United States Office of Water EPA

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Environmental Protection Washington, DC 20460 June 201 6 Agency



# Profile of the
Unconventional Oil and Gas Industry

# Profile of the Unconventional Oil and Gas Industry

EPA

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June 2016

U.S. Environmental Protection Agency Office of Water (4303T) Engineering and Analysis Division 1200 Pennsylvania Avenue, NW Washington, DC 20460Profile 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 pro cess 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 Natura l 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 an d 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

................................ ................................ ................................ ................................ ....... 46Profile 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 Segment a

................................ .. 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

................................ ................................ ....... 44Profile 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 UO G, Integrated, and

Other OGE firms

................................ ................................ ................................ ................................ . 39 Figure 5

- 12: Total Capital Spending, Year

- to

- Year Percent Change for UOG Firms

................................ 40Profile 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 Informa tion 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 acq uisition 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 IndexProfile 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 pr oduction, 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 subs tantially 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 fro m the current (May 2016 ) price of approximately $ 44 /bbl for WTI, $ 44 /bbl for Brent, and $2 /mmBtu for Henry Hub

. May

201 6 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.

 A fter 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, c ash

flows at OGE firms , generally, and UOG firms, specifically

, are falling in line with the declining prices since 2014. As a result, lenders are pressur ing 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 i ncrease 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 forecas t to increase through 2040 . Shale gas production is ex pected 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 dat a of a facility that does not use the zero discharge technology. Therefore, EPA determined that facilit ies can afford a technology to meet the zero discharge standard. Since facilities are already meeting a zero discharge standard

, EPA’s regulation will

im pose no additional cost. EPA also has no data to suggest that the zero discharge technology will be aProfile 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 cos t disadvantage to existing facilities

.Profile of the Unc onventional 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 t hese advanced drilling and production techniques

, coupled with large crude oil

and natural gas reserves in shale and other un conventional 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 201 5 Annual Energy Outlook ( AEO2015 ) published by the Energy Information Administration of the Department of Energy , natural gas production is expected to increase by 4 5 percent by 2040

, compared to 2013 production levels

. 1 EIA expects lower

- 48 s hale gas production to increase 73
percent by 2040 . Tight gas producti on, 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 (NGL s ) from tight and shale oil form ations

. 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 prod uction 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 calculat ed this number from Appendix A) ( U.S. DOE, 2015 a ).
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,

a s 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, t he Natural Gas Liquid Extraction

1 All AEO201 5 projections referred to in this document are for the R eference C ase 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 “shal e gas.”

3 NGL s include a wide range of components produced during natural gas processing and petroleum refining. NGL s include ethane, propane, normal butane (n

- butane), isobutane, and pentanes plus.Profile of the Unc onventional 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

. T herefore

, 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 petro leum 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
Source s : U.S. DOC 2012Profile 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 o il 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 pric es 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

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

and shale oil formations. Due to this increase d 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 inte rnational (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 ch anging the import/export dynamics in the region and further reducing

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

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 200 8. Since 2008, domestic crude oil production has increased except for a small period of decline in the first quarter of 2015. B etween 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 producti on has declined since 2000 but remains 11 percent of total domestic production. The biggest fraction of production comes from PADD 3: Gulf Coast, which a ccounted 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

pr oduction 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 accou nted 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). T he 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 m ostly 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)

Source s : U.S. DOE 2015m 0 5 10 15 20 25200020012002200320042005200620072008200920102011201220132014 PADD 5: West Coast

PADD 4: Rocky Mountain

PADD 3: Gulf Coast

PADD 2: Midwest

PADD 1: East CoastProfile 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 (M M bpd)

Source s : 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 specifi c 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 o f 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 fall en. WTI prices peaked at $ 105.79/bbl before falling to $ 42.87/bbl in

A ugust 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/bb l, 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, pea king at $ 111.80/bbl in June 2 014. Brent prices fell to $ 46.58/bbl in August

2015 be fo re 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 near

perfect 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 th e 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 oi l 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 )

Source s : 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 reflect s 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 quar ter 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 stock s . Consumption in this context represents the t otal 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 to tal 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 $120Dollars per barrel Europe Brent Spot Price FOB

WTI Spot Price FOBProfile 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 p roduction 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.

Source s : 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 2015Quadrillion Btu

Net Imports of Crude Oil Imports of Crude Oil Exports of Crude OilProfile 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.

Source s : 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

declin ing through September 2016 before increasing again. Th is production decline can be attri buted 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 Niobr ara formation s 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 depen d on wellhead prices and region

- and formation

- specific economics ( U.S. DOE, 2015j ).

Demand should begin to grow faster than supply in 2016 (Delo itte, 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 4020002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015Quadrillion Btu

Imports of Crude Oil Production of Crude Oil Less Exports of Crude Oil Less Crude Oil Stock ChangeProfile 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 pric e 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 non

OPEC 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 traded 5 with Mexico ( U.S. DOE, 2015c ). Under this relaxation, the U.S. will send light crude oil (which is being produc ed in larger quantities due to tight and shale oil produc tion) 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 refineri es were built to process light crude o il. However,

recent Mexican production h as tended toward heavy crude oil , which its refineries are not as well

equipped 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 ex pected 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 t o 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 sho uld 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 domest ic crude oil production. This share is expected to increase to 53 percent of total dome stic 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 vola tility 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 pric es 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 scen ario, 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

stabl e 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 subs tantially 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 formations 6 ) , especially in the Marcellus Shale formation

– which has more t han 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 Pr oduction, 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 Un ited 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 do mestic natural gas production has set a new record. This higher production result s from (1) increased drilling efficiencies; (2) improving completion technology and practices; (3) decreased drilling costs; (4) a focus on high output areas; (5) continued he dging contracts 8 ; 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 market ed 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

- dissolve d 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 f ield and processing plant operations).”

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

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

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 calc ulated annual equivalent values for each quarter beginning in 2014 by multiplying the total marketed production for each quarter by four.

Source s : U.S. DOE 2015i

The increase in marketed production since 2008 corresponds to increasing unconventional natu ral gas production. Figure 3

- 7 shows U.S. dry 9 shale gas production. Like tight and shale oil production, dry shale gas production has significantly i ncreased 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 s hale 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 investment s 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 201 5

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

but has increas ed 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 jus t 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 col d winter 0 5 10 15 20 25 30 35Quadrillion Btu Total U.S.

PADD 5: West Coast

PADD 4: Rocky Mountain

PADD 3: Gulf Coast

PADD 2: Midwest

PADD 1: East CoastProfile 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 p lant 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 to tal), 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)

Source s : 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'Profile of the Unconventional Oil and Gas Industry 3 : Overview of Crude Oil and Natural Gas and the U.S. Economy

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.

Source s : 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 per cent 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

dec lined in 2014 but remain ed 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 Ca nada, resulting in declining total exports. Overall since 2007, net imports have declined 78 percent. 0 5 10 15 20 25 30 3520002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015Quadrillion Btu

Annual Natural Gas Marketed Production Less Exports Annual Natural Gas ImportsProfile of the Unconventional Oil and Gas Industry 3 : Overview of Crude Oil and Natural Gas and the U.S. Economy

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.

Source s : U.S. DOE 2015t, 2015u, 2015v

Figure 3

- 10 shows the Henry Hub price from 2000 to the third quarter of 2015. Declines sinc e 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 3020002001200120022003200320042005200520062007200720082009200920102011201120122013201320142015Quadrillion Btu

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

June 2016 17 Figure 3

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

Source s : 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 prod ucers 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 S tates 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 liquefie d 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 a ddition, 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 o f 2016. Low prices have supported increased domestic natural gas consumption. C onsumption 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 b y 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 $10Dollars per Million BtuProfile 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

pro duction 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, compar ed 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 2 7 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 pr ices, 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 valu e 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

ac tual 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 201 5 . Between 2002 and 2005, real output in the overall OGE industry (NA ICS 21111) fell every year but increased steadily after that, showing large increase s from 2012 to 2014. Overall, during the 1 6

- year period of 2000 through 201 5 , 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 simila r 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 Segment a

Oil and Gas Extraction (NAICS 211 11 ) Crude Petro leum and Natural Gas Extraction (NAICS 211111) Natural Gas Liquid Extraction (NAICS 211112)
Year Index 20 12 =100 % Change Index 20 12 =100 % Change Index 20 12 =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%
2015 b 135.58 7.3% 135.95 7.3% 126.91 6.9%
2000

- 201 5 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

20 12 ; therefore, this index shows how much production occurred in a given year relative to the production that occurred in 20 12

. Real output in this case represents quan tity, not the actual value of the dollar, and of goods and services made. b. IPI for 2015 reflects data through the first three quarters.
Source s : 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 producti on 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 be ginning 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 cost 12 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 20 15 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 lev el of price protection as the older hedge positions expire

. In addition, these p rotections 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 20 16 , 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

pr oduction 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 ye ar 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 consolidat e (Deloitte , 2015a ).

In addition, a large number of wells have been drilled but u ncompleted (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 impr ove 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.

N atural 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 Deloitt e 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 s egments : 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

T he 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, t he 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 und er 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 pa yroll 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 Ga s 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 p hysical 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 Pe troleum 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 Petro leum 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 Petro leum 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 Extr action 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 least 14 9 8.5
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 incre ased 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

- 20 12 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 ana lysis 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

e mployment 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 du ring 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 occupatio ns 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; e xecutive 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, ind ustrial 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

– 20 12 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 201 2

, Oil and Gas Extractio n sector firms employed, on average, 1 9 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 1 8 and

7 3 , respectively.



### 4.4 Revenue and Payroll in the OGE Industry Segments

R evenue and payroll d ata from the Economic Census for years 1997, 2 002, 2007 , and 2012 als o can provide insight into the effects of changing business conditions on the overall Oil and Gas Extractio n sector and its two segments throughout the period of analysis. As reported in Table 4

- 5 , b etween 1997
and 2012 , the overall Oil and Gas Extractio n sector grew in revenue, annual payroll

, and revenue less payroll. Likewise, the Crude Petroleum and Natural Gas Extraction and Natur al Gas Liquid Extraction
segments experienced increases in all three metrics during that time, despite declines in 2002.

Table 4

- 5 also displays avera ge revenue per company (calculated as total revenues for the industry divided by the number of companies). For both the overall Oil and Gas Extractio n sector and the CrudeProfile 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 segme nts, average revenue values for the Natural Gas Liquid

Extraction segment are significantly higher than those in the Oil and Gas Extractio n sector; one explanation of this difference is that while total revenues for the Oil and Gas Extractio n 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 20 12 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%

Sou rces: U.S. DOC, 1997, 2002, 2007 , 2012



### 4.5 Capacity Utilization

Capacit y 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. B etween 2005 and 201 4

, capacity utilization overall increased steadily to 99.5 percent

, except for a mild decline in 2008 , and agai n 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 pr oduction of domestic crude oil since 2008. Between theProfile 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 211 11 )

Source s: FRS, 201 5 a



### 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 p oint 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 t he potential for imports to enter domestic supply channels and displace domestic production if

a nd 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 Pric ing 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 a re 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 OPECProfile 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 a t 12 (Arthur et al, 2014)

. I n 20 14

, 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 worl d 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 producer s like Exxon Mobil, have relatively smaller reserves and have no influence over price ( Grant et al, 20 06 ). 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 U nited S tates is also one of the largest crude oil produc ers , it remains a major importer of crude oil ; as a result the level of U.S. imports can sign ificantly infl uence 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 nat ural 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 pro ducers, natural gas producers have relatively small reserves with no influence over price. 15 Therefore, n atural gas producers also tend to be price takers.

Natural gas prices are determined by a combination of national and regional market factors. A “ gener al ” 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 g a s 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 th at 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 fro m 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 n atural gas from the point of production to market. For the s e reason s , shipment rates for interstate natural gas pipelines require approval from the U.S. Federal Ener gy 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 l onger 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 leadin g to falling prices, which may a gain 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 nat ural 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 r elatively 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 y ear. 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 continu ed to purchase U.S. properties, showing i nterest 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 s trengthen 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 r estructuring 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 r ecovery, 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, 2015 a ).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, EP A 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 tha t is more specifically focused on UOG activities.

Overall economic conditions affect d emand 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 inc rease 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

m

ust 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 assess ing 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 c apital 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 the se selected performance metrics over the past 1 1 years ( 200 5

- 201 5 ) for selected public reporting firms in the OGE industry. The firms in the analysis are U.S. firms reported by V alue 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 th e Market Vectors Global Unconv entional 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 defi ned 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 defi ned above for this analysis

. The objective in developing the UOG f irm 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 (Cr ooks, 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 internationa l, 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 F irms dataset
capture s 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 se gments of refining , distribution, and sales

. To develop the financial

- indicator metrics reported below, EPA assembled data for the firms for the 1 1

- year period of 200 5 through 201 5 from the source s listed above

. In developing data for this analysis, EPA

s orted firms according to their business activities, as described above: UOG F irm s, Integrated Firm s , and
Other OGE F irms

. In total

, 4 0 firms are in the final UOG F irms set

, 30 firms are in the Integrated Firms

set, and 1 43 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 firm s, years, and metrics

. Four of the six metri cs

– 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 v alues 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 an a lysis

. 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 include d two charts for each metric. The firs t 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 thr ee sets . This understanding i s 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 firmsProfile of the Unconventional Oil and Gas Industry 5 : Financial Performance and Conditio n

June 2016 31 only

, presents the median, 10 th percentile and 90 th percen tile 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 f irm set.



### 5.1 Revenue

R evenue 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 reve nue.

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 200 5 and 2008 before declin ing in 2009 at the time of the

recent recession

. Beginning in 20 1 0, 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 segmen ts of integrated firms) have seen increasing margins.

W ithin UOG firms, t he 90 th percentile revenue index , which can be seen in Figure 5

- 2

, grew at a much higher rate , especially between 2007 and 2008

, compared to Integrate d and Other OGE firms

. The 10 th
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

Source s : Value Line 2005

- 2015 ; EPA analysis

18 Values for 2015 reflect partial year values (typically through 3 rd 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, o perating m argin 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 set s , and the typically larger, vertically integrated firms in the Integrated firms set. Accordingly, what are more

s ignificant 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 t he same period

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

and Integrated firms sets 19 showed substantial declines in operating margin between 2014 and 2015, reflecting the substantial and rapid decl ines in crude oil and natural gas prices. In Figure 5

- 4

, all but the

10 th 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

Source s : Value Line 2005

- 2015 ; EPA analysis

Figure 5

- 4 : Operating Margin for UOG Firms

Source s : Value Line 2005

- 2015 ; EPA analysisProfile 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 busi ness 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 result s 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

– produc tion, 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 s ales from lower crude prices.

Figure 5

- 6 provides the median, 10 th percentile and 90 th percentile , and revenue

- weighted average for net profit margin of UOG firms . Over the period of analysis, all measures showed declines in net pro fit 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

Source s : Value Line 2005

- 2015 ; EPA analysisProfile of the Unconventional Oil and Gas Industry 5 : Financial Performance and Condition

June 2016 35 Figure 5

- 6 : Net Profit Margin for UOG Firms

Source s : Value Line 2005

- 2015 ; EPA analysis



### 5.4 Return on Total Capital

As defined in Value Line

, return on t otal c apital is net profit plus one

- half the interest charges on long

term debt 20 divided by total capital and indicates the financial performance of a firm in generating income

from its business assets

. This measure of r eturn on t otal c apital assesses asset productivity independent of

financial structure . If individ ual 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 a bility to invest in new assets, which for th e OGE industry is ne w 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

natura l 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 )

. T he 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 gene ral interest rates would add to this challenge.

As shown in Figure 5

- 8

, UOG firms experienced decline s in return on total capital between 200 5 and

201 5

.

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

Source s : Value Line 2005

- 2015 ; EPA analysis

Figure 5

- 8 : Return on Total Capital for UOG Firms

Source s : Value Line 2005

- 2015 ; EPA analysis



### 5.5 Long

- Term Debt to Total Assets

Long

- t erm d ebt to t otal a ssets 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 l ong

- t erm d ebt to t otal

a ssets can expose a firm to a greater degree of operating financial risk as fluctuat ions in financial performance ( e.g. , operating income) will be magnified in their impact on net income due to the in comeProfile of the Unconventional Oil and Gas Industry 5 : Financial Performance and Condition

June 2016 37 leverage effect associated with high er 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 equa l, 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, l ong

- t erm d ebt to t otal a ssets is all repayment liabilities ext ending for at least one year divided by the balance sheet value for all current and long

- term assets

.
As shown in Figure 5

- 9

, o ver all

, 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 pres ent 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 hig her 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 200 5 to 201 4 : between 2010 and 2014, the debt to asset ratio for UOG firms increased by over 30 perc ent

. Th es e relatively high debt to total asset value s 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 re cently 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

Source s : Value Line 2005

- 201 5 ; EPA analysisProfile of the Unconventional Oil and Gas Industry 5 : Financial Performance an d Condition

June 2016 38 Figure 5

- 10 : Long

- Term Debt to Total Assets for UOG Firms

Source s : Value Line 2005

- 201 5 ; EPA analysis



### 5.6 Total Capital Spending

The t otal c apital s pending 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 indicate s the extent to which firms are investing in UOG exploration and production. EPA developed the t otal c apital s pending 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. Increas ing 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 t otal c apital s pending 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 i n spending from 2008

- 2009. In addition, o utlays 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 devel opment began strong growth. At least in part, the divergence in the outlay patterns forProfile of the Unconventional Oil and Gas Industry 5 : Financial Performance and Condition

June 2016 39 UOG and Other OGE 21 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 f or new UOG projects.

Figure 5

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

for UOG firms

. F rom 200 3 to 201 4, total capital outlays increased each year by a substantial multiple for the median and average values, and even more so for the 90 th percentile value , except for declines in 2009

and 2013. The 10 th 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

Source s : Value Line 2005

- 201 5 ; EPA analysis

21 Even though the Other OGE firms do not have as strong a participation in UOG activity as the UO G 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

Source s : Value Line 2005

- 201 5 ; EPA analysis



### 5.7 Summary

UOG firms and Integrated firms differ in several ways (e.g., s tructural 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 segment 22 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 resource s 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 decli ne in crude oil prices beginning mid

- 2014 has severely affected

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

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

rev enue growth . However, between 2012 and 2014, the profiles diverge d 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 consi derably involved in unconventional resource development.Profile of the Unconventional Oil and Gas Industry 5 : Financial Performance and Condition

June 2016 41 unconventional O&G resource s

. 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 I ntegrated firms . In this case, the rapid decline in crude oil prices affected the UOG firms 23 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 ( M artén 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 2 015, 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 pre vailing 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 O GE 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 y ears, UOG and Other OGE firms

will likely be un able 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 p roduction 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 year s, 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 existi ng 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 als o the revenues in subsequent periods, due to the inability of firms to inv est 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 fun d 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 Unconvention al Oil and Gas Industry 6 : Outlook for UOG Exploration and Production Activity

June 2016 43 

## 6 Outlook for UOG Exploration and Production Activity

Key fi ndings 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 beca me 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 o il production and

4 6 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 in dependent 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 price s 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 a nd 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 pr ofiles 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 decli nes in production and cash flow: UOG firms mus t 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 positio n 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 p ossible 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 w illing 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 ar e forecast to increase through 2040 ( U.S. DOE, 2015a ). And w hile many factors will affect further UOG development

, and forecasts inevitably involve considerable uncertainty, production isProfile of the Unconvention al Oil and Gas Industry 6 : Outlook for UOG Exploration and Prod uction Activity

June 2016 44 expected to continue to increase. Growth in UOG activities depends o n 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 crud e 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 co ntinues 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 5 5 percent of U.S. natural

g as 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 lowe r 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 achievi ng energy independence by 2029 ( U.S. DOE, 2015a ).

Table 6

- 1 : UOG Formation Potential as of January 1, 201 3

EIA Basin UOG Formation Name Resource Type Oil EUR (MMbls per well) Gas EUR (Bcf per

well) Oil TRR (B bls) Gas TRR (T cf) Area with
Potential

(mi 2 )

Appalachian Clinton

- Medina Tight gas 0.002 0.058 0.4 12.4 26,907
Devonian Shale gas 0.00 0 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 0.00 0 1.188 0 .0 29.1 3,059

Michigan Antrim Shale gas 0.00 0 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 0.00 0 1.52 0 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 0.00 0 0.973 0.0 3.1 797 Fayetteville Shale gas 0.00 0 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 0.00 0 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 0.11 8 0.367 2.9 9. 0 5,444

Barnett

- Woodford Shale gas 0.00 0 1.181 0 .0 12.4 2,618Profile of the Unconvention al 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, 201 3

EIA Basin UOG Formation Name Resource Type Oil EUR (MMbls per well) Gas EUR (Bcf per

well) Oil TRR (B bls) Gas TRR (T cf) Area with
Potential

(mi 2 ) 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 0.00 0 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 0.04 0 2.1 2.4 19,464

San Juan Dakota Tight gas 0.002 0.258 0.0 3.8 1,819
Lewis Shale gas 0.00 0 2.2 00 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 0.00 0 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 0.00 0 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

Source s : 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 dete rmined 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 tec hnology 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 Unconvention al Oil and Gas Industry 7 : References

June 2016 46 

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