The Shale Gas Business Model and Some Political Implications1
Peter Clancy, Department of Political Science, St. Francis Xavier University
Antigonish, Nova Scotia, B2G2L1 [email protected]
A paper presented at IPSA Montreal meeting, 22 July 2014
Discussions of the ‘shale gas industry’ tend to assume that it centres on a relatively similar set of
firms that conduct upstream – exploration and production – activities. This is true only in the
formal sense that certain firms hold licence rights and are responsible under law. The actual
structure of shale gas E&P is far more complex. This paper explores the corporate organization
of the shale gas business and the implications of multi-stage operations for shale politics.
The paper draws upon two concepts, the business model and the industry cycle, to capture the
full dimensions of shale gas operations. It then examines three sites of commercial and political
interface involving, respectively, the landowner/shale operator; the financier/shale operator;
and the shale operator/subcontractors.
Business models
An analytic variable that is commonplace in business studies but seldom considered in political
studies is the ‘business model’ or ‘industry cycle’. Loosely put, a business model consists of a
series of core relationships and practices which provide a foundation for potentially profitable
operations. Another formulation that draws upon Joseph Schumpeter might define it the
business model as ‘the combining of previously disconnected production factors [that] could
result in new markets and industries, products, production processes and sources of supply.’ 2
For example, in the shale gas sector these postulates might include the following. First shale can,
under certain techniques, yield commercial volumes of gas after hydraulic fracturing. Second the
costs of locating, capturing and raising gas to surface allow breakeven operations in
contemporary markets. Third, the upstream operator-subcontractor structure of production
tends to minimize field extraction costs. Finally the regulatory externalities involved in shale
operations are susceptible to standard solutions.
Corporate performance within the framework of a business model is inevitably uneven. This is
in part because firm performance is limited by particular structures and internal relations.3
Consequently the results within those structures will be variable.
In an emerging industry or sub-industry, a core business model may not easily congeal. Equally
a business model may prove to be transitory, evolving through successive phases according to
commercial, technological or political disturbances. There is also the possibility that multiple
models may be in play simultaneously. The argument below is that North American shale gas
has experience all of this during its 25 year history.
On the subject of shale gas, the business press tends to stress entrepreneurial qualities such as
technological innovation and rapid scale-up. In North America, the industry did not really exist
in 1990 since shale rock was not yet considered commercially exploitable. This changed with the
synthesis of precision horizontal drilling and high pressure hydraulic fracturing. Early fracturing
experiments in Texas’s Barnett shale were anything but revelatory.4 Only when water-based
fluids were substituted for gels were commercial volumes of gas released. Since then the
industry has a strong record of technical innovation, including multi-stage fracturing, multi-well
drill pads, and mobile wastewater treatment systems. What this masks, however, are the
continuing limitations to the shale gas business model. A panoply of operational problems have
2
yet to be solved, including well casing failures, sharply declining production flow rates, fugitive
methane emissions at the wellhead, flowback water disposal, and groundwater contamination,
to name the most pressing ones.5 Especially ignored are the political and regulatory issues,
which industry has assumed could be shifted to public expense, or absorbed as necessary
externalities.
One insightful approach to the range of shale gas business models is offered by the consultancy
Oliver Wyman.6 The most familiar model, reflected in standard shale gas imagery, is the standalone upstream producing company. The shale fracturing pioneer, Mitchell Energy, is a case in
point here. So too are independent shale specialists like Southwest Energy, Range Resources,
and Cabot Oil and Gas. A second model is the integrated gas company that extends linkages
backward to field services and forward to pipeline gathering and direct marketing. The early
2000s industry leader Chesapeake Energy evolved into this sort of firm. A third model sees an
integrated petroleum major, often multinational, buying into the shale gas sector, often to
bolster its booked reserves. In 2009 Exxon Mobil mad just such a move in acquiring XTO for
$41b. Shell followed suit in taking over East Resources for $4.7b. In such cases, the acquisitor
seeks to use its established transmission and marketing units to enhance the primary value. A
fourth model begins with midstream gas gathering and transmission firms that extend their
operations in the ‘backward’ direction into exploration. The fifth and final type involves
downstream gas consumers, industrial and power generators which backwards into E&P seeking
secure feedstock. This framework is captured in Figure 1 below.
Figure 1
In chronological terms, the upstream independents set the pace in the first shale gas boom in
Texas’s Barnett formation in the 1990s. Integrated gas specialists began to appear after 2000, as
gas prices surged and companies turned to a second wave of major shale deposits. The oil
multinationals began to back in to shale operations through mergers and takeovers following the
2008 crash, when the combination of slumping primary prices and massive capital carrying
costs saw many independents vulnerable to takeover. The midstream acquisitors are firms
providing gathering pipelines, processing facilities and compressor stations that move gas from
the wellhead to trunk pipeline connections. Companies such as Access Midstream in the
Marcellus play became key actors once field production volumes begin to mature. Downstream
gas users were motivated, after 2010, by similar pressures. For example, in 2014 there is intense
manoevring for positional advantage in the gas liquefaction and export sector. In the U.S.,
Cheniere Energy’s Sabine Pass project was the first to be licensed and a half dozen further
applicants have won preliminary approval subject to environmental impact review. In Canada,
eight west coast projects now hold export licenses and are moving forward at the planning
stage.7
These ‘model’ categories are dynamic rather than fixed and firms are shifting positions as the
shale industry matures. For example, since 2012 there has been a tendency for upstream
independents to pivot, where possible, from dry gas shales to wet gas and to oil shales. A case in
point is Devon Energy in 2013-14, which sold more than $5b of gas properties in the western
U.S. and Canada, while buying into the Eagle Ford oil shale and creating a mid-stream
subsidiary as well.8
Taken together, this underscores the fact that it is misleading to treat the upstream shale sector
as a uniform set of E&P firms. Despite its relatively recent origin, the shale sector consists of an
accumulation of business models, layered together for functional purposes but distinguishable
3
in terms of core commercial (and political) interests. For any particular shale formation, it
matters considerably which configuration predominates.
Similarly each shale formation encompasses a commercial and political aggregation of interests.
It is misleading to talk simply of ‘shale gas producer interests’ without recognizing the
underlying differences rooted in function and profit source. Thus the Marcellus differs from
Barnett or Fayetteville or Horn River (or, potentially, from New Brunswick). Perhaps the core
interests were shared widely in the opening stage when licensing and drilling activities
predominated. Today however, core interests can vary according the degree of basin maturity.
Shale Development Cycle
Another framework, this time highlighting the developmental steps in primary shale gas
development, is that of the industry cycle. It refers to the essential steps required for production
and distribution. Surprisingly, the upstream sequence for shale gas exploitation is seldom
acknowledged in its entirety. Most of the standard public descriptions concentrate on the
drilling and fracturing stages only, where the twin innovations of directional drilling and high
pressure fracturing are celebrated.
A complete inventory of operational practices is far more complex. It begins with the delineation
of shale rock formations and continues with the acquisition of legal rights to use surface and
subsurface property. On this basis a field exploitation plan is developed. Only then does site
preparation begin, with infrastructure installation (construction of well pads, storage facilities,
roads and pipelines). This is followed by well construction and fracturing and ultimately
production of natural gas. The complete development cycle is captured in Figure 2 below.
Figure 2
Equally important to the discrete functional phases of this development cycle are the economic
and political relationships that are established at each phase. Take, for example, phase one. In a
private land tenure system, petroleum firms cannot commence operations until they have
secured the necessary legal rights, by contract, with the property owners. This covers right of
way to surface lands and royalty payments for subsurface product. There is nothing spontaneous
or automatic about this process. Indeed the professional specialty of “petroleum landmen”
evolved to represent developers in their relations with fee simple property owners and statute
law covers the eligible terms and conditions, along with dispute settlement provisions, for such
processes.
In a similar way the on-site development activities combine a complex set of activities governed
by contract and inter-firm alliances. This is a world of licensed operators and partners, prime
contractors and subcontractors. The operator holds the leases and syndicates shares of product
output among investors. Subcontractors, usually defined by specialized segment – roadbuilding, materiel provision, well drilling, hydraulic fracturing, gas gathering and storage – are
paid for services rendered. Normally the level of competition in specialized segments squeezes
the profit margins while depressing overall development costs.
The flip side of the sub-contracting chain is the innovation potential among specialist firms. This
is a complicated question. Among the most significant innovations in the shale sector would be
the following. The pioneer ‘hydra-fracking’ techniques by the Stanolind Company in the 1950s;
the directional drilling breakthroughs in the 1980s; Nick Steinhauer’s (Mitchell Energy)
4
substitution of water for gel as a fracturing agent in the late 1990s; the capacity to do multisection fracks along 1-2 km laterals, and frackwater recycling techniques in the mid-2000s.
Some indies innovate, many do not. Many are laggards. But there is evidence to suggest that
experimentation is more likely among independent upstream firms while the big corporations
block or decline to innovate.
Convergence & Divergence - Pressure Points and alliances
If the commercial shale gas industry is disaggregated in either of the ways suggested above, what
are the implications for shale gas politics? Much of the public debate since 2010 has been
dominated by the moratorium question – whether or not to permit the licensing and
exploitation of gas bearing shale. While this is certainly a valence issue in greenfield basins that
have yet to be drilled, the politics of shale gas in the half dozen leading commercial basins and
more modest followers is quite different.
It is useful to consider the question from two angles. One inquires into the potential for
corporate convergence and political alliance while the other probes corporate divergence and
the potential for difference. First, are there a cluster of broadly shared interests – embraced
irrespective of business model or cycle stage – that can be translated into an aggregate political
strategy? Second, whether or not the former exists, are some critical issues restricted to
particular sectors such that their fulfillment might be opposed by rival sectors?
On the consensual scale it is possible to identify a number of leading issues. Perhaps the first of
these is resistance to regional moratoria. This is the most blunt threat to the industry and its
acceptance in a series of states and basins, including New York and Vermont in the United
States and Quebec and Nova Scotia in Canada makes this a very real issue. The industry counter
argument has been made so widely that it can be simply summarized: shale gas opens a door to
domestic energy security and offers a potentially massive bridging fuel over the next generation.
Furthermore it is, in climate terms, more benign than any other hydrocarbon fuel source. Finally
it is cheap and abundant and commercially viable.
Another consensual issue is the need for a commercially viable market price to sustain
investment and corporate stability. While the break-even threshold will vary by shale formation
and by operator, there is general agreement that natural gas prices in the period since the
financial crisis are profit-inhibitors. Indeed the Henry Hub price through this period, ranging
from $2.00 to $5.00 per mcf (thousand cubic feet), has inflicted a profits crisis on the upstream
shale sector from which firms are trying to escape. By contrast a sustained price range of $6.00
to 8.00 per mcf would transform industry prospects.9 The structural difficulty is in large part
due to the price-depressing effects of shale gas over-supply as a handful of new formations came
into wide scale production since the crash.
There are a number of potential responses to the oversupply crisis – including production prorationing, price control, and the redefinition of tenure rules to enable longer periods of licensed
tenure prior to production. However the favoured strategy of the moment, and one that has
attracted broad industry support, is market expansion by means of high volume liquid natural
gas (LNG) export to Asia and Europe. By this scenario, shale gas will be delivered, liquefied and
shipped from a range of giant new export terminals on the Atlantic and Pacific coasts. Not only
will this absorb ‘excess supply’ but it will offer far more favourable terms of trade, with long
term LNG delivery contracts to Japan averaging over $15 MMbtu (million Btu).10
5
Notably the shale gas independent producer lobby, the America’s Natural Gas Alliance or ANGA,
called recently for “speedy permitting of LNG export facilities” on the grounds that shale gas
production forecasts suggest sufficient supply for both domestic and overseas sales.11
Three Case Studies of product cycle politics
To more intensively explore the politics of the product chain, the following sections present
three case studies. Each draws attention to a cluster of converging interests that has not been
sufficiently acknowledged. The first centres on the formalization of contracts between shale
operators and the private landowners on whose property the exploration and production take
place. The second centres on the financial underpinnings of the shale gas business as expressed
in relations between lenders and investors on the one hand and operating companies on the
other. The third case involves the business alliances that arise between operating companies and
the various subcontractors which furnish essential services in developing a property.
SUB-SECTOR 1
Shale Gas and the Rural Community: Property Relations
Perhaps the most neglected interest bloc in shale gas politics involves rural and municipal
landowners. Gas exploitation does not begin with the subterranean shale belt, or even with the
technical operations associated with production. It begins when prospective developers seek and
secure the legal rights that are required prior to exploitation. In rural North America, this
involves companies negotiating working rights with landowners, with state authorities shaping
the terms and processes by means of statute and administrative agency.
As a policy network, there are a number of distinguishing features here. First there is the
cultural setting in which land access and extraction rights are pursued. The extent of rural
private property tenure within oil and gas basins is a significant variable in shaping the politics
of rights-holding. Rural landowners, whether farm or non-farm, are closely tied to their physical
properties in family inheritance and amenity terms. Consequently there is a long tradition of
defending rural lands against the encroaching pressures from both state and corporation.
Should the smallholder segment attain critical mass (possible conditions for this are explored
below) it carries the potential for significant political intervention on shale fracturing.
A second factor is the prominence of the legal system in defining relationships and in resolving
disputes. Depending on whether land title is privately or state-held, petroleum land access is
formalized in contracts or in permits and licences. Activity rights are conveyed by two distinct
processes – private contract negotiated between title owner and aspiring developer, or licence
awarded by the state under statute. The focus here will be on the former. It should also be noted
that conflicts among contracted parties tend to be settled by courts and administrative
tribunals.12
There are two distinct types of property rights at stake here. One involves the legal licence to
extract oil or gas – in the form of an exploration permit or a development licence. Depending on
tenure law, ownership of sub-surface minerals (including petroleum) may lie with surface
landowners or with state or crown authorities. The second type involves the right to operate on
surface property, which makes possible the infrastructure and well pad operations necessary for
exploitation. Depending again on tenure system, surface lands may be held by private parties in
6
freehold or by state authorities in crown title. A third variant that is of growing importance
involves Aboriginal title to surface or sub-surface property.
As a general rule, the historically earliest land grants and land sales in Canada tended to confer
both surface and sub-surface rights. However the two bundles of rights were severed in
Canadian law by the early 1900s, resulting in a ‘split estate’ of private ownership on the surface
while crown title prevailed below the surface.
For the oil and gas industry, a necessary preliminary to exploration and production is the
securing of rights of access to private surface lands. This requires formal contracts that
authorize entry and activity on designated territory along with compensation to landowners in
return. This led to the emergence of the specialized profession known as ‘petroleum landmen’ –
trained individuals who contact landowners on behalf of upstream oil and gas companies to
obtain the required consents.13 While landmen may be directly employed by petroleum firms,
they are more commonly hired agents assigned to particular projects. In addition, landmen may
be associated with speculative rights-gathering, or the buying of land rights with the intention of
selling them on at a future date. Landmen are also employed by pipeline companies to secure
right-of-way agreements across private lands.
While the landman role has been part of upstream petroleum economies for generations, it is
less familiar in non-petroleum settings. (One example is in negotiating easements and right-ofway agreements for infrastructural projects like pipelines and transmission corridors.) However
third-party rights negotiation takes on new dimensions in the prospective shale basins since
1990, particularly ones lacking a tradition of conventional petroleum.
In structural terms, the landman is an agent acting on behalf of the petroleum company while
the landowner is the contractual target. Typically, the landman contacts the landowner and
through a series of meetings outlines the project, the desired contractual terms and the
proposed financial compensation. A standard draft contract is conveyed to the landowner along
with information about the state of negotiations with neighbours. Such interactions have been
described in terms of ‘David versus Goliath’.14 This can be an acutely asymmetric relationship
given the contrasting levels of information among the parties and the potential costs to
landowners of gaining relevant information. Notably, the private landowning bloc that is the
target of petroleum rights solicitation tends to be fragmented and incompletely organized. Farm
organizations provide some support in Canada, as does the more recently organized Canadian
Association of Energy and Petroleum Landowner Associations or CAEPLA15. Also recent years
have seen a series of landowner advisory manuals prepared by public law and university
extension bodies.16
A distinguishing feature of the North American shale boom that was set off in 1995 was the
frenetic corporate rush to assemble land rights. This meant that thousands of landmen swept
through the Permian, Fayetteville, Haynesville, Eagle Plain, Bakken, Marcellus and Utica shale
belts, bidding up the monetary offers for shale rights, surface use rights and related activities. At
one point, industry leader Chesapeake energy employed over 5000 landmen alone. The
assembly of that company’s holdings in the Barnett Shale required 260,000 transactions. As
Russell Gold put it, “drilling leases aren’t hard to obtain. They require a large checkbook.”17 In
addition to payments of up to $85 per acre and royalty rates of 25 per cent of lifted value, further
incentives were offered in the shape of up-front ‘signing bonuses’ that could approach $80,000
at the peak of the Marcellus land rush.
7
For a landowner, a first contact by a landman might seek an agreement for land sampling and
surveying in return for a modest cash fee. Or, if shale belt tenure is private held, contact might
begin with an offer for exclusive exploration and production rights and royalty payments, if
shale belt tenure is privately held. Even if shale tenure is in the state domain, a prospective
developer requires a land access and use contract with the surface owner. This covers possible
roads, pipeline rights of way, well pad sites and additional terms related to activities on the land.
Beyond the terms of the model contract that is proffered by landmen, it is common for addenda
to be negotiated according to landowner requirements. This may cover standards for on-site
activity and impacts, terms of notification and disclosure, land and water quality audits,
obligations and compensation for unforeseen damages and post-activity cleanup, and for
abandonment.
Landowner Resistance in New Brunswick: Since 2011, the province of New Brunswick has seen
the emergence of a broad and durable shale protest movement. Not only are rural landowners
and town dwellers integral to this movement, but their manner of involvement speaks to the
learned political outcomes on mineral exploitation.
Rural colonization took place in New Brunswick in the 19th century and again in the 1930s (in
the Acadian north). While original freehold property rights varied, ownership of sub-surface
mineral (including oil and gas) resources were later vested in the provincial crown under the
provincial Oil and Gas Act. This means that the focus of land agent interest today is confined to
negotiating surface access to lands atop the shale formation.
As a consequence of this split estate, the financial incentives in right of way negotiations are far
less substantial for eastern Canadian landowners than is the case south of the border in
Pennsylvania and Ohio. In New Brunswick, for example, crown title to shale means that there
will be no acreage payments or contractual royalty deals between developers and surface
owners. In the Marcellus shale belt in 2006, acreage payment offers began at $25 per acre and
for a large parcel of 250 acres could go as high as $85.18 Furthermore during the Marcellus
shale rights rush, signing bonuses to landowners could run as high as $80 per acre. No parallel
amounts are possible in eastern Canada.
For small rural landowners in the United States, the combination of one-time payments
(bonuses and lease payments) and continuing revenues (royalty payments) constituted a
powerful financial incentive. In eastern Canada, the far more modest monetary returns
underlined the sharply skewed terms of risk and reward. These issues went largely unaddressed
during the formative period of New Brunswick shale controversy beginning in 2009. Only in
2012 did the provincial government acknowledge that crown royalty sharing with landowners
and communities needed to be addressed.19
Looking beyond the land contract payments, there is the question of ongoing governance of
shale operations or put differently for landowners, living with the frackers. Here the political
culture is important and in rural New Brunswick, prior dealings with water contamination from
the Sussex mine was a formative influence. Small landowners in the Sussex area spent several
decades struggling with issues of land subsidence and well water loss in the vicinity of a large
potash mine.20 While this preceded the issuance of shale exploration permits, there were a
number of thematic similarities. For one, the institutional channels of landowner appeal –
through a provincial mines commissioner – were revealed to be weak and unresponsive. More
broadly, the provincial government declined to champion the landowners in their dealings with
the mine. Both the lessons and the parallels here were widely acknowledged. In the face of
environmental or health damage from corporate developers, landowners would be on their own,
8
forced to finance their own court actions, facing difficulty in marshalling expert witnesses and
with minimal support from the public service.21
More specifically for petroleum, landowner experiences in the western Canada sedimentary
basin are instructive. From an early date, surface right of way and pipeline easements were
negotiated between developers and landowners. In 1947 a Board of Arbitration was established
to set compensation in cases where negotiation failed. In the 1970s its successor, the Surface
Rights Board received broader powers to review damages to the land by petroleum operators.22
The Surface Rights Act of 1983 requires that, in addition to the compensation for right of entry,
an entry fee be awarded for each new taking (set at $500 per acre with a minimum of $250 and
a maximum of $5000). In 1977 jurisdiction over right of entry for pipeline, power and telephone
lines was transferred from the Expropriation Act to the Surface Rights Board.
In subsequent years, the American experience has demonstrated some of the mechanisms by
which corporate priorities can overwhelm rural landowners. One of the most telling involves the
design of a development plan for a shale block. Once surface entry and lease rights are obtained,
the corporate holder designs a plan for wellpad siting and associated roads and pipelines. In
part this is framed by the boundaries of the lease block and the desire to maximize the fracture
zone from each wellpad. However such siting priorities do not necessarily coincide with prior
uses (buildings, roads, fields, woods) by landowners. Provisions in surface entry contracts for
landowner right to approve sites in advance do not guarantee protection, since the meaning of
‘reasonable objection’ is frequently contested in court. For landowners, the potential
incompatibility of surface landscape use and fracture plan insert inevitable tensions that
remains unresolved on a broad scale.
The discussion above highlights the initial phases of the landowner-operator relationship, when
rights of way and royalty agreements are the focus. However as a field enters production,
another set of forces can impinge. A dramatic example is the remittance of fees to the
landowner. During the first phase of the modern shale gas industry, operators tended to
construct small diameter ‘gathering’ pipelines to move the product from the wellhead to the
treatment facility and the mid-stream conveyor. Yet as the financial crisis (discussed below)
impinged ever more deeply on shale operators, many opted to reorganize the gas gathering
phase. One strategy is to sell the gathering network to a separate company while signing longterm business contracts with the new firm. In some cases the new gathering fees were multiples
of the original fees. Since contracts normally designate gas transit fees as an eligible deduction
before remitting royalties to landowners, the effect is to shift the operators borrowing costs to
landowners.23 Once the new pipeline charges were factored in, the most severely affected areas
of Pennsylvania saw royalty cheques drop from $5300/month to $514/month over an eightmonth period of 2013-14.
Another evasive tactic adopted by financially pressured operators is to declare the cancellation
of land agreements. Reports began to mount in 2011 that groups of landowners, particularly in
Texas and Michigan, were receiving notice of their leases being cancelled. While reasons were
not always forthcoming, a common explanation was that ‘anomalies’ in the underlying land deed
resulted in the voiding of the shale rights contract.24 Potential issues included undisclosed liens
including mortgages and other restrictions on the future transfer of the shale rights. A variety of
individual and class action suits continue work their way through the courts. Chesapeake Energy
was particularly associated with these actions and the plaintiffs have argued that lease voiding
has become a widespread strategy for a firm that aggressively assembled a land base during
boom times and then came under massive pressure to retrench in the face of lesser results.
9
The lessons from these several confrontations in landowner politics are clear. Any sustainable
political ‘bargain’ for long-term shale development must attend to more than the conventional
terms between companies and state. The integral but largely unrecognized interests of private
landowners must be acknowledged and addressed in a structural recalibration of the
risk/reward equation. This priority may have been obscured in the first phase of shale
development in the leading American basins, once boomtime land contracts became the norm.
But it cannot be so easily bridged in jurisdictions (Canada, United Kingdom) where state title to
the shale resource serves to marginalize surface owners.
SUB-SECTOR 2
Shale Gas and Finance: Access to Capital
As a newly emerging segment of the petroleum sector, shale requires the mobilization of
formidable volumes of capital. This was never going to be straightforward however. As seen
earlier, the commercial shale sector emerged less than two decades ago. Given the geological
and engineering differences, there were no ready standards of comparison in weighing shale
operations. Indeed it took time for a shale gas ‘business model’ to be formalized.
The outlines of the shale story are now familiar. It became possible through a merger of two
distinct technologies – horizontal well drilling and hydraulic fracturing – that were both
pioneered in conventional oil and gas operations. Only a few innovative firms, driven as much
by raw belief as by technical science, persisted in the experimentation process that yielded a
practical field method for shale extraction by the late 1990s. Central to this was Mitchell Energy,
which led the shift from fracking gel stimulants to fracking waters.25 Once demonstrated,
however, it shifted the focus of US petroleum exploration to a series of hitherto ignored shale
formations, beginning with the Barnett shale in north Texas. The business economics of shale
production remained questionable so long as natural gas prices continued in range of $2-3 per
thousand cubic feet (mcf). Yet once gas prices broke through this barrier, in the early 2000s, the
shale industry was off and running, with major basins developed from 2004.
Given the more finite delineations of petroleum-bearing shales, the discovery process differed
significantly from conventional sandstone reservoirs. Major shale formations covered
continuous areas. The exploratory imperative was to map the shale in terms of petroleum
intensity, identifying the ‘sweet spots’ where yield stood to be greatest. From this followed the
land rush discussed earlier. The exploration frontier moved rapidly from the Barnett (1998) to
the Fayetteville (2004), the Bakken (2004), the Marcellus (2004) and the Haynesville (2008)
and Eagle Ford (2008).
When Devon Energy purchased Mitchell outright in 2002, it signaled a broadening of
commercial industry interest and a new form of realizing profits. A series of mergers and
acquisitions followed, first by independent E&Ps and later by American and foreign petroleum
multinationals. This represented massive capital inflow. One early 2000s estimate put the
annual shale industry requirement for new capital at $35b/year.26 Chesapeake Energy emerged
as the sector leader by 2005, aggressively accumulating land positions in each successive basin
with the aim of dominating shale gas production. As each basin developed, a set of core counties
attracted initial attention, with activity spreading gradually to less prospective locations.
Raising capital is not a new challenge for petroleum E&P. The traditional sources ranged from
company loans and bonds to equity issues to tax-incentivized drilling funds to joint venture
farm-ins. All of these applied to shale petroleum as well. Given the novel features of shale
10
extraction however, there was an added challenge to persuade investors. The remarkable shale
industry PR blitz and booster campaign be interpreted in this light.
The politico-business narrative framework for shale boosterism combines several threads. It
began with the prospect for American energy independence and continued with the potential for
this new hydro-carbon production cycle to power economic growth through capital investment,
resource royalties, new jobs in depressed regions and cheap fuel. Third was the emergence of a
mega-profit centre and fourth the opportunity for a ‘clean’ (in climate terms) energy bridge for a
generation.
One way to analyze the 2000-2005 period is from the point of view of shale market-making.
There were at least three key features here. First the natural gas price run-up altered the
perceived economics of shale extraction. Second the celebration of ‘game-changing’ technology
helped to assuage the early technical hesitations. Finally the Bush administration’s endorsement
of the emerging shale sector, most dramatically asserted by the ‘Halliburton loophole’ of 2005,
signaled that environmental impact concerns would not be allowed to pose a significant
regulatory challenge to the shale boom.27
Independents and finance: The emergence of the shale sector coincided with the apex of ‘casino’
finance and the two were not unconnected. There are several dimensions here. First, the shale
sector sought huge pools of capital with a risk premium attached and new financial instruments
were shaped accordingly. Two notable capital raising strategies were the resort to voluntary
production payments or VPPs, and the attraction of large private equity funds into shale
investments. Second, the rapid rise of a market in corporate land rights, and their recognition as
business assets, made early shale companies the targets of super-profit mergers and acquisitions
and a hot source of profit for financial intermediaries. (bundled leases, ‘sub-prime energy’,
Urbina series) Third, the increasing opacity of shale production came to resemble, ever more
closely, the commercial environment for pure financial transactions.
Independent and junior exploration companies of the sort that drove the shale revolution
traditionally raise capital from a variety of sources. The small firms lacking access to equity
markets rely on bank loans and tax-incentivized investor drill funds for working capital along
with selling farm-in participation (joint ventures) to other firms. Publicly traded firms can issue
equity (and bonds?) as well.
The particular character of shale land rights accumulation, noted earlier, posed a particular
financial challenge to aggressive firms seeking to lock up vast acreages before the drilling cycle
began. Moreover the requirement for early drilling on newly leased properties, normally within
a five year time frame, added to front-end costs. Several types of casino finance played key
bridging roles. One is the volumetric production payment or VPP, in which the financial
institution provides capital in exchange for ownership of future gas or oil product.28 This proved
to be a popular option in dealing with big banks, which swapped immediate cash for future gas
production. (This financial instrument was pioneered by Enron Corporation and was well
established prior to the shale boom.) Significantly, VPP transactions could be recorded as offbalance sheet debt, only surfacing in crisis conditions as a Chesapeake Energy in 20__. 29
[Engdahl, others, Rogers?] Another was the role of private equity funds in capitalizing shale
exploration, particularly in the preliminary stages. [details?] When the merger and acquisition
wave accelerated in the 2000s, profits were taken in the sale of first generation rights-holding
firms to integrated multinational petroleum majors.
11
The 2008 financial crisis marked a watershed in this industry as in so many others. Natural gas
prices, which peaked in the $12-13 mcf range in the summer of that year, cratered with the
business slump that followed the September crash. In addition the liquidity vacuum meant that
normal access to capital disappeared. Once the possibility of a rapid bounce-back was ruled out,
a new phase opened with growing shale firm asset sales sets in 2009/10. Eventually this brought
a massive new capital influx from domestic and foreign MNCs seeking to establish positions in
shale. Both private equity purchases and mergers were prominent in 2011 and 2012 before
slowing in 2013.
By this point a wider business debate had broken out about shale sector profitability. This began
with the question of the break-even price for shale gas production. While cost structures vary
between firms, fields and basins, it was widely argued that market prices in the $2.50-$3.50 mcf
range were grossly insufficient for all but the lowest cost fields.30 At the very least the breakeven
threshold, it was suggested, lay somewhere north of $5.00-$6.00 per thousand and for some
fields even $8.00.31
A second thread in the debate involved the gas production performance at particular wells.
There was an approximate ten year delay between the onset of Barnett shale drilling and the
accumulation and release of widespread well performance data. Once available, this suggested
that production volumes in fractured shale tends on average to decline sharply after one or two
years of operation rather than the decade or more that was originally projected. By 2011, the
steeply declining average well production curve became a fearsome symbol of shale industry
over-reach. The implication was either that sites would require costly re-fracturing to extend
their commercial lives or that new sites would have to be exploited on an ever-escalating scale
(the so-called ‘drilling treadmill’).32
Together these factors pointed to a third analytic thread – the question of accurate estimates for
economically recoverable oil and gas field reserves. Such numbers are crucial both in shaping
investor interest and in dictating levels of finance. Outside of technical circles, confusion over
terminology often obscured the issue. While ‘resource in place’ captures the total oil or gas
within the rock, ‘estimated ultimate recovery’ is the truer measure of commercially relevant
product. The former is inevitable higher than the latter. As EUR reserve calculations were
revised downward, this implied either that shale asset valuations would have to be similarly
scaled back or that an early exit from shale rights holding, preferably by sale to third parties, was
imperative. Beginning in 2012, sharp asset write-downs were announced by many leading shale
gas firms.33
There are operational and political implications if the reality of the great shale downgrade is
accepted. E&P companies are under relentless pressure, from positions of chronic losses, to
curtail outlays and to augment revenues by any means possible. This can be reflected in sharp
dealings with landowners, transfer pricing through third party firms, pressurizing contractors at
the drilling and fracking phase, and flipping assets for profit. A similar psychology can affect
regulatory authorities and government leadership, in becoming reluctant to enforce rules and
procedures that might jeopardize industry commitment within a county, state or even basin.
One final avenue of financial pressure is worthy of note here. The past half decade has seen the
rise of activist shareholders within shale gas firms and within the banks and other equity
institutions that support them. This is animated by fiduciary concerns that investor holdings be
adequately protected against adverse impacts. More positively, it seeks to institutionalize
disclosure and campaign for best practices. Beginning in 2009, organizations like the Investor
Environmental Health Network (IEHN) and Green Century Capital Management advanced
12
shareholder resolutions at annual meetings.34 These called variously for: i) enhanced reporting
by hydro-fracking companies; and ii) securing director and managerial commitments to mitigate
the impacts of operations on landowners and environments.
Though they were not carried, the response to these motions was surprisingly positive. More
than a dozen resolutions drew support in the 30%+ range, a strong showing in the context of
new shareholder initiatives. Practices that were flagged include: transparency in fracture fluid
reporting and in baseline water testing; increased adoption of green fracking fluids;
commitment to ‘green completions’ (including methane capture, flowback recycling, well
integrity testing); stringent contractor supervision and auditing; and mandated community
engagement.
The first outcome here was to launch a debate on environmental and social risks within the
investor public.35 A second response by many shale sector firms was to prepare and publish
more elaborate company strategies on the issues identified, thereby heading off parallel
resolutions in future years.
A third thread of fiduciary advocacy was directed not at publicly traded companies but at banks
and financial funds. Here it was argued that despite the apparent profitability of shale resources,
the industrial processes remained at a stage that firms bore high level risks. Financiers were
urged to assess prospective clients in terms of their abilities to control “operating practices on
the ground and through their supply chains.”36 To this end, a checklist of ‘high-level business
practices’ was identified.
SUB-SECTOR 3
The Contractor-Subcontractor Nexus
No firm is an island and the politics of a firm involves not only ‘internal’ relationships between
owners and workers but also ‘external’ relationships between the firm and it suppliers,
customers and bankers. The mapping of such relationships is directly relevant to the analysis of
strategic choices and business policy decisions by firms. While some industry models tend to
enclose key functions within vertically integrated chains, others procure such functions by
contracting in competitive markets. In upstream petroleum, primary production is based upon a
complex configuration of specialized business activities that are purchased rather than delivered
internally.37
In shale gas operations, the range of contracted services is extensive. They can be conceptualized
through a series of concentric circles around the wellhead. Figure 3 provides one illustrations of
these levels. Most consequential for the actual exploration and production are the inner circle of
service firms and consultants that are integral to well drilling, fracking and well completion.
Relationships here are market-driven and are governed by contracts negotiated in competitive
conditions. At the centre, both legally and operationally, is the land rights-holder who bears
ultimate responsibility. The rights-holder is normally designated the ‘operator’ on petroleum
lands. If rights-holding firms are stretched by the number of projects, they may assign this role
to an ‘operating subcontractor’, often one of the farm-in partners on the project. Multinational
service firms such as Halliburton or Schlumberger can play this role as well. Key contracting
roles range from the landmen discussed earlier to seismic mappers, wellpad builders, well
drillers, shale frackers and pipeliners for the gas gathering lines. A prime contractor is normally
responsible for overall site operations while sub-contractors fill designated roles on a site.
13
Figure 3
At one step removed from the core service providers are a panoply of suppliers of material goods
and services. This includes road and well pad builders. At the drilling stage there are also
suppliers of well pipe, well cement, specialist well engineers and geologists. At the fracking stage
the suppliers of materials like sand, water and chemicals enter the picture. Truck carriage
operators are involved for delivery of all of the above. As wells are completed, the storage tank
suppliers and the gas pipe suppliers, the frackwater disposal or recycling firms get involved.
From the standpoint of operational integrity, any of these core and intermediary supply links is
a potential point of vulnerability.
At a third level are the more generic support service providers. This includes the
accommodation and food provisioners and the real estate, insurance and safety equipment
suppliers among others. This is the category that can be most readily managed to maximize local
and regional business participation.
With companies drilling dozens to hundreds of wells per year, the scheduling and negotiating of
onsite sub-contracts, not to mention the monitoring of results, pose constant challenges.
Bargaining leverage varies between tight markets where suppliers are scare and slack markets
where service firms are desperate for business.
During the opening phases of shale gas development, onsite operations and contracting were
largely ‘black box’ activities that were organized by anchor firms. The assertion of proprietorial
rights was vast. One of its most notorious manifestations involved the refusal to divulge the
chemicals involved in frack fluids, on the grounds that they constituted trade secrets. Such
prerogatives went largely unchallenged by state and federal authorities during this time. At the
drill site, authority is organized under the ‘operator rep’ system, where the licensed company
has a designated official on site to coordinate and protect the licensee interests. As Linley puts it,
“generally, companies have an on-site representative at drilling operations who is responsible
for ensuring that the drilling process is conducted in accordance with the operator’s standards.”
38
The black box era served to obscure the dynamics of onsite activities. In practice,
operators relied on continuing connections with preferred suppliers, either through shared
histories of successful collaboration or through a pre-approved tendering roster. In the
overheated conditions prior to 2008, operators were stretched to the limit. Fringe companies
and newly established ventures enjoyed opportunities at peak cycle that brought a potential
added level of risk to the well pad. While the prevailing cloak of confidentiality and regulatory
vacuum blocked a systemic review of conditions, such capacity differentials were significant. As
one commentator put it, “there are wide disparities in how gas drillers operate, monitor their
wells and engage with local communities.”39 This was echoed by Shell Oil President Marvin
Odum, who asserted in 2011 the view that “you are only as good as the worst operator in your
industry.”
The closed character of traditional contracting came to an abrupt end in 2010. The combined
political impacts of BP’s oil blowout in the Gulf of Mexico and the release of the Josh Fox film
Gasland put shale wellsite activities squarely on the public consciousness.
The industry responses in the period since can be arranged on a continuum. At the first level,
the business sponsored codes of oil and gas trade business practice were extended to the shale
sector. A case in point is the Canadian Association of Petroleum Producers, which released a set
14
of Guiding Principles and Operating Practices for hydraulic fracturing operations in 2011-12.40
Described as voluntary but strongly encouraged, this package was presented as a responsible
approach. It centres on a number of well-drilling practices, including the disclosure of water use
volumes, adherence to ‘sound’ well construction practices and recycling of frack water and the
general pursuit of improved best practice. The central message is that, while industry practice
can be improved, the baseline performance is acceptable as presently found. Not surprisingly,
there is no acknowledgement that on-the-ground practices vary widely and that sub-contracting
practices can account for a significant part of the variance.
As a further step, many firms have opted to develop and publish their own corporate codes. One
of the driving forces here was the rise of environmental shareholder activism mentioned earlier.
When environmental resolutions began to attract significant (though usually minority) support
at annual meetings, corporate Boards responded with new policies. As __ observes, “given the
number of incidents in the U.S., it is clear that the presence of [the operator] representative may
not always be sufficient. Clear contractual expectations as well as ongoing contractor auditing
and training are essential.”41
A more rigorous approach, in terms of arms-length criteria and audited assessment, involves
third-party certification. Such frameworks began to emerge in the 1990s, in natural resource
sectors like forestry and fisheries where large firms were under mounting commercial and
political pressure for industrial harvesting practices. In the so-called ‘sustainable management’
certification, candidate companies submit management plans for assessment against stipulated
criteria, by third-party organizations. A driving force for such schemes is the preference by
corporations to be monitored by non-state authorities.42
Since shale gas falls squarely into the category of industries risking de-legitimation, it is not
surprising that such systems have arisen. In 2012 the Centre for Sustainable Shale Development
was formed in the Marcellus basin. A joint product of some of the larger shale firms (Chevron,
Consol Energy, EQT and Shell) and some national and regional ENGOs (Environmental Defense
Fund, Pennsylvania Environmental Council and the Group Against Smog and Pollution), the
CSSD drew upon foundation support to develop a series of fifteen performance standards. In
2014 it began to accept applications for assessment.43 While the CSSD remains at a formative
stage, certain political trends are evident. The process of establishing trust between the two
stakeholder blocks has been uneven. Large shale capital is more supportive and more willing to
pay the potential costs of preparation, review and compliance than is smaller shale capital. And
the institutional capabilities of the certifier are yet to be demonstrated.
Conclusion
This paper makes the case for a micro-political approach to the shale gas industry. This is not to
deny that there are certain unifying issues that draw umbrella corporate support, particularly
issues that pit industry against environmentalists or state regulators. However there is another
level of shale industry politics which, to date, has not attracted the attention it deserves. In
particular, insights can be drawn from the concepts of the ‘business model’ and the ‘shale
product cycle’. The interface of rival models, or discrete development phases, offers evidence of
secondary political tensions that shape the scope of business solidarity.
The paper explores three cases in particular. Relations between shale operator and landowner
have been largely overlooked, due no doubt to the early-stage convergence of interest secured by
bonus, surface rights and royalty incentives. As the working relationship matures, however, a
15
combination of disputes over financial calculations and environmental externalities serve to
divide the landholder block. In addition, where surface ownership has been severed from subsurface shale, the reduced scale of financial incentives can alter the risk/reward calculus and
generate opposition at the land assembly stage.
Relations between shale operators and financiers reveal a distinct though no less complex
picture. It is evident that geological and engineering considerations form only part of the
strategic calculus. The substantial front-end capital costs of land acquisition, coupled with
perpetual imperative for new well drilling and fracking, obliged shale developers to utilize a
range of capital suppliers. Over time the resulting debt loads and service costs eated deeply into
cash flow and precipitated secondary consequences in terms of asset sales and ownership
changes.
Finally, the contractor-subcontractor networks on the well pad illustrate the fragility of core
development processes. The less-than-standard operating practices in shale gas production,
combined with potentially uneven performance among subcontractors and grossly undeveloped
monitoring and auditing systems, raise a series of concerns. Indeed these should be recognized
as generic challenges both to operators and state regulators.
These finding suggest that political and administrative leadership needs to appreciate that shale
gas development includes a far wider set of relationships than is generally conceded. The gaps
and omissions in contemporary policy coverage can threaten the legitimacy of the industry as a
whole. Also, shale gas activity is far from homogenous. Variations based on structural position
and degree of basin maturity must be factored into a political analysis. The dominant political
coalition may vary by place and time. This suggests that the wholesale transplantation of legal
and policy regimes from one basin to another must be critical weighed. The policy tools of the
1990s are unlikely to fit the problems of the 2010s, not least due to the factors reviewed above.
16
ENDNOTES
This project has been supported by a grant from the Centre for Regional Studies at St. Francis Xavier
University.
1
Jonas Hedman and Thomas Kalling, “The Business Model Concept: theoretical underpinnings and
empirical illustrations” European Journal of Information Systems, 12, 2003, 45-59.
2
Peter Clancy, Micropolitics and Canadian Business: Paper, Steel and the Airlines, Peterborough:
Broadview Press, 2004.
3
4
Gregory Zuckerman, The Frackers, New York: Portfolio/Penguin, 2013, chap. 3,4.
Dayna Linley, Fracking Under Pressure: the Environmental and Social Impacts and Risks of Shale Gas
Development, Sustainanalytics, 2011.
5
66
Oliver Wyman, Evolving Business Models in the Natural Gas Shales, 2012. www.oliverwyman.com
Nick Cunningham, “DOE approves sixth LNG export terminal” Oilprice.com, 11 February 2014; “8 LNG
projects have export permits” Pipeline News North, 27 March 2014.
7
8
Devon Energy Corporation “Investor Relations – News Release” Oklahoma City, 30 June 2014.
Natural gas prices are quoted in dollars per thousand cubic feet and by dollars per million Btu
equivalence. These two denominators represent approximately the same volume of gas.
9
Canadian Association of Petroleum Producers, An Overview of the World LNG Market and Canada’s
Potential for Exports of LNG, Calgary: January 2014.
10
11
ANGA,Letter to Boehner and Pelosi, 23 June 2014.
For one intriguing example, see Kaori Suzuki, “The Role of Nuisance in the Developing Common Law of
Hydraulic Fracturing” Boston College Environmental Affairs Law Review, 41(1) 2014, 265-94.
12
13
Canadian Association of Petroleum Landmen, www.landmen.ca
Alan D. Wenger, “David vs Goliath: Representing Oil ad Gas Lessors” Ohio Lawyer, Ohio State Bar
Association. www.ohiobar.org
14
Canadian Association of Energy and Pipeline Landowner Associations. www.landownerassociation.ca.
Based in Regina, CAEPLA is a federation of regional landowner groups. The most recent adhesion came
from New Brunswick during the shale protest period of 2011-14.
15
See for example: CAEPLA, When the Landman Comes Calling Regina 2010; Penn State University
Cooperative Extension, Natural Gas Exploration: A Landowner’s Guide to Leasing in Pennsylvania,
University Park Pa., 2013.
16
Russell Gold, The Boom: How Fracking Ignited the Energy Revolution and Changed the World, New
York: Simon and Schuster, 2014, p.191.
17
18
Gold, p.216.
Government of New Brunswick, Responsible Environmental Management of Oil and Gas Activities in
New Brunswick, New Brunswick Natural Gas Group, May 2012, pp.49-51.
19
17
20
A source for further detail is the Concerned Citizens of Penobsquis, www.penobsquis.ca
Peter Clancy, “Politics and Social License in New Brunswick’s Shale Gas Sector” paper presented to the
Canadian Political Science Association Annual meeting, Victoria, BC, June 2013.
21
22
Sinclair-Santos 2007
23
Abrahm Rustgarten, “Chesapeake Energy’s $5 billion Shuffle” ProPublica, 13 March 2014.
24
Christopher Helman, “Chesapeake Energy: What’s up with these lawsuits?” Forbes, 21 January 2011.
25
For an account of Mitchell Energy’s role see Russell Gold, The Boom, chap.5,6.
26
Russell Gold, The Boom, p.195.
Notwithstanding the crucial symbolic and substantive signals associated with this 2005 amendment to
the Safe Drinking Water Act, it needs to be studies in the wider context of petroleum industry actions to
curtail or prevent federal regulation by the EPA. James Browning and Allan Kaplan, “Deep Drilling, Deep
Pockets in Congress” Common Cause, November 2011.
27
28
Surge Capital Corp, “Volumetric Production Payments: Non-dilutive Commodity Finance”.
29
Russell Gold, The Boom, p.209.
See for example Ivan Andrea, US Shale Gas and Tight Oil Industry Performance: Challenges and
Opportunities, Oxford Institute for Energy Studies, March 2014.
30
31
Arthur Berman 2011: $8-9mcf to break even on full cycle basis and $5-6 mcf on point-forward basis.
Oil Drum as ref by Engdahl.
32
Deborah Rogers, “Shale Promises, Shale Spin” Energy Policy Forum, October 2012.
Deborah Rogers, Shale and Wall Street: Was the Decline in Natural Gas Prices Orchestrated?, Energy
Policy Forum, February 2013, pp.15-17.
33
Investor Environmental Health Network, “Hydraulic Fracturing for Natural Gas and Oil Develoment”
//iehn.org
34
See for example, Susan Williams, Discovering Shale Gas: An Investor Guide to Hydraulic Fracturing,
New York: IRCC Institute, 2012.
35
The Climate Principles, Shale Gas Exploration and Production: Key Issues and Responsible Business
Practices – Guidance Notes for Financiers, March 2013, p.5.
36
J.D. House, The Last of the Free Enterprisers, Toronto: Macmillan of Canada, 1980, chap.3; Peter
Clancy, Offshore Petroleum Politics: Regulation and Risk in the Scotian Basin, Vancouver: UBC Press,
2011, chap.7.
37
Dayna Linley, Fracking Under Pressure: The Environmental and Social Impacts and Risks of Shale
Development, Sustainanalytics, 2011, p.16.
38
39
Marc Gunther, “Shell: We need tough fracking rules.” 17 April 2011. www.marcgunther.com
18
Canadian Association of Petroleum Producers, CAPP Guiding Principles and Operating Practices for
Hydraulic Fracturing. www.capp.ca/canadaIndustry/naturalGas/Pages/default.aspx#operating
40
41
___
For an overview see Benjamin Cashore, “Legitimation and the Privatization of Environmental
Governance: Hoe Non-State Market-Driven (NSMD) Governance Systems Gain Rule-Making Authority”
Governance, 15(4) (October 2002), 503-29. For a profile of early Canadian third-party forestry
certification see Peter Clancy, “The Politics of Stewardship: Certification for Sustainable Forest
Management in Canada: in L. Anders Sandberg and Sverker Sorlin (eds.) Sustainability: the Challenge,
Montreal” Black Rose Books, 1998.
42
43
Centre for Sustainable Shale Development, www.sustainableshale.org