The Fracking Revolution: Shale Gas as a Case Study in Innovation Policy

Article (PDF Available)inEmory law journal 64(4):955 · March 2015with 143 Reads
Abstract
The early twenty-first century has witnessed a boom in oil and natural gas production that promises to turn the United States into a new form of petrostate. This boom raises various questions that scholars have begun to explore, including questions of risk governance, federalism, and export policy. Relatively neglected, however, have been questions of why the technological revolution behind the boom occurred and what this revolution teaches about innovation theory and policy. The boom in U.S. shale gas production reflected long-gestating infrastructure developments, a convergence of technological advances, government-sponsored research and development, the presence or absence of intellectual property rights, rights in tangible assets such as land and minerals, and tax and regulatory relief. Consequently, the story behind the boom reaches far beyond the risk-taking and persistence of George Mitchell, whose independent production company achieved pioneering success with hydraulic fracturing (fracking) in Texas’ Barnett Shale. Indeed, the broader story demonstrates how a blend of distinct policy levers, reasonably adjusted over time, can combine to foster a diverse innovation ecosystem that provides a robust platform for game-changing innovation. As exemplified by this story, the centrality of other policy levers can mean that patents play only a modest role, even in spurring technological development by profit-driven private players. Other lessons drawn from this case study include “negative lessons” about the possibility and even likelihood of downsides of a technological boom or the policies used to promote it—for example, environmental damage that more careful regulation of a developing technology such as fracking might have avoided. Anticipatory and continuing attention to such potential downsides can help prevent innovation-promoting policies from becoming “sticky” in a way that undercuts innovation’s promise and popular appeal. Such lessons can helpfully inform efforts either to extend the United States’ “fracking revolution” abroad or to develop other potentially revolutionary technologies such as those associated with renewable energy.
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THE FRACKING REVOLUTION: SHALE GAS AS A CASE
STUDY IN INNOVATION POLICY
John M. Golden
Hannah J. Wiseman∗∗
ABSTRACT
The early twenty-first century has witnessed a boom in oil and natural gas
production that promises to turn the United States into a new form of
petrostate. This boom raises various questions that scholars have begun to
explore, including questions of risk governance, federalism, and export policy.
Relatively neglected, however, have been questions of why the technological
revolution behind the boom occurred and what this revolution teaches about
innovation theory and policy. The boom in U.S. shale gas production reflected
long-gestating infrastructure developments, a convergence of technological
advances, government-sponsored research and development, the presence or
absence of intellectual property rights, rights in tangible assets such as land
and minerals, and tax and regulatory relief. Consequently, the story behind the
boom reaches far beyond the risk-taking and persistence of George Mitchell,
whose independent production company achieved pioneering success with
hydraulic fracturing (fracking) in Texas’ Barnett Shale. Indeed, the broader
story demonstrates how a blend of distinct policy levers, reasonably adjusted
over time, can combine to foster a diverse innovation ecosystem that provides
a robust platform for game-changing innovation. As exemplified by this story,
the centrality of other policy levers can mean that patents play only a modest
role, even in spurring technological development by profit-driven private
Loomer Family Professor in Law, The University of Texas at Austin.
∗∗ Attorneys’ Title Professor, Florida State University College of Law. The authors thank Ivan Cassuto
and Nick Wenker for research assistance. For comments, they thank Michael Abramowicz, David Adelman,
Mark Ascher, Ian Ayres, Yochai Benkler, Mario Biagioli, Lynn Blais, Paul Bommer, Oren Bracha, Jens
Dammann, Rebecca Eisenberg, Kinnan Golemon, Calvin Johnson, Jennifer Laurin, Jake Linford, Tom
McGarity, Jim Morriss, Susan Morse, Sean O’Connor, Lucas Osborn, Bob Peroni, Richard Pierce, John
Robertson, David Spence, James Spindler, Dan Steward, Melinda Taylor, Abe Wickelgren, Sean Williams, the
editors of the Emory Law Journal, participants in the 2014 Works-in-Progress Intellectual Property
Conference, the Yale Information Society Project’s 2014 “Innovation Law Beyond IP” conference, a faculty
colloquium at the University of Texas School of Law, and students in a Science and Innovation Policy seminar
at the University of Texas at Austin.
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956 EMORY LAW JOURNAL [Vol. 64:955
players. Other lessons drawn from this case study include “negative lessons”
about the possibility and even likelihood of downsides of a technological boom
or the policies used to promote it—for example, environmental damage that
more careful regulation of a developing technology such as fracking might
have avoided. Anticipatory and continuing attention to such potential
downsides can help prevent innovation-promoting policies from becoming
“sticky” in a way that undercuts innovation’s promise and popular appeal.
Such lessons can helpfully inform efforts either to extend the United States’
“fracking revolution” abroad or to develop other potentially revolutionary
technologies such as those associated with renewable energy.
INTRODUCTION .............................................................................................. 957
I. THE SHALE GAS BOOM AND TECHNOLOGIES BEHIND IT ................... 964
A. Boom in U.S. Production of Natural Gas .................................. 964
B. The Web of Technologies Behind the Boom .............................. 968
II. INFRASTRUCTURE AND MARKETS BEYOND THE WELLHEAD ............. 974
A. Pipelines and “Pipeline Neutrality” ......................................... 976
B. Oil and Gas Markets ................................................................. 981
III. GOVERNMENT SUPPORT ..................................................................... 983
A. Publicly Funded Research and Public–Private Partnerships ... 983
B. Tax Relief ................................................................................... 989
C. Regulatory Relief ....................................................................... 995
IV. INTELLECTUAL PROPERTY, COMPLEMENTARY ASSETS, AND
SHARING ........................................................................................... 1000
A. Complementary Assets, Financing, and the “No Patents”
Story ......................................................................................... 1000
B. Information Sharing ................................................................ 1003
C. Secrecy and Non-Kitchian Patents .......................................... 1010
V. LEARNING FROM THE CASE STUDY .................................................. 1017
A. Lessons for Innovation Policy and Theory .............................. 1018
1. Patience and Stable Reward Mechanisms ......................... 1018
2. A Diverse Innovation Ecosystem ....................................... 1019
3. Government and Infrastructure ......................................... 1020
4. Mixed Information Strategies and Non-Kitchian Patents . 1021
5. Innovation in Governance ................................................. 1023
B. Applications Abroad and to Other Technologies .................... 1027
1. International Transfer ....................................................... 1028
2. Renewable Energy ............................................................. 1031
CONCLUSION ................................................................................................ 1037
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INTRODUCTION
Innovations in hydraulic fracturing and horizontal drilling (often
collectively referred to as “fracking”)1 have produced a technological
revolution in natural gas and oil extraction. The United States, the world leader
in these technologies’ development and exploitation, has suddenly returned to
the role of energy-producing superpower.2 Cheaper and more stably priced
natural gas, commonly derived from underground shale formations, has
promised to provide a long-lasting boost to a flagging U.S. economy,3 even
aiding in a revival of U.S.-based manufacturing.4 Both positive and negative
spillover effects associated with the boom in use of new extraction
technologies—spillovers that range from the economic to the environmental or
political5—promise to reach not only across the United States’ continental
1 There is debate over whether the abbreviated form of “hydraulic fracturing” should be “fracing” or
“fraccing,” rather than “fracking,” with the latter form often being associated with more negative views of
hydraulic fracturing as a social practice. RUSSELL GOLD, THE BOOM: HOW FRACKING IGNITED THE AMERICAN
ENERGY REVOLUTION AND CHANGED THE WORLD 297 (2014). In using “fracking,” we do not mean to take
sides in debates over hydraulic fracturing’s overall social benefits but instead follow what we believe to be the
more dominant popular spelling as well as a spelling that seems to best signal how the term is pronounced. See
id. at 297 n.* (explaining that the book employs “the spelling frack and fracking” because “they are the
preferred spelling of the Wall Street Journal and other major newspapers” and because “the spelling fraced
simply doesn’t convey the clipped cadence of the word as it is pronounced by opponents and engineers”); see
also GREGORY ZUCKERMAN, THE FRACKERS: THE OUTRAGEOUS INSIDE STORY OF THE NEW BILLIONAIRE
WILDCATTERS 27 (2013) (explaining that industry initially called the technique “hydraulic fracturing” or
“fraccing” and that “from the beginning industry members detested the word” fracking, and accused
environmental groups of coining the term to imply negative impacts of the practice, but noting that the term
originated in Battlestar Galactica).
2 See U.S. Expected to Be Largest Producer of Petroleum and Natural Gas Hydrocarbons in 2013, U.S.
ENERGY INFO. ADMIN. (Oct. 4, 2013), http://www.eia.gov/todayinenergy/detail.cfm?id=13251.
3 See U.S. ENERGY INFO. ADMIN., ANNUAL ENERGY OUTLOOK 2014 EARLY RELEASE OVERVIEW 1
(2014), http://www.eia.gov/forecasts/aeo/er/pdf/0383er%282014%29.pdf (“Ongoing improvements in
advanced technologies for crude oil and natural gas production continue to lift domestic supply and reshape
the U.S. energy economy.”).
4 ALAN KRUPNICK, ZHONGMIN WANG & YUSHUANG WANG, RES. FOR THE FUTURE, SECTOR EFFECTS OF
THE SHALE GAS REVOLUTION IN THE UNITED STATES 36–39 (2013), http://www.rff.org/RFF/Documents/RFF-
DP-13-21.pdf (exploring the impacts of domestic shale gas production on the manufacturing sector and
projecting that “[a]n expansion in the production capacity of ethylene will probably boost production in a wide
variety of manufacturing industries”); AM. CHEMISTRY COUNC IL, SHALE GAS, COMPETITIVENESS, AND NEW
US CHEMICAL INDUSTRY INVESTMENT: AN ANALYSIS BASED ON ANNOUNCED PROJECTS 27 (2013),
http://chemistrytoenergy.com/sites/chemistrytoenergy.com/files/shale-gas-full-study.pdf (noting that “renewed
competitiveness from shale gas is already occurring,” creating an estimated $2.2 billion in added value in
2012).
5 For discussions of these effects, see, inter alia, the following sources: Endangered and Threatened
Wildlife and Plants, Endangered Species Status for Diamond Darter, 78 Fed. Reg. 45,074 (July 26, 2013)
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breadth but around the globe.6
The technological revolution that preceded this U.S.-centered oil and gas
boom represents a massive burst of innovation that could hold lessons for
further technological development, including additional energy
transformations. The revolution reflects a classic disruptive innovation,
potentially the very kind of innovation that government policy should most
look to foster. Yet few scholars have explored why this innovation occurred, or
how the story behind the fracking revolution comports with or departs from
dominant innovation theory. This Article examines the public policies,
economic forces, and private initiatives that helped produce the fracking
revolution, focusing on the development of shale gas extraction in particular.
The Article primarily concentrates on developments leading to the revolution,
including decades of work that preceded late-twentieth century breakthroughs.
But the Article also gives some attention to the post-breakthrough diffusion of
new extraction technologies and difficulties encountered as use of those
technologies has become widespread.
(codified at 50 C.F.R. § 17.11 (2014)) (describing a species in the Marcellus Shale area that has become
endangered in a final rule issued by the Department of the Interior’s Fish and Wildlife Service); TIMOTHY W.
KELSEY ET AL., MARCELLUS SHALE EDUC. & TRAIN ING CTR., ECONOMIC IMPACTS OF MARCELLUS SHALE IN
PENNSYLVANIA: EMPLOYMENT AND INCOME IN 2009, at 5 (2011), http://www.shaletec.org/docs/
EconomicImpactFINALAugust28.pdf (exploring positive economic benefits); KENNETH B. MEDLOCK III, AMY
MYERS JAFFE & PETER R. HARTLEY, JAMES A. BAKER III INST. FOR PUB. POLICY, RICE UNIV., SHALE GAS AND
U.S. NATIONAL SECURITY 13 (2011), http://bakerinstitute.org/media/files/Research/ccecf6b6/EF-pub-DOE
ShaleGas-07192011.pdf (describing many positive economic and security-based impacts); WILLISTON ECON.
DEV., WILLISTON IMPACT STATEMENT 2014, at 1, 28 (2014), http://www.willistondevelopment.com/usrimages/
Williston_Impact_Statement.pdf (describing local infrastructural and service-based impacts as well as tax
revenues); Cliff Frohlich et al., The Dallas–Fort Worth Earthquake Sequence: October 2008 Through May
2009, 101 BULL. SEISMOLOGICAL SOCY AM. 327 (2011) (describing small earthquakes possibly induced by
the disposal of liquid oil and gas wastes from the Barnett Shale); Michelle L. Hladik, Michael J. Focazio &
Mark Engle, Discharges of Produced Waters from Oil and Gas Extraction via Wastewater Treatment Plants
Are Sources of Disinfection By-Products to Receiving Streams, 466–467 SCI. TOTAL ENVT 1085, 1092 (2014);
Brian G. Rahm & Susan J. Riha, Toward Strategic Management of Shale Gas Development: Regional,
Collective Impacts on Water Resources, 17 ENVTL. SCI. & POLY 12, 15 (2012) (describing water quality and
quantity impacts); Hannah J. Wiseman, Risk and Response in Fracturing Policy, 84 U. COLO. L. REV . 729,
733–34 (2013) (describing many of the impacts based on state enforcement of oil and gas regulations at
unconventional well sites).
6 See generally GOLD, supra note 1, at 5 (noting that, from the U.S. perspective, hydraulic fracturing “is
providing an abundance of domestic energy, helping to drive a rebirth of manufacturing, and easing
dependence on overseas energy peddlers”); Diana Davids Hinton, The Seventeen-Year Overnight Wonder:
George Mitchell and Unlocking the Barnett Shale, 99 J. AM. HIST. 229, 229 (2012) (“[T]he opening of massive
natural gas production in north Texas from a geological formation called the Barnett Shale has begun a new
era in world energy.”).
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Studying innovation through a case study of the fracking revolution is apt
in light of current levels of understanding. Limits on our knowledge of the
mechanics of innovation often renders generalized theorizing and narrow
econometric studies of relatively little use for drawing practical,
policy-oriented conclusions. In this context, case studies of specific innovation
trajectories can inform the intuitions that necessarily guide much present
policymaking, and case studies can support and guide later theoretical and
econometric efforts. Such focused observational studies have substantial limits.
But we suspect that the physicist Richard Feynman had reason for listing
observation first in describing “[o]bservation, reason, and experiment [as]
mak[ing] up what we call the scientific method.”7 As with careful recording of
celestial motions in the early stages of the Scientific Revolution, careful
observation of specific innovation trajectories might be among the best ways to
advance understandings of innovation and innovation policy.8
Why study fracking as a foundation for more nuanced innovation theory?
Pharmaceutical, biotechnology, communications, and computer-related
technologies have commonly provided the basis for modern debates about how
innovation works.9 Given the social and political salience of these
technologies, the attention devoted to these areas is understandable. But energy
technologies seem a more than worthy addition to this common grouping. The
energy sector has a long history of cutting-edge innovation, and innovations in
energy technology have long undergirded innovation in much of the rest of the
economy. The Industrial Revolution motored forward on the basis of, first,
new technologies for harnessing wind and water10 and, second, even newer,
7 RICHARD P. FEYNMAN, SIX EASY PIECE S: ESSENTIALS OF PHYSICS EXPLAINED BY ITS MOST BRILLIANT
TEACHER 24 (Robert B. Leighton & Matthew Sands eds., 1995) (emphasis omitted).
8 Cf. id. at 90 (describing how Tycho Brahe’s careful observation of planetary trajectories laid the basis
for Kepler’s discovery of “some very beautiful and remarkable, but simple, laws”); GERALD HOLTON &
STEPHEN G. BRUSH, INTRODUCTION TO CONCEPTS AND THEORIES IN PHYSICAL SCIENCE 38 (2d ed. 1973)
(noting that Tycho Brahe “spen[t] nearly a lifetime in patient recording of planetary motion with unheard-of
precision”).
9 See John M. Golden, Principles for Patent Remedies, 88 TEX. L. REV. 505, 507 & nn.7–8 (2010)
(describing conflicts over patent legislation that featured a coalition including “information technology,
semiconductor, computer, and financial-services companies” on one side and a coalition, including
“pharmaceutical, biotechnology, and chemical companies” on the other).
10 JOEL MOKYR, THE LEVER OF RICHES: TECHNOLOGICAL CREATIVITY AND ECONOMIC PROGRESS 34
(1990) (noting medieval advances in harnessing energy from wind and water).
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interconnected technologies for extracting coal and harnessing steam.11 The
modern Information Revolution has relied on later advances in the production
and harnessing of electrical energy.12
In short, energy technologies are vitally important, and fracking has proven
remarkably so. It also happens to have a fascinating origin story. A common
quasi-myth is that fracking’s commercial development is largely the tale of a
single oil-industry entrepreneur, George Mitchell, who bucked conventional
wisdom, risked millions, and persisted for years in efforts to make
unconventional gas reserves commercially exploitable.13 Indeed, Mitchell
deserves great credit both for unusual persistence and for his company’s
ultimate development of a formula for combining horizontal drilling and
“slickwater” fracturing in a way that industry adapted with awesome rapidity
to shale and other formations around the United States.14
11 Id. at 85 (observing that “[t]he first economically successful [steam] engine . . . was installed in a coal
mine near Wolverhampton in 1712” and “solved drainage problems . . . in the deep coal mines in the north of
England”).
12 Cf. ALFRED C. CHANDLER, JR., INVENTING THE ELECTRONIC CENTURY: THE EPIC STORY OF THE
CONSUMER ELECTRONICS AND COMPUTER INDUSTRIES, at xiv–xvii (rev. ed. 2005) (comparing the Information
Revolution and the Industrial Revolution); Warren D. Devine, Jr., From Shafts to Wires: Historical
Perspectives on Electrification, 43 J. ECON. HIST. 347, 371 (1983) (examining the historical “shift from steam
power to electric power”).
13 See DAN IEL YERG IN, THE QUEST: ENERGY, SECUR ITY, AND THE REMAKING OF THE MODERN WORLD
325 (2011) (“[M]itchell’s relentless commitment . . . would transform the North American natural gas market
and shake expectations for the global gas market.”); America’s Bounty: Gas Works, ECONOMIST, July 14,
2012, at 5, 5–6, available at http://www.economist.com/node/21558459 (explaining that “the biggest
difference [in fracking’s development] was down to the efforts of one man: George Mitchell, the boss of an
oil-service company,” who “spent ten years and $6m to crack the problem,” even though “[e]veryone, he said,
told him he was just wasting his time and money”); Jonathan D. Silver, Origins: The Story of a Professor, a
Gas Driller and Wall Street, PITT. POST-GAZETTE, Mar. 20, 2011, at A-1, available at http://www.post-
gazette.com/business/businessnews/2011/03/20/The-Marcellus-Boom-Origins-the-story-of-a-professor-a-gas-
driller-and-Wall-Street/stories/201103200259 (“[I]n the early 1980s, Texas oilman George P. Mitchell pursued
a fringe strategy—exploring the Barnett Shale.”); see also ZUCKERMAN, supra note 1, at 5 (asserting that “a
small group of individuals made [a new age in U.S. oil and gas production] happen, against all odds,” and
crediting Mitchell, “who discovered a novel way to extract gas from shale formations” with “impact [that]
eventually might even approach that of Henry Ford and Alexander Graham Bell”). But see ZHONGMIN WANG
& ALAN KRUPNICK, RES. FOR THE FUTURE, A RETROSPECTIVE REVIEW OF SHALE GAS DEVELOPMENT IN THE
UNITED STATES: WHAT LED TO THE BOOM? 3 (2013), http://www.rff.org/RFF/documents/RFF-DP-13-12.pdf
(exploring in detail the many factors contributing to the technological innovations behind the shale gas boom
and largely agreeing that “it was the private entrepreneurship from Mitchell Energy & Development . . . that
played the primary role in developing the Barnett play in Texas”); ZUCKERMAN, supra note 1 (providing a
richer account by describing efforts by Mitchell, leading individuals at Chesapeake Energy, and others in
inducing the technological revolution).
14 See infra text accompanying notes 84–91; see also MICHAEL RATNER & MARY TIEMANN , CONG.
RESEARCH SERV., R43148, AN OVERVIEW OF UNCONVENTIONAL OIL AND NATURAL GAS: RESOURCES AND
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But even a Mitchell-centric view of fracking’s development acknowledges
that there were other factors that contributed critically to the technological
revolution behind commercially viable shale gas extraction and the associated
boom in oil and gas production more generally. A great number of these
related to physical, legal, and economic infrastructure including pipelines,
natural gas markets, and property systems for land and mineral rights, which
provided a foundation upon which unconventional natural gas pioneers could
successfully operate.15 Further vital preconditions for Mitchell’s successful
“fracking synthesis” included multiple lines of innovation—for example, in
hydraulic fracturing, directional drilling, and seismic imaging to identify oil
and gas deposits—that sometimes reached decades into the past.16
Significantly, private forces for innovation benefited substantially from
public aid. In the 1970s and 1980s, the U.S. Bureau of Mines (later part of the
Energy Research and Development Administration)17 and Department of
Energy (DOE) “spent hundreds of millions”18 on research and development
that helped both point and pave the way for Mitchell’s ultimate success.19
Moreover, public support extended far beyond early R&D. Fracking and
associated technologies have long benefited from public–private research
FEDERAL ACTIONS 3 (2014), http://fas.org/sgp/crs/misc/R43148.pdf (“The application of advances in
directional drilling and hydraulic fracturing were first applied to shale gas formations, particularly as natural
gas prices increased in the mid-2000s.”).
15 See WANG & KRUPNICK, supra note 13, at 4 (discussing the importance of property systems in land
and mineral rights); America’s Bounty, supra note 13, at 5 (discussing factors behind the fracking revolution
such as “a deep and liquid gas market that allowed the risks of drilling to be hedged, ready access to capital,
America’s home-grown oil industry,” and “the liberalisation of access to existing pipelines by third parties”).
16 See infra notes 62–80 and accompanying text.
17 For a discussion of consolidations in the 1970s, after which the Department of Energy (DOE) oversaw
all energy R&D, see WANG & KRUPNICK, supra note 13, at 7–8.
18 Alex Trembath, Letter to the Editor, A Joint Effort, ECONOMIST, Aug. 4, 2012, at 14, available at
http://www.economist.com/node/21559890.
19 MICHAEL SHELLENBERGER ET AL., BREAKTHROUGH INST., WHERE THE SHALE GAS REVOLUTION CAME
FROM 6 (2012), http://thebreakthrough.org/images/main_image/Where_the_Shale_Gas_Revolution_Came_
From2.pdf (discussing how the Bureau of Mines’ Morgantown Energy Research Center “initiated the Eastern
Gas Shales Project, which established a series of partnerships with universities and private companies” to
demonstrate gas recovery from “unconventional resource bases that stood out of reach from contemporary
drilling technologies, including coalbed methane deposits, “tight sands” natural gas, and shale gas”); id. at 3
(noting that Department of Energy’s role in the first demonstrations of “massive hydraulic fracturing” and
“directional drilling in shale”); see also WANG & KRUPNICK, supra note 13, at 3 (concluding that “some of the
key technology innovations resulted from government research and development (R&D) programs and private
entrepreneurship” but that “some of the key technologies . . . were largely developed by the oil industry”); id.
(noting, in particular, the role of government research in developing early “key technologies” in the Michigan
and Appalachian Basins in the 1970s when “US gas producers were small”).
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partnerships20 as well as both tax21 and regulatory22 relief.23 Further, trade
secret protection has enabled companies to invoke proprietary rights as a
means, not only to stay ahead of competitors but also to avoid disclosure of
fracking chemicals to regulators and the public.24
Notably, patents appear to have been only bit players in the basic story
behind the fracking revolution. Somewhat ironically, in light of Edmund
Kitch’s use of resource-extraction rights to motivate his “prospect theory” for
relatively broad patent rights,25 “during the late 1990s and early 2000s neither
Mitchell [Energy] nor [its ultimate acquirer,] Devon [Energy,] pursued patent
protection for their respective innovations in slickwater hydraulic fracturing
and horizontal drilling.”26 Far from holding fracking’s further development
back, such restraint in patenting might have helped enable the recent natural
20 SHELLENBERGER ET AL., supra note 19, at 9 (“In 1991, Mitchell partnered with DOE and GRI [the
federally funded Gas Research Institute] to develop tools that would effectively fragment formations in the
Barnett Shale . . . .”).
21 Trembath, supra note 18, at 14 (noting that the U.S. government offered a “$10 billion production tax
credit for unconventional gas between 1980 and 2002”).
22 David B. Spence, Federalism, Regulatory Lags, and the Political Economy of Energy Production,
161 U. PA. L. REV. 431, 449 (2013) (“Fracking operations enjoy some exemptions from federal environmental
regulation.”); cf. Michael Burger, Response, Fracking and Federalism Choice, 161 U. PA. L. REV. ONLINE
150, 157 (2013) (“[D]ue to a toxic blend of agency capture, flawed research, and shortsighted administrative
decisions, the federal government’s leadership in fracking regulation has been paralyzed.”).
23 Cf. Daniel J. Hemel & Lisa Larrimore Ouellette, Beyond the Patents–Prizes Debate, 92 TEX. L. REV.
303, 311–12 (2013) (describing how prizes, grants, and tax relief, as well as intellectual property rights, can
affect a would-be innovator’s incentives).
24 Barbara Warner & Jennifer Shapiro, Fractured, Fragmented Federalism: A Study in Fracking
Regulatory Policy, 43 PUBLIUS 474, 486 (2013) (noting that various states limit disclosure requirements for
fracking chemicals “that companies deem proprietary”); Hannah Wiseman, Trade Secrets, Disclosure, and
Dissent in a Fracturing Energy Revolution, 111 COLUM. L. REV. SIDEBAR 1, 4–8 (2011) (describing federal
and state trade secret allowances). Many public comments on proposed state and regional fracturing
regulations—even rules unrelated to chemical disclosure—have focused on concerns about the chemicals used
in hydraulic fracturing and the lack of trade secret disclosure. See, e.g., 36 TEX. REG. 9307, 9312 (Dec. 30,
2011) (noting comments calling for greater disclosure of “proprietary chemicals”); Email from Mark Mackin
to Tom Richmond, Mont. Bd. of Oil & Gas Conservation (June 5, 2011, 11:52 AM), available at http://bogc.
dnrc.mt.gov/PDF/CombinedComments.pdf (page sixteen of the file) (calling for greater disclosure of
chemicals used in hydraulic fracturing).
25 Edmund W. Kitch, The Nature and Function of the Patent System, 20 J.L. & ECON. 265, 266 (1977)
(arguing that the patent system enables a patent owner to coordinate exploitation of a “prospect”—“a particular
opportunity to develop a known technological possibility”—in a way that increases social efficiency); see also
id. at 267 (contending that “the scope accorded to patent claims, a scope that reaches well beyond what the
reward function would require,” is evidence of “[t]he importance of the prospect function in the American
patent system”).
26 Daniel R. Cahoy, Joel Gehman & Zhen Lei, Fracking Patents: The Emergence of Patents as
Information-Containment Tools in Shale Drilling, 19 MICH. TELECOMM. & TECH. L. REV. 279, 291 (2013).
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gas “gold rush,” “with companies racing to capitalize on innovative, yet
unpatented techniques in other geographies.”27 Although patents might have
played a nontrivial role in the technology buildup that enabled Mitchell’s
turn-of-the-millennium breakthrough, their marginalization at this critical point
demonstrates how, under appropriate circumstances, innovation’s development
and diffusion can proceed apace—perhaps even at a faster pace—without great
resort to intellectual property.
Generally speaking, the translation of lessons from one technological and
social context to another can be perilous. Nonetheless, the story behind the
fracking revolution provides lessons both for innovation theory and also, at
least at a strategic level, for specific problems of technological development in
the present day. In particular, the story provides lessons that can productively
inform efforts to replicate the United States’ shale gas boom abroad and efforts
to revolutionize wind and solar markets at home. These lessons include not
only “positive lessons” about how to promote innovation but also “negative
lessons” about how to avoid or mitigate downsides of innovation that could
undercut innovation’s promise and popular appeal. As with many
technological booms, environmental concerns28 and social dislocations29 have
accompanied the shale gas boom, and their emergence affords instruction in
how policymakers might act anticipatorily or reactively to maximize
technology’s potential.
This Article’s exploration of the story of the fracking revolution proceeds
as follows. Part I introduces the wellhead technologies that converged to
generate the “Mitchell synthesis” of techniques of horizontal drilling and
hydraulic fracturing. Part II explores factors beyond the wellhead—in
particular, the development of open-access pipelines and national markets in
natural gas. Part III describes the role of federal and state governments in
advancing hydraulic fracturing and horizontal drilling through such policy
mechanisms as research partnerships and regulatory and tax relief. Part IV
discusses how private property rights in land and minerals, patents, secrecy,
and information exchange contributed to the technological developments
behind the shale gas boom. Part V explores lessons, positive and negative,
from this case study in technological innovation and potential application of
27 Id. at 291–92.
28 See infra notes 262–66 and accompanying text.
29 See infra notes 268–70 and accompanying text.
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these lessons to oil and gas development abroad and renewable-energy
development in general. A concluding section follows.
I. THE SHALE GAS BOOM AND TECHNOLOGIES BEHIND IT
Hydraulic fracturing and horizontal drilling are now key factors in the
exploitation of a great variety of fossil fuel resources. But this Article focuses
on the most revolutionary field of these technologies’ recent use—the
extraction of natural gas from underground shale formations, which consist of
“hard, concretelike shale rock”30 formed by sediment and organic matter that
accumulated in formerly marine environments.31 The Article focuses on shale
gas extraction because development of unconventional reserves of shale gas is
commonly recognized to be at the heart of the now more general oil and gas
boom32 and because, among affected fossil fuels, newly exploitable natural gas
reserves seem to have the greatest potential for disruption of energy economies
historically tied more tightly to oil and coal.33 This Part discusses the United
States’ shale gas boom and the intricate combination of technological
developments that lies behind it.
A. Boom in U.S. Production of Natural Gas
The remarkable nature of the recent growth of domestic, unconventional
gas production is underscored by comparing the current situation to that in the
30 YERGIN, supra note 13, at 326.
31 Q.R. PASSEY ET AL., SOCY OF PETROL. ENGRS, SPE 131350, FROM OIL-PRONE SOURCE ROCK TO
GAS-PRODUCING SHALE RESERVOIR—GEOLOGIC AND PETROPHYSICAL CHARACTERIZATION OF
UNCONVENTIONAL SHALE-GAS RESERVOIRS 10 (2010) (describing how most shales “had their origin as
organic-rich mud” and how the sediments in shale “could have been deposited in the marine environment, in
lakes (lacustrine), or in associated swamps and mires along the margins of lakes or seas”).
32 Shale of the Century, ECONOMIST, June 2, 2012, at 77, available at http://www.economist.com/node/
21556242 (“As a proportion of America’s overall gas production shale gas has increased from 4% in 2005 to
24% today.”).
33 See, e.g., Monthly Coal- and Natural Gas-Fired Generation Equal for First Time in April 2012, U.S.
ENERGY INFO. ADMIN. (July 6, 2012), http://www.eia.gov/todayinenergy/detail.cfm?id=6990 (noting that “for
the first time since EIA began collecting the data, generation from natural gas-fired plants is virtually equal to
generation from coal-fired plants, with each fuel providing 32% of total generation,” in April 2012 in part
because “natural gas prices as delivered to power plants were at a ten-year low”); Natural Gas Generation
Lower than Last Year Because of Differences in Relative Fuel Prices, U.S. ENERGY INFO. ADMIN. (Sept. 25,
2013), http://www.eia.gov/todayinenergy/detail.cfm?id=13111 (“The increasing gas use for power is a
structural change that is occurring across a wide range of temperatures and seasons. Several factors underpin
this trend, including moderate natural gas prices, increased shale gas production, and additions of natural gas
generating capacity.”).
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very first years of the twenty-first century. Already in 2001, after surveying a
history of relatively incremental progress but before recognizing the
imminence of the impending boom, the National Research Council declared
past public support for shale gas a substantial success.34 The Council reported
that in the mid-1970s the United States extracted about 70 billion cubic feet
(Bcf) of natural gas per year from shale formations.35 By 1998, that amount
had risen by over a factor of five to 380 Bcf per year.36 With natural gas
production from the Barnett Shale expected to join that from the Eastern Gas
Shales, shale gas production was expected to rise to 0.8 trillion cubic feet
(0.8 Tcf, equivalent to 800 Bcf) by 2010 and to nearly 1 Tcf per year by
2020.37 According to the Council, the federal government’s Eastern Gas Shales
Project of 1976 to 1992 had already generated benefits to industry of $705
million in 1999 dollars, and these benefits exceeded project expenditures of
$148 million by a ratio of 4.8 to 1.38 A much higher benefit-to-cost ratio would
have resulted from taking into account “over $8 billion in consumer savings
due to lower gas prices.”39 Given such figures, the Council had good reason to
conclude that the past quarter century’s fivefold increase in shale gas
production and the future promise of a nearly threefold increase over the next
couple decades were cause for celebration.40
Wonder then at how we should react to what actually occurred. By 2007,
six years after the Council’s report and thirteen years before annual shale gas
production had been expected to “approach 1 Tcf,41 the United States
34 NATL RESEARCH COUNCIL, ENERGY RESEARCH AT DOE: WAS IT WORTH IT? ENERGY EFFICIENCY
AND FOSSIL ENERGY RESEARCH 1978 TO 2000, at 201 (2001), http://www.nap.edu/catalog/10165.html
(“[I]ncentives through tax credits, combined with optimum deployment of advanced technology, served to
revive a domestic gas province in decline.”).
35 Id.
36 Id.
37 Id.
38 Id.
39 Id.
40 In 2002, another set of commentators reacting to unconventional natural gas production levels of 4,500
Bcf per year were similarly impressed. Vello A. Kuuskraa & Hugh D. Guthrie, Translating Lessons Learned
from Unconventional Natural Gas R&D to Geologic Sequestration Technology, J. ENERGY & ENVTL. RES.,
Feb. 2002, at 75, 81 (citing 1999 production level of 4,500 Bcf, 370 Bcf of which resulted from gas shale
production). As they observed, “[a] poorly-understood, high-cost energy resource, one that the U.S. Geological
Survey had not even included in its national appraisals of future gas resources (until their most recent 1995
assessment), is now providing major volumes of annual gas supplies.” Id. at 80.
41 NATL RESEARCH COUNCIL, supra note 34, at 201.
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extracted nearly 2 Tcf of shale gas.42 In the past decade and a half, growth in
shale gas production has been more than exponential. As noted above, shale
gas production approximately quintupled in the more than twenty years from
the mid-1970s to the late 1990s.43 If the growth in shale gas production were
exponential, production would have taken another couple of decades to rise by
another factor of five.44 But in half that time—the ten years from 1998 to
2007—shale gas production more than quintupled again, rising from nearly
400 Bcf to nearly 2 Tcf.45 Within a mere five additional years, United States’
shale gas production had quintupled a third time. Production in 2012 amounted
to more than 10 Tcf,46 more than five times the production level in 2007 and
about ten times the amount that the National Research Council had projected
for 2020.47 From 2000 to 2012, shale gas had gone from supplying only about
1% of the United States’ natural gas to supplying well over one-fourth.48 As
Daniel Yergin put it, “[p]erennial shortage gave way to substantial surplus.”49
The United States now looks forward to becoming a net exporter of natural
gas.50
The world is still absorbing the significance of this natural gas boom, one
that has helped turn the United States into an unexpected, technology-driven
“petrostate” of a type never seen before.51 The “shale gale”52 of the past decade
has generated a vast range of straightforward economic benefits, including
improved GDP and balance-of-payments numbers, increased employment and
42 U.S. Natural Gas Withdrawals from Shale Gas (Million Cubic Feet), U.S. ENERGY INFO. ADMIN.
(Aug. 29, 2014), http://www.eia.gov/dnav/ng/hist/ngm_epg0_fgs_nus_mmcfa.htm [hereinafter U.S. Natural
Gas Withdrawals].
43 See supra text accompanying note 38.
44 WILLIAM J. BAUMOL & ALAN S. BLINDER, ECONOMICS: PR INCIPLES AND POLICY 820 (5th ed. 1991)
(“Exponential growth is growth at a constant percentage rate.” (emphasis omitted)).
45 Compare supra text accompanying note 36, with supra text accompanying note 42.
46 U.S. Natural Gas Withdrawals, supra note 42.
47 See supra text accompanying note 37.
48 YERGIN, supra note 13, at 329.
49 Id.
50 JASON BURWEN & JANE FLEGAL, AM. ENERGY INNOVATION COUNCIL, UNCONVENTIONAL GAS
EXPLORATION & PRODUCTION 7 (2013) (“The US is now expected to become a net exporter of natural gas in
the next decade.”).
51 The Petrostate of America, ECONOMIST, Feb. 15, 2014, at 10, available at http://www.economist.com/
news/leaders/21596521-energy-boom-good-america-and-world-it-would-be-nice-if-barack-obama-helped
(noting that the United States’ “‘fracking’ revolution . . . . owes less to geological luck than enterprise, ready
finance and dazzling technology”).
52 YERGIN, supra note 13, at 329 (internal quotation marks omitted).
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tax revenues,53 and by at least one estimate “on the order of $100 billion of
gains to consumers each year.”54 Low natural gas prices have helped revitalize
U.S. manufacturing, particularly in the natural-gas-dependent petrochemicals
industry.55 Reduced U.S. and foreign dependence on energy-rich states that
have often been either unstable or hostile to U.S. interests could shake up
geopolitics for decades to come.56 Finally, although records of incidents at
shale gas sites, as well as broader scientific data, show a range of negative
environmental effects that have been associated with natural gas extraction,57
ample supplies of natural gas offer the possibility of significant environmental
benefits—particularly if concerns with methane leakage from wells, gathering
lines, and pipelines are addressed.58 Natural gas is a much cleaner-burning fuel
53 See Thomas W. Merrill & David M. Schizer, The Shale Oil and Gas Revolution, Hydraulic
Fracturing, and Water Contamination: A Regulatory Strategy, 98 MINN. L. REV. 145, 157 (2013) (reporting on
combined contributions of unconventional fossil fuel resources to U.S. economic figures).
54 BURWEN & FLEGAL, supra note 50, at 7.
55 See AM. CHEM ISTRY COUNCIL, SHALE GAS AND NEW PETROCHEMICALS INVESTMENT: BENEFITS FOR
THE ECONOMY, JOBS, AND US MANUFAC TURING (2011), http://chemistrytoenergy.com/sites/
chemistrytoenergy.com/files/ACC-Shale-Report.pdf; Merrill & Schizer, supra note 53, at 159.
56 See Merrill & Schizer, supra note 53, at 162–63 (suggesting that U.S. natural gas could reduce
European dependence on Iran and Russia, as well as “enabl[ing] the U.S. to cut its defense budget”); The
Petrostate of America, supra note 51, at 11 (“A world in which the leading petrostate is a liberal democracy
has much to recommend it.”). But see BakerInstitute, Shell Distinguished Lecture Series—World Energy
Outlook, YOUTUBE (Feb. 20, 2014), https://www.youtube.com/watch?v=WcVNrWZ9rwU (noting that U.S.
production likely will not continue at this pace beyond several decades and that Middle Eastern resources will
continue to be very important).
57 See supra note 5; infra notes 262–69 and accompanying text; see also GOVERNORS MARCELLUS
SHALE ADVISORY COMM IS SION REPORT 75 (2011), http://files.dep.state.pa.us/PublicParticipation/Marcellus
ShaleAdvisoryCommission/MarcellusShaleAdvisoryPortalFiles/MSAC_Final_Report.pdf (documenting
certain “high-profile” well blowouts at fractured wells); E.T. SLONECKER ET AL., US GEOLOGICAL SURVEY,
LANDSCAPE CONSEQUENCES OF NATURAL GAS EXTRACTION IN BRADFORD AND WASHINGTON COUNTIES,
PENNSYLVANIA, 2004–2010, at 26 (2012), http://pubs.usgs.gov/of/2012/1154/of2012-1154.pdf (noting that
both conventional and unconventional wells cause forest fragmentation, which can have negative effects on
“interior species” that prefer undisturbed habitat); Mitchell J. Small et al., Risks and Risk Governance in
Unconventional Shale Gas Development, 48 ENVTL. SCI. & TECH. 8289, 8290–91 (2014) (exploring the
scientific literature and summarizing the risks); cf. Katie M. Keranen et al., Potentially Induced Earthquakes in
Oklahoma, USA: Links Between Wastewater Injection and the 2011 Mw 5.7 Earthquake Sequence,
41 GEOLOGY 699, 701–02 (2013) (noting that injection of liquid wastes from oil and gas wells might have
triggered a large earthquake in Oklahoma but not isolating this observation to wastes from unconventional
wells).
58 For discussions of methane leakage at various points in the process of producing, transporting, and
using natural gas, see, for example, David T. Allen et al., Measurements of Methane Emissions at Natural Gas
Production Sites in the United States, 110 PNAS 17,768, 17,772 (2013) (estimating lower emissions from
wellheads than the EPA has estimated, but noting uncertainty), and A.R. Brandt et al., Methane Leaks from
North American Natural Gas Systems, 343 SCIENCE 733 (2014) (finding high methane emissions from natural
gas used in transportation).
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than coal and has already contributed to recent declines in the United States’
greenhouse gas emissions.59 In a post-Great Recession world highly concerned
with promoting economic growth, there is hope that, with appropriate
regulation of extraction and use, natural gas can act as a “bridge fuel,” enabling
relatively painless reductions in near-term greenhouse gas emissions while the
world works toward greater reliance on nonfossil fuels.60
B. The Web of Technologies Behind the Boom
Multiple new technologies undergird the shale gas boom, and the most
prominent of these are hydraulic fracturing—specifically slickwater
fracturing—and horizontal drilling. In a sense, both are relatively old
technologies. A horizontal well existed at least as early as 1929,61 and judges,
scholars, and industry experts have commonly traced hydraulic fracturing to
increase fuel extraction back to the late 1940s.62 But the combination and
enhancement of these techniques by a host of improvements and ancillary
technologies have yielded results that are qualitatively new.
Fundamentally, hydraulic fracturing—commonly known as “fracking”—is
a process of pumping large amounts of liquid into a wellbore and selected
areas of surrounding rock, with the liquid being pumped at a high enough
59 See U.S. ENERGY INFO. ADMIN., U.S. DEPT OF ENERGY, NO. DOE/EIA-0560(98), NATURAL GAS
1998: ISSUES AND TRENDS 52–53, 53 fig.22 (1999), http://www.eia.gov/pub/oil_gas/natural_gas/
analysis_publications/natural_gas_1998_issues_trends/pdf/it98.pdf (comparing emissions of nitrogen oxides,
sulfur dioxide, particulates, carbon monoxide, and hydrocarbons from natural gas and coal and noting much
lower emissions from natural gas); Spence, supra note 22, at 440–41 (citing these data and emphasizing the
cleaner-burning qualities of gas).
60 J. Rothstein, Hydrogen and Fossil Fuels, 20 INTL J. HYDROGEN ENERG Y 283, 284 (1993); see also
JOHN D. PODESTA & TIMOTHY E. WIRTH, CTR. FOR AM. PROGRESS, NATURAL GAS: A BRIDGE FUEL FOR THE
21ST CENTURY (2009), http://cdn.americanprogress.org/wp-content/uploads/issues/2009/08/pdf/
naturalgasmemo.pdf; Merrill & Schizer, supra note 53, at 165–66; Hannah Wiseman, Regulatory Adaptation
in Fractured Appalachia, 21 VILL. ENVTL. L.J. 229, 231–32 (2010).
61 BURWEN & FLEGAL, supra note 50, at 3.
62 Coastal Oil & Gas Corp. v. Garza Energy Trust, 268 S.W.3d 1, 7 (Tex. 2008) (“First used
commercially in 1949, fracing is now essential to economic production of oil and gas and commonly used
throughout Texas, the United States, and the world.”); Carl T. Montgomery & Michael B. Smith, Hydraulic
Fracturing: History of an Enduring Technology, J. PETROLEUM TECH., Dec. 2010, at 26, 26–27 (“The first
experimental treatment to ‘Hydrafrac’ a well for stimulation was performed in . . . Kansas, in 1947 . . . .”);
Hydraulic Fracturing 101, HALLIBURTON, http://www.halliburton.com/public/projects/pubsdata/
Hydraulic_Fracturing/fracturing_101.html (last visited Mar. 5, 2015) (stating that Halliburton “first” used “the
process in 1947 to stimulate flow of natural gas from the Hugoton field in Kansas”).
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pressure that the rock fractures.63 In a natural-gas-bearing shale formation, the
cracking of the hard but slightly porous rock helps expose surface area of the
shale64 and frees natural gas trapped within the shale to travel through the
wellbore to the surface, where it is collected, processed, and transported,
typically by pipeline.65
The oil and gas industry long sought to increase recovery of fossil fuels
through predecessor techniques to hydraulic fracturing. Beginning in the
1860s, some operators used nitroglycerin to generate underground explosions
in wells,66 and by the 1930s, enterprising individuals injected acid into wells to
open up fractures in surrounding formations.67 Hydraulic fracturing emerged in
1947, when Floyd Farris of Stanolind Oil and Gas Corporation (later Amoco)
performed an experimental “[h]ydrafrac” in Kansas, using 1,000 gallons of
gasoline thickened with napalm followed by a gel injection to fracture a
limestone formation.68
To enhance the effectiveness of fracking, the liquid pumped into the rock is
mixed with chemicals and one or more forms of “proppant,” commonly sand.69
Proppant particles are trapped in cracks generated by fracking and help “prop”
them open—facilitating the continued flow of gas through the fractures.70 For
decades, operators have experimented with various combinations and
concentrations of gels, proppants, and water (and sometimes foam)—often
63 See BURWEN & FLEGAL, supra note 50, at 2 & fig.2; CHING H. YEW, MECHANICS OF HYDRAULIC
FRACTURING 1 (1997) (“This fluid pressure creates a fracture extending into the rock medium which contains
oil or gas.”).
64 See P. KAUFMAN, G.S. PENNY & J. PAKTINAT, SOCY OF PETROL. ENGRS, SPE 119900, CRITICAL
EVALUATIONS OF ADDITIVES USED IN SHALE SLICKWATER FRACS, 1 (2008) (noting that horizontal wells are
used to “create as much contact with the reservoir as possible”).
65 See C. CLARK ET AL., ARGONNE NATL LAB., ANL/EVS/R-125, HYDRAULIC FRACTURING AND SHALE
GAS PRODUCTION: TECHNOLOGY, IMPACTS, AND REGULATIONS 3 (2013), http://www.afdc.energy.gov/uploads/
publication/anl_hydraulic_fracturing.pdf (noting the reduction in pressure following fracturing, after which
fluid (and later gas) flows out of the well, and noting that propped fractures create “a pathway for natural gas
to flow back to the well”).
66 Montgomery & Smith, supra note 62, at 26–27.
67 Id.
68 Id. (internal quotation marks omitted).
69 Id. at 28.
70 See BURWEN & FLEGAL, supra note 50, at 2; CAROLYN SETO, THE FUTURE OF NATURAL GAS
SUPPLEMENTARY PAPER SP 2.3: ROLE OF TECHNOLOGY IN UNCONVENTIONAL GAS RESOURCES 11–12 (2011),
http://mitei.mit.edu/system/files/Supplementary_Paper_SP_2_3_Unconventional_Technology.pdf; YEW, supra
note 63, at 61.
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varying the technique for different formations.71 The nature of the fracking
fluid and proppant is generally tailored to the particular geological formation
being fracked.72 For the types of shale gas formations of concern here, the
fracking mixture tends to be at least about 98% to 99% water and sand, with
the remainder comprising any of a number of substances.73 These substances
can include “friction reducing” agents such as polyacrylamides, biocides such
as methanol to kill bacteria, “scale inhibitors” such as hydrochloric acid, and
various other materials such as guar gum, borate salts, and isopropanol that can
help optimize any of a variety of fracking fluid properties such as viscosity and
the ability to carry and release proppant.74 Proppants can also be varied in
terms of grain size, shape, coating, or source.75 Some form of sand remains the
dominant choice, but at one time or another fracturing service companies have
tried a host of alternatives, including “plastic pellets, steel shot, Indian glass
beads, aluminum pellets, high-strength glass beads, rounded nut shells,
resin-coated sands, sintered bauxite, and fused zirconium.”76 Industry players
have apparently been willing to look far and wide for materials that could help
improve fracturing solutions or proppants: in the 1970s, energy companies
“‘borrowed’ [chemical agents] from the plastic explosives industry.”77
Such broad experimentation reflects the trial-and-error approach through
which fracking has commonly developed—an approach that at least partly
71 See Wiseman, supra note 5, at 744 n.60 (compiling and describing sources on historic fracturing fluids
and treatments).
72 See ANTHONY ANDREWS ET AL., CONG. RESEARCH SERV., R40894, UNCONVENTIONAL GAS SHALES:
DEVELOPMENT, TECHNOLOGY, AND POLICY ISSUES 24 (2009) (“It is important to note that the service
companies adjust the proportion of frac fluid additives to the unique conditions of each well.”); JOHN H.
GRAVES, FRACKING: AMERICAS ALTERNATIVE ENERGY REVOLUTION 100–02 (2012) (noting that “[s]lick
water is most commonly used in deep holes” and “[a]cid fracing . . . is used where the rock is susceptible to the
etching of an acid wash”—for example, in a limestone or dolomite formation (emphasis omitted)); KAUFMAN
ET AL., supra note 64, at 1 (“[T]he selection of the fluid and additives [is] based upon the mineralogy.”).
73 N.Y. DEPT. OF ENVTL. CONSERVATION, NATURAL GAS DEVELOPMENT ACTIVITIES & HIGH-VOLUME
HYDRAULIC FRACTURING: SUPPLEMENTAL GENERIC ENVIRONMENTAL IMPACT STATEMENT 40–48 (rev. draft
2011), http://www.dec.ny.gov/docs/materials_minerals_pdf/rdsgeisch50911.pdf (describing the typical
percentage of chemicals by volume and listing the chemicals used); Jo Melville, Fracking: An Industry Under
Pressure, 18 BERKELEY SCI. J., no.1, at 22, 25 (2013) (“Modern fracking fluid consists on average of 99.5%
freshwater and sand and a mere 0.5% additives.”).
74 GRAVES, supra note 72, at 100–01 (describing “slick water” fracking fluids); KAUFMAN ET AL., supra
note 64 (describing the additives and their purposes); supra note 73.
75 GRAVES, supra note 72, at 102–03; id. at 106 (“The choice of sand type, its source, and its composition
varies with each wellbore.”).
76 Montgomery & Smith, supra note 62, at 28.
77 Id.
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reflects difficulties in modeling the high-pressure dynamics of “sand-infused
liquids” and their interactions with rock formations that can be more than a
mile underground.78 Computer programs have been used to plan or simulate
fracking operations since the mid-1960s,79 but they have failed to remove all
elements of personal skill and luck from the process.80
In any event, fracking itself has not necessarily proven adequate to make
shale gas production economically viable. Even with fracking, traditional
vertical wells might not stimulate release of enough natural gas to justify their
cost. Gas is commonly trapped at low densities throughout large areas of a
shale and is often found in the greatest quantities in a small layer of the
formation—sometimes within a portion of the shale that is less than one meter
thick.81 To optimize gas recovery, another technology has frequently been
necessary: effective “directional drilling” in which oil and gas companies drill
a well vertically toward the formation that they are targeting, then
progressively slant the drill bit, and ultimately drill laterally through the
formation, sometimes for over a mile.82 This horizontal drilling can address
concerns with fracturing containment (limiting fractures to targeted areas of
underground rock)83 and, more intuitively for the inexpert, can allow more oil
or gas to flow from the shale by exposing more surface area in the formation,
both through the drilling itself and through the fractures that later emanate
78 See, e.g., GRAVES, supra note 72, at 107 (“The modeling of the fluid dynamics of sand-infused liquids
is an ongoing aspect of deep research in frac tech.”).
79 Montgomery & Smith, supra note 62, at 31–32.
80 GRAVES, supra note 72, at 103 (“Each choice [of fracking materials] depends on the engineering of the
hole, the rock below, the skill and function of the men and equipment—and a goodly dose of luck.”).
81 PASSEY ET AL., supra note 31, at 2 (noting that “the vertical variability in organic richness can vary on
relatively short vertical scales” that are “often much less than one meter”).
82 HALLIBURTON, U.S. SHALE GAS: AN UNCONVENTIONAL RESOURCE. UNCONVENTIONAL
CHALLENGES., 3 (2008) (noting that a “typical lateral” in the Barnett shale is “2,500 feet to 3,000 feet”); David
Blackmon, Horizontal Drilling: A Technological Marvel Ignored, FORBES (Jan. 28, 2013, 3:31 PM),
http://www.forbes.com/sites/davidblackmon/2013/01/28/horizontal-drilling-a-technological-marvel-ignored/
(“Horizontal Drilling now allows these [fracking] operators to drill and set pipe for a mile or more horizontally
through this same rock formation.”).
83 See Kent A. Bowker, Development of the Barnett Shale Play, Fort Worth Basin, SEARCH &
DISCOVERY, Apr. 18, 2007, art. no. 10126, at 1, 12 http://www.searchanddiscovery.com/documents/2007/
07023bowker/images/bowker.pdf (noting difficulty extending early successes in the Barnett Shale to areas
where the shale was “not bound above and below by effective frac barriers,” and observing that operators were
“experimenting with various completion techniques (including four horizontal wells) . . . in an attempt to
overcome the problem of fracing out of zone”).
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from the lateral wellbore.84 Although a horizontal well might cost, say, twice
as much as a traditional vertical well,85 it can also be three times as productive,
thereby substantially increasing the well’s overall benefit-to-cost ratio.86
The existence of a basic rationale for drilling horizontally through shale
formations was probably never hard to grasp. Developing the drilling and
drill-monitoring technologies necessary to do it efficiently was the hard part.87
Prior to the 1980s, available technologies were crude.88 “Early directional
drilling involved placing a steel wedge downhole (whipstock) that deflected
the drill toward the desired target, but [this technique] lacked control and
consumed time.”89 A great breakthrough came in the 1980s with the
introduction of the “steerable downhole motor.”90 This decade also witnessed
the first successful commercial horizontal drilling tests in the oil and gas
sector, tests initiated in the early 1980s by a French operator that worked in
southwestern France and offshore from Italy.91 Later in the decade, U.S.
84 See U.S. ENERGY INFO. ADMIN., U.S. DEPT OF ENERGY, NO. DOE/EIA-TR-0565, DRILLING
SIDEWAYS—A REVIEW OF HORIZONTAL WELL TECHNOLOGY AND ITS DOMESTIC APPLICATION 7 (1993); see
also YERGIN, supra note 13, at 328 (“Advances in controls and measurement allowed operators to drill down
to a certain depth, and then drill at an angle or even sideways. This would expose much more of the reservoir,
permitting much greater recovery of gas (or oil) from a reservoir.”).
85 S.D. JOSHI, SOCY OF PETROL. ENGRS, SPE 83621, COSTS/BENEFITS OF HORIZONTAL WELLS 2 (2003),
available at http://www.joshitech.com/images/spe83621.pdf (estimating that U.S. newly drilled horizontal
well costs to be “1.5 to 2.5 times more than a vertical well”).
86 G. WATERS ET AL., SOCY OF PETROL. ENGRS, SPE 103202, USE OF HORIZONTAL WELL IMAGE TOOLS
TO OPTIMIZE BARNETT SHALE RESERVOIR EXP LOITATION 2 (2006) (observing that Devon Energy’s experience
in drilling “over 50 horizontal wells” in 2002 and 2003 “indicated that compared to vertical wells, the
horizontals would have about three times the [estimated ultimate recovery] for twice the well cost”).
87 John E. Fontenot, Measurement While Drilling—A New Tool, J. PETROLEUM TECH., Feb. 1986, at 128;
see also Sara Pratt, A Fresh Angle on Oil Drilling, GEOTIMES (Mar. 2004), http://www.geotimes.org/mar04/
feature_horizdrill.html.
88 Lynn Helms, Horizontal Drilling, DMR NEWSL. (N.D. Dept. of Mineral Res., Bismarck, N.D.), Jan.
2008, art. no. 2, at 2, available at https://www.dmr.nd.gov/ndgs/documents/newsletter/2008Winter/pdfs/
Horizontal.pdf (asserting that one early source for notions of drilling horizontally through rock came from an
1891 patent for a flexible drilling shaft, which the inventor envisioned would be used by dentists but also for
“flexible shafts [of larger size,] . . . for example, . . . for drilling holes in boiler-plates or other like heavy
work” (internal quotation marks omitted)).
89 ANDREWS ET AL., supra note 72, at 19.
90 Pratt, supra note 87.
91 Helms, supra note 88, at 2; see also NATL RESEARCH COUNCIL, supra note 34, at 13 (describing the
government role in this area as “absent or minimal,” supporting that the U.S. government was not, for the most
part, involved in horizontal drilling research or direct financial support); U.S. ENERGY INFO. ADMIN., supra
note 84, at 7 (noting that earlier limited horizontal drilling also occurred, with “[t]he first recorded true
horizontal oil well, drilled near Texon, Texas” completed in 1929, another in 1944 in Pennsylvania, and still
others in China in 1957 and “later” in the Soviet Union, but observes that “little practical application occurred
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operators began applying this technique commercially in North Dakota’s
Bakken Shale and Texas’s Austin Chalk formations.92 The 1990s witnessed
further significant improvement through the development of “rotary steerable
systems” that could be redirected without having to interrupt drilling by
stopping rotation of the drill string.93 Finally, the development of
“measurement while drilling” technology, first commercialized in 1978,
enabled real-time downhole measurement of parameters “such as position,
temperature, pressure and porosity,” thereby facilitating better directional
control and more efficient and safer drilling, with the result being an even
more favorable benefit-to-cost ratio.94
The above description of fracking and drilling technologies allows some
appreciation of the web of technological developments that helped spur the
shale gas boom. But any such appreciation is only a beginning. Many
additional innovations underlie the boom and help explain comparison of
modern wellheads to “high-tech factories.”95 New or improved technologies in
locating, drilling, and fracturing for oil and gas include, among others, (1) 3D
seismic imaging techniques to locate areas of abundant gas and to better
understand the location of faults or of dips or rises in shale formations
themselves,96 techniques that have benefited from advances in computing and
that draw on technology originally developed to track submarines;97
until the early 1980’s”); WANG & KRUPNICK, supra note 13, at 10 (also noting the lack of government
involvement in horizontal drilling).
92 U.S. ENERGY INFO. ADMIN., supra note 84, at vii.
93 ANDREWS ET AL., supra note 72, at 19.
94 Pratt, supra note 87; see also Formation Evaluation Advances: An Integrated Focus, WEATHERFORD
MAG., May 2012, at 11, 12, http://www.weatherford.com/dn/WFT196437; cf. Drilling Dynamic Sensors and
Optimization, SCHLUMBERGER, http://www.slb.com/~/media/Files/drilling/brochures/mwd/drilling_dynamics_
sensors_opt_br.ashx (last viewed Mar. 5, 2015) (observing that various forms of downhole sensing allow
operators to avoid various drilling failures and thus reduce costs).
95 The Petrostate of America, supra note 51, at 10.
96 See Bowker, supra note 83, at 13 (testifying to the value of “[e]xcellent structural mapping” because
“wells located on structural flexures or near major faults are less productive”); Murray Roth, Unconventional
Reservoirs Require Unconventional Approach to Integrate, Interpret Data, AM. OIL & GAS REPORTER (Sept.
2010), available at https://www.transformsw.com/wp-content/uploads/2013/05/Unconventional-Reservoirs-
Require-Unconventional-Approach-To-Integrate-Interpret-Data-2010-American-Oil-and-Gas-Reporter-Roth.
pdf (noting how 3D seismic imaging can help to identify the particular fracturing “sweet spots”—in shale
areas with particular rock characteristics that make fracturing more efficient—and how understanding the
overall “thickness” of a shale is often not sufficient for effective shale production, as operators must identify
key characteristics of the shale in addition to faults, including portions of the shale where fracturing will most
likely create “permeability paths”).
97 WANG & KRUPNICK, supra note 13, at 10, 13–14 (describing horizontal drilling, hydraulic fracturing,
and 3D seismic mapping as the three technologies that spurred the boom); Kevin Begos, Fracking Developed
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(2) “microseismic fracturing mapping,” which typically uses a monitoring well
to study the “height, length, orientation, and other attributes of induced
fractures”;98 (3) equipment that isolates portions of a lateral wellbore and
thereby enables increased fracturing of the rock around a well;99
(4) polycrystalline drill bits with artificial diamond surfaces100 that are
particularly well suited to drilling hard rock;101 (5) “flexible coiled tubing,
continuously unreeled from a giant spool,” that, during the completion process,
can replace rigid well pipe and eliminate the need to interrupt use of a drill
while new “sections of pipe are screwed together”;102 (6) friction reducers for
fracking fluids;103 and (7) “smaller and lighter” drilling rigs that are easier to
transport between well pads.104 In short, an ever-expanding multiplicity of
technological developments have helped increase yields or reduce costs
associated with the exploitation of shale gas formations, thereby enabling the
favorable cost–benefit projections for producers that have spurred the shale gas
boom.
II. INFRASTRUCTURE AND MARKETS BEYOND THE WELLHEAD
Despite the shale gas boom’s multifarious technological backdrop, its
triggering is often described as the work of a single man. After expending
millions of dollars over a time period of nearly two decades,105 the
entrepreneurial George Mitchell ultimately saw his efforts to exploit the
Barnett Shale bear fruit: by the late 1990s, his company had developed an
with Decades of Government Investment, HUFFINGTON POST (Nov. 23, 2012, 5:12 AM EST), http://www.
huffingtonpost.com/2012/09/23/fracking-developed-government_n_1907178.html (“[T]echnology created to
track sounds of Russian submarines during the Cold War was repurposed to help the industry use sound to get
a 3-D picture of shale deposits and track exactly where a drill bit was, thousands of feet underground.”).
98 WANG & KRUPNICK, supra note 13, at 14.
99 See CLARK ET AL., supra note 65, at 3 (“Approximately 1,000 feet of wellbore is hydraulically
fractured at a time, so each well must be hydraulically fractured in multiple stages, beginning at the furthest
end of the wellbore.”).
100 MICHAEL P. GALLAHER, ALBERT N. LINK & ALAN O’CONNOR, PUBLIC INVESTMENTS IN ENERGY
TECHNOLOGY 97 (2012).
101 BURWEN & FLEGAL, supra note 50, at 6.
102 Pratt, supra note 87.
103 See HONG SUN ET AL., SOCY OF PETROL. ENGRS, SPE 139480, A NONDAMAGING FRICTION REDUCER
FOR SLICKWATER FRAC APPLICATIONS (2011) (discussing new friction reducers that enable better production).
104 Al Pickett, Technologies, Methods Reflect Industry Quest to Reduce Drilling Footprint, AM. OIL &
GAS REP. (July 2010), http://www.oilandgasbmps.org/docs/GEN170-reducedrillingfootprint.pdf.
105 See WATERS ET AL., supra note 86, at 1 (“Development of the Barnett Shale in the Ft. Worth basin
began in 1981 with the drilling of the Mitchell Energy C.W. Slay #1.”).
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approach to hydraulic fracturing that could yield surprising quantities of gas
relative to cost.106
This story is largely true. Mitchell was an innovator of remarkable
persistence, and he drew attention to the potential for shale gas production and
for the combined use of two distinct techniques that had been deployed
piecemeal over time. After years of failed trial and error, he and his
independent production company, Mitchell Energy and Development,
succeeded in “crack[ing] the Barnett’s code”107 through a technique of
slickwater fracturing that used formulas for fracking fluids remarkable for their
relative simplicity.108 In combination with horizontal drilling, the other leg of
the Mitchell synthesis, slickwater fracturing promised to make shale gas
production commercially viable on a broad scale, rather than the more limited
scale on which Mitchell’s shale gas production had previously occurred.109
When natural gas prices rose in the early 2000s,110 Mitchell’s example, which
106 See DAN B. STEWARD, THE BARNETT SHALE PLAY: PHOENIX FOR THE FORT WORTH BASIN, A HISTORY
124–29 (Frank Paniszczyn ed., 2007) (recounting how the results from 1998 “light sand” fracturing in the
Barnett Shale “changed [Mitchell Energy] and the industry’s attitudes about the Barnett” and “basically started
a leasing and drilling boom in southwest Denton and northwest Tarrant counties”).
107 YERGIN, supra note 13, at 327.
108 Bowker, supra note 83, at 8 (affirming that “[w]ater fracs . . . were a radical concept” for the Barnett
Shale “because the general consensus among completion engineers was that as much proppant (sand) as
economically possible had to be placed in the Barnett” and “un-gelled water can carry very little” proppant).
Slickwater fracturing combined several previous techniques, using more water, different chemicals, and
moderate amounts of sand, although even the slickwater technique varies among formations. See SUN ET AL.,
supra note 103 (“Slickwater fracturing, different from fracturing using cross-linked fluids, has been developed
and used in tight gas sand reservoirs since successful operations in the Cotton Valley Sand in East Texas in
1997.”); Silver, supra note 13 (“Instead of exotic formulas for hydraulic fracturing fluids used elsewhere, such
as in North Sea fields, Mr. Mitchell’s company simplified the process and used water . . . .”); see also WATERS
ET AL., supra note 86, at 1 (“In 1997 Mitchell Energy began to experiment with Slickwater stimulation
treatments. These treatments contained roughly twice the fluid volume of the large crosslinked treatments
previously pumped, but less than 10% of the proppant volume.”); Cahoy et al., supra note 26, at 285 (noting
that, in 1997, Mitchell energy found that well performance with slickwater hydraulic fracturing “was
somewhat better than [with] the crosslinked jobs, but stimulation costs were reduced by approximately 65%”).
See generally Wiseman, supra note 5, at 744 n.60 (describing older gel-based and high-sand-volume
techniques and providing sources).
109 See Thomas W. Merrill, Four Questions About Fracking, 63 CASE W. RES. L. REV. 971, 973 (2013)
(“After a long period of trial and error, an independent gas producer named George Mitchell . . . figured out
the right combination of horizontal drilling, pressure, and proppants to get the gas flowing out of shale.”).
110 See U.S. ENERGY INFO. ADMIN., U.S. DEPT OF ENERGY, DOE/EIA-0383, ANNUAL ENERGY OUTLOOK
2014 WITH PROJECTIONS TO 2040, at MT-21 to MT-23 & figs.MT-39 to MT-44 (2014), http://www.eia.gov/
forecasts/aeo/pdf/0383(2014).pdf (providing graphs showing how U.S. production of shale gas took off in the
middle of the first decade of the twenty-first century, a period when natural gas prices spiked upward and oil
prices consistently rose).
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culminated in the sale of Mitchell Energy to Devon Energy for $3.5 billion in
2002,111 became irresistible.112
Nonetheless, Mitchell himself would likely have disclaimed this tale’s
simplicity. Far from being an isolated innovator, he actively sought and used
private and public collaborators,113 and he applied for and received federal
incentive pricing for gas from the Barnett Shale.114 Private partners were also
critical for Mitchell’s success. In particular, Mitchell Energy’s long-term
contract to supply Natural Gas Pipeline of America was a major impetus
behind Mitchell’s interest and persistence in developing the Barnett.115
Moreover, a variety of other factors rooted in government support for
innovation and natural gas markets were essential drivers of the technological
revolution behind the shale gas boom. Of most immediate interest, changing
national approaches to oil and gas regulation of pipelines and pricing reshaped
potential markets for natural gas in ways that likely accounted for Mitchell’s
being active in the Barnett Shale at all.
A. Pipelines and “Pipeline Neutrality”
The availability of pipeline infrastructure centrally affects incentives to
produce oil and gas. Generally speaking, fossil fuels are extracted in locations
where they are abundant, and they must then be transported to the areas of
111 YERGIN, supra note 13, at 328.
112 J. DANIEL ARTHUR, BRUCE LANGHUS & DAVID ALLEMAN, ALL CONSULTING, AN OVERVIEW OF
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES 4–5 (2008), http://www.all-llc.com/
publicdownloads/ALLShaleOverviewFINAL.pdf (noting that “rapid increases in natural gas prices” in part
drove the recent expansion in use of Mitchell’s techniques).
113 See infra text accompanying notes 114–15.
114 See WANG & KRUPNICK, supra note 13, at 25 (noting that the Federal Energy Regulatory Commission,
at the request of Mitchell and the Texas Railroad Commission—the state’s oil and gas agency—approved the
designation of the Barnett Shale play as a “tight gas” formation, thus allowing sales of gas at a higher price,
but not as high of a price as other types of unconventional gas could receive).
115 See STEWARD, supra note 106, at 44 (observing that Mitchell Energy’s “NGPL contract in the North
Texas area” provided critical “price guarantees”); WANG & KRUPNICK, supra note 13, at 16 (stating that
contractual obligations to NGPL provided an “initial incentive for Mitchell Energy to develop the Barnett
play”).
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highest demand.116 For oil and gas, such transport commonly comes via
pipelines.117
But the need for pipelines leads to classic problems of mismatch between
group interests and individual capacities or incentives. Pipelines, particularly
long interstate pipelines, can be expensive to build, and successful construction
of interstate pipelines in the United States had historically required navigation
of multiple states’ policies on siting and land acquisition, as well as the hazard
of potentially inconsistent regulation even after construction.118 Producers
could lack either the resources or incentive to run this gauntlet individually,
and even if a private entity succeeded in constructing an interstate pipeline, the
pipeline might be closed—or accessible only irregularly or at exorbitant cost—
to others.119 The federal government addressed these problems by regulating
prices associated with the use of interstate pipelines120 and by providing federal
siting and eminent domain authority121 to ease the process of construction.
Eventually, the federal government also required open access to pipelines, thus
enabling more competition in the production of gas for remote markets.122 By
the late 1990s, these changes had converged to create abundant pipeline
capacity that, combined with updated pricing policies, helped spur new natural
116 See Richard J. Pierce, Jr., Reconstituting the Natural Gas Industry from Wellhead to Burnertip,
9 ENERGY L.J. 1, 4 (1988) (noting that when interstate pipelines began to be developed, “the available supplies
of natural gas were in different states than the major population and industrial centers where demand for gas
was large and growing”).
117 Id. (“[G]as can be transported economically only by pipeline.”); Refinery Receipts of Crude Oil by
Rail, Truck, and Barge Continue to Increase, U.S. ENERGY INFO. ADM IN. (July 17, 2013),
http://www.eia.gov/todayinenergy/detail.cfm?id=12131 (noting that half of the crude oil received by U.S.
refineries flows through pipelines, although transport by barge, truck, and rail is growing).
118 See Alexandra B. Klass & Danielle Meinhardt, Transporting Oil and Gas: U.S. Infrastructure
Challenges, 100 IOWA L. REV. (forthcoming 2015) (manuscript at 36), available at http://ssrn.com/abstract=
2410977 (“Consuming and producing states regularly imposed regulations on pipelines that were
inconsistent . . . .”); Pierce, supra note 116, at 5 (noting state policies that served as barriers to interstate
pipelines).
119 See Robert J. Michaels, The New Age of Natural Gas: How the Regulators Brought Competition,
REGULATION, Winter 1993, at 68, 68–69 (noting that the Natural Gas Act of 1938 capped the prices that
interstate pipelines could charge for the use of their lines but did not require open access, and pipelines
typically purchased “gas . . . at the wellhead and, passing on the purchase price, resold it to distributors” rather
than giving “producers or users” direct access to pipelines); Pierce, supra note 116, at 6–7 (observing that
pipelines “were not obligated to provide third parties access to their facilities” and noting their “precluding” of
beneficial transactions).
120 See infra note 133 and accompanying text.
121 See infra notes 133–34 and accompanying text.
122 See infra note 143 and accompanying text.
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gas production for sale to out-of-state markets.123 This transition was not quick,
however; it was the culmination of several historic innovations and policy
changes.
As Alexandra Klass and Danielle Meinhardt describe, improved
technologies for welding, stronger pipeline materials, and better compressors
necessary for transporting natural gas long distances matured shortly after
discovery of large natural gas fields in Kansas, Oklahoma, and Texas in
1918.124 In 1924, the U.S. Supreme Court declared that states could not
regulate the prices charged by interstate pipelines,125 thereby removing one set
of obstacles to pipeline construction and operation. In the wake of these
developments, “twelve major gas transportation systems” emerged between
1927 and 1931.126 But the constituent pipelines did not form a truly national
network, and they left the Northeast, for example, in a common state of
shortage.127 Further, in the absence of federal regulation, abolition of state
regulation had opened a regulatory gap.128 Interstate pipeline companies, which
purchased gas from producers and sold the gas to instate and out-of-state
consumers, became local monopsonists in dealing with producers and
oligopolists in dealing with consumers (typically simply called monopolists,
although in some cases more than one pipeline was available within a region),
exercising their resulting pricing power to their own advantage.129
In the 1930s, the pricing practices of pipeline companies, combined with an
abundance of gas in and around Texas and relative scarcity in the Northeast,
induced a diverse group of lobbyists to demand federal intervention.130 This
group included a coalition of cities that wanted better access to gas, the coal
industry that believed federal regulation would in fact “drive up prices,” and
producers and consumers who suffered from the pipeline companies’ pricing
123 Cf. Michael J. Doane, R. Preston McAfee & Michael A. Williams, Evaluating and Enhancing
Competition in the Interstate Natural Gas Transportation Industry, 44 NAT. RESOURCES J. 761, 768 (2004)
(noting the interconnection and integration of pipelines by the 1990s and expanded regional and national
access to gas).
124 Klass & Meinhardt, supra note 118 (manuscript at 36).
125 Missouri v. Kan. Natural Gas Co., 265 U.S. 298 (1924).
126 Klass & Meinhardt, supra note 118 (manuscript at 36).
127 Id. (manuscript at 38) (observing that “from 1932 until World War II” the “Northeastern market
potential was immense, but no major pipelines existed to bring gas to that populous region”).
128 See id. (manuscript at 37) (discussing regulation arising in the aftermath of Kansas Natural Gas Co.).
129 See Pierce, supra note 116, at 4–6.
130 Klass & Meinhardt, supra note 118 (manuscript at 37).
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practices.131 At the recommendation of the Federal Trade Commission,
Congress passed the Natural Gas Act of 1938, providing for federal authority
over the interstate transportation of natural gas, among other interstate gas
activities.132 The Federal Power Commission (FPC) and, later, the Federal
Energy Regulatory Commission (FERC) regulated natural gas prices,133
approved certificates for new interstate pipelines,134 and granted eminent
domain authority for the siting of pipelines,135 allowing an interstate network
of natural gas pipelines to flourish.136
Nonetheless, access to pipelines remained limited. The FPC capped the
price that natural gas pipelines could charge for the natural gas they purchased,
transported, and sold, but these companies were not required to allow
producers to use the pipelines.137 Moreover, the FPC had long “refused to
allow pipelines to transport gas sold directly by producers to end-users”
because of the Commission’s inability to regulate prices for such sales.138 As a
result, pipelines typically purchased gas from producers and resold it, and a
number of producers had only limited access to markets.139 Beginning in 1976,
however, the FPC began to grant a limited number of producers direct access
to consumers, allowing case-by-case approvals for pipeline transport of gas
sold directly from producers to “high priority” commercial and industrial
consumers.140 Two additional orders (now from FERC) in 1979 further
supported sales directly from producers to consumers: Order 27 provided
blanket approvals for pipelines to transport gas sold from producers directly to
131 Id.
132 Natural Gas Act, ch. 556, 52 Stat. 821 (1938) (codified as amended at 15 U.S.C. §§ 717–717z (2012)).
133 Id. § 4(a), 52 Stat. at 822.
134 Id. § 7(c), 52 Stat. at 825.
135 Id. § 7(a), 52 Stat. at 824.
136 Klass & Meinhardt, supra note 118 (manuscript at 36) (“Between 1927 and 1931 about twelve major
gas transportation systems developed, all over 200 miles long.”).
137 See Pierce, supra note 116, at 24 (“[B]y regulating pipeline sales but not pipeline transportation,
Congress and the FERC had created artificially pipeline monopoly power . . . .”).
138 Robert C. Means & Robert S. Angyal, The Regulation and Future Role of Direct Producer Sales,
5 ENERGY L.J. 1, 5 (1984).
139 See Michaels, supra note 119, at 69 (“[I]nstead of transporting gas owned by producers or users,
pipelines purchased it at the wellhead and, passing on the purchase price, resold it to distributors.”); Richard J.
Pierce, Jr., Natural Gas Regulation, Deregulation, and Contracts, 68 VA. L. REV. 63, 79 (1982) (explaining
that from the 1930s through 1950s, “monopsony conditions prevailed in much of the market: a single pipeline
provided the sole market outlet for a number of competing producers”).
140 Certification of Pipeline Transportation Agreements, 40 Fed. Reg. 41,760, 41,760 (Aug. 28, 1975); see
also Sean J. McNulty, Comment, Freeing the Captives: Nondiscriminatory Access to Transportation in the
Interstate Natural Gas Market, 47 U. PITT. L. REV. 843, 849 (1986) (describing the order).
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critical agricultural users, hospitals, and schools,141 and Order 30 granted
similar pipeline transport authority for natural gas sold directly from producers
to consumers in lieu of scarce fuel oil.142 Later, in 1985, FERC Order 436 gave
pipelines “expedited,” blanket approval to enter into open-access gas
transportation contracts with third-party shippers if the pipelines accepted the
risk for the pipeline (rather than passing costs to existing customers) and met
other conditions.143 Finally, in 1992, FERC Order 636 dramatically
restructured the pipeline business, requiring the functional separation of
interstate pipeline companies’ gas purchasing and selling activities from their
transportation business144 and mandating that these companies offer
open-access service.145 Under Order 636, pipeline companies could not favor
their own gas in the operation of pipelines,146 and they had to provide
electronic pricing and service information so that their terms were
transparent.147
When producers, including smaller independents like Mitchell Energy,
could directly access larger numbers of distant purchasers—particularly those
in the relatively gas-poor Northeast—they could anticipate lucrative returns
141 Certification of Pipeline Transportation for Certain High Priority Uses, 44 Fed. Reg. 24,825, 24,825,
24,828 (Apr. 27, 1979) (allowing “the transportation of natural gas sold by a producer to an eligible user” and
defining eligible uses).
142 Transportation Certificates for Natural Gas for the Displacement of Fuel Oil, 44 Fed. Reg. 30,323,
30,329 (May 25, 1979) (exempting pipelines from previously-required FERC approval of transportation of
natural gas from producers—“first sales”—to suppliers of natural gas who would otherwise use fuel oil); see
also McNulty, supra note 140, at 850 (describing the order).
143 See Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 50 Fed. Reg. 42,408,
42,467 (Oct. 18, 1985) (establishing “Optional Expedited Certificates” that provided blanket authorizations for
pipelines to transport gas for third-party shippers if pipelines agreed to take on the risk of building the pipeline
and met other conditions); see also Thomas P. Lyon & Steven C. Hackett, Bottlenecks and Governance
Structures: Open Access and Long-term Contracting in Natural Gas, 9 J.L. ECON. & ORG. 380, 387 (1993)
(describing the order).
144 Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing
Transportation; and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 Fed. Reg.
13,267, 13,281 (Apr. 16, 1992) (requiring “firm and interruptible transportation services to be provided
unbundled from firm and interruptible sales”).
145 See id. at 13,281–82 (requiring “an open-access pipeline that offers firm and interruptible
transportation services to provide those transportation services . . . on a basis that is equal in quality for all gas
supplies, whether purchased from the pipeline or elsewhere” and allowing “firm” shippers—those who commit
to using a certain amount of pipeline space—to “release unwanted capacity to those desiring capacity”).
146 Id. at 13,288 (prohibiting pipeline companies from “creating an advantage to the pipeline as seller or
to its marketing affiliate” in “operational provisions”).
147 See id. at 13,281 (requiring “a pipeline to provide all shippers equal and timely access to certain
information through the use of electronic bulletin boards”).
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even from more-expensive, less-accessible gas reserves that required
sophisticated technologies for extraction. The natural result was incentive to
exploit such reserves. As “commons” theorists might hasten to point out,148 it
seems more than mere coincidence that FERC’s adoption of a “pipeline
neutrality” policy was followed within about a decade by Mitchell Energy’s
breakthroughs and subsequent market recognition of shale gas’s commercial
potential.149
B. Oil and Gas Markets
As pipeline policy gradually expanded access to the infrastructure needed
by natural gas producers, federal pricing policies also attempted to encourage
the production of oil and natural gas from unconventional formations.150 A
Supreme Court decision in the 1950s forced the FPC, and later FERC, to
regulate all prices of gas at the wellhead if that gas was eventually to be sent
interstate.151 Such regulation effectively discouraged the overall production of
natural gas, including unconventional natural gas.152 As the interstate price was
capped, producers commonly had insufficient incentive to sell gas to distant
interstate users who badly needed the gas.153 Likewise, price caps could
148 Cf. Yochai Benkler, Commons and Growth: The Essential Role of Open Commons in Market
Economies, 80 U. CHI. L. REV. 1499, 1504 (2013) (reviewing BRETT M. FRISCHMANN, INFRASTRUCTURE: THE
SOCIAL VALUE OF SHARED RESOURCES (2012)) (“Rapid growth and change . . . depend on significant levels of
freedom to operate . . . and therefore require substantial commons in resources.”).
149 Interview by Michael Shellenberger with Dan Steward, Former Mitchell Energy Vice President, (Dec.
12, 2011), available at http://thebreakthrough.org/archive/interview_with_dan_steward_for [hereinafter
Shellenberger Interview] (recording Steward’s statements that Mitchell Energy had proven shale gas’s
commercial viability by 2000 and that financial markets ultimately recognized this in 2002).
150 Pierce, supra note 116, at 11–16 (describing and criticizing Natural Gas Policy Act pricing policies,
including policies that maintained price ceilings on “old,” conventional gas that already was being produced
and raised or eliminating ceilings for other types of gas); Pierce, supra note 139, at 68 (“Lower ceilings were
established for ‘old gas,’ or gas flowing from existing wells, reflecting the Commission’s determination that
gas would continue to flow from existing wells at roughly constant costs. Higher ceilings were established for
‘new gas,’ or gas produced from wells drilled later, to preserve exploration incentives.”).
151 Phillips Petrol. Co. v. Wisconsin, 347 U.S. 672 (1954); see also Pierce, supra note 139, at 66
(discussing the Supreme Court decision and FERC’s previous interpretation of its authority).
152 Pierce, supra note 139, at 69 (“There is no longer serious doubt that regulation of gas producer prices
was the dominant factor responsible for the gas shortage that caused significant economic dislocations in the
United States from 1969 through 1978.”).
153 See supra note 152; see also ENERGY CHARTER SECRETARIAT, PUTTING A PRICE ON ENERGY:
INTERNATIONAL PRICING MECHAN ISMS FOR OIL & GAS 111 (2007) (“It gradually became apparent that
wellhead price controls in their then-existing form were unworkable. By the late 1960s, the system was
beginning to develop serious supply problems, and by the early 1970s gas shortages became increasingly
severe, leading to supply curtailments of large customers.”); PAUL W. MACAVOY, THE NATURAL GAS
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eliminate prospects for profit from more marginal reserves, including
unconventional gas reserves, for which the private cost–benefit calculus was
not among the most favorable.154
Government attempts to reform gas markets followed. In the 1960s, FERC
attempted to enhance the production of domestic gas without causing excessive
inflation, and it did this by setting lower prices for gas from existing wells that
was sold interstate and allowing higher prices for interstate gas produced from
newly drilled wells.155 But shortages remained, and an increasingly complex
pricing scheme coincided with an overall decline of the “total quantity of gas
made available to the market.”156 In the Natural Gas Policy Act of 1978,
Congress later helped stimulate the production of “deep” gas and “tight” gas—
resources that tended to require unconventional technologies like horizontal
drilling (and ultimately fracturing)—by allowing producers to charge higher
interstate rates for gas produced from unconventional formations.157 In 1989,
Congress fully deregulated the price of natural gas at the wellhead, albeit with
several transition years for price deregulation to take complete effect.158
Deregulation allowed all producers to charge market prices for all types of
gas.159
In short, gradual changes in pricing policies, combined with regulations
enabling the siting and construction of pipelines and requiring open access to
these pipelines, created the national market that was necessary to support
MARKET: SIXTY YEARS OF REGULATION AND DEREGULATION 1–2 (2000) (“Federal regulatory policy in the
1960s and 1970s placed limits on gas prices that caused significant nationwide shortages, and in response, new
policy in the late 1970s then caused surpluses that closed down production facilities and led to dumping gas in
spot markets.”).
154 Cf. Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 50 Fed. Reg. 42,408, 42,416
(Oct. 18, 1985) (noting various market distortions caused by price ceilings and that when Congress deregulated
the price that could be charged for alternative gas supplies and gas found very deep underground, “[p]rices
rose sharply,” and “[m]any millions of dollars were spent on exploring for gas that the market seemed to be
saying could be sold” at a high price); Pierce, supra note 139, at 68–69 (in discussing the regional—“area”—
rates established for natural gas prices at the wellhead, and the higher price allowed to be charged for newly
drilled gas in an effort to encourage production, noting that “to avoid discouraging production would have
required ongoing company-by-company cost determinations”).
155 Pierce, supra note 139, at 68.
156 Id. at 69.
157 Natural Gas Policy Act of 1978, Pub. L. No. 95-621, 92 Stat. 3350, amended by Natural Gas Wellhead
Decontrol Act of 1989, Pub. L. No. 101-60, 103 Stat. 157; see Hinton, supra note 6, at 233 (noting that the
Natural Gas Policy Act of 1978 “offered natural gas producers substantial price incentives to find and produce
gas from riskier, more expensive exploration”).
158 § 2(b), 103 Stat. at 158.
159 Id. § 2(a), 103 Stat. at 157–58 (providing that “maximum lawful prices” of gas should cease to apply).
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high-priced drilling and fracturing by a multitude of independent producers,160
smaller players that, unlike “major multinational companies such as
ExxonMobil,” are generally “not vertically integrated” and “are usually
regionally focused.”161 By the early 1990s, the foundations for a vibrant
national market in natural gas—open-access interstate pipelines and favorable
policies on pricing—were in place.
III. GOVERNMENT SUPPORT
Government contributions to the fracking revolution did not stop with
transport and market infrastructure. Federal and state governments also
supported relevant technological and commercial developments through a
variety of frequently more targeted means, including direct government
research, government funding, collaborative research projects and public–
private partnerships, tax preferences, and regulatory exemptions.162 This Part
discusses such mechanisms and their roles in fostering the shale gas boom.
A. Publicly Funded Research and Public–Private Partnerships
The U.S. government funded or performed both basic and applied research
that helped prime the pump for the ultimate shale gas boom. Energy crises of
the early and mid-1970s prompted Congress and President Ford to create the
Energy Research and Development Administration (ERDA) in 1976, with
promotion of “Unconventional Gas Research” as one of its goals.163 ERDA
promptly began collaborating with universities and industry to “develop[] an
160 One could argue that without federal intervention, we would not have had the pricing problems
initially created by interstate price caps. This is true, but the specific incentives provided to tight and deep gas
on the interstate market—although part of a generally problematic pricing policy—did serve to encourage the
development of unconventional resources. See Hinton, supra note 6, at 233 (observing that, after the Natural
Gas Policy Act of 1978, “[t]hose willing to focus on natural gas and willing to try expensive, marginally
profitable projects that would likely be rejected by the majors’ boards of managers finally had federal blessing
to try their luck”).
161 Id. at 229.
162 See infra Part III.C. See generally Federal Financial Support for Energy Technologies: Assessing
Costs and Benefits: Hearing Before the Subcomm. on Energy of the H. Comm. on Sci., Space & Tech., 113th
Cong. 20 (2013) (statement of Terry Dinan, Senior Analyst, Congressional Budget Office), available at http://
www.cbo.gov/sites/default/files/cbofiles/attachments/03-12-EnergyTechnologies.pdf (describing different
financial mechanisms for government support).
163 BURWEN & FLEGA L, supra note 50, at 2 (“In 1976, Congress funded the Energy Research and
Development Administration . . . to launch the Unconventional Gas Research (UGR) program.”).
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inventory of the unconventional gas resources across several regions,”164 and
ERDA’s 1977 successor, the DOE, continued such work.165
For our purposes, perhaps the most important program initiated by ERDA
was the Eastern Gas Shales Program (EGSP), which ERDA launched in 1976
and the DOE sustained until 1992.166 In 1975, the federal government had
partnered with industry to drill the “first Appalachian Basin directional wells to
tap shale gas, and shortly thereafter completed the first horizontal shale well to
employ seven individual hydraulically fractured intervals.”167 Building from
these successes, EGSP focused on the Devonian shales of the Appalachian,
Michigan, and Illinois Basins.168 Through EGSP, ERDA worked with industry,
universities, and state geological surveys169 “to assess the resource base, in
terms of volume, distribution, and character” and also to develop technologies,
including massive hydraulic fracturing, for monitoring and completing drilling
of wells to exploit those resources.170 The EGSP supported the drilling of about
thirty-five experimental wells that demonstrated, among other things,
possibilities for horizontal drilling.171 The EGSP also supported “theoretical
and experimental research on hydraulic fracturing by Lawrence Livermore
Laboratory” and collaborative work on fracturing by the Stanford Research
164 Id.
165 NATL RESEARCH COUNCIL, supra note 34, at 1.
166 Id. at 201.
167 NATL ENERGY TECH. LAB., U.S. DEPT OF ENERGY, SHALE GAS: APPLYING TEC HNOLOGY TO SOLVE
AMERICAS ENERGY CHALLENGES 5 (2011), http://www.netl.doe.gov/file%20library/research/oil-gas/Shale_
Gas_March_2011.pdf [hereinafter NETL REPORT].
168 See NATL ENERGY TECH. LAB., U.S. DEPT OF ENERGY, DOE’S UNCONVENTIONAL GAS RESEARCH
PROGRAMS 1976–1995, at 16 (2007), http://www.netl.doe.gov/KMD/cds/disk7/disk2/Final%20Report.pdf
(discussing the Appalachian, Illinois, and Michigan Basins in relation to “[t]hick Devonian-age black shales
underl[ying] extensive areas of the eastern United States”).
169 Leo A. Schrider & Robert L. Wise, Potential New Sources of Natural Gas, 32 J. PETROLEUM TECH.
703, 703–04 (1980).
170 NATL RESEARCH COUNCIL, supra note 34, at 201; cf. Schrider & Wise, supra note 169, at 709
(reporting that, by 1980, “36 stimulation treatments [of wells, at least some involving a form of hydraulic
fracturing,] ha[d] been performed in 22 Devonian shale wells”); see also ENERGY SYS. PLANNING DIV., TRW,
INC., CORING AND LOGGING PLAN: EASTERN GAS SHALES PROJECT (1977), available at http://www.netl.doe.
gov/kmd/cds/disk7/disk1/EGS%5CCoring%20and%20Logging%20Plan,%20Eastern%20Gas%20Shales%20P
roject.pdf.
171 BURWEN & FLEGAL, supra note 50, at 3 (“The EGSP resulted in the drilling and coring of
approximately 35 experimental wells in Devonian shales of the Appalachian basin, which revealed the impact
of horizontal drilling on shale gas recovery.”); see also THADDEUS S. DYMAN, U.S. DEPT OF INTERIOR
GEOLOGICAL SURVEY, NO. 81-598, EASTERN GAS SHALES PROJECT (EGSP) DATA FILES : A FINAL REPORT
(1981), http://www.netl.doe.gov/kmd/cds/disk7/disk1/EGS%5CEastern%20Gas%20Shales%20Project%20%
28EGSP%29%20Data%20Files%20A%20Final%20Report.pdf.
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Institute, Sandia Laboratories, and others.172 In total, the EGSP spent about
$185 million in 2011 dollars,173 with peak spending occurring during the first
several years of the program.174
The amounts spent by the EGSP were modest in the context of overall
spending of tens of billions of dollars by industry and government on
energy-related research and development.175 But the EGSP’s contributions
came at critical times when the possibilities for exploitation of shale gas
reserves were poorly understood,176 when large oil and gas companies were
reducing investment in research and development,177 and when, as has
continued to be the case,178 the field of unconventional gas recovery was
largely dominated by relatively small independents with limited budgets for
research and development.179 As one set of commentators concluded, “The
resulting maps and technical reports both proved the extent of shale gas
resources and shared technological know-how with industry, demonstrating
market potential and lowering risks to early entrants.”180 Resource estimates of
172 Schrider & Wise, supra note 169, at 709.
173 BURWEN & FLEGAL, supra note 50, at 3.
174 Id. (reporting that the EGSP’s peak budget was $18 million—or $47 million in 2011 dollars—in
1979); NATL RESEARCH COUNCIL, supra note 34, at 201 (“DOE expenditures from 1978 through termination
of the program in 1992 amounted to $137 million (1999 dollars), with about two-thirds of the total having been
expended between 1978 and 1982.” (citation omitted)).
175 Cf. MIT ENERGY INITIATIVE, THE FUTURE OF NATURAL GAS: AN INTERDISCIPLINARY MIT STUDY 160
(2011), https://mitei.mit.edu/system/files/NaturalGas_Report.pdf [hereinafter MIT STUDY] (“Relative to the
role of natural gas in the energy sector, the Department of Energy (DOE), the lead government funder of
energy R&D, has historically had very small programs dedicated to natural gas exploration, production,
transportation and use.”); NATL RESEARCH COUNCIL, supra note 34, at 1 (“From 1978 through 1999, the
federal government expended $91.5 billion (2000 dollars) on energy R&D, mostly through DOE programs.
This direct federal investment constituted about a third of the nation’s total energy R&D expenditure . . . .”).
176 See NATL RESEARCH COUNCIL, supra note 34, at 201 (“The DOE program was responsible for
bringing together and integrating a significant amount of scattered data on the Eastern gas shales critical to a
solid assessment of the resource base.”).
177 BURWEN & FLEGAL, supra note 50, at 5 (“Starting in the early 1980s, major oil and gas companies
began to decrease their research and development spending . . . .”).
178 Hinton, supra note 6, at 235 (“It is significant that as shale production has taken off in many areas,
independents still dominate shale action, greatly outnumbering and outspending major and national oil
companies.”).
179 See BUR WEN & FLEGAL, supra note 50, at 2 (“[T]he Eastern Gas Shales Project (EGSP) determined
the recoverable reserves of Devonian shale gas and financed experimental shale wells—at a time when most
firms in unconventional gas recovery had little or no research budgets.”); NATL RESEARCH COUNCIL, supra
note 34, at 201 (describing the EGSP as “designed to assess the resource base . . . and to introduce more
sophisticated logging and completion technology to an industry made up mostly of small, independent
producers”).
180 BURWEN & FLEGAL, supra note 50, at 2.
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the kind generated by the EGSP are essential for the industry, as they help
determine where productive wells might most reasonably be drilled and
fractured. Mitchell and his staff themselves studied EGSP data in support of
their efforts to “crack” the Barnett Shale even though that formation was not
part of the Devonian formations on which the EGSP focused.181
A number of the EGSP’s investments turned out to be not only relatively
well targeted but also well leveraged through the DOE’s partnerships with
other actors and especially the Gas Research Institute (GRI), “a private
non-profit research management organization formed in 1976 and funded
through a FERC-sanctioned surcharge placed on interstate pipeline gas
volumes.”182 From the start, a goal of the EGSP was to “encourage[] private
industry to initiate and direct R&D projects by sharing the risks and costs of
development.”183 In turn, GRI was perhaps the leading embodiment of a
public–private partnership in this area.
GRI, which had “members from all three segments of the industry—
producers, pipelines, and local distribution companies”—acted “as the R&D
arm of the natural gas industry,” a regulated industry that policymakers had
believed underinvested in research and development.184 GRI had much more
money at its disposal than did the EGSP: its “early budget was approximately
$40 million per year, growing to $200 million per year in the 1990s.”185 GRI’s
peak annual budgets thus exceeded the total amount spent by the EGSP during
the decade and a half of its existence.186 Moreover, of likely significance for
businesses seeking assurance in making long-range plans, GRI’s funding was
relatively stable and “independent of annual Congressional appropriations.”187
181 Loren Steffy, How Much Did the Feds Really Help with Fracking?, FORBES (Oct. 31, 2013, 9:21 AM),
http://www.forbes.com/sites/lorensteffy/2013/10/31/how-much-did-the-feds-really-help-with-fracking/.
182 MIT STUDY, supra note 175, app. 8A, at 3. Deregulation of the natural gas industry ultimately led to
the termination of GRI, which was replaced by the Gas Technology Institute in 2000 and then, after the ending
of the FERC surcharge in 2004, the Royalty Trust Fund, which has a narrower focus on production and a
research budget less than one fourth that of GRI at its peak. Id. app. 8A, at 5–6. But GRI lasted through the late
1990s, when Mitchell made his critical breakthrough with slickwater hydraulic fracturing.
183 Schrider & Wise, supra note 169, at 704.
184 William M. Burnett, Dominic J. Monetta & Barry G. Silverman, How the Gas Research Institute (GRI)
Helped Transform the US Natural Gas Industry, INTERFACES, Jan.–Feb. 1993, at 44, 45 (“Regulated
industries, most notably electric and gas utilities, historically have underinvested in R&D.”).
185 BURWEN & FLEGAL, supra note 50, at 4.
186 See supra text accompanying notes 173–74.
187 MIT STUDY, supra note 175, app. 8A, at 5.
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Consistent with the nature of GRI’s membership, GRI “was dedicated to
natural gas [research, development, and demonstration] across the value
chain,” from wellhead to consumer.188 Overall, GRI’s work had a more applied
focus than the DOE’s work,189 with GRI concentrating on “commercialization
and deployment of technologies that were of interest to the industry, including
new logging techniques, reservoir models, and simulation technologies.”190 But
the work of the DOE and GRI was not purely complementary: they sometimes
collaborated directly, as in coordinating with private companies to fund the
drilling of experimental horizontal wells.191 Indeed, the reduction in DOE
funding for natural gas research and development in the 1980s has been at least
partly attributed to the availability of funding through GRI.192
DOE and GRI funding and leadership not only helped set the technological
agenda for improvements in natural gas extraction but also encouraged
information sharing. As a condition of federal support for GRI, its projects
were required to publish all findings, and industry partners were required to
surrender claims to intellectual property rights in these findings.193 “Moreover,
FERC made GRI indifferent to [intellectual property] royalties by subtracting
any royalties from FERC funding; this ensured that GRI focused on technology
diffusion as much as possible, rather than [on] support[ing] itself from
licensing income.”194
Quite generally, GRI appears to have helped foster an environment
favorable to adoption of new technologies by independent producers, with
whom GRI collaborated extensively. In 1991, Mitchell Energy began working
directly with the DOE and GRI, joining with them over a period of several
years to drill Mitchell’s first horizontal well in the Barnett and, more generally,
188 Id. at 160.
189 BURWEN & FLEGAL, supra note 50, at 4 (“DOE and GRI complemented each other; DOE concentrated
on basic research R&D to generate more data on and develop new exploration and production techniques,
while the GRI program focused on commercialization and deployment of technologies for industry.”).
190 MIT STUDY, supra note 175, app. 8A, at 5.
191 BURWEN & FLE GAL, supra note 50, at 2 (“Experimental horizontal wells for shale gas, drilled
conjointly with DOE, GRI, and individual companies, proved methods for the industry at a time when no firm
was willing to try on its own.”); see also MIT STUDY, supra note 175, app. 8A, at 4 (noting that GRI
“sometimes provid[ed] substantial industry match into the smaller DOE programs”).
192 MIT STUDY, supra note 175, app. 8A, at 4 (“To a large extent, the sharp decrease in the DOE natural
gas [research, development, and demonstration] program funding in the 1980s is attributable to the existence
of the larger GRI program and the prevailing view that oil and gas RD&D could be left to industry.”).
193 BURWEN & FLEGAL, supra note 50, at 5.
194 Id.
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to develop knowledge and techniques that would prove useful later.195 More
generally, the GRI board apparently showed a solid capacity to respond to
input from industry.196 Mitchell was on the GRI board, and Mitchell’s
persistence was “generally credited with establishing the GRI focus” on
unconventional natural gas.197 In turn, the GRI board “convinced DOE to
refocus away from Eastern Gas shales to first Michigan’s Antrim shales and
then Texas’ Barnett shales,” where the revolution ultimately took off.198
In addition to helping individual operators like Mitchell, DOE and GRI
supported development of a number of significant technologies. DOE and GRI
contributions to demonstrations and development of techniques of horizontal
drilling and hydraulic fracturing have already been noted.199 Other key
technologies to which DOE and GRI contributed were polycrystalline diamond
drill bits,200 measurement and logging of critical data while drilling,201 and 3D
seismic imaging.202
The story of DOE’s support of innovation in drill bits is of particular
interest because it illustrates the unpredictable path that breakthrough
innovations can take. In the 1970s, the DOE supported the development of new
drill bits “that would be more suitable than traditional drill bits for the
high-density, high-temperature applications needed to drill geothermal
195 See Shellenberger Interview, supra note 149 (quoting a former Mitchell Energy vice president as
saying that, through the end of the 1990s, the federal government and GRI helped Mitchell Energy develop
knowledge about the Barnett Shale, drill its “first horizontal well” in the Barnett, map cracks, and work on
“re-fracks of shale wells”); supra note 20.
196 Burnett et al., supra note 184, at 46 (“GRI uses a comprehensive strategic planning and analysis
approach with wide-ranging advisory input to develop its annual five-year plan.” (citation omitted)).
197 MIT STUDY, supra note 175, app. 8A, at 5.
198 BURWEN & FLEGAL, supra note 50, at 4–5.
199 See supra text accompanying notes 188–95.
200 See supra text accompanying note 100.
201 NATL RESEARCH COUNCIL, supra note 34, at 195 (noting that the DOE “supported a field
demonstration of [mud pulse telemetry] in its very early and critical phase of development”); NETL REPORT,
supra note 167, at 6 (suggesting that modern directional drilling technologies such as electromagnetic
telemetry had their “roots in DOE research from the 1980s and 90s.”).
202 See WANG & KRUPNICK, supra note 13, at 13–14 (discussing a DOE seismic imaging program that
began in 1988, DOE-sponsored mapping research at Los Alamos National Laboratory, and a “DOE Multiwell
Site experiment in Colorado”); cf. N
ATL RESEARCH COUNC IL, supra note 34, at 208, 211 (noting that,
although “[t]he advances in seismic technology have been developed mostly by industry,” “federal
government funding geared to certain niche areas—for instance, cross-well seismic, utilization of special
expertise and facilities such as the high-performance computing capabilities of the national laboratories, or the
support of seismic surveying for independent operator . . . is a useful adjunct to a major private sector
activity”).
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wells.”203 Fortuitously, the resulting polycrystalline diamond bits turned out to
be tremendously useful in drilling oil and gas wells and lowered drilling costs
substantially204—a development that was presumably of particular importance
for the drilling of long horizontal wells through concrete-like shale rock. A
recent study estimates that the new polycrystalline drill bits yielded cost
savings of $15.6 billion from 1982 to 2008, with half of this added value
attributed to the DOE’s investment of a mere $26.5 million during that
period.205
B. Tax Relief
Government support for new and improved oil and gas development
techniques has included a variety of tax incentives and regulatory exemptions.
The tax benefit that tends to draw the greatest attention is the Section 29 tax
credit for “natural gas production from unconventional natural gas wells drilled
between 1980 and 1992,” which “extend[ed] to natural gas produced from
those wells until 2002.”206 This tax credit, which Congress enacted as part of
the Windfall Profits Tax Act of 1980,207 generated tax savings of about
$10 billion for operators between 1980 and 2002,208 including about
$760 million in savings in 1993 alone.209 Although these savings were shared
with developers of other unconventional gas sources such as coalbed methane,
the numbers suggest that the tax credit made financial contributions to shale
gas development at least on the order of the direct monetary contributions to
shale gas development made by GRI and DOE combined.210 Even small
operators who lacked substantial tax liabilities were able to benefit from the
credits by engaging in tax equity financing transactions in which they
203 GALLAHER ET AL., supra note 100, at 97.
204 Id. (“Approximately 60 per cent of worldwide oil and gas well footage in 2006 was drilled using PDC
drill bits. . . . [They] yiel[ded] a present value cost savings of $15.6 billion from 1982 to 2008.” (citations
omitted)).
205 Id. at 97–98 (crediting DOE with “significant contribution[s] to (1) developing the bit and getting it to
the market, (2) overcoming performance flaws, and limitations, and (3) spurring the innovation that resulted in
overall market success of PDC drill bits”).
206 MIT STUDY, supra note 175, at app. 8A, at 5; see also YERGIN, supra note 13, at 326 (“Fortunately,
something of a carrot was available, what was called Section 29. . . . Over the years, that incentive did what it
was supposed to do—it stimulated activity that would otherwise not have taken place.”).
207 BURWEN & FLEGAL, supra note 50, at 2.
208 Begos, supra note 97.
209 MIT STUDY, supra note 175, at app. 8A, at 5.
210 See supra text accompanying notes 173–74, 185–86.
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“effectively ‘sold’ their credits to larger firms.”211 Once again, Mitchell Energy
took advantage of the opportunity for government assistance, using tax credits
to “help[] underwrite the cost of developing hydraulic fracturing.”212
Beyond the now-defunct Section 29 credit, there are a wide variety of
extant “lenient rules regarding the recognition, timing, character, and
calculation of taxable profits [that] create large [effective] subsidies for
taxpayers engaged in” oil and gas production.213 For independent producers,
aggregation of these various additional incentives can result in a double-digit
“negative tax rate” that substantially increases pretax returns on investment.214
Many of these tax preferences are controversial215: the Obama Administration
has repeatedly proposed repealing a number of them.216 For purposes of this
study, however, the key point is that, to the extent these more general tax
preferences attracted investment either in shale gas extraction or in associated
technologies,217 they too contributed to the shale gas boom.
211 BURWEN & FLEGAL, supra note 50, at 7.
212 Steffy, supra note 181.
213 John A. Bogdanski, Reflections on the Environmental Impacts of Federal Tax Subsidies for Oil, Gas,
and Timber Production, 15 LEWIS & CLARK L. REV. 323, 324 (2011).
214 See Calvin H. Johnson, Accurate and Honest Tax Accounting for Oil and Gas, 125 TAX NOTES 573,
573, 577 (2009) (calculating a negative tax rate of 42% under a model in which “four important tax
preferences”—“the expensing of intangible drilling costs, the pool of capital doctrine, the percentage depletion
allowance, and the domestic manufacturing deduction”—are applied to an investment); see also GILBERT E.
METCALF, MANHATTAN INST. FOR POLICY RESEARCH, TAXING ENERGY IN THE UNITED STATES: WHICH FUELS
DOES THE TAX CODE FAVOR? 5 tbl.2 (2009), http://www.manhattan-institute.org/pdf/eper_04.pdf (estimating
effective tax rates of negative 13.5% for independent production companies and 15.2% for “integrated firms”).
215 See, e.g., MAURA ALLAIRE & STEPHEN BROWN, RESOURCES FOR THE FUTURE, ELIMINATING SUBSIDIES
FOR FOS SIL FUEL PRODUCTION: IMPLICATIONS FOR U.S. OIL AND NATURAL GAS MARKETS 14 (2009),
http://rff.org/RFF/Documents/RFF-IB-09-10.pdf (“[T]here is divergent opinion about the effects of such
subsidies.”); Johnson, supra note 214, at 573 (“The government should get out of the business of subsidizing
oil and gas via the tax system.”).
216 See U.S. DEPT OF THE TREASURY, GENERAL EXPLANATIONS OF THE ADMINIS TRATIONS FISCAL YEAR
2010 REVENUE PROPOSALS 59–69 (2009) (explaining proposals to eliminate various tax preferences favoring
oil and gas companies); ROBERT PIROG, CONG. RESEARCH SERV., R42374, OIL AND NATURAL GAS INDUSTRY
TAX ISSUES IN THE FY2014 BUDGET PROPOSAL 2 (2013) (reporting that for the FY2014 budget proposal the
Obama Administration proposed to eliminate various fossil fuel benefits).
217 Cf. Mona Hymel, The United States’ Experience with Energy-Based Tax Incentives: The Evidence
Supporting Tax Incentives for Renewable Energy, 38 LOY. U. CHI. L.J. 43, 44 (2006) (“Early empirical studies
of the impact of oil and gas tax incentives on resource allocation consistently concluded that these special
provisions allowed the petroleum industry to maintain a higher level of private investment than it would have
absent these policies.”).
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In particular, one of these tax preferences, the “percentage depletion
allowance,”218 is of interest because, since 1975, it has been available only for
independent producers, operators that, as indicated before,219 are non-vertically
integrated “producers that do not have refining and retailing operations, and
are unrelated to those that do.”220 Under the percentage depletion allowance,
independent producers of oil and gas may “deduct against their gross receipts a
depletion amount equal to 15% of their oil and gas revenue”—thereby
effectively rendering that share of revenue free from tax.221
Percentage depletion can play a substantial role in generating an effective
negative tax on production.222 The Congressional Budget Office (CBO) has
estimated that percentage depletion provided $900 million in tax relief in the
2011 fiscal year.223 Even aside from direct benefits to fracking’s development
through the attraction of additional investment, one might conjecture that the
post-1975, independent-producer-favoring rules on percentage depletion
helped support the vibrant community of independent producers that
spearheaded the shale gas boom.224
Another major tax advantage likewise discriminates between independent
producers and majors, although only partially. In 1916, the federal government
allowed the immediate “expensing of intangible drilling costs (IDCs) and dry
hole [non-producing well] costs.”225 This allowance remains in effect and
218 Johnson, supra note 214, at 581.
219 See supra text accompanying note 161.
220 Bogdanski, supra note 213, at 325. Compare id. (describing current provisions for percentage
depletion), with Stephen L. McDonald, Distinctive Tax Treatment of Income from Oil and Gas Production,
10 NAT. RESOURCES J. 97, 98 (1970) (noting that 1926 legislation introduced percentage depletion at a 27.5%
rate as a substitute for “discovery-value depletion”). See generally Walter J. Mead, The Performance of
Government in Energy Regulations, 69 AM. ECON. REV. (PAPERS & PROC.) 352, 352 (1979) (reporting that
1975 legislation “removed the benefits of percentage depletion allowances for integrated oil companies only”
but also decreased the allowances for independent producers).
221 Bogdanski, supra note 213, at 325.
222 Johnson, supra note 214, at 581; see also METCALF, supra note 214, at 5 tbl.2 (estimating effective tax
rates of negative 13.5% for independent production companies and 15.2% for “integrated firms”).
223 CONG. BUDGET OFFICE, FEDERAL FINANCIAL SUPPORT FOR THE DEVELOPMENT AND PRODUCTION OF
FUELS AND ENERGY POLICIES 2–3 (2012), http://www.cbo.gov/sites/default/files/cbofiles/attachments/03-06-
FuelsandEnergy_Brief.pdf.
224 See WANG & KRUPNICK, supra note 13, at 31 (“The major oil firms, which are much larger than any
independent natural gas firm, had the capacity [for large investments], but they did not invest in shale gas
early.”).
225 MOLLY F. SHERLOCK, CONG. RESEARCH SERV., R41227, ENERGY TAX POLICY: HISTORICAL
PERSPECTIVES ON THE CURRENT STATUS OF ENERGY TAX EXPENDITURES 2–3 (2011); see also Bogdanski,
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permits operators to fully deduct non-salvageable expenses in the year in
which they were incurred, rather than capitalizing them and deducting their
value only more gradually through depletion or depreciation.226 Costs
encompassed within this allowance “typically include [those of] labor, fuel,
hauling, power, materials, supplies, tool rentals, drilling equipment repairs, and
other items incident to and necessary for drilling and equipping productive
wells.”227 Congress has specifically indicated that such costs include expenses
from fracturing.228 Although Congress has not restricted IDC deductions to
independent producers, it has applied special limitations to their use by
integrated producers: as noted by John Bogdanski in 2011, “Integrated
companies are eligible for the expense election, but the election is limited to
70% of IDC each year; the other 30% must be recovered no more rapidly than
through a 60-month amortization.”229
Like percentage depletion, IDC deduction is viewed as a substantial tax
preference. The CBO has estimated that in the 2011 fiscal year this allowance
provided a total of $800 million in tax relief.230 Although such relief was not
exclusive to fracking, horizontal drilling, independent producers, or
unconventional natural gas, the heavy reliance of hydraulic fracturing and
horizontal drilling on special equipment and know-how suggests that the IDC
deductions likely provided substantial encouragement for the extraction
techniques that are hallmarks of the fracking revolution. Consistent with this
sense, the Western Energy Alliance, a trade association formerly known as the
Independent Petroleum Association of Mountain States,231 gave the IDC
deductions top billing in a position paper responding negatively to Obama
Administration proposals for repeal of various oil and gas tax preferences,
including the percentage depletion allowance.232 The Alliance specifically
supra note 213, at 325 (“The intangible costs of drilling and developing domestic oil and gas wells may be
deducted immediately, rather than capitalized and recovered over time, at the election of the taxpayer.”).
226 SHERLOCK, supra note 225, at 3.
227 Hymel, supra note 217, at 49.
228 STAFF OF JOINT COMM. ON TAX, 99TH CONG., GENERAL EXPLANATION OF THE TAX REFORM ACT OF
1986, at 195 (Joint Comm. Print 1987) (“IDCs may be paid or accrued to drill, shoot, fracture, and clean the
wells.”).
229 Bogdanski, supra note 213, at 326 (footnote omitted).
230 CONG. BUDGET OFFICE, supra note 223, at 3.
231 About Western Energy Alliance, W. ENERGY ALLIANCE, http://www.westernenergyalliance.org/
alliance (last visited Mar. 5, 2015).
232 W. ENERGY ALLIANCE, INTANGIBLE DRILLING COSTS (IDC) AND OTHER DEDUCTIONS DRIVE
INNOVATION AND JOB CREATION (2013), http://waysandmeans.house.gov/uploadedfiles/western_energy_
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characterized the IDC deductions as “the R&D program for the oil and natural
gas industry,” one that “made economically feasible” “[s]hale, tight sands, and
other unconventional plays from North Dakota to Colorado to Texas.”233
Other federal tax rules and provisions have also favored oil and gas
production. These include, inter alia, depreciation of natural gas pipelines over
fifteen years and natural gas gathering lines over seven years; an allowance for
“tax-exempt bond-financed prepayments” for natural gas;234 a deduction for
the use of tertiary injectants, such as carbon dioxide, in old reservoirs to wring
remaining resources out of them;235 a “passive loss exception for working
interests in oil and natural gas properties;”236 and limited time periods for
amortization of “geological and geophysical” expenses (seven years for large,
integrated companies and two years for independents)237 that allow for a higher
annual deduction than might otherwise apply.238 In 2004, Congress added to
the list by enacting a general “domestic manufacturing tax deduction” that has
enabled oil and gas producers to deduct three to six percent239 “of the lesser of
taxable income or income from domestic ‘production’ activities” up to a
payroll limitation generally set at “50% of the wages that are paid by the
taxpayer and allocable to the [relevant] income.”240 Much longer lived has
been the “pool of capital doctrine,” which for decades has exempted from
federal income taxation transfers in which oil and gas producers “compensate
alliance_wg_comment.pdf (headlining the proposal for repeal of IDC deductions and discussing this proposal
before those for repeal of other tax preferences, such as the percentage depletion allowance).
233 Id.
234 SHERLOCK, supra note 225, at 8. An additional benefit that does not contribute to the development of
new wells is the marginal well tax credit, implemented in 1994 “to keep low-production oil and natural gas
wells in production during periods of low prices for those fuels.” PIROG, supra note 216, at 3.
235 PIROG, supra note 216, at 4.
236 Id.
237 Bogdanski, supra note 213, at 326.
238 PIROG, supra note 216, at 6–7. Last-in, first-out (LIFO) rules for inventory accounting can also favor
oil and gas producers reporting sales of inventory by allowing them to identify “the most recent, usually higher
costs with the units that are sold and deductible,” while “identify[ing] the lowest costs with the units that have
been retained and remain as nondeductible basis.” Johnson, supra note 214, at 582. “International accounting
standards no longer permit use of the LIFO system, but taxpayers who are not subject to those rules (including
many U.S. oil companies) can, if they use LIFO on their financial books as well as on their tax returns, reduce
their taxable income considerably.” Bogdanski, supra note 213, at 328 (footnotes omitted).
239 PIROG, supra note 216, at 6 (noting that the deduction began “at 3% in 2005, . . . rising to a maximum
of 9% in 2010,” but with a cap of 6% on the rate for oil and gas production).
240 Bogdanski, supra note 213, at 327.
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landowners, suppliers, and drillers with economic interests in the future profits
of their operations.”241
In addition to the preceding host of forms of favorable treatment under
federal tax law, drilling and fracturing operations have received and continue
to enjoy state tax advantages. Most states place a severance tax on oil and gas
when it is extracted, often in the range of three to twelve percent of the market
value of the oil and gas sold.242 Many of these states, however, exempt
unconventional or “high-cost” gas from the tax.243 In Texas in 2006, when the
Barnett Shale boom was still in full swing, the state provided more than
$1.1 billion to oil and gas companies under its high-cost gas exemption.244
Meanwhile, with agreement from the governor, Pennsylvania’s legislature
repeatedly refused to pass a severance tax on resource extraction.245 By
February 2012, when the Pennsylvania legislature finally agreed upon an
241 Id. at 328. This doctrine treats the transactions in question—including transactions for services that are
entirely complete—as nontaxable on the ground that their effect is to generate a sort of joint venture in which
the various partners will share in profits that only appear later. Mark P. Gergen, Pooling or Exchange: The
Taxation of Joint Ventures Between Labor and Capital, 44 TAX L. REV. 519, 520–21 (1989) (“The theory
underlying the [pool of capital] doctrine is that people who join in a venture contributing their capital and
services for a share of a venture’s profits give up and receive nothing. Instead, they pool their resources and
keep a corresponding share of profits.”); see also Johnson, supra note 214, at 579 (noting IRS embrace of the
doctrine in G.C.M. 22730, 1941-1 C.B. 214); Walter D. Schwidetzky, The Pool of Capital Doctrine: A Peace
Proposal, 61 TUL. L. REV. 519, 526 (1987) (describing the “much celebrated, highly abstruse and syntactically
bizarre General Counsel Memorandum (GCM) 22730” as “arguably the most authoritative General Counsel
Memorandum ever issued”). The pool of capital doctrine is liable to criticism for “creat[ing] an incentive for
in-kind compensation and a disincentive for normal equity financing.” Gergen, supra, at 539 n.56; cf. id. at
539 & n.56 (characterizing the “subsidy argument” for the pool of capital doctrine as “preposterous because
even if we wanted to subsidize oil and gas ventures through the [Internal Revenue] Code, it is absurd to do that
by not recognizing gains from exchanges of labor for capital,” rather than “by making [oil and gas] returns tax
exempt or by providing a deduction for the cost of such investments”).
242 See, e.g., LA. REV. STAT. ANN. § 47:633(7)(a), (c)(ii)(aa) (Supp. 2015) (12.5% tax on oil’s “value at
the time and place of severance” with temporary suspension of the tax for horizontally-drilled wells); MISS.
CODE ANN. § 27-25-503(1)(b), (c)(1) (West Supp. 2013) (tax of 3% of “the value of the oil at the point of
production” and 1.3% for oil from horizontally drilled wells for a limited time period); N.M. STAT. ANN.
§ 7-29-4(A)(1), (4) (West 2012) (tax of 3.75% of the taxable value of natural gas, but 2.45% for natural gas
from “well workover” projects).
243 See, e.g., SUSAN COMBS, TEX. COMPTROLLER OF PUB. ACCOUNTS, THE ENERGY REPORT 379 (2008)
(“The High-Cost Gas program provides a tax incentive for high-cost gas wells based on the ratio of each
well’s drilling and completion costs to twice the median cost for all high-cost Texas gas wells submitted in the
prior fiscal year.”); supra note 242.
244 COMBS, supra note 243, at 68, 378.
245 Susan Phillips, Corbett Defends Impact Fee over Severance Tax, STATEIMPACT (June 14, 2013,
5:06 PM), http://stateimpact.npr.org/pennsylvania/2013/06/14/corbett-defends-impact-fee-over-severance-tax/.
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impact fee instead,246 the state had already issued more than ten thousand
permits for unconventional wells.247
C. Regulatory Relief
Like taxes, regulations can impact the profitability of innovation-related
activity, and governments have commonly used regulatory relief to try to spur
investment. But at least in relation to the fracking revolution, the impact of
such relief might be more marginal than is commonly assumed. When
Pennsylvania’s Department of Environmental Protection implemented rules
required by the state’s Act 13, which included enhanced environmental
protections for hydraulically fractured wells such as better secondary
containment under tanks (to catch spills), larger setbacks between well sites
and water resources, and a heightened presumption of fault for water pollution,
the Department estimated that total compliance costs imposed through the
rulemaking would be “between $75,002,050 and $96,636,950 annually.”248
Spread among approximately 1,751 Marcellus Shale wells drilled and fractured
in 2011,249 the estimated upper-bound cost was approximately $55,200
annually per well—an amount that is a small fraction of the more than
$6 million that one unconventional well can cost,250 although the total cost of
regulatory compliance rises, of course, through annual accretion.
In any event, regulations, even those that arguably only hit margins, can
risk discouraging development to a degree that policymakers find intolerable.
For example, in 1988, the Environmental Protection Agency determined that
oil and gas “exploration and production” wastes—most of the soil and rock
cuttings, liquid wastes, used drilling fluids and muds, and other wastes
246 58 PA. CONS. STAT. ANN. §§ 2301–2318 (West, Westlaw current through 2014 Reg. Sess.).
247 Year to Date—Permits Issued by County and Well Type Report, PA. DEPT OF ENVTL. PROT.,
http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil_Gas/Permits_Issued
_Count_by_Well_Type_YTD (enter “1/1/2001” for “PERMITS ISSUED START DATE,” “2/14/2012” for
“PERMITS ISSUED END DATE,” select “All” for “REGION,” select “Yes” for “UNCONVENTIONAL
ONLY,” and view final page of the resulting report) (last visited Mar. 5, 2015).
248 Environmental Protection Performance Standards at Oil and Gas Well Sites, 43 Pa. Bull. 7377
(Dec. 14, 2013), available at http://www.pabulletin.com/secure/data/vol43/43-50/2362.html.
249 Bureau of Oil & Gas Mgmt., Wells Drilled, PA. DEPT OF ENVTL. PROTECTION (Dec. 5. 2011), http://
www.dep.state.pa.us/dep/deputate/minres/oilgas/2011%20Wells%20Drilled.gif.
250 Pad Drilling and Rig Mobility Lead to More Efficient Drilling, U.S. ENERGY INFO. ADMIN. (Sept. 11,
2012), http://www.eia.gov/todayinenergy/detail.cfm?id=7910 (“EIA analysis of average Bakken, Eagle Ford,
and Marcellus well-related expenses finds that total costs per horizontal well can vary between approximately
$6.5 million and $9 million.”).
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produced at well sites—should not be regulated as hazardous wastes under
Subtitle C of the Resource Conservation and Recovery Act.251 The EPA
concluded that states and the federal government were, for the most part, doing
a reasonable job of controlling the impacts of these wastes.252 Tellingly, the
EPA highlighted the costs of regulatory compliance if the federal government
were to treat the wastes as hazardous, concluding that, under high-end
estimates, compliance could cost several billion dollars.253 With 70,000 wells
apparently in play, the average cost per well of such regulatory compliance
might not have seemed so overwhelming254: $7 billion divided by 70,000 is
$100,000. But, the EPA was apparently impressed. It ultimately exempted
most oil and gas wastes from RCRA Subtitle C regulation,255 thus ensuring that
what was perceived as a potentially costly regulatory barrier would not impede
well development.
As members of the oil and gas industry, unconventional gas producers also
benefited from other exemptions during the developmental stages of the shale
gas boom. For example, Congress did not hold operators liable for cleanup of
land contamination under the Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA) if these operators spilled
petroleum substances, including natural gas, natural gas liquids, and liquefied
natural gas, on the ground.256
In short, in the decades preceding the shale gas boom, producers looking to
exploit shale gas and other unconventional reserves enjoyed regulatory
exemptions that might have tipped cost–benefit analyses in favor of such
activities. By analogy with the “infant industry” exception to arguments for
free trade,257 one can envision an “infant technology” argument for such
251 Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production
Rates, 53 Fed. Reg. 25,446, 25,447 (July 6, 1988). See generally James R. Cox, Revisiting RCRA’s Oilfield
Waste Exemption as to Certain Hazardous Oilfield Exploration and Production Wastes, 14 VILL. ENVTL. L.J.
1, 2–7 (2003) (providing a history of the exemption and explaining the exemption’s scope).
252 53 Fed. Reg. at 25,446.
253 Id. at 25,450.
254 These numbers were based on an estimated “70,000 crude oil and natural gas wells” and additional
wastes from geothermal energy wells. Id. at 25,448.
255 42 U.S.C. §§ 6921(b)(2)(A)–(B); 6982(m)(1) (2012); 53 Fed. Reg. 25,446.
256 42 U.S.C. § 9601 (14) (2012). Oil companies, though, still faced Clean Water Act liability and, as of
1990, Oil Pollution Act liability for onshore spills. 40 C.F.R. § 112.1 (1990).
257 Marc J. Melitz, When and How Should Infant Industries Be Protected?, 66 J. INTL ECON. 177, 178
(2005) (“The infant industry argument is one of the oldest arguments used to justify the protection of industries
from international trade.”); see also JOHN STUART MILL, PRINCIPLES OF POLITICA L ECONOMY 612 (J. Laurence
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favorable regulatory treatment as a means to encourage a critical mass of
early-stage activity when broad-scale commercial feasibility is still in doubt
and the activity in question is economically marginal enough that it is at great
risk of being snuffed out. Further, at least while activity levels are low in such
a period of infancy, one might expect that the costs of regulatory exemptions
will be relatively small and isolated.
But the broad-based regulatory exemptions for oil and gas activities
described above have commonly applied to well-established as well as
arguably “infant” activities and thus have not been tailored to fit an
infant-technology rationale. Moreover, when more tailored regulatory relief
was enacted, the period of infancy was past. Through the so-called
“Halliburton Loophole,”258 the Energy Policy Act of 2005 exempted all
hydraulic fracturing, with the exception of fracturing that uses diesel fuel, from
the definition of “underground injection” under the Safe Drinking Water
Act.259 As a result, fracturing could occur without a permit that would have
required the operator to show that the process would not endanger underground
sources of drinking water. Although this exemption is well tailored to fit
fracturing activities that proved critical to shale gas extraction, it came more
than three years after Mitchell Energy merged with Devon Energy260 and more
than half a decade after a pronounced upward kink in Barnett Shale gas
production from 1999 to 2000.261 In short, when lawmakers ultimately
provided regulatory relief tailored to the exploitation of shale gas reserves,
they apparently did so at a time when they were no longer nurturing infant
activity but instead feeding an already gathering boom.
Laughlin ed., New York, D. Appleton & Co. 1884) (“The only case in which, on mere principles of political
economy, protecting duties can be defensible, is when they are imposed temporarily . . . in hopes of
naturalizing a foreign industry, in itself perfectly suitable to the circumstances of the country.”).
258 Warner & Shapiro, supra note 24, at 479–80.
259 42 U.S.C. § 300h(d)(1) (2012). Also in 2005, Congress attempted to narrow the Clean Water Act
“stormwater” permitting required for the construction of oil and gas well sites—a permitting process intended
to reduce soil erosion. 33 U.S.C. § 1362(24) (2012). But the effectiveness of this exemption has been unclear.
See Natural Res. Def. Council v. EPA, 526 F.3d 591, 594 (9th Cir. 2008) (curtailing EPA’s efforts to
implement the statutory exemption); Regulation of Oil and Gas Construction Activities, U.S. ENVTL.
PROTECTION AGENCY (Mar. 9, 2009), http://water.epa.gov/polwaste/npdes/stormwater/Regulation-of-Oil-and-
Gas-Construction-Activities.cfm (attempting to clarify relevant regulations).
260 STEWARD, supra note 106, at 179 (“In January 2002, the merger of Mitchell Energy and Devon
closed . . . .”).
261 Id. at 189 fig. 6-2 (showing relatively linear growth in Barnett Shale gas production from 1992 through
1999, followed by a pronounced upward kink in the growth trajectory from 1999 to 2000).
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As the scope of drilling and fracturing activities has scaled upward, the
wisdom of such late-coming regulatory relief has become subject to serious
question.262 More effective regulation might have limited now-evident social
costs. There have been substantial spills and outflows of fracturing and drilling
materials at well sites that have sometimes led to water contamination.263
Moreover, disposal wells that accept liquid wastes from drilling and fracturing
have been associated with earthquakes in several regions.264 Drilling and
fracturing also emit air pollution that can increase smog265 and greenhouse
gases.266 Finally, although communities that have become hosts to booming
natural gas production have experienced benefits,267 they have also
262 For a discussion of how scaling up activities can generate problems, see Hannah J. Wiseman,
Remedying Regulatory Diseconomies of Scale, 94 B.U. L. REV. 235 (2014).
263 See, e.g., Wiseman, supra note 5, at 766–68, 799–801 (describing spills at well sites, including spills
that entered swamps and other waters, based on state inspection reports); Cases Where Pit Substances
Contaminated New Mexico’s Groundwater, N.M. OIL CONSERVATION DIV. (Sept. 12, 2008), http://www.
emnrd.state.nm.us/ocd/documents/GWImpactPublicRecordsSixColumns20081119.pdf (listing instances of
groundwater contamination); Press Release, Md. Attorney Gen., AG Gansler Secures Funding to Safeguard
Susquehanna Water Quality (June 14, 2012), available at http://www.oag.state.md.us/Press/2012/061412.html
(reporting contamination by fracking fluids of farmland and a creek tributary).
264 Frohlich et al., supra note 5; Austin Holland, Oklahoma Geological Survey: Potential for Induced
Seismicity Within Oklahoma, GROUND WATER PROT. COUNCIL 6 (Jan. 23, 2013) http://www.gwpc.org/sites/
default/files/event-sessions/Holland_AustinFINAL.pdf; Press Release, U.S. Geological Survey, Record
Number of Oklahoma Tremors Raises Possibility of Damaging Earthquakes (May 2, 2014), available at
http://earthquake.usgs.gov/contactus/golden/newsrelease_05022014.php (reporting that statistical analysis of
“recent earthquake rate changes” in Oklahoma “suggests that a likely contributing factor . . . is triggering by
wastewater injected into deep geologic formations”). Disposal wells are regulated under the Safe Drinking
Water Act, but the Act does not cover induced seismicity. See generally UNDERGROUND INJECTION CONTROL
NATL TECHNICAL WORKGRP., U.S. ENVTL. PROT. AGENCY, MINIMIZIN G AND MANAGING POTENTIAL IMPACTS
OF INDUCED-SEISMICITY FROM CLASS II WELLS: PRACTICAL APPROACHES (2012), http://www.eenews.net/
assets/2013/07/19/document_ew_01.pdf (studying the problem but not regulating it). Only Arkansas and Ohio
have changed their regulations to fill the gap. OHIO ADMIN. CODE 1501:9-3-07 (2013); Permanent Disposal
Well Moratorium Area, ARK. OIL & GAS COMMN (June 7, 2011), http://www.aogc.state.ar.us/notices/
Ex.%201B%20-Permanent%20Disposal%20Well%20Moratorium%20Area.pdf.
265 See N.Y. DEPT OF ENVTL. CONSERVATION, SUPPLEMENTAL ENVIRONMENTAL IMPACT STATEMENT
6-187 to 6-188 (2011), http://www.dec.ny.gov/data/dmn/rdsgeisfull0911.pdf (describing N2O and carbon
dioxide emissions from combustion at well sites); DALE WELLS, COLO. DEPT OF PUB. HEALTH & ENVT,
CONDENSATE TANK EMISSIONS 2, 10 (2012), http://www.epa.gov/ttnchie1/conference/ei20/session6/dwells.pdf
(showing that condensate tanks were the largest cause of regional nonattainment of air quality standards in the
Denver area).
266 Allen et al., supra note 58, at 17,769; Ramón A. Alvarez et al., Greater Focus Needed on Methane
Leakage from Natural Gas Infrastructure, 109 PNAS 6435, 6438 (2012). EPA Clean Air Act regulations
effective on January 1, 2015, will introduce partial regulation by requiring operators to capture certain
emissions of volatile organic compounds (including methane). 40 C.F.R. § 60.5375 (2014).
267 Cf. E.B., Well-Being in America: Shale Gas Buys You Happiness, ECONOMIST (Feb. 21, 2014, 5:59),
http://www.economist.com/node/21597121 (suggesting that the shale gas boom is a large factor behind North
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experienced a variety of costs. These include road damage and traffic,
increased demand for physical infrastructure,268 increased demand for city
services such as fire and emergency response, rises in crime and drug use,269
changes in historic economic activities like tourism and agriculture, and
nuisances from the noise, light, dust, and pollution at well sites.270
In considering lessons from the story behind the fracking revolution, Part V
examines how future policymakers might limit the downsides of regulatory
relief as well as its possible tendency to persist and even expand after
innovation-fostering justifications have substantially expired.271 In the
meantime, Part IV continues the discussion of factors behind the revolution
itself by describing roles played by complementary assets, intellectual property
rights, secrecy, and information sharing.
Dakota’s rise to the top of the Gallup-Healthways Well-Being Index, meant to act as a measure of the mental
and physical health of states’ residents).
268 See, e.g., WILLISTON ECON. DEV., supra note 5, at 1 (noting that a prior increase in “major
infrastructure capacity for up to 40% more population (pop 16,000)” had fallen short and there was additional
need for “water, sewer, and road infrastructure for workforce housing and industry facility needs”).
269 A number of media sources report rising crime and drug use following fracking-related booms. See,
e.g., Jack Healy, As Oil Floods Plains Towns, Crime Pours In, N.Y. TIMES, Nov. 30, 2013, at A1, available at
http://www.nytimes.com/2013/12/01/us/as-oil-floods-plains-towns-crime-pours-in.html; Michael Marks,
Drugs Follow Eagle Ford Energy Boom, AUSTIN AM. STATESMAN (June 22, 2014), http://projects.statesman.
com/news/eagle-ford-drugs/. Academic literature and government reports provide a more nuanced picture in
which increases in crime might largely reflect population growth associated with such booms. See, e.g., CARO L
A. ARCHBOLD, “POLICING THE PATCH”: AN EXAMINATION OF THE IMPACT OF THE OIL BOOM ON SMALL TOWN
POLICING AND CRIME IN WESTERN NORTH DAKOTA 55 (2013), available at http://www.ndsu.edu/fileadmin/
cjps/Policing_the_Patch_Report_-_Final_Draft_August_4th_-_Archbold.docx (noting that an apparent
increase in crime was “proportionate with the increase in population”); Rick Ruddell et al., Drilling Down: An
Examination of the Boom-Crime Relationship in Resource-Based Boom Counties, W. CRIMINOLOGY REV.,
Apr. 2014, at 3, 9 (finding “modest support for the proposition that crime is higher in oil producing counties
and that crime increased after the Boom”); MONT. ALL THREAT INTELLIGENCE CTR. & N.D. STATE & LOC AL
INTELLIGENCE CTR., IMPACT OF POPULATION GROWTH ON LAW ENFORCEMENT IN THE WILLISTON BAS IN
REGION 1 (2012), http://www.ag.nd.gov/reports/jointproductfinal.pdf (“With the increase in population there
has been an increase in arrests, criminal activity and vehicle crashes.”).
270 WILLISTON ECON. DEV., supra note 5, at 26–28, 35; Susan Christopherson & Ned Rightor, The
Boom-Bust Cycle of Shale Gas Extraction Economies, Community & Regional Development Institute, CARDI
REP. (Cornell Univ. Cmty. & Reg’l Dev. Inst., Ithaca, N.Y.), Sept. 1, 2011, at 4, available at http://www.
greenchoices.cornell.edu/downloads/development/shale/Economic_Consequences.pdf; Jeffrey Jacquet, Energy
Boomtowns & Natural Gas: Implications for Marcellus Shale Local Governments & Rural Communities 14,
17, 22, 25, 28 (Ne. Reg’l Ctr. for Rural Dev., Paper No. 43, 2009), available at http://aese.psu.edu/nercrd/
publications/rdp/rdp43; CJ Randall, Hammer Down: A Guide to Protecting Local Roads Impacted by Shale
Gas Drilling 2 (Cornell Univ. Comprehensive Econ. Impact Analysis of Natural Gas Extraction in the
Marcellus Shale Working Paper Series, 2010), available at http://www.greenchoices.cornell.edu/downloads/
development/shale/Protecting_Local_Roads.pdf.
271 See infra text accompanying notes 406–24.
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IV. INTELLECTUAL PROPERTY, COMPLEMENTARY ASSETS, AND SHARING
A. Complementary Assets, Financing, and the “No Patents” Story
As described in the Introduction, a common part of the origin story of the
shale boom is that its beginnings were fundamentally patent free. The key
entrepreneur, Mitchell, and his successor, Devon Energy, did not patent key
breakthroughs in slickwater fracturing and horizontal drilling.272 The resulting
lack of patent protection might have facilitated the subsequent shale gas boom,
enabling others to rapidly copy Mitchell and Devon’s techniques without
having to pay licensing fees or worry about lawsuits for patent infringement.273
There is plausibility to the basic “no patent” story—really a “no patent” and
“limited trade secret” story to the extent it suggests that significant information
about advances, such as those by Mitchell Energy, was freely circulated for
others to use. A major source of plausibility for this story comes from the fact
that, without obtaining patents or keeping certain forms of key information
permanently secret, companies like Mitchell Energy and Devon Energy could
use investments in complementary assets—private land and mineral rights—to
appropriate substantial returns from innovation.274
Mitchell Energy provided a classic example of how to appropriate value
from innovation by acquiring substantial land and mineral rights in the Barnett
Shale at a time when prices were relatively low. After Mitchell had greatly
increased the value of those rights by developing and publicizing such
advances as slickwater fracturing, Mitchell was able to sell those rights at a
comparatively high price.275
Mitchell pursued this strategy of buying low and selling high quite
deliberately. In the late 1980s, Mitchell Energy apparently delayed joining
forces with GRI because of concern that such collaboration would draw too
much attention and thereby too quickly drive up prices for rights to land and
272 Cahoy et al., supra note 26, at 291 (“[D]uring the late 1990s and early 2000s, neither Mitchell nor
Devon pursued patent protection for their respective innovations in slickwater hydraulic fracturing and
horizontal drilling.”).
273 Id. at 291–92.
274 WANG & KRUPNICK, supra note 13, at 30 (“Private land ownership contributed to the development of
shale gas in that it offered entrepreneurial natural gas firms a method of obtaining reasonable returns from their
early investments . . . .”).
275 See infra text accompanying notes 276–78.
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minerals in the Barnett Shale.276 After Mitchell Energy had improved “its
acreage position,” it began working with GRI in the 1990s and ultimately made
the key breakthroughs that it publicized in the early 2000s.277 In 2002, Mitchell
reaped the rewards: having proven the Barnett Shale’s profitability, Mitchell
sold itself and its carefully acquired land and mineral rights to Devon Energy
for $3.5 billion.278
Other early movers mimicked Mitchell’s success. Range Resources—the
first successful developer of a Marcellus Shale well in Appalachia—snapped
up land and mineral rights in southwestern Pennsylvania and its environs.279
“By August 2007, Range had spent more than $150 million on what it
described to its investors as its ‘Appalachian Basin Devonian shale gas play’—
a sizeable investment for a company that had a market capitalization of $400
million.”280 When prices for gas rights “climbed from about $50 to thousands
of dollars per acre at the height of the leasing frenzy in 2008 and 2009,”
Range’s value swelled as well: within a few years, the $400 million company
was worth $8 billion.281
Consequently, in the case of the shale gas boom, there is no mystery about
how private firms could share basic information on new techniques for gas
extraction while still hoping that their large capital investments would yield
handsome profits. In Jonathan Barnett’s terms, state-backed land and mineral
rights provided the supplemental means for appropriation—the background
“access limitations”282—that underwrote the firms’ capital investments and
thus enabled a regime of information sharing with limited reliance on
intellectual property.283
276 See WANG & KRUPNICK, supra note 13, at 18 (noting that in the late 1980s, “Mitchell Energy was in
the process of acquiring leases on large tracts of land, so George Mitchell was, according to Steward,
‘concerned that any unnecessary publicity might adversely affect the growth of [the firm’s] acreage position’”
(alteration in original) (citation omitted)).
277 Id.
278 See supra text accompanying note 111.
279 Silver, supra note 13.
280 Cahoy et al., supra note 26, at 287 (quoting Silver, supra note 13).
281 Silver, supra note 13.
282 Jonathan M. Barnett, The Illusion of the Commons, 25 BERKELEY TECH. L.J. 1751, 1754 (2010)
(contending that “economically significant levels of innovation investment almost never appear without some
form of property rights or other access limitations”).
283 Id. at 1814 (arguing for the proposition that, “[a]t least in innovation settings that demand substantial
capital investments, . . . sharing regimes . . . are unlikely to persist unless supplemented by state-provided
property rights or some other exclusionary mechanism of functional equivalence”).
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Indeed, the quick and geographically widespread adoption of the Mitchell
synthesis by a host of independent producers highlights an aspect of
complementary assets in land and minerals that contrasts with the nature of
intangible intellectual property. The spatially limited nature of typical “real
world” land and mineral leases, plus the generally self-limiting nature of
processes for their acquisition as purchase efforts predictably drive up
prices,284 can make difficult and even impractical the effective
“monopolization” of an extraction technology through purchase of leases
covering all relevant deposits. Hence, even while enabling large rewards for
innovators such as Mitchell, reliance on land and mineral leases as the primary
means for appropriating innovation’s value helped ensure that rewards were
less than fully exclusionary: rewards for the earliest movers left ample
opportunities for others to profit from joining the game a bit later. Further,
reliance on land and mineral leases helped ensure that rewards were
proportional to at least one dimension of the cost and risk that a would-be
innovator took on.
The naturally limited scope of private land and mineral leases as
mechanisms for appropriation of value from innovation contrasts with the
readily extensive nature of disembodied intellectual property rights. Based on a
stroke of the legislative pen, property rights such as patents can claim
exclusionary effect across entire countries, and, at least partly as a result of
several strokes of a patent applicant’s pen, a patent can have a
substantive breadth bearing little necessary proportion to the attorney fees and
filing costs that constitute its direct expenses of acquisition. These elements of
contrast between land and mineral rights and intellectual property rights
suggest that the relatively natural spatial limitations on privately held land and
mineral rights can, under appropriate circumstances, make them particularly fit
to support a regime of decentralized development and exploitation by nimble,
independent actors such as those who rapidly spread implementation of the
Mitchell synthesis.
Another significant aspect of oil and gas leases is the developmental
pressure that they can exert after being acquired. A typical oil and gas lease
284 Cf. John D. Sterman, System Dynamics Modeling: Tools for Learning in a Complex World, CAL.
MGMT. REV., Summer 2001, at 8, 17 (discussing “self-limiting” processes featuring negative feedback such as
how the relative attractiveness of a city generates increased “migration from surrounding areas . . . increasing
unemployment, housing prices, crowding in the schools, and traffic congestion until the city is no more
attractive than other places”).
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includes a clause stating that the lease has a “primary term” of a specified
number of years and a secondary term that extends “as long thereafter as oil or
gas is produced.”285 Once acquired, such a lease can provide a positive
inducement to develop the acquired oil and gas resources before the end of the
primary term in order to avoid losing the option to continue producing during
the indefinitely long secondary term. Mitchell Energy itself appears to have
responded to such inducement,286 and it presumably was far from alone. As
primary terms for leases appear commonly to be ten years or less,287 the result
of such lease arrangements could have been significant cumulative pressure to
develop means of profitable exploitation within a quite limited span of time.
The effects of such developmental pressure were not necessarily
unambiguously positive, however. On the minus side, once commercial
viability was established, the developmental spur of otherwise expiring lease
rights might have contributed to excessive growth—from a social standpoint—
of fracking and drilling activities by goading production activities forward
even when more general social interests would have counseled restraint.288
B. Information Sharing
Of course, the ability of companies like Mitchell to make profits without
patenting key innovations does not necessarily explain their failure to seek
patent protection. If Mitchell had obtained patent rights relating to slickwater
hydraulic fracturing, Mitchell might have made even more money,
supplementing through patent royalties the amounts earned from an increase in
the value of its lease rights in the Barnett Shale. Why did it not seek to do so?
One reason might be that Mitchell believed that patent rights were
unavailable. Hydraulic fracturing using water, rather than relying more
substantially on fancier foams or gels, had long been known as a technique for
285 JOHN S. LOWE ET AL., CASES AND MATERIALS ON OIL AND GAS LAW 336 (5th ed. 2008).
286 STEWARD, supra note 106, at 124–25 (reporting management approval of various drilling operations in
the wake of realization that various lease provisions could mean “that in the absence of drilling we would lose
more than 5,000 acres”).
287 LOWE ET AL., supra note 285, at 336 (“Ten years was once a common primary term, and it is still
frequently the primary term of leases in unproven or marginally producing areas. Primary terms of from one to
five years are more typical in states with established oil and gas production.”).
288 Cf. Clifford Kraus & Eric Lipton, After the Boom in Natural Gas, N.Y. TIMES, Oct. 21, 2012, at BU1,
available at http://www.nytimes.com/2012/10/21/business/energy-environment/in-a-natural-gas-glut-big-
winners-and-losers.html (suggesting that natural gas companies are drilling and fracturing despite losing
money overall).
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increasing fossil fuel recovery.289 Mitchell might have believed that, given this
preexisting public knowledge, Mitchell’s adaptation of the technique to the
peculiarities of the Barnett Shale would not support a patent or, at least, would
not support a patent broad enough to cover the particular fracturing techniques
that other operators would find optimal for other formations. Indeed, there
seems to be an impression among some commentators that, in the business of
fossil fuel extraction, “few technologies are patentable.”290
The posited assumption that patents were either unavailable or believed
unavailable seems belied by the fact that the U.S. Patent and Trademark Office
has issued scores of patents relating to the technologies of hydraulic fracturing
and directional drilling over the course of decades.291 Moreover, Mitchell
Energy, Devon Energy, and other players in the early stages of shale gas
development did not lack sophistication that might be thought necessary to
appreciate the potential availability of patent rights. “By the time Mitchell
Energy drilled the first Barnett well in 1981, it was the largest gas producer in
North Texas and a diversified, publicly traded company whose business
included not only the exploration, production, gathering, and processing of
natural gas, but also drilling rigs and real estate operations.”292 Mitchell Energy
was a sharp user of legal regimes in many respects293 and was specifically
familiar with the possibility of obtaining a patent for a novel variation on a
previously developed technique: in the 1980s, Mitchell Energy obtained two
patents on processes relating to previously developed fluid-injection
techniques in which a fluid such as water is injected into a formation to force
oil in the formation toward a well.294 Thus, it seems unlikely that Mitchell
Energy refrained from patenting its improvements on previously developed
289 See Michael Quentin Morton, Unlocking the Earth: A Short History of Hydraulic Fracturing, GEO
EXPRO, Dec. 2013, at 86, 87, available at http://assets.geoexpro.com/uploads/31566c31-c43f-4cf1-8964-
c1406108d667/GEO_ExPro_v10i6_Full.pdf (“From 1953, water was also used as a fracturing fluid, and
various additives were tried to improve its performance.”).
290 WANG & KRUPNICK, supra note 13, at 3; see also id. at 17–18 (“Since few innovations are patentable
and licensable and it is difficult to keep innovations proprietary, the best way to obtain financial reward from
R&D investments in the natural gas industry is through leasing large tracts of land that can be sold at higher
prices later.”).
291 See infra Part IV.C.
292 WANG & KRUPNICK, supra note 13, at 16–17.
293 See supra text accompanying notes 114, 195.
294 U.S. Patent No. 4,742,873 (filed Mar. 11, 1987) (issued May 10, 1988) (listing Mitchell Energy Corp.
of The Woodlands, Texas, as the assignee); U.S. Patent No. 4,291,765 (filed Aug. 2 1979) (issued Sept. 29,
1981) (listing Mitchell Energy Corp. of Houston, Texas, as the assignee).
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techniques of hydraulic fracturing as a result of straightforward mistakes about
patent rights’ potential availability.
Was Mitchell Energy motivated by philanthropic goodwill? In a 2012
interview, George Mitchell indicated that he believed Mitchell or Devon
“could have patented [their] proprietary process and made exponentially more
money” but that he “already had enough money from the sale of Mitchell
Energy & Development Corp. to Devon Energy,” and he “was more motivated
to introduce this technology into the public domain—make it public record—
so that the world could benefit from natural gas as an important energy and
fuel source.”295 George Mitchell might well have believed this, but Mitchell
Energy’s commitment to not pursuing patent protection appears to have
preceded the large payday with Devon. The key technical breakthroughs were
made by the end of 1998,296 and those breakthroughs were apparently used to
generate natural gas for sale essentially immediately.297 This commercial
exploitation presumably barred Mitchell Energy from seeking related patents at
any time more than a year after its occurrence298—substantially before the
2002 sale to Devon.
A better explanation for the non-pursuit of patent protection might be that
Mitchell Energy simply believed that, as a matter of pure private interest,
pursuing patent rights was not worth the trouble. This conclusion might have
followed from a combination of (1) difficulties in enforcing patent rights on
processes of extraction commonly conducted in relatively isolated locations,
out of plain sight, or even deep underground;299 (2) the potential value of
keeping certain aspects of Mitchell’s advances secret, as opposed to disclosed
in issued patents or published patent applications;300 (3) open-access
295 S.W., An Interview with George Mitchell: The Industry Can No Longer Simply Focus on the Benefits
of Shale Gas, ECONOMIST, Aug. 1, 2013, http://www.economist.com/blogs/schumpeter/2013/08/interview-
george-mitchell.
296 See supra note 106 and accompanying text.
297 See STEWARD, supra note 106, at 123 (“Mitchell’s expansion phase of the Barnett began in 1998 and
continued through the end of 2001.”).
298 See JANICE M. MUELLER, AN INTRODUCTION TO PATENT LAW 141 (2d ed. 2006) (discussing how, even
if an invention’s use is kept secret, a time-based statutory bar to patenting can prevent patenting of the
invention at any time more than one year after the invention’s “secret commercialization”).
299 Cf. Golden, supra note 9, at 518 (“[D]ifficulties in enforcing patent rights might . . . cause rational
parties either not to obtain patent rights at all or, alternatively, to leave such rights unenforced or licensed for
only pennies on the dollar.” (footnote omitted)).
300 See id. at 521–22 (noting surveys indicating that private firms commonly view patent disclosures as
“cost[s] to the patentee”). U.S. applications filed before November 29, 2000, were not subject to a requirement
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requirements resulting, for example, from Mitchell’s collaboration with
GRI;301 and (4) developed industry norms of competition based on an accepted
mix of partial disclosure, partial secrecy, and localized exclusive rights in land
and minerals—norms that might have successfully fostered an environment in
which relevant players could appropriate a satisfactory amount of value from
their own technological advances but at the same time benefit generally from
advances made by others.302
These potential factors in Mitchell’s non-pursuit of patent rights merit
additional discussion. First, there is the fact that, at least from an ex ante
perspective, a producer like Mitchell might very likely have viewed patents on
processes of fracturing or directional drilling as unlikely to have great value.
Mitchell was looking to generate a commodity—salable natural gas. Generally
speaking, innovations in hydraulic fracturing such as a new technique of
slickwater fracturing—the sorts of innovation that an independent producer
like Mitchell would most likely generate—would not be visible in publicly
sold end products. Instead, such a new technique would likely appear in
practice only ephemerally in privately deployed processes to extract natural
gas whose most directly relevant aspects could occur a mile or so
underground.303 Detection and proof of the infringement of a patent on such a
technique might be difficult.304 Further, the patented technique might have
only localized and thus significantly limited value: its advantages might be
limited to the specific kinds of geologic conditions for which it was originally
that they be published if still pending after eighteen months, but Mitchell Energy could have applied for
applications abroad, where a practice of publishing patent applications after eighteen months would likely have
applied. See ROBERT PATRICK MERGES & JOHN FITZGERALD DUFFY, PATENT LAW AND POLICY: CASES AND
MATERIALS 61 (5th ed. 2011) (“By the mid-1990’s, the United States was one of the last holdouts of secret
applications in the world.”).
301 See supra text accompanying notes 195–98.
302 Cf. Lior Jacob Strahilevitz, Social Norms from Close-Knit Groups to Loose-Knit Groups, 70 U. CHI. L.
REV. 359, 359–60 (2003) (arguing for extension of the study of the development and maintenance of social
norms of cooperation to “non-close-knit groups”).
303 See supra text accompanying note 78.
304 See, e.g., Rebecca S. Eisenberg, Technology Transfer and the Genome Project: Problems with
Patenting Research Tools, 5 RISK 163, 169 (1994) (noting that a patent on a manufacturing process can be
“less effective” than on a marketed “end product” “because of practical problems in detecting and proving
infringing activities in the manufacturing process that are not apparent from inspection of the end product”);
Ted Sichelman & Stuart J.H. Graham, Patenting by Entrepreneurs: An Empirical Study, 17 MICH. TELECOMM.
& TECH. L. REV. 111, 176 (2010) (“[A]ll else being equal, one would expect that process patents are more
difficult to litigate, because of problems proving infringement.”).
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developed.305 Under such circumstances, the expected costs of obtaining and
enforcing patent rights could well have outweighed the expected benefits.
The cost of patent-law-mandated disclosure seems likely to have been one
that Mitchell Energy would have considered. Mitchell separately demonstrated
its appreciation of the desirability of keeping certain information secret. Recall
how Mitchell deliberately sought to delay information flow about its
knowledge and activities so as not to interfere with its plans for profitable
acquisition of land and mineral rights.306
Further, Mitchell had worked with GRI and might therefore have been at
least partially subject to GRI-imposed restrictions on intellectual property.307
Even if such restrictions only partly limited the extent to which Mitchell could
seek or enforce rights in particular techniques of well drilling or development,
such limitations could help cap the expected value of any patent rights or, at
the very least, highlight what GRI-imposed restrictions required to remain
uncovered.
More generally, however, Mitchell Energy might simply have followed a
mixed strategy of partial secrecy, acquisition of local exclusionary rights in
land and minerals, and partial disclosure that generally served its interests and
was also well within the established norms—the laws of economic warfare—
for its industrial context. In this context, private parties such as Mitchell had
substantial interests in at least partially free information exchange. Mitchell
appreciated that the sharing of information could serve its strategic interests. In
the mid-1990s, “management recommended that [Mitchell] begin sharing data
with other operators in hopes of increasing competitor activity to evaluate
wildcat areas.”308 Later, a “Barnett Shale Symposium” on September 28, 2000,
that featured “a variety of excellent technical presentations” helped stoke
interest in the Barnett play to Mitchell’s apparent benefit.309
Further, presumably like many independents with limited research budgets,
Mitchell Energy actively sought valuable information from others, both
through direct talks and through hiring. Mitchell pursued the technique of
305 See supra notes 78–80 and accompanying text.
306 See supra text accompanying notes 275–78.
307 See infra text accompanying notes 313, 319.
308 STEWARD, supra note 106, at 175–76.
309 Id. at 178–79 (“Following the symposium Mitchell Energy received numerous inquiries about the play.
Soon afterwards Devon approached Mitchell concerning a merger.”).
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slickwater fracturing in shale only after the Mitchell engineer “assigned
completion responsibility for the Barnett,” Nick Steinsberger, followed
experimentation with the use of a low concentration of gel with outreach to
representatives of Union Pacific Corporation.310 Union Pacific had developed a
slickwater technique for fracturing “in low permeability rock,” and “Nick
obtained approval . . . to discuss their frac[turing] design and its possible
application to the Barnett Shale.”311 Shortly before Mitchell’s 1998
breakthrough, Mitchell also benefited from Chevron’s abandoned efforts in the
Barnett Shale by hiring “Kent Bowker, a highly-experienced,
unconventional-gas geologist from Chevron,” whom Mitchell valued not only
for his innate talent but also for “his knowledge of Chevron’s Barnett
science.”312
Government actors or partners might have contributed to a culture and
strategic calculus of information exchange. Partnerships such as those Mitchell
Energy had with GRI apparently triggered requirements of “full publication of
findings” and surrender of claims to intellectual property.313 As noted
earlier,314 FERC, for its part, helped ensure that GRI “focused on technology
diffusion,” rather than developing revenue from intellectual property, by
“subtracting any royalties [from intellectual property] from FERC funding.315
The plausibility of FERC and GRI thereby influencing the more general
industry culture might find support in the history of the largely
contemporaneous “Bayh-Dole model” for university research that encouraged
universities to seek patents on the results of federally funded research and then
to use these patents as levers for commercialization.316 Whether the Bayh-Dole
310 Id. at 112–13.
311 Id. at 113 (“In the fall of 1996 [Nick, a Mitchell Energy representative,] met with Mike Meyerhoffer
and his supervisor Ray Walker, and reviewed their well and frac data. Nick was extremely encouraged about
the techniques’ potential in the Barnett.”).
312 Id. at 122–23; see also id. at 129 (“Kent Bowker joined Mitchell Energy in February 1998, and was
given geological responsibility for the Barnett play.”).
313 BURWEN & FLEGAL, supra note 50, at 5.
314 See supra text accompanying notes 193–94.
315 BURWEN & FLEGAL, supra note 50, at 5.
316 John M. Golden, Biotechnology, Technology Policy, and Patentability: Natural Products and
Invention in the American System, 50 EMORY L.J. 101, 120 (2001) (“The Bayh-Dole Act . . . sought to
stimulate such technology transfer by allowing government grantees and contractors to patent inventions and
to sell exclusive licenses for their use.”).
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model has proven optimal is controversial,317 but there can be little doubt that
government endorsement of this approach helped foster an environment in
which universities took increasingly proprietary and exclusionary views of the
fruits of their intellectual efforts.318 GRI’s quite distinct, partly opposite
approach might predictably have nudged private actors in an alternative
direction.
In any event, information-sharing requirements and cultural norms fostered
by GRI were not the only government supports for information sharing. Under
regulations applicable in most of North America, oil and gas producers had to
“reveal fracturing and production-performance data within 6 months.”319 In a
world in which simply developing information about the possibilities for
fracturing and resource recovery from a particular rock formation often
demanded huge capital investments, competitors could be expected to “plunder
[such data] for insight.”320 Instead of complaining that other prospectors were
free riding, members of the relevant industrial community seem to have
accepted the fact that such information would circulate and designed their
business models accordingly. It probably aided such acceptance that, as
suggested by Mitchell’s story,321 as long as a producer had made sufficient
advance purchases of land and mineral rights, circulation of credible
information about successful fracturing and well development could work to
an early prospector’s substantial favor by attracting copycats who would drive
up the value of the early mover’s land and mineral rights by seeking to buy
their way into a winning play.
Moreover, energy companies might have partly embraced information
sharing because of a sense of its inevitability in an industry where producers
typically relied on various specialized service companies to drill and fracture
wells. These service companies, whose ranks include multinational firms such
as Halliburton Co. and Schlumberger Ltd.,322 acted as natural cross-pollinators
317 Arti K. Rai & Rebecca S. Eisenberg, Bayh-Dole Reform and the Progress of Biomedicine, 66 L. &
CONTEMP. PROBS. 289, 291 (2003) (contending that university patenting under the Bayh-Dole Act might
“hinder rather than accelerate biomedical research”).
318 Id. (describing a “frenzy of proprietary claiming” by universities under the Bayh-Dole Act).
319 Montgomery & Smith, supra note 62, at 36.
320 Id.
321 See supra text accompanying notes 275–78.
322 See Corporate Profile, HALLIBURTON, http://www.halliburton.com/en-US/about-us/corporate-profile/
default.page?node-id=hgeyxt5p (last visited Mar. 5, 2015); Multistage Fracturing Services, SCHLUMBERGER,
http://www.slb.com/services/completions/stimulation/reservoir/contact.aspx (last visited Mar. 5, 2015).
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of techniques and geological information as they moved from job to job and
company to company, making tight restriction of certain transfers of
knowledge likely to be difficult, if not practically impossible.323
In short, general difficulties with policing infringement of process-patent
violations might have combined with the overall regulatory environment,
government policies, industry norms, difficulties with restricting information
flow and enforcing patent rights, and the viability of a mixed strategy of
secrecy and disclosure to make pursuit of patenting undesirable to individual
players. At a group level, failure to seek or enforce patent rights and
willingness to share certain kinds of information might have enabled a regime
of relatively open access to new techniques and knowledge, an environment in
which a great number of variegated players had an opportunity to benefit.324
C. Secrecy and Non-Kitchian Patents
Nonetheless, despite a substantial amount of information sharing within the
oil and gas industry, characterization of the fracking revolution’s relevant
technology space as an “IP-free” or “negative IP” zone325 would be mistaken.
Although broad swaths of information apparently circulated relatively freely,
players in the unconventional natural gas industry have long kept or tried to
keep some forms of information secret. Further, patents on aspects of hydraulic
fracturing, directional drilling, or associated technologies have long been a
feature of various lines of innovation that converged to foster the shale gas
boom.
Generally speaking, there is some schizophrenia in accounts of information
flows in the oil and gas industry. As indicated above, the ease of information
323 NATL RESEARCH COUNCIL, supra note 34, at 55 (“[M]any projects in the drilling, completion, and
stimulation (DCS) areas are very risky and difficult for any one company to keep proprietary, since they are
often implemented by service companies.”); see also Hinton, supra note 6, at 234–35 (observing that, although
George Mitchell “tried to keep his remarkable success [in the Barnett Shale] under wraps to pick up more
leases,” other independents obtained “information passed along the well-service-contractor grapevine” and
“began leasing in areas adjoining Mitchell Energy’s leased land”).
324 See Brett M. Frischmann & Mark A. Lemley, Spillovers, 107 COLUM. L. REV. 257, 270 (2007)
(suggesting how an environment favoring information “spillovers” can generally benefit industry members
through the example of Silicon Valley’s flourishing “in significant part because employees and knowledge
moved freely to new companies”).
325 Cf. Kal Raustiala & Christopher Sprigman, The Piracy Paradox: Innovation and Intellectual Property
in Fashion Design, 92 VA. L. REV. 1687, 1764 (2006) (describing the fashion industry as “part of IP’s
‘negative space’” because it “is a substantial area of creativity into which copyright and patent do not penetrate
and for which trademark provides only very limited propertization”).
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flow and difficulties in controlling that flow are often emphasized.326 On the
other hand, as indicated above in discussing companies’ hybrid strategies of
disclosure and nondisclosure,327 it is clear that not all information is shared. In
emphasizing the value of federal R&D support for smaller independents, Jason
Burwen and Jane Flegal explain that “[m]ajor companies in the industry tend
to guard knowledge of their own innovations as competitive advantages.”328
Indeed, the fact that processes often occur miles below ground might make
patents difficult to enforce, but it also might make secrecy easier. Firms have
regularly entered into consortia that conduct seismic testing and mapping of
shales—complex processes that rely on data captured from far beneath the
earth’s surface—with an accompanying agreement that the data will not be
shared beyond the consortium.329 Perhaps even more tellingly, firms involved
in hydraulic fracturing have long fought against requirements that they disclose
details of the chemical composition of fracking fluids on grounds that these
details are commercially valuable trade secrets.330 Whether the anticipated
“regulatory cost” of disclosure to the public, as opposed to the anticipated
“competitive cost” of disclosure to other producers, is decisive in motivating
the holding of these secrets might be an open question. For purposes here,
however, the most relevant point is that, although much information flows
relatively freely in the unconventional natural gas industry, there is a
substantial residuum of information that individual players seek to hold as their
own.
Secrecy is not the only way by which companies have sought control over
technical innovations. One set of commentators has suggested that, as demands
for disclosure of the details of chemical mixtures used in fracking have
increased, firms have increasingly obtained patents on these mixtures,
presumably because the reality or prospect of forced disclosure has rendered
trade secrecy a nonviable option.331 Regardless of whether this is true, patents
326 See supra notes 299–302 and accompanying text.
327 See supra text accompanying notes 308–18.
328 BURWEN & FLEGAL, supra note 50, at 5.
329 See, e.g., Grynberg v. Total S.A., 538 F.3d 1336, 1342 (10th Cir. 2008) (noting a consortium
agreement among energy companies with a primary purpose to “implement an ‘exploration research study’ to
obtain and interpret seismic and other geologic data”).
330 See supra note 24 and accompanying text.
331 Cahoy et al., supra note 26, at 283 (“Simply put, given the demand for disclosure, companies could be
paradoxically pursuing patenting in part as a means of information containment.”); see also id. at 290–91
(“[F]racturing fluids are the apparent reason for the increase in patent activity in the gas extraction industry.”).
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have essentially always been present with respect to key technologies that
undergird the shale gas boom.
In the mid-twentieth century, patent protection went hand-in-hand with the
early stages of hydraulic fracturing’s development. As discussed in Part I, in
1947, Stanolind Oil and Gas Corporation engaged in the first experiment with
hydraulic fracturing.332 By 1948, Stanolind, through named inventors Joseph
Clark, Riley Farris, and G.C. Howard, had begun obtaining a series of patents
on hydraulic fracturing processes.333 Soon after these patents issued, Stanolind
licensed them to a service company, Halliburton Oil Well Cementing Co.334
Monetization of patent rights was not unknown. In 1953, the companies agreed
that Halliburton’s license would be nonexclusive but that Halliburton would be
compensated for this non-exclusivity by receiving one third of royalties
received under Stanolind’s licenses with others.335
Stanolind was not the only company obtaining patents in the area. Even
with only a little searching, one can find multiple patents on hydraulic
fracturing processes that issued from the 1950s through the 1990s. The original
assignees of such patents include major companies or major-company affiliates
such as Atlantic Richfield Company,336 the Dow Chemical Co.,337 Esso
Production Research Co.,338 Mobil Oil Corp.,339 Pan American Petroleum
332 Montgomery & Smith, supra note 62, at 27.
333 E.g., Well Completion Process, U.S. Patent No. 2,667,224 (filed June 29, 1949) (issued Jan. 26, 1954);
Treatment of Wells, U.S. Patent No. 2,596,845 (filed May 28, 1948) (issued May 13, 1952); Treatment of
Wells, U.S. Patent No. 2,596,844 (filed Dec. 31, 1949) (issued May 13, 1952); Fracturing Formations in
Wells, U.S. Patent No. 2,596,843 (filed Dec. 31, 1949) (issued May 13, 1952) (reissued as U.S. Patent Re.
23,733 on Nov. 10, 1953).
334 Montgomery & Smith, supra note 62, at 27.
335 Cahoy et al., supra note 26, at 289.
336 U.S. Patent No. 5,054,554 col. 1 ll. 41–46 (filed July 13, 1990) (“[A] fracturing method is provided
wherein the rate of fluid injection is such as to control the growth of the fracture by packing proppant into the
fracture tip to arrest fracture length increase and then increasing the width of the fracture by injecting higher
concentrations of proppant.”).
337 U.S. Patent No. 3,302,717 col. 8 ll. 11–13 (filed Dec. 26, 1961) (claiming a “method of fracturing a
well penetrating a subterranean formation”); U.S. Patent No. 3,181,612 col. 9 ll. 49–51 (filed July 7, 1961)
(claiming the same).
338 U.S. Patent No. 3,378,074 col. 1 ll. 26–28 (filed May 25, 1967) (“This invention relates to the
hydraulic fracturing of subterranean formations surrounding oil wells, gas wells and similar boreh