96/bbl in 2020 and $135.67/bbl in 2040. These projections reflect market 

 5 Under this relaxation, U.S. crude oil may be exported to Mexico for an equal volume of imports of crude oil from Mexico.
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 12

conditions only through the end of 2014, but EIA has continued to lower its short-term price projections 

as prices have continued to fall throughout 2015, indicating a slower price recovery than described in 

AEO 2015 (U.S. DOE, 2015a). The International Energy Agency also reports Brent price projections, in 

its 2015 World Energy Outlook. In IEA’s central scenario, Brent prices will reach $80/bbl in 2020 and 

continue to increase after that. However, IEA also describes plausible circumstances under which Brent 

prices remain close to $50/bbl through 2020: lower near-term growth in the global economy, a more 

stable Middle East, a change in OPEC production in favor of securing a higher share of the crude oil 

market, and more resilient non-OPEC supply (particularly from U.S. tight oil production) (IEA, 2015).

3.2 Natural Gas

U.S. natural gas production has increased substantially since 2005. This increase results from the increase 

in production of unconventional gas – shale gas (including associated natural gas production from tight 

and shale oil formations6

), especially in the Marcellus Shale formation – which has more than offset the 

decline in other, conventional production. This has led to falling natural gas prices, encouraging natural 

gas consumption for electric power generation; decreasing natural gas imports; and increasing exports.

3.2.1 Recent Trends in Natural Gas Production, Prices, Imports, and Consumption

Figure 3-6 shows natural gas marketed production for 2000 through the second quarter of 2015 (by 

PADD through 2014).

7 Between 2000 and 2005, natural gas production declined 6 percent but increased 

48 percent between 2006 and the second quarter of 2015. Between 2000 and the second quarter of 2015, 

total marketed production of natural gas in the United States increased 43 percent. The natural gas share 

of total energy consumption has also increased, from 23 percent in 2005 to 27 percent in 2013 (U.S DOE, 

2015a). Despite falling production from conventional formations and the Gulf of Mexico, total domestic 

natural gas production has set a new record. This higher production results from (1) increased drilling 

efficiencies; (2) improving completion technology and practices; (3) decreased drilling costs; (4) a focus 

on high output areas; (5) continued hedging contracts8

; and (6) bringing uncompleted wells into 

production (U.S. DOE, 2015z).

Production data are not available for individual PADDs for 2015, but regional trends can be compared 

through the fourth quarter of 2014. The greatest increase in marketed natural gas production, by far, 

occurred in PADD 1: East Coast, where the Marcellus shale formation is located. However, PADD 3: 

Gulf Coast remains the largest producer of natural gas in the United States and has not seen any increase 

over the analysis period. Production in each of the other three PADDs has increased as well.

 6 EPA assumes that natural gas production from tight oil formations is associated-dissolved natural gas.

7 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).”

8 Hedging contracts may allow otherwise uneconomical production to remain profitable through the duration of the hedge 

contract.
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June 2016 13

Figure 3-6: 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. Production data are not available by PADD for 

2015. EPA calculated annual equivalent values for each quarter beginning in 2014 by multiplying the total marketed production 

for each quarter by four.

Sources: U.S. DOE 2015i

The increase in marketed production since 2008 corresponds to increasing unconventional natural gas 

production. Figure 3-7 shows U.S. dry9 shale gas production. Like tight and shale oil production, dry 

shale gas production has significantly increased since 2008. Dry shale gas production in August 2015 was 

almost seven times that in January 2008. Most of this increase has come since 2010 from the Marcellus 

formation. August 2015 dry shale gas production from the Marcellus formation (in PA, WV, OH, and 

NY) was 28 times that in January 2010 and is now by far the biggest producer of shale gas (producing 

more than three times as much shale gas as the next biggest producer, the Eagle Ford formation in TX).

Conversely, dry shale gas production from the Haynesville formation has fallen almost 50 percent from 

its peak in January 2012.

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 3-8 shows total domestic consumption of natural gas from 2000 

to 2015. In the same way as described for Figure 3-5, the lower part of the chart represents domestic 

production available for consumption, while the upper part represents imports. The sum of these parts 

represents total domestic consumption. Total consumption of natural gas declined between 2000 and 2006 

but has increased since then, except for a small decline from 2008-2009, most likely due to the recession. 

Overall, between 2000 and 2014, total consumption of natural gas increased by 14 percent. If 2015 

consumption levels continue through the end of the year, total consumption of natural gas will have 

increased almost 25 percent since 2000 to 30.4 quadrillion Btu, with imports accounting for just 2.5 

quadrillion Btu (8 percent of total domestic consumption).

10 According to 2014 EIA data, a non-trivial 

 9 After processing to remove natural gas liquids. EIA reports shale gas production as dry production.

10 Total year consumption for 2015 is an annual estimate based simply on doubling the consumption reported for the first two 

quarters. However, natural gas consumption is highest in the first quarter, due to heating requirements in the cold winter 

0

5

10

15

20

25

30

35

Quadrillion Btu

Total U.S.

PADD 5: West Coast

PADD 4: Rocky Mountain

PADD 3: Gulf Coast

PADD 2: Midwest

PADD 1: East Coast
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 14

share (9 percent) of the gross domestic supply of natural gas was consumed in the natural gas production 

and delivery process itself, as lease and plant fuel (6 percent of total) and fuel for pipeline and distribution 

services (3 percent of total). The remaining 91 percent of gross supply is available to natural gas 

consumers and was delivered to the following sectors: electric power (31 percent of total), industrial (29 

percent of total), residential (19 percent of total), commercial (13 percent of total), and vehicle fuel (less 

than 1 percent of total).

Figure 3-7: Dry Shale Gas Production in the United States by Formation (Bcfd)

Sources: U.S. DOE 2015p

 

months. As a result, average quarterly consumption will likely decrease through the end of 2015, and total annual 

consumption will likely be lower than reported in Figure 3-9.

0

5

10

15

20

25

30

35

40

45

Marcellus (PA,WV,OH & NY)

Haynesville (LA & TX)

Eagle Ford (TX)

Fayetteville (AR)

Barnett (TX)

Woodford (OK)

Bakken (ND)

Antrim (MI, IN, & OH)

Utica (OH, PA & WV)

Rest of US 'shale'
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June 2016 15

Figure 3-8: Total Domestic Consumption of Natural Gas (Quadrillion Btu)a

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

Sources: U.S. DOE 2015i, 2015t, 2015u, 2015v

Domestic production has more than been able to keep pace with increasing domestic consumption, 

leading to reduced imports and increased exports. Figure 3-9 presents net imports, imports, and exports of 

natural gas from 2000 to 2014. The import/export market continues to change. Net imports declined in 

2014 due to lower imports from Canada, which were 41 percent below the five-year average. Ninety-eight 

percent of natural gas imports arrive via pipeline from Canada, and imports have declined almost every 

year since 2007. 2014 saw the lowest level of natural gas imports since 1995. Natural gas exports also 

declined in 2014 but remained 9 percent above the 5-year average due to record high exports to Mexico to 

satisfy Mexico’s growing demand of natural gas for electric power generation (U.S. DOE, 2015w).

Exports to Mexico did not offset declines in exports to Canada, resulting in declining total exports. 

Overall since 2007, net imports have declined 78 percent.

0

5

10

15

20

25

30

35

20002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015

Quadrillion Btu

Annual Natural Gas Marketed Production Less Exports

Annual Natural Gas Imports
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June 2016 16

Figure 3-9: 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 2015t, 2015u, 2015v

Figure 3-10 shows the Henry Hub price from 2000 to the third quarter of 2015. Declines since 2008 result 

from abundant U.S. production of natural gas resulting largely from the growth in unconventional 

production. After two years of increasing Henry Hub prices from 2012-2014, prices have fallen since the 

first quarter of 2014. The Henry Hub price in the third quarter of 2015 was 2.76 $/mmBtu, a 47 percent 

decline from the first quarter of 2014 and a 69 percent decline from its peak in 2008. Recent declines also 

result from increased production, due to higher than expected production from the Marcellus shale 

formation, gains in efficiency, and an increase in the production of natural gas as a byproduct from tight 

oil production (To, 2015).

0

5

10

15

20

25

30

20002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015

Quadrillion Btu

Imports of Natural Gas Net Imports of Natural Gas Exports of Natural Gas
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June 2016 17

Figure 3-10: Henry Hub Natural Gas Price (Dollars per million Btu)

Sources: U.S. DOE 2015f, 2015g

3.2.2 Short Term Projections

Growth in natural gas marketed production began to slow in the summer of 2015 (U.S. DOE, 2015z) but

production is still expected to increase 6.3 percent in 2015 and 2.0 percent in 2016, as increased lower-48 

onshore production offsets declines from the Gulf of Mexico. Most of this increase will come from 

production in the Marcellus shale formation, where the number of previously drilled but uncompleted 

wells will fall and new pipelines will allow producers to deliver more natural gas to markets in the 

Northeast. Inventories at the end of October 2015 tied the inventory record set in November 2012, and 

warmer winter temperatures predict a lower-than-normal winter drawdown (U.S. DOE, 2015j).

The United States is projected to become a net exporter of natural gas by 2017 (U.S. DOE, 2015a). 

Increased production should reduce the demand for imports from Canada and support growth in U.S. 

exports to Mexico, and the United States will continue to export liquefied natural gas (LNG). Exports to 

Mexico, especially from the Eagle Ford formation, are expected to continue to increase as Mexico’s 

production of natural gas is not expected to keep pace with its growing demand, primarily for electric 

power generation. In addition, gross exports of LNG are projected to increase in 2016 with the completion 

of a new liquefaction plant (U.S. DOE, 2015j).

EIA projects that Henry Hub prices will stay below $3 per mmBtu through June 2016 and below $3.50 

per mmBtu through the end of 2016. Low prices have supported increased domestic natural gas 

consumption. Consumption is forecast to average 76.3 Bcfd in 2015 and 76.8 Bcfd in 2016, compared to 

73.1 in 2014. In the electric power sector, EIA projects that consumption will increase by 16.8 percent in 

2015 but then decrease by 1.2 percent in 2016. Industrial sector consumption is forecast to remain flat in 

2015 and increase by 4.2 percent in 2016, as new industrial projects (in fertilizer and chemicals sectors) 

come online in late 2015 and in 2016 and industrial consumers continue to experience low prices. 

Residential and commercial consumption is projected to decline in 2015 and 2016, reflecting lower 

heating demand in winter 2015-2016 (U.S. DOE, 2015j).

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

Dollars per Million Btu
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 18

3.2.3 Long Term Projections

EIA projects that total U.S. dry natural gas production will increase from 24.4 Tcf in 2013 to 35.5 Tcf in 

2040, a 45 percent increase. Most of that increase will come from increasing lower-48 shale gas 

production, which is expected to increase 73 percent between 2013 and 2040, but increasing tight gas, 

offshore, and Alaskan onshore production will also contribute. More than half of the increase in shale gas 

production is expected to come from the Marcellus and Haynesville formations. Future natural gas 

production depends on the size and cost of shale and tight gas resources,

11 technology improvements, 

domestic demand, and the relative price of oil (U.S. DOE, 2015a).

Total domestic natural gas consumption is projected to increase by 13 percent by 2040, compared to 

2013. Current projections are lower than previous projections. Natural gas use for electric power 

generation is projected to be lower due to expected increased competition from nuclear power and 

renewables, increased building efficiency, and changing lighting standards. Natural gas represented 27

percent of total primary energy consumption in 2013. This share is expected to remain relatively constant, 

increasing only slightly to 29 percent in 2040 (U.S. DOE, 2015a).

EIA projects that Henry Hub prices will more than double, from $3.73 per mmBtu in 2013 to $7.85 per 

mmBtu in 2040, as increased domestic and international demand leads to production of increasingly 

expensive resources. Future natural gas prices will continue to be influenced by crude oil prices, resource 

availability, and demand (U.S. DOE, 2015a).

3.3 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 2012. This index therefore shows how much production occurred in a given 

year relative to the production that occurred in 2012. Real output in this case represents quantity, not the 

actual value of the dollar, of goods and services made. Table 3-1 provides the Federal Reserve System’s 

IPI for the OGE industry sector for 2000 to 2015. Between 2002 and 2005, real output in the overall OGE 

industry (NAICS 21111) fell every year but increased steadily after that, showing large increases from 

2012 to 2014. Overall, during the 16-year period of 2000 through 2015, real output increased by 62

percent, at an average annual growth rate of 3 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 saw similar overall changes and a similar average 

annual growth rate, though experienced more year-to-year fluctuations in growth.

 11 Tight gas as a resource is not in historical reporting but is projected forward by EIA.
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 19

Table 3-1: 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 2012=100 % Change Index 2012=100 % Change Index 2012=100 % Change

2000 83.46 N/A 83.56 N/A 80.60 N/A

2001 84.09 0.7% 84.42 1.0% 78.25 -2.9%

2002 82.30 -2.1% 82.47 -2.3% 78.44 0.2%

2003 81.37 -1.1% 82.06 -0.5% 71.56 -8.8%

2004 79.33 -2.5% 79.52 -3.1% 75.55 5.6%

2005 76.26 -3.9% 76.51 -3.8% 71.74 -5.0%

2006 76.60 0.4% 76.81 0.4% 72.79 1.5%

2007 78.08 1.9% 78.24 1.9% 74.98 3.0%

2008 78.94 1.1% 79.16 1.2% 74.80 -0.2%

2009 83.10 5.3% 83.26 5.2% 80.16 7.2%

2010 85.70 3.1% 85.63 2.8% 87.42 9.1%

2011 89.67 4.6% 89.51 4.5% 93.12 6.5%

2012 100.00 16.7% 100.00 16.8% 100.00 7.4%

2013 110.81 10.8% 111.02 11.0% 105.74 5.7%

2014 126.34 14.0% 126.66 14.1% 118.70 12.2%

2015b 135.58 7.3% 135.95 7.3% 126.91 6.9%

2000-2015 Comparison

Total Percent Change 62.4% 62.7% 57.5%

Average Annual 

Growth Rate 3.3% 3.3% 3.1%

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 

2012; therefore, this index shows how much production occurred in a given year relative to the production that occurred in 2012. 

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

b. IPI for 2015 reflects data through the first three quarters.

Sources: FRS, 2015b

3.4 Financial Outlook

The general industry outlook points to slow recovery of crude oil and natural gas prices, and increased 

pressure on oil and gas companies to improve cash flows from production or find new sources of cash. 

Activity in the OGE industry has thus far reflected the expectation that low crude oil prices would be 

short-lived. However, EIA and other industry analysts project WTI and Brent crude oil prices to remain 

below $60/bbl through the end of 2016 (U.S. DOE, 2015j).

The increasing likelihood that crude oil and natural gas prices will remain low for longer than previously 

expected is beginning to weigh on financial assessments of oil and gas firms and may affect the 

willingness of creditors to finance firms at the same levels as in previous years. Equity prices for oil and 

gas producers have already declined significantly since mid-year 2014, with the Standard & Poor’s 

Exploration and Production Industry Index (XOP) falling by more than one-half from June 2014 through 

October 2015. This decline largely results from falling crude oil and natural gas prices, and the resulting 

contraction in company cash flow and earnings. These declines in financial performance also lead to 

reduced security of credit extended to these firms; lenders will likely look to reduce their exposure to 

default risk by limiting future lending, and increasing the cost12 and tightening other credit terms in future 

lending. 

Oil and gas producers are required to submit to commercial lenders a reserve report twice a year in which 

they estimate total crude oil and natural gas proved reserves at certain wells, and report assumptions about 

the cost and production levels associated with those wells. Lenders use these reports to evaluate expected 

revenues and determine the borrowing base (Shaw, 2015). These redeterminations occur each spring and 

fall. The April 2015 redeterminations resulted in little change in borrowing bases, which would have put 

 12 Beyond increases in general interest rates – i.e., increasing the relative cost (spread above U.S. Treasury rates) of credit 

provided for oil and gas exploration, development and production. 
Profile of the Unconventional Oil and Gas Industry 3: Overview of Crude Oil and Natural Gas and the U.S. Economy

June 2016 20

pressure on producers to raise cash (e.g., through asset sales or sale of equity) and reduce debt as a 

fraction of capital structure. Instead, asset sales and merger and acquisition activity remained low through 

the first half of 2015, as producers have focused on cost-cutting and high efficiency drilling instead of 

financial restructuring measures (Deloitte, 2015a).

Hedging contracts and improved efficiency have allowed higher production levels, despite falling spot 

prices. Hedging contracts have kept the received prices higher for some companies, but these contracts 

are typically of short duration (one year or less) and will not be able to be replaced with comparable level 

of price protection as the older hedge positions expire. In addition, these protections are expected to be 

lower in 2016, falling to just 11 percent of total production compared to 28 percent in 2015. Small E&Ps 

will have the highest hedging rates in 2016, while large E&Ps will be able to rely on stronger balance 

sheets to weather the low prices (IHS, 2015). OGE firms have also begun to focus on their most 

productive wells, relying on technological improvements to cut production costs and increase the 

production efficiency of existing wells. This improved efficiency has allowed production to increase 

despite a decreasing rig count that reflects decreased capital expenditures. In October 2015, the number of 

oil-directed rigs was just 37 percent of prior year levels, and the number of gas-directed rigs was just 40 

percent (Baker Hughes data).

While the spring 2015 credit redeterminations yielded few changes, the fall 2015 redeterminations are 

likely to yield different results. As lenders put more pressure on producers to raise cash, firms will look to 

sell assets, likely leading to increased mergers and acquisitions activity in fourth quarter 2015 and into 

2016. Fall redeterminations could also result in higher borrowing costs, lower lending levels, and/or 

accelerated repayment schedules. This, coupled with low cash flows due to falling prices, is likely to lead

producers to sell assets or consolidate (Deloitte, 2015a).

In addition, a large number of wells have been drilled but uncompleted (DUCs). In June 2015, EIA 

reported between 2,000 and 4,000 DUCs in the lower 48, predominantly located in the Bakken, Permian, 

and Eagle Ford formations. As prices stabilize or increase, these wells are available for immediate 

production to improve cash flows. EIA estimates that hundreds of thousands of barrels per day could be 

added to the current supply if these wells are completed, which is likely to exacerbate the oversupply 

problem and push prices back down (U.S. DOE, 2015l).

Natural gas production will likely provide little help to OGE firms desperate for cash due to low prices. 

Natural gas inventories at the end of October matched the record set in 2012 (U.S. DOE, 2015j). If these 

inventories are not depleted this winter, which is likely the case with warmer weather than last year 

expected, prices will stay low. EIA forecasts Henry Hub prices to average $3.00/mmBtu in 2016 (U.S. 

DOE, 2015j). Standard and Poor’s and Deloitte have similar projections for 2016, with prices averaging 

$3/mmBtu (“S&P Revised its Crude Oil and Natural Gas Price Assumptions,” 2015) and $3.15/mmBtu

(Deloitte, 2015c), respectively.
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 21

4 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 since 2000: (1) the number of firms and number of establishments in the 

United States have risen by approximately 3 percent and 4 percent, respectively, (2) the number of OGE 

industry employees has increased by 51 percent, (3) revenue has more than doubled, and (4) annual 

payroll has increased substantially. On the other hand, the character of the industry, with regard 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.

13

4.1 Number of Firms and Establishments

Table 4-1 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 2000-2012. 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 70 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 2012, the 

number of establishments in the overall Oil and Gas Extraction sector, reported in Table 4-2, saw a larger 

increase of 4 percent, with largest the increases of 6 to 7 percent occurring in 2006 and 2008. 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 6 percent. Between 2000 

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

fell by 26 percent, at an average annual rate of 2.5 percent.

As both tables – Table 4-1 and Table 4-2 – 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 2012, 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.

 13 Data on the number of firms and establishments, employment, revenue, and payroll in the OGE industry come from the 

Statistics of U.S. Businesses and U.S. Economic Census, and are only available through 2012. Therefore, data in Sections 

4.1-4.4 do not reflect changes in the industry since 2012 (e.g., the large decrease in crude oil prices since June 2014).
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 22

Table 4-1: 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%

2012 6,646 0.3% 6,536 0.2% 143 5.1%

2000-2012 Comparison

Total Percent Change 2.7% 1.9% 70.2%

Average Annual 

Growth Rate 0.2% 0.2% 4.5%

Sources: SUSB, 2000-2012

Table 4-2: 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 3.0% 7,757 3.1% 338 0.0%

2012 8,064 -0.4% 7,720 -0.5% 344 1.8%

2000-2012 Comparison

Total Percent Change 4.2% 6.1% -26.3%

Average Annual 

Growth Rate 0.3% 0.5% -2.5%

Sources: SUSB, 2000-2012

4.2 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 1,250 or fewer employees in the Crude Petroleum and 

Natural Gas Extraction segment, and 750 or fewer employees in the Natural Gas Liquid Extraction

segment (U.S. SBA, 2016). Table 4-3 reports the distribution of firms by firm size for 2000 through 2012. 
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 23

The percentage of small firms in the overall Oil and Gas Extraction sector remained at least14 98.5

percent for this period. The Crude Petroleum and Natural Gas Extraction segment similarly maintained a 

high percentage of small firms, at least about 99 percent, throughout the period. On the other hand, the 

number of small firms in the Natural Gas Liquid Extraction segment increased substantially; the 

percentage of small firms in this segment rose from at least 60 percent in 2000 and to at least 75 percent 

in 2012.

Table 4-3: 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%

2012 <500 6,547 98.5% 6,444 98.6% 107 74.8%

>500 99 1.5% 92 1.4% 36 25.2%

2000-2012 Comparison

Total Percent Change <500 2.7% 1.8% 114.0%

>500 0.0% 2.2% 5.9%

Average Annual 

Growth Rate

<500 0.2% 0.2% 6.5%

>500 0.0% 0.2% 0.5%

Sources: SUSB, 2000-2012

4.3 Employment 

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

for 2000 through 2012. Over this period, total industry employment increased substantially, by 51

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 55 percent during the analysis period. While employment in the Natural Gas 

 14 SUSB data on the number of firms is available only for firms with greater than 500 employees but cannot be broken down 

further into firms with greater than 750 or 1,250 employees. Therefore, some or all of the firms in the “greater than 500” 

employment group may also be small firms. The percentage of firms with 500 or fewer employees represents a minimum 

value for the fraction of small firms in the industry.
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 24

Liquids Extraction segment also increased during that time, this increase was much smaller, at 13 percent. 

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 increase slowly; by 

2024, total sector-wide employment is projected to increase by 0.9 percent, compared to 2014 (U.S. DOL, 

2014b). Employment in most occupations within the overall Oil and Gas Extraction sector (with the 

exception of surveying and mapping technicians; bookkeeping, accounting, and auditing clerks; payroll 

and timekeeping clerks; procurement clerks; file clerks; executive secretaries and executive

administrative assistants; data entry keyers; and machine tool cutting setters, operators, and tenders, metal 

and plastic) will grow by 0.9 percent to 34.6 percent. The occupations with the highest expected growth 

include operations research analysts, industrial machinery mechanics, and web developers (U.S. DOL, 

2014a).

Table 4-4: 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%

2012 125,001 5.1% 114,524 5.1% 10,477 4.7%

2000 – 2012 Comparison

Total Percent Change 50.6% 55.4% 12.6%

Annual Average 

Growth Rate 3.5% 3.7% 1.0%

Sources: SUSB, 2000-2012

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

provides estimates of average employment per firm. In 2012, Oil and Gas Extraction sector firms 

employed, on average, 19 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 18 and 

73, respectively. 

4.4 Revenue and Payroll in the OGE Industry Segments

Revenue and payroll data from the Economic Census for years 1997, 2002, 2007, and 2012 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 4-5, between 1997 

and 2012, the overall Oil and Gas Extraction sector grew in revenue, annual payroll, and revenue less 

payroll. Likewise, the Crude Petroleum and Natural Gas Extraction and Natural Gas Liquid Extraction

segments experienced increases in all three metrics during that time, despite declines in 2002. 

Table 4-5 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 
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 25

Petroleum and Natural Gas Extraction segment, average revenue rose between 1997 and 2012 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 and 

between 2007 and 2012. 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 4.1, above). Using the number of firms 

as reported by SUSB, in 2012 the Oil and Gas Extraction sector had an estimated average $53 million in 

revenue per firm.

Table 4-5: Key Economic Performance Statistics for OGE Industry Sector, by Year and 

Segment, 1997-2012

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 

2012 $351,963 $65 $17,330 $334,632

Total Percent Change 

1997-2012

150.8% 220.4% 130.5% 152.0%

Average Annual Growth 

Rate 1997-2012

6.3% 8.1% 5.7% 6.4%

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 

2012 $300,285 $57 $16,147 $284,138

Total Percent Change 

1997-2012

182.10% 264.2% 138.1% 185.1%

Average Annual Growth 

Rate 1997-2012

7.2% 9.0% 6.0% 7.2%

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 

2012 $51,677 $413 $1,184 $50,494

Total Percent Change 

1997-2012

52.5% 8.6% 60.2% 52.4%

Average Annual Growth 

Rate 1997-2012

2.9% 0.6% 3.2% 2.8%

Sources: U.S. DOC, 1997, 2002, 2007, 2012

4.5 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 4-1, 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 4.1), along with domestic production (Section 3.1

and Section 3.2). This may partly result from the recession of early 2000s. Between 2005 and 2014, 

capacity utilization overall increased steadily to 99.5 percent, except for a mild decline in 2008, and again 

between 2010 and 2011, the first likely due to weakening of the overall economy. The overall increase in 

capacity utilization between 2005 and the second quarter of 2014 coincides with the increase in natural 

gas production during that period and with production of domestic crude oil since 2008. Between the 
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 26

second quarter of 2014 and the third quarter of 2015, however, capacity utilization fell sharply from 99.5 

percent to 95.1 percent. This decrease corresponds to the fall in crude oil prices since June 2014. 

Figure 4-1: Capacity Utilization for OGE Industry (NAICS 21111)

Sources: FRS, 2015a

4.6 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 

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

LNG.

4.6.1 Market Structure and Pricing in the OGE Industry Sector

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

differences are discussed below.

Crude Oil

The crude 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 crude 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 crude oil are Saudi Arabia, Russia, the United States, China, Canada, and Iran (Levine et al, 

2014). However, the largest eight oil companies, as of 2005, were all national oil companies of the OPEC 
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 27

states, with Russian companies coming in at 10 and 11 and Exxon Mobil at 12 (Arthur et al, 2014). In 

2014, OPEC accounted for 73 percent of world crude oil reserves and 43 percent of world crude oil 

production. Nevertheless, OPEC’s influence over crude oil prices has varied over time, as evidenced by 

the steep decline in world prices for crude oil in 2008 suggesting that supply and demand forces in the 

global crude oil market limit OPEC’s ability to influence crude oil prices (Levine et al, 2014).

As an international cartel, OPEC places producer quotas on members in an effort to manage world crude 

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 crude 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 crude oil; as a result the level of U.S. 

imports can significantly influence crude oil prices. The recent upsurge in U.S. crude oil production, 

largely from tight and shale oil formations, with a consequent decline in U.S. imports, has exerted 

downward pressure on international crude oil prices, as seen in recent Brent prices (Figure 3-3) (U.S. 

DOE, 2014).

Natural Gas

Unlike the crude 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.15 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 

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. Natural 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 natural 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 natural 

gas production from shale formations, can lead to relative price declines. 

 15 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 natural 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. 
Profile of the Unconventional Oil and Gas Industry 4: OGE Industry Structure and Economic Performance

June 2016 28

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 crude oil and natural gas. When the price of natural gas is low relative 

to crude oil, these consumers could switch to natural gas, increasing demand for natural gas and 

increasing natural gas prices. Alternatively, when natural gas prices are high, demand could shift in the 

opposite direction causing a relative decrease in natural gas prices (U.S. DOE, 2011).

4.6.2 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 between 2009 and 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 crude oil from shale formations. Financial buyers also were making deals involving shale 

oil and gas formations. Deals by midstream businesses remained relatively constant with most 

transactions involving natural gas gathering and processing formations 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 formations. 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). 

M&A activity has stayed relatively constant since the beginning of 2012 with the exception of two sharp 

upturns, in the fourth quarter of 2012 and the second quarter of 2015. However, 80 percent of the value of 

2Q15 M&A activity can be attributed to a single deal, the acquisition of BG Group by Shell. Without this 

deal, second quarter activity would be half that in the fourth quarter of 2014. The second largest deal was 

the acquisition of Rosetta Resources by Noble Energy, driven by Noble Energy’s desire to strengthen its 

onshore unconventional portfolio, particularly in the Eagle Ford formation. Through the first half of 2015, 

E&P firms have continued to focus on cutting costs and improving drilling efficiencies instead of turning 

to M&A and other financial restructuring to grow production and revenue and improve financial 

performance. North America remains the center of M&A activity due to the large number of E&P firms, 

providing more opportunity for upstream deals. As discussed in Section 3.4, continued low crude oil and 

natural gas prices may increase pressure on firms to make M&A deals, especially as hedging contracts 

expire. In addition, slow price recovery, as is now predicted, increases the risk that highly leveraged firms 

will be forced into bankruptcy, releasing assets into the market at low prices (Deloitte, 2015a).
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 29

5 Financial Performance and Condition

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. 

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

compared to firms in many other industries. Low crude 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 crude oil and natural

gas reserves, thus requiring asset write-downs, 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 crude oil and natural 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

 Long-term debt to total assets

 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 11 years 

(2005-2015) for selected public reporting firms in the OGE industry. The firms in the analysis are U.S. 

firms reported by Value Line as operating in the Natural Gas Diversified, Petroleum Production, or 

Petroleum Integrated OGE industry sub-sectors. EPA divided these firms into three categories:

1. UOG Firms. These are firms that generate at least 50 percent of their revenue from

unconventional oil and gas. The definition of unconventional oil and gas for purposes of this 

analysis is coal bed methane, coal seam gas, shale oil, shale gas, tight oil, tight gas, and tight 

sands (MVIS, 2015).

16 EPA used the Market Vectors Global Unconventional Oil & Gas Index for 

this analysis.

17

 16 EPA considers the contribution of coalbed methane to the financial performance of firms in the UOG firm set to be very 

small, approaching a de minimis value.

17 This index is limited to firms with a market capitalization of at least $150 million, a three month average-daily-trading 

volume of at least $1 million, and at least 250,000 shares traded per month over the last six months. The UOG Firms set may

not, therefore, be entirely comprehensive.
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 30

2. Integrated Firms. Firms reported by Value Line as operating in the Petroleum Integrated OGE 

industry sub-sector but not reported as generating 50 percent of their revenue from 

unconventional oil and gas, as defined above for this analysis.

3. Other OGE Firms. Firms reported by Value Line as operating in the Natural Gas Diversified or

Petroleum Production OGE industry sub-sectors that do not generate 50 percent of their income 

from unconventional oil and gas, as defined above for this analysis.

The objective in developing the UOG firm dataset was to identify firms for which UOG activity is a 

majority 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 formations, in particular shale formations, 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 formations 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 

captures firms with U.S. exploration and production operations, which in many cases are known to 

include UOG operations, but for which UOG development and production is less than 50 percent of their 

overall business in terms of contribution to revenue. These firms are therefore not included in the UOG 

firm dataset. Similarly, the Integrated Firms dataset also captures firms for which UOG development and 

production is a less important element of overall business (and are therefore not included in the UOG firm

dataset), but which are further distinguished by substantial activity in the downstream segments of 

refining, distribution, and sales. 

To develop the financial-indicator metrics reported below, EPA assembled data for the firms for the 11-

year period of 2005 through 2015 from the sources listed above. In developing data for this analysis, EPA

sorted firms according to their business activities, as described above: UOG Firms, Integrated Firms, and 

Other OGE Firms. In total, 40 firms are in the final UOG Firms set, 30 firms are in the Integrated Firms

set, and 143 firms are in the Other OGE firms set, and there is no overlap of firms between the three sets; 

however, the number of firms used in the calculation for a given metric is less than these totals because 

data were not available for all of the firms, years, and metrics. Four of the six metrics – operating margin, 

net profit margin, return on total capital, and long-term debt to total assets – are percentage values and 

were reported as such in the analysis. The revenue and total capital spending metrics are reported in Value 

Line as absolute values and thus display a wide range of values across firms of varying sizes. For these 

metrics, EPA calculated the year-to-year percentage change to present in the analysis. A positive value 

therefore represents an increase in revenue or total capital spending from the previous year; a negative 

value represents a decrease from the previous year.

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, Integrated Firms, and Other OGE firms. This chart provides insight into whether and 

how the profile of performance and change over time differs across the three sets. This understanding is 

important for assessing the momentum and financial performance/condition in UOG extraction and 

production compared to the other OGE industry segments. The second chart, which is for the UOG firms
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 31

only, presents the median, 10th percentile and 90th percentile values, and the revenue-weighted 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.

5.1 Revenue

Revenue 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, EPA 

calculated the year-to-year percentage changes in revenue.

As shown in Figure 5-1, OGE-industry revenue (as represented by the indexes for UOG firms, Integrated 

Firms, and Other OGE firms) rose between 2005 and 2008 before declining in 2009 at the time of the 

recent recession. Beginning in 2010, revenue rebounded for all three firm sets. Revenue declined in 2015 

compared to 2014, as OGE firms faced falling crude oil prices beginning in the summer of 2014.18

Revenue declined more sharply from 2014-2015 for UOG firms, which do not have the same downstream 

buffer that Integrated firms have. Refined product prices have fallen more slowly than crude oil prices, so 

refiners (including the downstream refining segments of integrated firms) have seen increasing margins.

Within UOG firms, the 90th percentile revenue index, which can be seen in Figure 5-2, grew at a much 

higher rate, especially between 2007 and 2008, compared to Integrated and Other OGE firms. The 10th

percentile value experienced negative growth every year except 2008 and 2011. 

Figure 5-1: Revenue, Year-to-Year Percent Change (Median) for UOG, Integrated, and Other OGE 

Firms

Sources: Value Line 2005-2015; EPA analysis

 18 Values for 2015 reflect partial year values (typically through 3rd quarter of 2015) with Value Line estimates for the full year. 

This figure and several that follow do not report values for 2015 for the Other OGE firms segment. The Value Line data 

include 2015 values for only a few firms in this segment.
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 32

Figure 5-2: Revenue, UOG Firms, Year-to-Year % Change

Sources: Value Line 2005-2015; EPA analysis

5.2 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 5-3, the operating margin for UOG firms and Other OGE firms was higher than that 

of Integrated firms for the entire period of analysis, due to structural differences in the business models of 

the typically smaller, non-integrated E&P firms comprising the UOG firms and Other OGE firms sets, 

and the typically larger, vertically integrated firms in the Integrated firms set. Accordingly, what are more 

significant in this comparison are the differences in the profile of change over time in the margin values 

for the groups of firms. The UOG and Other OGE firms’ operating margin declined slightly between 

2005 and 2014, while operating margin for the Integrated firms increased slightly during the same period. 

Operating margin for both the UOG and Integrated firms sets declined in 2015. Notably, the UOG firms

and Integrated firms sets19 showed substantial declines in operating margin between 2014 and 2015, 

reflecting the substantial and rapid declines in crude oil and natural gas prices. In Figure 5-4, all but the

10th percentile operating margins show an overall decrease through 2014, while all declined in 2015.

 19 And very likely the Other OGE firms set as well, if sufficient 2015 data were available to characterize these firms’ 

performance.
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 33

Figure 5-3: Operating Margin (Median) for UOG, Integrated, and Other OGE Firms

Sources: Value Line 2005-2015; EPA analysis

Figure 5-4: Operating Margin for UOG Firms

Sources: Value Line 2005-2015; EPA analysis
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 34

5.3 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 5-5, the UOG firms had a higher net profit margin than Integrated and Other OGE 

firms throughout the analysis period. Again, this difference in net income margin is due to differences in 

the business models of the firm sets: what are more important in this information are the profiles of 

change in net profit margin over time. From 2005 to 2014, net profit margin declined for all three sets of 

firms, with the declines in the UOG and Other OGE firms set much larger than for the Integrated firms. 

This difference likely results from UOG and Other OGE firms’ business areas being more affected by 

price swings, while the Integrated firms have a business presence in all three major segments of OGE –

production, refining, and distribution and sales – allowing greater stability of overall financial 

performance, given, for example, the opportunity for reduced prices and margins in upstream (E&P) 

operations to be offset by the improved margins in refining and sales from lower crude prices. 

Figure 5-6 provides the median, 10th percentile and 90th percentile, and revenue-weighted average for net 

profit margin of UOG firms. Over the period of analysis, all measures showed declines in net profit 

margin, with the largest declines occurring following the economic downturn in 2009 and in 2015. 

Figure 5-5: Net Profit Margin (Median) for UOG, Integrated, and Other OGE Firms

Sources: Value Line 2005-2015; EPA analysis
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 35

Figure 5-6: Net Profit Margin for UOG Firms

Sources: Value Line 2005-2015; EPA analysis

5.4 Return on Total Capital

As defined in Value Line, return on total capital is net profit plus one-half the interest charges on longterm debt20 divided by total capital and indicates the financial performance of a firm in generating income 

from its business assets. This measure of return on total capital assesses asset productivity independent of 

financial structure. 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 crude 

oil and natural 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., crude oil and 

natural gas reserves) in the ordinary course of business. 

UOG firms, Integrated firms, and Other OGE firms had similar trends in returns on total capital 

throughout the period (Figure 5-7). The return on total capital for Integrated firms was higher than that 

for the UOG firms throughout the period, especially in the period 2005-2008. However, all three groups

experienced declines in return on total capital over the analysis period. Nevertheless, the weaker 

performance of all three segments, and the sharp decline, in particular, for the UOG firms suggests greater 

financing challenges, near-term. Increasing general interest rates would add to this challenge.

As shown in Figure 5-8, UOG firms experienced declines in return on total capital between 2005 and 

2015. 

 20 Adding back one-half of interest expense to net income is an approximate adjustment for the tax treatment of interest, and 

restates net income (after-tax) to a pre-interest basis. 
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 36

Figure 5-7: Return on Total Capital (Median) for UOG, Integrated and Other OGE Firms

Sources: Value Line 2005-2015; EPA analysis

Figure 5-8: Return on Total Capital for UOG Firms

Sources: Value Line 2005-2015; EPA analysis

5.5 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 
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 37

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 5-9, overall, the median value of the debt to total assets ratio for all three firm sets 

increased from 2005 to 2014. This likely reflects, at least in part, the unusually low interest rates present 

since the beginning of the severe recession in the last decade, and OGE firms’ desire to finance resource 

development and capital outlays, generally, via low-cost debt instead of more expensive equity. The debt 

to total assets ratio is consistently higher for UOG firms than Integrated firms, but is lower than Other 

OGE firms. Figure 5-10 shows an overall increase in the long-term debt to total assets measure for UOG 

firms from 2005 to 2014: between 2010 and 2014, the debt to asset ratio for UOG firms increased by over 

30 percent. These relatively high debt to total asset values expose the UOG and Other OGE industry 

segments to greater risk of volatile and declining cash flow and net income. Given creditors’ realization 

of the financial risk present in these firms because of recently increased volatility of, and decline in, 

resource prices, the firms in these segments may experience significant challenges in financing new 

resource development programs. 

Figure 5-9: Long-Term Debt to Total Assets (Median) for UOG, Integrated, and Other OGE Firms

Sources: Value Line 2005-2015; EPA analysis
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 38

Figure 5-10: Long-Term Debt to Total Assets for UOG Firms

Sources: Value Line 2005-2015; EPA analysis

5.6 Total Capital Spending

The total capital spending metric represents annual outlays for plant and equipment, including, for the 

crude oil and natural gas E&P segments, outlays for exploration, development, and production. This 

metric is important for the UOG firms set as it indicates the extent to which firms are investing in UOG 

exploration and production. EPA developed the total capital spending metric by multiplying capital 

spending per share by average shares outstanding for each reporting year. In the same way as for 

revenue, EPA then calculated the year-to-year percentage change. 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. 

Figure 5-11 reports the median values of the total capital spending year-to-year percentage change for 

UOG firms, Integrated firms, and Other OGE firms. All three sets of firms had almost identical patterns 

of change in 2006 and 2007. Beginning in 2008, however, UOG firms and Other OGE firms had much 

bigger variations in total capital spending. From 2007 to 2008 and 2009 to 2011, UOG firms and Other 

OGE firms had higher rates of growth in total capital spending than Integrated firms; these two groups 

also had bigger decreases in spending from 2008-2009. In addition, outlays for both sets of firms declined 

in 2013, while total capital spending continued to increase for Integrated firms, though at a smaller pace 

than in 2012. It can be expected that capital spending will decrease in 2015 relative to 2014. Many firms 

announced cuts in capital budgets in early 2015 (EY, 2015a). The divergence and substantial increase in 

UOG and Other OGE firms’ outlays beginning in 2006 coincides with the period in which shale gas and 

other UOG development began strong growth. At least in part, the divergence in the outlay patterns for 
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 39

UOG and Other OGE21 firms compared to Integrated firms reflects this substantial increase in exploration 

and production activity for shale gas. This strong growth in total capital outlays through 2014 for the 

UOG firms confirms the assessment by these firms of the favorable outlook for unconventional oil and 

gas exploration and production. However, this data series omits data for 2015, which would very likely 

show a different near-term profile, with declining capital outlays due to reduced product prices and 

constrained and more expensive access to financing for new UOG projects.

Figure 5-12 provides the median, 10th percentile and 90th percentile, and average for total capital spending 

for UOG firms. From 2003 to 2014, total capital outlays increased each year by a substantial multiple for 

the median and average values, and even more so for the 90th percentile value, except for declines in 2009 

and 2013. The 10th percentile value showed declining capital spending for most of the period. Again, as 

described above, the data series does not include 2015; capital spending can be expected to decrease from 

2014-2015 for UOG firms. 

Figure 5-11: Total Capital Spending, Year-to-Year Percent Change (Median) for UOG, Integrated, 

and Other OGE firms

Sources: Value Line 2005-2015; EPA analysis

 21 Even though the Other OGE firms do not have as strong a participation in UOG activity as the UOG firms, they, almost 

undoubtedly, are participating in UOG activity, as UOG has become the primary growth segment of O&G resource 

development over the past 10 years. 
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 40

Figure 5-12: Total Capital Spending, Year-to-Year Percent Change for UOG Firms

Sources: Value Line 2005-2015; EPA analysis

5.7 Summary

UOG firms and Integrated firms differ in several ways (e.g., structural differences in the business models, 

production profiles of unconventional versus conventional wells, required financing) that result in 

differences in financial performance and outlook. 

Except for the recession year of 2009, between 2005 and 2014, the UOG segment22 of the oil and gas 

industry showed generally favorable financial performance with increasing revenue, substantial operating 

and net profit margins and return on capital, and sustained growth in capital outlays. Increased production 

supported by accessibility to unconventional resources with new technology, higher prices, and a 

beneficial financing environment – low interest rates and willingness of providers of capital to support 

increasing reliance on debt – facilitated substantial growth and strong financial performance for the UOG

segment. However, the substantial decline in crude oil prices beginning mid-2014 has severely affected 

the UOG segment, in particular in relation to the Integrated industry segment. 

Over the analysis period, all segments of the crude oil and natural gas industry showed a similar profile of 

revenue growth. However, between 2012 and 2014, the profiles diverged with UOG and Other OGE firms

reporting stronger revenue growth than Integrated firms. This divergence and faster growth likely result 

from the substantial increase in production allowed by new technology that increased access to 

 22 And the Other OGE segment, which though not as reliant on UOG activity, is also considerably involved in unconventional 

resource development. 
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 41

unconventional O&G resources. In addition, crude oil prices also continued to grow strongly during this 

period and natural gas prices broke their declining trend during these years. UOG and Other OGE firms

benefitted from the combination of increased production and increasing prices. In the following year, 

2015, though, the fall in revenue growth is much greater for UOG firms than for Integrated firms. In this 

case, the rapid decline in crude oil prices affected the UOG firms23 more adversely as they lack the buffer 

from downstream operations. With refined product prices falling less than crude oil prices, refiners 

(including the downstream refining segments of integrated firms) have actually seen increasing margins 

(Martén et al, 2015). The very substantial fall in revenue growth for UOG firms (19 percent growth in 

2014 to 34 percent decline in 2015) marks a considerable break in their largely favorable performance 

over the analysis period.

Other financial metrics show a similar profile, with favorable performance prior to 2014, but with 

substantial adverse impact on the UOG segment due to the decline in crude oil prices. Operating margin, 

net profit margin, and return on capital all declined markedly between 2014 and 2015, with declines for 

the UOG segment exceeding the decline for the Integrated segment. At the same time, UOG (and Other 

OGE) firms increasingly relied on debt for financing resource development over this period. Given the 

unusually low interest rates prevailing since 2009, the ability to rely on low cost debt is favorable in 

supporting capital outlays and resource development at a lower cost of financial capital. The availability 

of lower cost debt financing, and willingness of creditors to finance UOG and Other OGE firms at higher 

debt levels, facilitated the substantial increases in capital outlays by these segments and the associated 

increase in UOG resource development since 2010. However, the increased financial leverage exposes the 

UOG and Other OGE firms to greater financial risk from the crude oil price-related revenue decline that 

began in 2014. With debt and equity investors less willing to finance unconventional resource 

development at the same levels and at as favorable of terms as in prior years, UOG and Other OGE firms

will likely be unable to continue resource development at the same pace as in recent years. 

Apart from the financial issues affecting UOG and Other OGE firms’ ability to continue UOG resource 

development at the previous pace, UOG production characteristics and the associated need for ongoing 

investment compound the near-term challenge. UOG production is characterized by achieving peak 

production rates in the first month after well completion, followed by a sharp decline: UOG production 

rates fall by as much as 79 percent in the first 12 months of production (Hughes, 2013). This differs 

substantially from the production profile of conventional oil and gas resources, which build up production 

rates over the course of several years, produce at a plateau for several more years, then decline, at a much 

lower rate (estimates range from 5-10 percent per year) (IHS 2008). UOG firms must therefore 

continuously invest in drilling new wells and/or new laterals, or in refracturing of existing wells, in order 

to maintain or increase production in the short term. This requires a steady flow of capital outlays to 

support production. Cash flows generated near the beginning of unconventional production must be 

immediately reinvested to fund more drilling and/or new capital acquired, to ensure production and cash 

flows in the next period. UOG firms are therefore more susceptible to changes in crude oil and natural gas 

prices. Declines in prices affect not only the current period’s revenues, but also the revenues in 

subsequent periods, due to the inability of firms to invest in new wells (EY, 2014).

The preceding reviews of financial performance and condition metrics indicate a recent deterioration in 

financial performance and condition for OGE firms since mid-2014 due to the fall in crude oil and natural 

gas prices. While Integrated firms are generally better positioned to weather low prices, they have not 

been immune to falling prices and the resulting impact on revenue, cash flow, and general financial 

performance. The prediction of slow price recovery indicates that the financial condition of OGE firms in 

 23 And probably the Other OGE firms, for which data are not yet available.
Profile of the Unconventional Oil and Gas Industry 5: Financial Performance and Condition

June 2016 42

general, and UOG firms in particular, may not recover in the short term. As discussed in Section 3.4, OGE 

firms will likely face tightened access to capital due to reduced cash flows and asset values, which will, as 

just discussed, more adversely impact UOG firms, which need capital in the short-term to fund resource 

development. The more financially vulnerable UOG and Other OGE firms are also expected to increase 

asset sales over the next few months, and M&A activity is likely to accelerate in 2016.
Profile of the Unconventional Oil and Gas Industry 6: Outlook for UOG Exploration and Production Activity

June 2016 43

6 Outlook for UOG Exploration and Production Activity

Key findings from this profile are summarized below:

 Natural gas production has increased substantially since 2005 due to shale gas; crude oil 

production has increased substantially since 2008 due to tight oil and shale oil. 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. In 2009, shale gas became the third largest source for natural gas production and by 

2011 became the number one source of U.S. production (U.S. DOE, 2013). Likewise, between 

2008 and 2015, tight and shale oil production grew almost ten times. According to EIA, in 2013, 

tight and shale oil and shale gas accounted for 42 percent of total U.S. crude oil production and 

46 percent of total U.S. natural gas production, respectively (U.S. DOE, 2015a).

 Increased production has led to reduced crude oil and natural gas prices, increased exports, 

and lower imports. The United States is expected to be energy independent by 2029. The 

substantial increase in production over the last decade, especially since 2008, has caused crude oil 

prices to fall considerably since the summer of 2014. Prices are expected to recover slowly. 

November EIA projections have WTI prices at $52/bbl in 2016, Brent prices at $56/bbl, and 

Henry Hub prices at $3.00/mmBtu. The IEA, Standard and Poor’s, and Deloitte have similar price 

forecasts, indicating a slow recovery of crude oil prices (see Sections 3.1.2 and 3.1.3). The greater 

than 50 percent fall in crude oil prices since June 2014, along with low natural gas prices, has had 

significant adverse effects on OGE firms in general, and UOG firms in particular.

 The financial performance and condition of OGE firms, generally, and UOG firms, 

specifically, have declined considerably over the past year, and may not improve materially 

in the near term. Cash flows at OGE firms are falling, and lenders are beginning to pressure 

firms to raise cash and reduce reliance on debt in the overall capital structure. This is expected to 

lead to asset sales, perhaps at depressed prices, and M&A activity is likely to increase going into 

2016. Because of the generally shorter, and more front-loaded production profiles for crude oil 

and natural gas produced from shale and tight formations compared to production from 

conventional formations, UOG production requires a more continuous capital outlay to prevent 

rapid declines in production and cash flow: UOG firms must continuously reinvest cash from the 

current period into drilling wells in order to maintain production and cash flows in the next 

period. Given the relatively high and increasing reliance of UOG on debt financing, these factors 

make UOG firms’ financial performance particularly susceptible to price declines. UOG firms 

also do not have the downstream refining and retail sales buffer that integrated firms do. While 

integrated firms and larger, more strongly financed firms, generally, are in a better position to 

weather this period of low prices, they have not been immune to the adverse effects of the fall in 

crude oil prices. The nature of UOG production and the financial structure of UOG firms, along 

with the slow price recovery that is predicted, make it possible that the financial performance and 

condition of UOG firms will not improve substantially, and may deteriorate further, in the short 

term. Creditors and equity investors view UOG prospects less optimistically than as recently as 

2013, and are less willing to provide financing for ongoing and future UOG resource 

development.

 The long term outlook is more favorable for UOG development and production. Though 

price volatility is expected to remain high going into 2016, crude oil and natural gas prices are 

forecast to increase through 2040 (U.S. DOE, 2015a). And while many factors will affect further 

UOG development, and forecasts inevitably involve considerable uncertainty, production is 
Profile of the Unconventional Oil and Gas Industry 6: Outlook for UOG Exploration and Production Activity

June 2016 44

expected to continue to increase. Growth in UOG activities depends on the production profile of 

individual wells, the cost of drilling and operating the wells, and the revenue generated. One 

measure of long-term viability of domestic production is the remaining technically recoverable 

resources (TRR), or the amount of crude oil and natural gas that can still be produced given 

current technology and practices. Table 6-1 shows crude oil and natural gas TRR by basin and 

formation, as well as estimated ultimate recovery (EUR). EUR is a measure of the total amount of 

crude oil and natural gas likely to be produced from a formation over its entire productive life. 

Unconventional oil and gas production continues to move into areas with little production history, 

making estimating TRR difficult. However, this data show the potential for substantial additional 

UOG production. EIA forecasts that by 2040, shale gas will account for 55 percent of U.S. natural 

gas production, with tight gas as the second leading source at 22 percent. Production of tight and 

shale 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 and shale oil will account for 45 percent of total U.S. oil production (U.S. 

DOE, 2015a). This increased production is projected to lead to lower net imports, resulting in the 

United States achieving energy independence by 2029 (U.S. DOE, 2015a).

Table 6-1: UOG Formation Potential as of January 1, 2013

EIA Basin UOG Formation Name

Resource 

Type

Oil EUR 

(MMbls per 

well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(Bbls)

Gas TRR 

(Tcf)

Area with 

Potential 

(mi2)

Appalachian

Clinton-Medina Tight gas 0.002 0.058 0.4 12.4 26,907

Devonian Shale gas 0.000 0.061 0.0 23.7 51,842

Marcellus Shale gas 0.003 2.475 0.3 148.7 20,757

Tuscarora Tight gas 0.000 0.724 0.0 4.4 765

Utica Shale gas 0.004 1.45 0.2 53.1 26,460

Shale oil 0.091 0.223 0.7 1.5 6,161

Illinois New Albany Shale gas 0.000 1.188 0.0 29.1 3,059

Michigan Antrim Shale gas 0.000 0.120 0.0 12.7 13,178

Berea Sand Tight gas 0.000 0.110 0.0 6.6 7,451

Black Warrior Floyd-Neal/Conasauga Shale gas 0.000 1.520 0.0 4.3 1,402

TX-LA-MS Salt Cotton Valley Tight gas 0.008 1.323 0.8 139.3 8,773

Haynesville-Bossier Shale gas 0.003 7.014 0.0 73.3 3,404

Western Gulf

Austin Chalk Tight oil 0.12 0.33 5.5 10.4 12,438

Buda Tight oil 0.059 0.109 2.0 3.8 8,640

Eagle Ford Shale gas 0.090 1.473 1.1 18.4 2,085

Shale oil 0.373 1.643 9.2 37 8,476

Olmos Tight gas 0.008 1.162 0.2 25.4 5,463

Pearsall Shale gas 0.001 0.676 0.0 4.9 1,196

Tuscaloosa Shale oil 0.107 0.021 3.2 0.6 7,448

Vicksburg Tight gas 0.026 0.980 0.1 2.6 329

Wilcox Lobo Tight gas 0.000 1.403 0.0 12.8 1,142

Woodbine Shale oil 0.120 0.061 0.6 0.3 1,222

Anadarko

Cana Woodford Shale gas 0.023 1.995 0.1 5.9 737

Shale oil 0.057 2.271 0.2 8.3 1,528

Cleveland Tight gas 0.048 0.384 0.1 1.0 639

Granite Wash Tight gas 0.040 0.579 0.6 8.8 3,788

Red Fork Tight gas 0.019 0.459 0.0 0.9 513

Arkoma

Caney Shale gas 0.000 0.973 0.0 3.1 797

Fayetteville Shale gas 0.000 1.673 0.0 20.4 2,838

Woodford Shale gas 0.003 1.342 0.0 6.3 591

Black Warrior Chattanooga Shale gas 0.000 0.968 0.0 1.6 205

Fort Worth Barnett Shale gas 0.011 2.242 0.2 17.5 7,342

Permian

Abo Tight gas 0.067 0.149 0.7 1.5 2,540

Avalon/Bone Spring Shale oil 0.118 0.367 2.9 9.0 5,444

Barnett-Woodford Shale gas 0.000 1.181 0.0 12.4 2,618
Profile of the Unconventional Oil and Gas Industry 6: Outlook for UOG Exploration and Production Activity

June 2016 45

Table 6-1: UOG Formation Potential as of January 1, 2013

EIA Basin UOG Formation Name

Resource 

Type

Oil EUR 

(MMbls per 

well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(Bbls)

Gas TRR 

(Tcf)

Area with 

Potential 

(mi2)

Canyon Tight gas 0.016 0.209 0.9 10.9 6,482

Spraberry Tight oil 0.131 0.152 10.6 12.3 12,209

Wolfcamp Shale oil 0.085 0.347 6.1 24.9 17,560

Denver Muddy Tight gas 0.001 0.180 0.1 11.5 3,999

Niobrara Shale oil 0.013 0.078 0.4 2.7 6,985

Greater Green 

River

Hilliard-Baxter-Mancos Shale gas 0.000 0.293 0.0 10.5 4,477

All tight oil plays Tight oil 0.105 0.014 0.9 0.1 1,452

Montana Thrust 

Belt All tight oil plays Shale oil 0.100 0.068 0.6 0.4 2,630

North Central 

Montana Bowdoin-Greenhorn Tight gas 0.000 0.068 0.6 0.4 461

Paradox Fractured Interbed Tight oil 0.534 0.427 1.0 0.8 1,171

Powder River All tight oil plays Shale oil 0.035 0.040 2.1 2.4 19,464

San Juan

Dakota Tight gas 0.002 0.258 0.0 3.8 1,819

Lewis Shale gas 0.000 2.200 0.0 9.8 1,481

Mesaverde Tight gas 0.002 0.548 0.0 6.8 1,036

Pictured Cliffs Tight gas 0.000 0.262 0.0 0.1 101

Southwestern 

Wyoming

Fort Union – Fox Hills Tight gas 0.010 0.792 0.1 12.0 1,888

Frontier Tight gas 0.017 0.312 0.4 7.1 2,827

Lance Tight gas 0.020 1.152 0.4 21.2 2,297

Lewis Tight gas 0.006 0.312 0.2 9.7 3,885

Tight Oil Plays Tight oil 0.108 0.014 1.1 0.1 1,730

Uinta-Piceance

Iles-Mesaverde Tight gas 0.001 0.372 0.0 11.9 3,997

Mancos Shale gas 0.000 0.752 0.0 9.3 1,553

Tight Oil Plays Tight oil 0.047 0.105 0.1 0.2 91

Wasatch-Mesaverde Tight gas 0.030 0.568 0.5 9.8 2,161

Williams Fork Tight gas 0.004 0.692 0.1 11.2 1,619

Williston

Bakken Shale oil 1.052 1.28 22.8 23.3 44,017

Gammon Shale gas 0.000 0.433 0.0 3.3 3,836

Judith River-Eagle Tight gas 0.000 0.154 0.0 0.9 1,449

Wind River Fort Union-Lance Tight gas 0.018 1.131 0.1 6.4 709

Columbia Basin Centered Shale gas 0.000 1.620 0.0 12.2 943

San Joaquin/Los 

Angeles Monterey/Santos Shale oil 0.028 0.151 0.6 3.0 3,141

Sources: U.S. EPA, 2016; U.S. DOE, 2015b

 For purposes of this rulemaking, these key findings are not expected to change the economic 

achievability of the industry to meet a zero discharge standard. EPA has no data of a facility that 

does not use the zero discharge technology. Therefore, EPA determined that facilities can afford a 

technology to meet the zero discharge standard. Since facilities are already meeting a zero 

discharge standard, EPA’s regulation will impose no additional cost. EPA also has no data to 

suggest that the zero discharge technology will be a barrier to entry because all facilities already 

meet the zero discharge standard and new facilities would likewise be able to meet this standard 

at no cost disadvantage to existing facilities.
Profile of the Unconventional Oil and Gas Industry 7: References

June 2016 46

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