The New York Times published an article this week about how EPA and other federal agencies have quietly increased the dollar value assigned to a human life, to be used for regulatory impact and cost-benefit analysis.
According to the Times:
The Environmental Protection Agency set the value of a life at $9.1 million last year in proposing tighter restrictions on air pollution. The agency used numbers as low as $6.8 million during the George W. Bush administration.
The Food and Drug Administration declared that life was worth $7.9 million last year, up from $5 million in 2008, in proposing warning labels on cigarette packages featuring images of cancer victims.
The reason for the increasing value of human life? A combination of inflation adjustment and choice of methodologies. EPA has tended towards using a capitalized “risk premium” for hazardous occupations such as mining to set a “market price” for risk of death. Industry prefers to use surveys about the price the public would be willing to pay to avoid a statistical risk, or simply to add up lost wages, capping the value of a human life with her expected earnings until death. And therein lies a fundamental flaw in cost-benefit approaches — the illusion of mathematical certainty presented by comparing numbers, while hiding the policy and value assumptions underlying the calculation of these numbers.
Given that administrative policy is subject to change from administration to administration, and even from agency to agency within the same administration, perhaps the assignment of a numerical value for human life should not be left to the regulatory agencies at all. If Congress wants cost-benefit analysis to be part of the environmental regulatory calculus (as it has in TSCA section 6, and the Safe Drinking Water Act), then let Congress put a price on life — let’s establish by statute what value Congress wants to use. Many in the environmental community may fear that Congress would pander to industry and low-ball the number, but I think that the opposite might occur were Congress to have to explain exactly what they think their constituent’s lives should be worth.
The Appalachian Mountain range dates back 300 million years. Its coal is the residue of peat bogs formed in tropical coastal swamps when there was a single supercontinent, Pangaea. But it takes only a matter of months to tear down a mountain peak using explosives and giant excavators. The technique is both faster and less labor-intensive than underground mining, and allows profitable access to thin coal seams that otherwise might not be worth harvesting. Since the mid-1990s, the coal industry has cut a swath of devastation through Appalachia’s remote, coal-rich highlands, one of the nation’s most dramatic cases of environmental devastation and regulatory failure.
The fate of the peaks has drawn international attention, but what goes on in the valleys is in many ways more significant. Each spring, the rain that falls on Appalachian mountainsides gathers into thin rivulets, mixing with spring water and groundwater. These streams, often no more than a foot wide, teem with microscopic, insect and animal life that is the foundation of the forest and river food chains and biodiversity. Plug up those intermittent and ephemeral streams with mining debris, and the ecological fallout extends far beyond the edge of the valley fill, into the surrounding forest and the larger perennial streams and rivers down the mountain.
A valley fill, for instance, profoundly alters forest hydrology. When the rainwater hits a valley fill instead of a stream bed, it filters through broken shale and sandstone before flowing out at the bottom. Ordinary minerals liberated from deep inside demolished mountains – heavy metals such as selenium and magnesium – infiltrate it and flow downstream.
During the Bush years, government scientists produced a growing pile of studies that show how valley fills foul waterways. FWS biologists found that heavy concentrations of selenium in West Virginia’s Mud River, downstream from the huge Hobet 21 mountaintop mine, were causing deformed fish. A 2008 EPA study showed that a huge increase in “specific conductance” – the concentration of electricity-conducting metallic ions – immediately downstream from valley fills was wiping out entire populations of mayflies, a ubiquitous species whose disappearance indicates broader ecological effects.
Destroying waterways and aquatic life are, of course, illegal. But in the bureaucratic funhouse of mountaintop removal, laws may say one thing while actions point in the opposite direction. By a commonsense interpretation, valley fills violate parts of two federal laws, the Clean Water and Surface Mining and Reclamation Acts. But since the 1990s the coal industry and its allies in government have engineered a series of legal and regulatory workarounds.
For instance, the surface mining law banned mining activity within a hundred feet of a stream if it had a significant impact on water quality or the environment — something that would seem to prohibit actually dumping mining debris into the stream in question. But that rule was never enforced, and in the waning days of the Bush administration it was rewritten to make the practice legal. (Interior Secretary Ken Salazar recently announced plans to revoke that change, but left it unclear whether he intended to enforce a ban on dumping.)
Yet it’s the Clean Water Act that environmental groups have relentlessly focused on, filing a series of lawsuits charging the Corps with failing to meet its enforcement obligations, which state that “dredged or fill material should not be discharged into the aquatic ecosystem” if it will cause “significant degradation to the waters of the United States.” Among other things, that includes disrupting the life cycles of aquatic organisms and the loss of fish and wildlife habitat. Again, it seems logical to assume that burying a mountain stream would meet those criteria. But that’s not the way it’s worked up to now.
Put simply, the Corps evaluates the environmental effects of valley fills using techniques that many scientists criticize as insufficiently rigorous. Scientists and environmental groups also object to the Corps’ approach to mitigation, the notion that you can make up for destroying one stream by building another one. That might mean digging a new stream bed nearby, or “mitigation banking” in which a mining company pays to protect and restore a wetland elsewhere.
But streams evolve in landscapes over the millennia and support complex webs of life that cannot be easily replaced, if at all. Stream creation is outside the realm of current science. There’s no evidence at this point in time it’s even feasible. A typical stream construction technique practiced by coal companies, is crude at best: old drainage channels are converted to “streams.”
This dispute remains unresolved in part because the law divides responsibility for valley fills between the Corps, EPA, the Interior Department’s Office of Surface Mining, and the states. The Corps’ jurisdiction is limited to the stream itself and 100 feet on either side, the OSM oversees what happens on the whole mine site. It’s the EPA’s job to look at the entire ecosystem. And the crossed lines of authority have created a regulatory morass and led to erratic, desultory enforcement. The result has been drift: Coal companies can get permission to demolish mountains and fill streams, but they must also deal with more regulatory hurdles while facing continued uncertainty. It’s this situation, untenable for all involved, that the EPA is attempting to resolve.
But the stakeholders do not seem eager for a compromise. At least up to now, the coal industry has usually gotten most of what it wants, giving it little incentive to negotiate. Environmental groups want to see mountaintop removal banned outright. And the Corps, which must also participate in any negotiation, has jealously guarded its permit authority from what it sees as EPA interference. While Obama’s nominee to run the Corps, Jo-Ellen Darcy, handled environmental issues for the Senate Finance Committee and is well-regarded by environmental groups, the Corps is notoriously resistant to change. Lastly, it’s doubtful that a true middle ground — in which mountaintop removal continues with limited changes and the mountain environment is preserved — even exists.
EPA hopes to limit the damage to stream beds by reducing the size of some valley fills, paying more attention to their placement, and by doing more, and better, stream restoration. Such a negotiated, incremental approach could blunt some of the damage, but may not significantly reduce the vast scale of mountaintop projects. And coal companies will resist major changes, especially in the size of valley fills. A study commissioned by the EPA found that sharply limiting the size of valley fills would also restrict the amount of coal harvested. Capping them at 35 acres — a fraction of the size of the average fill, which can cover hundreds of acres — would reduce mountaintop coal production by 77 percent.
The Marcellus Shale has the potential to be one of the largest natural gas plays in the United States, and its successful development appears to entail widespread use of horizontal well drilling and hydraulic fracturing. While the oil and gas industry asserts these technologies are safe, the environmental impacts associated with extraction remain unknown. In light of the current regulatory framework under NEPA and the ESA as applied to hydraulic fracturing activities on federal lands, particularly on federal lands overlying privately-held mineral estates in the Marcellus, the lack of information about environmental impacts is not surprising. It’s a problem.
Natural gas extracting using horizontal drilling and hydraulic fracturing has been underway in Wyoming, Texas and Colorado, among other states, since the early 2000s. In 2005, Congress exempted hydraulic fracturing from regulation under the Safe Drinking Water Act as part of the Energy Policy Act. Specifically, Congress modified the definition of “underground injection” to exclude “the underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities.” As a result of this exemption, EPA cannot use the SDWA to regulate hydraulic fracturing unless it can show the use of diesel fuels, and energy companies engaged in hydraulic fracturing are not required to disclose any information about the chemicals they pump into the ground.
A 2008 study in Colorado concluded that the methane gas tapped by drilling had migrated into dozens of water wells, possibly through natural faults and fissures exacerbated by hydraulic fracturing. In Illinois, geologists have documented methane gas seeping underground for more than seven miles – several times what industry spokespeople say should be possible. In another case, benzene, a chemical sometimes found in drilling additives, was discovered throughout a 28-mile long aquifer in Wyoming. In New York, there is a moratorium on drilling while the state reviews public comments on a proposal to extract gas from the Marcellus.
In May 2009, EPA Administrator Lisa Jackson said that she found allegations of drinking
water contamination linked to hydraulic fracturing “startling” and told members of Congress that
it may be time to take another look at the safety of the hydraulic fracturing process. EPA hired
a consulting firm to survey media reports and publicly available documents describing several
cases of drinking water contamination allegedly linked to hydraulic fracturing. Based on this
review of available literature, the firm concluded that 12 of the contaminant cases examined
“may have a possible link to hydraulic fracturing, but, to date, EPA has insufficient information
on which to make a definitive decision.”
The conference report for the Department of the Interior, Environment, and Related
Agencies Appropriations Act for Fiscal Year 2010, signed into law on October 30, 2009,
requested that EPA conduct a new scientific study of the hydraulic fracturing process.
Specifically, the report states that EPA is to “carry out a study of the relationship between
hydraulic fracturing and drinking water, using a credible approach that relies on the best
available science, as well as independent sources of information.” Implementation of the requested study began in March, 2010.
Meanwhile, in Pavillion, Wyoming, EPA, using its authority under CERCLA, has been
testing residential and municipal wells, in response to community concerns about declining
drinking water quality. The first phase of testing found hydrocarbons and 2-butoxyethanol, a foaming agent used in hydraulic fracturing fluids, in several wells. While EPA has been unable
to “pinpoint any specific source at this time,” the agency acknowledged a potential connection
between this contamination and nearby oil and gas production activities.
The Marcellus Shale extends from west central New York on a northeast to southwest trend down into Pennsylvania, Ohio, and West Virginia, with minor portions of the eastern side of the basin extending into Maryland and Virginia. A highly organic black shale, the Marcellus was formed when a shallow continental seaway existed in the area that now makes up the eastern United States west of the Appalachian Mountains. The interior seaway was a result of the African Plate and the North American plate colliding approximately 380 million years ago. The Marcellus Shale was deposited in a deep trough basin (below the pycnocline, a layer in water bodies below which a density difference prevents water from overturning and bringing oxygen to the lower portions of the water) located between the rise of the Cincinnati Arch and the collision boundary of the two plates. This collision created a deep basin in which little clastic sediment deposition (from rivers and streams) occurred. This depositional environment is analogous to the Black Sea of Europe, where a lack of fresh water flow from rivers prevents the deposition of significant quantities of clastic sediments.
The deposition of large quantities of organic matter below the pycnocline, combined with the thrust faulting from the continued collision of the two continental plates, resulted in a rapid burial process for the organic matter that proved to be the source materials for the natural gas present in this black shale. The rapid burial of the Marcellus, a result of continued sedimentation and thrust faulting, eventually resulted in the sediments surpassing the temperature and pressure of the oil window leading to the formation of large quantities natural gas entrained in the shale’s porosity. The subsequent uplift and erosion of the Marcellus has resulted in the natural formation of an extensive array vertically orientated joints (or fractures). Because these natural fractures run vertically, horizontal drilling provides greater wellbore exposure to the gas reserves in comparison to traditional vertical drilling. In the Marcellus, a vertical well may only be exposed to as little as 50 ft of formation, whereas a horizontal well may be developed with a lateral wellbore extending 2,000 to 6,000 ft within a 50 to 300 ft thick formation.
Hydraulic fracturing is the process through which gas is extracted from shale. In a fracking operation, millions of gallons of fluid — water mixed with sand and blends of chemicals — are pumped into the ground through horizontally-drilled wellbores. The pressurized fluid pulverizes the shale, expanding and extending the existing vertical fractures. The chemicals transform the fluid into a frictionless mass that works its way through the rock, prying open additional tiny fissures that can extend thousands of feet in any direction. Propping agents, such as particles of sand or silicon, wedge inside the fissures, holding the earth open just enough to allow the gas to slip by.
Environmental Concerns and Information Asymmetries
Scientists have found it difficult to determine the environmental impacts of hydraulic fracturing for three primary reasons. First, two kinds of information gaps are problematic – the gap between the gas industry and the public, and the gap between the technology and its effects on hydrogeology. Fracking has not received the same regulatory scrutiny as the processes used for many other energy sources. Because the identities of the chemicals used in fracking fluids have been tightly held as trade secrets, scientists don’t know precisely what to look for when they sample contaminated streams and taps. Scientific uncertainty about the connection between fracking operations and groundwater contamination underscores the possibility that hidden environmental costs could cut deeply into the anticipated economic benefits. For example, it is unclear how far the tiny fissures that radiate through the bedrock from hydraulic fracturing might reach, or whether they can connect underground passageways or open cracks into groundwater aquifers that could allow the chemical solution to escape into drinking water. It is unclear that the fracking chemicals – some, such as benzene and 2-butoxyethanol, are known to cause cancer and have been linked to bizarre disorders of the nervous and endocrine systems – are adequately contained by either the well structure beneath the earth or by the people, pipelines and trucks that handle it on the surface. It is unclear how much of the voluminous waste the process creates can be recovered from the ground, and unclear whether waste that cannot be extracted could migrate into underground sources of drinking water.
These are reasons for concern. Even if layers of rock can seal water supplies from the layer where fluid is injected, the gas well itself creates an opening in that layer. The well bore is supposed to be surrounded by cement, but often there are large empty pockets or the cement itself cracks under pressure. In many instances, the high pressure of the fluids being injected into the ground has created leaks of gas – and sometimes fluids – into surrounding water supplies.
Second, there is the problem of proving causation in cases involving groundwater migration. The abundance of possible explanatory variables in this context make it difficult to establish that any given instance of contamination was a result of fracking operations.
Finally, the federal regulatory scheme seems to be based on an assumption that hydraulic fracturing is safe until proven dangerous. And that burden of proof has been allocated to the states, or – as in the National Forests — to federal land managers, rather than to the O&G permit seekers, who have a monopoly on the crucial information, or to the federal government, which has greatest resources for research and enforcement. The lack of scientific certainty about hydraulic fracturing can be traced in part to the drilling industry’s success in persuading Congress to leave regulation of the process to the states, which often lack manpower and funding to do complex studies of underground geology. As a consequence, regulations vary wildly across the country and many basic questions remain unanswered.
Frackwater in the Monongahela
On the East coast, one of the most important unanswered questions about drilling is how to dispose of the chemically tainted wastewater that hydraulic fracturing produces. Most drilling wastewater in other parts of the country is stored in underground injection wells that are regulated by EPA under the Safe Drinking Water Act. However the geology in the Marcellus makes injection less viable, and less common. In West Virginia, millions of gallons of drilling wastewater could eventually be produced each day.
That wastewater likely contains high levels of Total Dissolved Solids – a mixture of salts, metals and minerals – that can increase the salinity of fresh water streams and interfere with the biological treatment process at sewage treatment plants, allowing untreated waste to flow into waterways. High TDS levels also can harm industrial and household equipment and affect the color and taste of water. But without identification and routine testing for the problematic chemicals, it will be impossible to know how much of them are making their way to drinking water sources, or how they are accumulating over time. Evolving medical science says low-dose exposure to some of those chemicals could have much greater health effects than the EPA or doctors have previously thought.
In the Monongahela, regulation of the hydraulic fracturing process has failed to address at least three critical scientific issues. The first of these are the substantial risks posed by fracking in karst landscapes. “Karst” refers to a specific type of landscape containing caves and extensive underground water systems that is developed on especially soluble rocks such as limestone, marble and gypsum. Many hydrogeologists mistakenly assume that if karst landforms are absent or not obvious on the surface, then the groundwater system will not be karstic. This assumption can lead to serious errors in groundwater management and assessment of environmental impacts, because karst groundwater circulation can develop even though surface karst is not apparent. Karst is typified by seeps, springs, sinkholes, sinking streams and caves. Fracking in karst thus increases the risk of contamination to groundwater supplies, threatens the habitat of cave-dwelling endangered species such as the Indiana bat and Virginia big-eared bat, and, where springs and seeps exist, risks surface water contamination as well.
Karst is abundant in the U.S., particularly in areas where gas drilling and hydraulic fracturing are becoming increasingly common, like the Marcellus. The Independent Petroleum Association of America (IPAA), which represents the thousands of independent oil and natural gas producers that develop 90 percent of U.S. wells and produce over 80 percent of U.S. natural gas, has acknowledged that “approximately 90 percent of these wells now require the use of hydraulic fracturing.” This increase in the use of hydraulic fracturing in West Virginia has led to the development of the Oriskany formation in the Monongahela, where land application of hydraulic fracturing fluids resulted in the immediate death of 3 acres of vegetation in the MNF’s Fernow Experimental Forest. There is also significant overlap between karst areas and the Marcellus shale formation. As development of the Marcellus increases, the risks of significant drinking water contamination and wildlife habitat in karst will grow.
Second, regulation should reflect a comprehensive understanding of the full lifecycle of the hydraulic fracturing process, including an examination of water sourcing issues. Given the massive amounts of water needed for each frack (approximately 2-4 million gallons per well ) and the various uses to which available water supplies are already committed, ensuring both quantity and quality of drinking water is paramount.
Finally, permitting decisions must include informed assessments of the potential cumulative impacts of fracking activities on the drinking water quality of those citizens who rely on individual water wells to supply their drinking water needs. Because natural gas development tends to take place in rural areas, which are also the areas where people are most likely to rely on well water, regulators must consider both threats to continued water supply from water drawdown at the beginning of the process and the risks of well water contamination and habitat destruction as fracking activities proceed and expand in the future.
Federal Property Rights and Obligations in the Monongahela
Most of the lands in the Monongahela are split estates, where the United States owns the surface of the property and another entity owns the subsurface mineral rights. When the United States acquired the Monongahela forest lands by deed, dated November 26, 1915, the sellers reserved the underlying mineral rights. The 1915 deed reserving the mineral rights provided that the mining and removal of minerals shall be done in accordance with the rules and regulations prescribed by the Department of Agriculture, which were incorporated into the deed. The mineral reservation terms require the Forest Service to 1) approve the locations of structures or improvements, such as roads or bridges on MNF land, needed to carry out the private mining operations; and 2) to ensure that these mining operations are carried out in a manner that prevents the “obstruction, pollution, or deterioration of National Forest streams, lakes, ponds or springs, and the escape of harmful or deleterious material or substances to National Forest System land from the operations.”
REGULATORY FRAMEWORK: Managing Vertical Externalities
1. Forest Service and the NFMA
The Forest Service administers National Forest land pursuant to the National Forest Management Act (“NFMA”). The Forest Service has a responsibility to manage the landscape for wildlife, energy development, and many other purposes. The NFMA requires the FS to “manage the public lands under principles of multiple use and sustained yield,” in a manner that will “minimize adverse impacts on the natural, environmental, scientific, cultural, and other resources and values (including fish and wildlife habitat) of the public lands involved.” NFMA also requires the FS to inventory its lands and their resources and values, and then take this inventory into account when preparing land use plans. Through management plans, the FS can and should protect wildlife (as well as scenic values, recreation opportunities, and wilderness character) on the public lands by prescribing various management actions, including the exclusion or limitation of certain uses of the public lands. This is necessary and consistent with NFMA’s definition of multiple use, which identifies the importance of wildlife (in addition to other values) and requires the FS to consider the relative values of these resources but “not necessarily to [choose] the combination of uses that will give the greatest economic return.”
In the Monongehela, as in other national forests, the Forest Service is responsible for land use and permitting decisions concerning use of the surface, while administration of federal mineral rights and the issuance of federal oil and gas leases are the purview of the Bureau of Land Management, though the FS retains veto power over such decisions.
Section 101 of the National Environmental Policy Act declares a broad national commitment to protecting and promoting environmental quality. To ensure that this commitment is “infused into the ongoing programs and actions of the Federal Government, the act also establishes important ‘action-forcing’ procedures.” The procedural requirements of NEPA apply whenever federal agencies contemplate “major Federal actions significantly affecting the quality of the human environment.” Section 102 requires every federal agency contemplating such action to put its reasoning and conclusions in writing and subject them to public scrutiny and judicial review. Section 102 provides that the federal agency prepare an environmental impact statement, detailing the environmental impact of the proposed action, including the potential adverse environmental effects of the action, and identifying and addressing alternative courses of action that may be more environmentally friendly.
The EIS requirement serves NEPA’s sweeping policy commitment in two respects. First, it ensures that the agency, in reaching its decision, will obtain and will carefully consider detailed information concerning significant environmental impacts. It requires federal agencies to take a “hard look” at the potential environmental consequences of the proposed action, such as a resource management plan or oil and gas development project. Second, it guarantees that the relevant information will be made available to the larger audience that may also play a role in the processes of making and implementing decisions.
The acting agency, be it the FS or BLM, must assess impacts and effects that include: “ecological (such as the effects on natural resources and on the components, structures, and functioning of affected ecosystems), aesthetic, historic, cultural, economic, social, or health, whether direct, indirect, or cumulative.” NEPA’s hard look at environmental consequences must be based on “accurate scientific information” of “high quality.” The agencies’ interpreting guidance expand on this obligation, requiring that “influential information” (information that is expected to lead to a “clear and substantial” change or effect on important public policies and private sector decisions as they relate to federal public lands and resources issues, such as that information contained in or used to develop a resource management or major oil and gas development project) use the “best available science and supporting studies conducted in accordance with sound and objective scientific practices.”
The key CEQ regulation, 40 C.F.R. 1508.25, requires agencies to consider in a single analysis actions that are connected, cumulative, or similar. Connected actions are those that cannot or will not proceed unless other actions are taken previously or simultaneously, and those that are interdependent parts of a larger action and depend on the larger action for their justification. For example, in Thomas v. Peterson, 753 F.2d 754 (9th Cir. 1985), the court required the FS to analyze the impacts of subsequent, anticipated timber sales in conjunction with a decision to build road whose justification depended on the sales. Thomas also considered, and rejected, the FS’s argument that it was sufficient to consider the cumulative environmental impacts in ex-post NEPA documentation it would produce in connection with the timber operation, after the road was built:
Where agency actions are sufficiently related so as to be “connected” within the meaning of CEQ regulations, the agency may not escape compliance with the regulations by proceeding with one action while characterizing the others as remote or speculative.
2. Ongoing Implementation of Plans
In certain circumstances an EIS or EA must be supplemented to account for the impacts of activities not considered in the original NEPA documentation . Specifically, the regulations require supplementation where there are “significant new circumstances or information relevant to environmental concerns and bearing on the proposed action or its impacts.” In Marsh v. Oregon Natural Resources Council, 490 U.S. 360 (1989), the Supreme Court interpreted § 4332 in light of this regulation to require an agency to prepare supplementation only if “there remains major Federal action to occur,” as that term is used in § 4332(2)(C). In Norton v. Southern Utah Wilderness Alliance, 542 U.S. 55 (2004), the Court, citing Marsh, held that “although the approval of a [land use plan] is a major federal action” requiring an EIS, that action is completed when the plan is approved.
The implication is that ongoing implementation of plans may not trigger NEPA analysis. Norton addressed a claim that BLM had violated NEPA by failing to prepare a supplemental environmental analysis to the EIS it originally completed on the land use plan, in order to discuss the impact of unexpectedly large ORV traffic in the wilderness area in question. The Court rejected this argument, finding that there was no ongoing “major Federal action” that could require supplementation (though additional NEPA analysis is required if a plan is amended or revised.).
3. Categorical Exclusions
Categorical exclusions, originally created in the 1969 NEPA, allow federal agencies to approve certain projects on federal land without any extensive review of environmental impacts if the agency determines the projects will not have significant environmental impacts. For the purpose of reducing delay and paperwork, the CEQ regulations provide for categorical exclusions (CEs) to implement the NEPA. CEQ regulations allow federal agencies to exclude from documentation in an environmental assessment (EA) or environmental impact statement (EIS) categories of actions that do not individually or cumulatively have a significant effect on the human environment. (emphasis added). After an agency promulgates counterpart regulations identifying which of its common actions ordinarily do not require even an EA to confirm no significance, implementation generally requires little notice or documentation.
In recent years, the FS has moved aggressively to expand the use of CEs. In 2005, it attempted to exempt the entire forest planning process from NEPA. The Energy Policy Act of 2005 (Section 390) established CEs for five categories of oil and gas exploration and
development activities conducted pursuant to the Mineral Leasing Act on federal oil and gas leases. In Section 390, Congress replaced the standard procedural mechanism for compliance
with NEPA. The categorical exclusions addressed in this guidance are established by
statute and not under the Council for Environmental Quality (CEQ) procedures pursuant
to 40 CFR 1507.3 and 1508.4. Therefore, their use is not dependent on the usual CEQ process
for approving new categorical exclusions or other NEPA procedures. Thus, if a proposed activity meets the criteria of any of the five categories for categorical exclusion, it is also presumed that no further NEPA analysis is required. Specifically, if a proposed activity falls under one of the statutory categorical exclusions, agency categorical exclusion direction, or the extraordinary circumstances contained therein are not to be used. Importantly, however, Section 390 does not limit or diminish the Forest Service’s substantive authority or responsibility regarding review and approval of a Surface Use Plan of Operation (SUPO) conducted pursuant to 36 CFR 228.107-108. The Authorized Forest Officer must continue to assure that operations on leaseholds on National Forest lands will minimize effects on surface resources and prevent unnecessary or unreasonable surface resource disturbance, including effects to cultural and historical resources and fisheries, wildlife and plant habitat. Best management practices are to be applied as necessary to reduce impacts of any actions approved under these categorical exclusions.
Section 390 gives federal land managers the benefit of a “rebuttable presumption that the use of a categorical exclusion” under NEPA would apply to several categories of activities involved in developing oil and gas leases. Such categories include surface disturbances of less than five acres where the total surface disturbance on the lease is not more than 150 acres and a site-specific analysis had previously been completed in a NEPA document; drilling a well in a developed field where previous NEPA documents had “analyzed such drilling as a reasonably foreseeable activity” and had been approved within the last five years; and “maintenance of a minor activity, other than any construction or major renovation o(f) a building or facility.” To use a “minor activity” exclusion, the Authorized Forest Officer must determine and document that the activity under consideration constitutes maintenance of a minor activity (a non-exclusive list of such activities include maintenance of a well, wellbore, road, wellpad, or production facility having surface disturbance). The Authorized Forest Officer must include in the project record three types of documentation to demonstrate use of the categories apply to the activities under consideration: 1. identification of the categories used; 2. a brief narrative stating the rationale for making the determination that use of the CE applies to the activity under consideration, specifically addressing the applicable review criteria; and 3. copies or reference to materials used to support its use determination.
In its administration of land use in the Monongahela, the Forest Service has cited the categorical exclusion at 36 CFR 220.6(e)(3) for surface activities associated with the hydraulic fracturing operations of private mineral rights-holders. The 220.6(e)(3) CE applies to “approval, modification, or continuation of minor special uses of National Forest System lands that require less than five contiguous acres of land. Consequently, the environmental impacts of many steps in the hydraulic fracturing process, including those caused by on-land wastewater disposal, have not received NEPA scrutiny. For example, the potential impacts that so-called “land applications” of wastewater from hydraulic fracturing may have, individually and cumulatively, on USDWs and ecological resources in the forest have not been assessed. The risks of water contamination and habitat degradation posed by this practice are particularly concerning in areas overlying rich karst structures, such as the Fernow Experimental Forest near Parsons, WV. But the extent of such risks remain unknown, as they were not considered by the FS in NEPA documentation. The FS has taken the position that its use of the CE is warranted because land application of hydraulic fracturing fluids is a routine activity with known effects, and that no extraordinary circumstances exist that could be impacted by land application.
Use of 220.6(e)(3) in this context is inappropriate for at least three reasons. First, the Section 390 CEs apply “exclusively to oil and gas exploration and development activities
conducted pursuant to the Mineral Leasing Act of 1920 on Federal oil and gas leases. The USDA guidance clarified that the phrase “on Federal oil and gas leases” means that the applicability Section 390 does not extend to private or outstanding rights. Since the gas leases at issue in split estate context of the Monongahela’s are privately issued, it is difficult to see how development activities associated with those leases are covered by the Section 390 CEs.
Second, NEPA’s effectiveness depends entirely involving environmental considerations in the initial decision-making process. The purpose of an environmental assessment is to provide the agency with sufficient evidence and analysis for making an informed determination that considers the potential environmental effects of a proposed action before approving it. By circumventing this vital information-gathering step, the FS was unable to make an informed determination. Instead, it gave land application a rubber stamp without considering the potentially disastrous consequences that this manner of disposing of toxic fluids may have on the Monongahela. The FS does not even know what chemicals or elements will be contained in the fracture fluid, and likely will not know until after application has occurred. Finally, this method of wastewater disposal simply does meet the requirements for a 220.6(e)(3) exclusion. Given the unknown chemical composition of frackwater and the lack of information available to the FS regarding the potential impact on wildlife and water sources of dumping thousands of gallons of frackwater in the Monongahela, the FS is hardly qualified to dismiss the practice as a “minor” land use.
Moreover, the FS actions in this context – namely, approving the construction of gas wells, pipelines, and plans for disposal of wastewater proposed by the energy company –sufficiently related so as to be “connected” within the meaning of CEQ regulations. All are interdependent parts of the company’s larger plan to exercise its subsurface mineral rights in the Monongahela, and all depend on the larger plan for their justification. As discussed in Thomas, an agency may not escape compliance with the regulations by proceeding with one action while characterizing the others as remote or speculative.
The FS has made no effort to detail or disclose reasonably foreseeable actions on MNF lands arising from the Berry Energy’s ongoing hydraulic fracturing. Nor has it discussed any potential effects – direct, indirect or cumulative – in any of the comment letters for Berry’s surface activities. The FS’s use of the CE and its failure to properly assess the effects on extraordinary circumstances in the has allowed the agency to inappropriately narrow its assessment of the cumulative impacts of wastewater disposal and other post-leasing activities in the Fernow. No cumulative effects analysis was presented for public comment and the only effects analysis (a biological evaluation under ESA, discussed below) was limited in scope and available only after the decision. The FS indicates that there is not likely to be any assessment or disclosure of the cumulative impacts of the overall Berry Energy development plan. This piecemeal approach to the environmental impacts analysis improperly ignores what are reasonably foreseeable activities – and cumulative impacts – beyond the proposed instance of land application of fracking fluids.
For the site-specific pre-drilling NEPA analysis necessary to assess the impacts arising from oil and gas development on these leases, the FS Decision Memos rely heavily on the analysis contained in the 2006 Monongahela NF Forest Plan and and Final EIS. However, neither of these documents contain the site-specific analysis necessary to satisfy NEPA’s requirements, especially that for a “hard look” at the impacts. The 2006 MNF Forest Plan actually tiers to a 1992 Forest Plan amendment (Amendment #4) identifying federally owned oil and gas available for lease on the Forest. This would be inadequate under NEPA and arbitrary and capricious. The 1992 Plan Amendment did not consider the cumulative impacts of ongoing extensive hydraulic fracturing and wastewater disposal in the Forest, which would have been unforeseeable at that time. The circumstances have changed and new information has arisen since then, necessitating further analysis.
Alternatives to land application, such as disposal in toxic waste treatment facilities, do exist and are mandated by law many states. Propping agents consisting of sand and water without any additives have been used effectively, as have agents containing sand and water with non-toxic additives. Non-toxic additives are being used by the offshore oil and gas industry, which has had to develop fracturing fluids that are non-toxic to marine organisms. Oil and gas wastes are often flowed back to and stored in pits on the surface. Often these pits are unlined. But even if they are lined, the liners can tear and contaminate soil and possibly groundwater with toxic chemicals. The same chemicals that are injected may come back to the surface in the flowed-back wastes. As well, hydrocarbons and naturally-occurring radioactive materials from the fractured formation may flow back into the waste pits. A reasonable alternative of storing wastes may be flow them back into steel tanks.
The Forest Service should prepare EAs that address these and other alternatives. Recent studies in Pennsylvania, New York, Colorado, and Wyoming have traced contaminated streams and underground sources of drinking water to local hydraulic fracturing operations and their voluminous waste products. This new information, combined with the possibility of safer propping agents and the availability of safer methods of hazardous wastewater disposal, would seem to constitute new circumstances and information relevant to environmental concerns and bearing on the the impacts of Berry Energy’s wastewater dumping program. Given the ongoing nature and anticipated escalation of natural gas development in the Monongahela, the FS should scrutinize such activities in light of the expected cumulative effects, and support its findings with scientific evidence. This would be consistent with Metcalf v. Daley, where the court ordered the agency to repair its flawed EA by preparing another EA, and consistent with National Audobon Society v. Hoffman, 132 F.3d 7 (2d Cir. 1997), where the court found that the FS violated NEPA in an EA for constructing a road and then logging in a portion of the Green Mountain National Forest in Vermont. In Hoffman, the court ordered another EA, based on its conclusion that the FS failed to consider a number of relevant environmental factors and to include sufficient mitigation to justify the finding of no significant impact.
B. Forest Service obligations under the ESA
Under the NFMA the Forest Service must create land and resource management plans for the forests within its jurisdiction. The planning process consists of two stages: programmatic and site specific. The programmatic stage involves the development of a broad, long-term planning document for an entire forest. The forest plan guides the management of the forest in a multiple-use framework. It establishes planning goals and objectives for units of the National Forest system and specific standards and guidelines for management of forest resources, taking into account both environmental and economic factors. There is an opportunity for public participation in development of the plan and for public review of the plan and comment. Forest plans are implemented through individual site-specific projects. At this stage, the Forest Service proposes, analyzes, and decides upon specific actions.
The Endangered Species Act expresses a legislative mandate that the Forest Service, FWS, and other federal agencies “afford first priority to the declared national policy of saving endangered species.” The ESA authorizes the Secretary of the Interior to list a species of wildlife as either “endangered” or “threatened.” The Act requires each federal agency to “insure that any action authorized, funded, or carried out by such agency … is not likely to jeopardize the continued existence of an endangered or threatened species or result in the destruction or adverse modification of [the critical] habitat of such species …”. “Jeopardize the continued existence of” means to engage in an action that reasonably would be expected, directly or indirectly, to reduce appreciably the likelihood of both the survival and recovery of a listed species [i.e., a species which has been determined to be endangered or threatened under the Act] in the wild by reducing the reproduction, numbers, or distribution of that species.” “ ‘Recovery’ means improvement in the status of listed species to the point at which listing is no longer appropriate under the criteria set out in section 4(a)(1) of the Act.”
Section 7 of the ESA, 16 U.S.C. § 1536, and its implementing regulations found at 50 C.F.R. Part 402 establish the procedure for determining the impacts of a proposed federal agency action. An agency that proposes an action must first determine whether the action “may affect” the listed species or critical habitat. With certain exceptions, if an agency determines that an action it proposes to take may adversely affect a listed species or critical habitat, it must engage in formal consultation with FWS to determine whether the proposed action may jeopardize the continued existence of the endangered species or critical habitat. The federal agency requesting consultation must provide FWS the best scientific and commercial data available.
FWS’s responsibilities during formal consultation are to review all relevant information provided by the federal agency or otherwise available; evaluate the current status of the listed species or critical habitat; evaluate the effects of the action and cumulative effects on the listed species or critical habitat; formulate its BiOp as to whether the action, taken together with the cumulative effects, is likely to jeopardize the existence of the species or result in the destruction or adverse modification of critical habitat; and discuss with the federal agency and any applicant FWS’s review and evaluation, the basis for any finding in the BiOp, and in the event a jeopardy opinion is to be issued, the availability of reasonable and prudent alternatives that the agency and applicant can take to avoid violating § 7(a)(2). The BiOp produced must include a summary of the information on which FWS’s opinion is based; a detailed discussion of the “effects of the action” on the listed species or its critical habitat; FWS’s determination of “jeopardy” or “no jeopardy;” and reasonable and prudent alternatives in the event a jeopardy determination is made.
If FWS concludes that the agency action will not result in jeopardy to the species, or if FWS offers RPAs to avoid that consequence, FWS must provide the agency with an Incidental Take Statement. The ITS must specify the impact of the incidental taking on the species; reasonable and prudent measures that the FWS considers necessary or appropriate to minimize such impact; and the terms and conditions … that must be complied with by the Federal agency or applicant (if any) or both, to implement [those measures].” “Incidental take” means “takings that result from, but are not the purpose of, carrying out an otherwise lawful activity conducted by the Federal agency or applicant.” “Reasonable and prudent measures” means “those actions necessary or appropriate to minimize the impacts, i.e., amount or extent, of incidental take.” If the proposed action complies with the terms and conditions of the Incidental Take Statement, the incidental take is not prohibited under the ESA.
The Monongahela Forest Service has cited the “highly conditional” and unpredictable nature of surface activities stemming from natural gas development as grounds for not addressing the impacts of such activities in a pre-lease biological evaluation. But this position is inconsistent with Thomas, where the Ninth Circuit held that surface leases required BiOps that addressed post-leasing activities, even though forecasting what those activities might be was difficult.
While the MNF has repeatedly acknowledged the presence of karst topography on the Fernow, it has not assessed the direct and indirect effects that horizontal and hydraulic drilling and land application of wastewater might have on groundwater and endangered species habitat in the karst system. The Berry Energy gas field lies within a “key area” of the endangered Indiana bat’s primary range. Big Springs Cave (BSC) is located half a mile east of the land application area, but is part of a larger cave system underlying this part of the Forest. The BSC has been identified as hibernacula for approximately 300 Indiana bats. In fact, a Well Operator’s Report of Well Work filed with the WV Department of Environmental Protection, Office of Oil and Gas on October 7, 2008, by Berry Energy for the B-800 well, notes on page 3 that during initial drilling and first fracture open caves were encountered at 92 and 149 feet and that a mud filled cave was encountered at 164 feet. Additionally, fresh water was encountered at 395’. This indicates there are likely abundant natural fractures, caverns and solution cavities existent within this karst structure and that it serves as a conduit for groundwater.
Land application of waste to soils overlaying such obviously rich karst structures creates the potential for seepage into the caves and caverns, thus altering the chemistry of such structures. The alteration of the chemistry could produce changes in the humidity level, which could in turn alter the temperature. Additionally, the air quality could be diminished if such toxic chemicals are introduced into a confined space. Disturbance of cave habitat due to the initial drilling, including modification of delicately balanced air flow and temperature regimes has potentially already occurred. Indiana bats, in particular, can only hibernate successfully within a very narrow, specific temperature range, and have been known to abandon hibernacula when structural or other changes to the caves resulted in unsuitable temperatures.
In the Monongahela, the Forest Service’s administration of surface activities relating to hydraulic fracturing looks a lot like an ongoing violation of the ESA. By letter dated November 2, 2007, the FS transmitted to the FWS a Biological Evaluation and Decision Memo for Berry Energy’s proposed Gas Well B-800 and access road. In its cover letter and in the BE itself, the FS stated that the mineral owner had a right to develop their minerals and that the FS did not have authority to control the use of surface beyond the terms in the mineral reservation. The FS concluded that it had a mandatory duty to allow Berry Energy to exercise its mineral rights and no discretionary control over the operations, such that would trigger the requirements of NEPA or Section 7 of the ESA. In response to the FS’s position in the 2007 BE for the B-800 well, the Office of the Solicitor for the Department of the Interior issued a memorandum to the FS West Virginia field office in February 2008. The memorandum stated that the FS’s “conclusion that it has no discretionary control over Berry Energy’s right to develop their mineral interests is incorrect. . . When the owner of the surface estate is the United States, the government has the authority to regulate the use of the surface and impose conditions on that use. Federal law, if applicable, preempts state law.”
To date, the FS does not appear to have exercised that discretion. It has continued to grant special use permits for hydraulic fracturing activities on the surface without assessing cumulative effects to the human environment under NEPA or providing mitigation measures to protect Indiana bat habitat from drilling in karst structures. The ESA requires federal agencies to consult with the FWS regarding the impacts of proposed federal actions that may affect threatened and endangered species. Given the existence of Indiana bats and karstic hibernacula in the Fernow, the proper conclusion is that drilling and land application of wastewater “may affect” this listed species, which triggers the requirement that the FS engage in consultation with the FWS. But the FS has apparently not consulted with FWS on these special use permits. The FS mailed its Biological Evaluation for the proposed well B-800 wastewater discharge to FWS on the same day it issued its Decision Memo granting the proposal. Thus it is difficult to see how consultation could have occurred prior to the decision.
Further, as the ESA’s implementing regulations make absolutely clear,“[e]ach federal agency shall review its actions at the earliest possible time” to determine whether an action may affect protected species, and, if so, to engage in the appropriate level of conferral. Thus, the FS must consult with the FWS over the impacts to Indiana bats and Virginia big-eared bats on proposed drilling and wastewater disposal activities. The FS’s failure to initiate meaningful consultation with FWS violates the ESA.
Berry Energy has now obtained a state permit for a plug to be placed to access a shallower horizon the same B-800 well, and plans to develop 8-10 additional wells in the Fernow gas field. Additional hydraulic fracturing could force fracking fluids into formations that would increase the risk of adverse effects to groundwater resources. It could also result in greater risks of adverse effects on the cave system and a higher likelihood of take under the ESA. These potential impacts must be analyzed and disclosed under NEPA and an updated BiOp.
In conclusion, the FS’s responsibility for regulating land uses associated with oil and gas leasing necessitates a full environmental analysis of the likely post-leasing impacts of ongoing gas production before any special use permits are issued. Overall, the Forest Plan data is far too old for use under NEPA and should be updated. Changes in the nature and extent of surface disturbing activities, the lack of analysis of the cumulative effects of hydraulic fracturing on groundwater, increased future development well beyond that considered in the DMs and BEs for gas wells and land application of wastewater, as well as the presence of threatened, endangered and sensitive species since the 1992 analysis render this data moot. No other updated site-specific analysis was included in the 2006 Forest Plan. Given the absence of an underlying NEPA document or BiOp that adequately considers the impacts of these activities on forest resources, issuance of these special use permits violated NEPA and the ESA.
For several years, many voices, including Texas energy baron T. Boone Pickens, have been touting natural gas as the best energy source to form a bridge between the current fossil-fuel economy and a renewable energy future. Proponents contend that not only is natural gas a cleaner-burning fuel than coal, producing lower greenhouse gas emissions, but that reserves of natural gas are far greater than previously believed because of vast reserves trapped throughout the U.S — and around the world — in huge underground formations of shale.
Recently, the Wall Street Journal ran its own fawning ode to shale gas: “Shale Gas Will Rock the World.” The author, Amy Myers Jaffe — a fellow in energy studies at Rice University — wrote, “I am convinced that shale gas will revolutionize the industry — and change the world — in the coming decades.” She even suggested that the abundance of natural gas in shale deposits worldwide will slow the transition to a renewable energy future.
“It may be a lot harder to persuade people to adopt green power that needs heavy subsidies when there’s a cheap, plentiful fuel out there that’s a lot cleaner than coal, even if gas isn’t as politically popular as wind or solar,” Jaffe wrote.
The water pollution concerns alone should be sufficient to make the U.S. and other countries rethink future reliance on shale gas. Separating the gas from the shale, a process known as hydrofracturing, involves forcing a mixture of water, chemicals, and sand at high pressure down a well bore and into rock formations, creating small fractures that release the trapped gas. The process uses a huge amount of water — the New York State Department of Environmental Conservation estimates as much as 1 million gallons per well — at a time when water is already a limiting and precious resource. Second, hydraulic fracturing fluid may come back to the surface, or near enough, to affect groundwater supplies. This fluid is a mixture of chemicals including friction reducers, biocides to prevent the growth of bacteria that would damage the well piping or clog the fractures, a gel to carry materials into the fractures, and various other substances. Returning to the surface, it could also bring other environmentally damaging materials, such as heavy metals.
Advocates for shale gas claim that these effects will be minor. Others, including those in charge of water supplies, are not persuaded. In Pennsylvania, wells claimed to be safe have leaked natural gas into local domestic water supplies, with the gas bubbling out of faucets. Also in Pennsylvania, fracturing fluids have leaked before they have been sent underground and have also contaminated drinking water. These problems suggest that returning fracturing fluids to the surface could cause similar problems on a large scale.
That shale gas exists in abundance — in the U.S., Europe, Australia, China, South Africa, and other regions — is beyond question. The Marcellus Shale region in the eastern U.S. reportedly contains enough shale gas to meet U.S. natural gas demand for a century. MIT released a report last week forecasting that, in part because of the exploitation of abundant shale gas reserves, natural gas will go from making up 20 percent of he U.S.’s energy supply today to 40 percent within several decades.
But what is the reality behind the optimistic claims for shale gas? The U.S. Geological Survey lists natural gas “reserves” — the amount believed to be in the ground — in four categories: readily available with current technologies, which accounts for only 1 percent of the known natural gas in U.S. territorial limits; technically recoverable (5 percent); marginal targets for accelerated technology (6 percent); and unknown but probable (84 percent). Shale gas shares the fourth category with coal gas and methyl hydrates. The latter are a kind of water ice with methane embedded in it and occur only where it is very cold, in Arctic permafrost and below 3,000 feet in the oceans.
How long would the natural gas in each of the four categories would last if we obtained it independently — that is, only from U.S. territory? Just using our 2006 rates of use of natural gas consumption — not including any major transition to fueling our cars and trucks — the “readily available” gas within the United States would be exhausted in just one year. That, plus what is called “technically recoverable” gas, would be gone in less than a decade. What is termed “unknown but probable” would last about a century.
This means that any significant increase in our consumption of natural gas will have to come from the “unknown but probable” reserves, much of which will be from formations of shale, a sedimentary rock formed from muds in which bacteria released methane. Most of this gas is so deep underground or otherwise not very accessible that nobody is really sure that we can get at a lot of it, or of how high an environmental price we must pay to retrieve it.
Currently available wind and solar energy technologies, on the other hand, are up to the job right now. There just aren’t enough wind and solar installations, so today they provide less than 1 percent of the nation’s energy. We will need to rapidly scale up, so that by 2050 we can receive the Solar and wind do not have the enormous environmental and economic costs of developing shale gas. majority of our energy from wind and solar power. That’s an enormous task: The U.S. Census Bureau forecasts that our population will reach 440 million by 2050 — nearly a 50 percent increase from today. That’s 150 million more people, each hoping to live at the standard of living we have grown accustomed to. When that happens, the amount of fossil fuels we use today, and which provide 86 percent of America’s energy, would provide those 440 million with less than two-thirds the energy they would need, if per-capita energy use remains the same as today.
Contrary to standard criticisms of solar and wind, providing this much energy in the future would not use up a lot of land. Based on current installations, less than 1 percent of U.S. land area would be required. Right now, 22 percent of U.S. land is in agriculture, not counting grassland pasture and range used by grazing animals.
What about costs? Wind is the cheapest energy source, with installation costs as low or lower than coal’s. There’s no need to pay for fuel, and no huge costs to repair the environmental damage caused by strip-mining and underground mining, let alone costs involved to try to develop “clean-burning coal.” As for solar power, the costs of producing new cells — photovoltaic or otherwise — are moving rapidly down, and increased research and development will inevitably lead to a similar decline in installation costs.
As domestic U.S. pools of conventional oil and gas dwindle, energy companies are increasingly turning to fossil fuel reserves contained in the carbon rich-sands and deep shales of Canada, the Great Plains, and the Rocky Mountain West.
Colorado, Utah, and Wyoming hold oil shale reserves estimated to contain 1.2 trillion to 1.8 trillion barrels of oil, according to the U.S. Department of Energy, half of which the department says is recoverable. Eastern Utah alone holds tar sands oil reserves estimated at 12 billion to 19 billion barrels. The tar In North Dakota and other states, residents worry that the energy boom will deplete aquifers. sands region of northern Alberta, Canada contains recoverable oil reserves conservatively estimated at 175 billion barrels, and with new technology could reach 400 billion barrels. Deep gas-bearing shales of the Great Plains, Rocky Mountain West, Great Lakes, Northeast, and Gulf Coast contain countless trillions of feet of natural gas. If current projections turn out to be accurate, there would be enough oil and gas to power the United States for at least another century.
But even as one of the largest energy booms in history has erupted along a great arc of the continent, the consequences are prompting civic discontent, lawsuits, and political battles in state capitals. The boom is producing fresh scars on the land and new threats to scarce water supplies. Government studies show that exploiting unconventional fossil-fuel reserves generates more C02 emissions than drilling for conventional oil and gas and uses three to five times more water. “It’s a pact with the devil,” says Randy Udall, a consulting energy analyst from Colorado. “The tar sands and shale oil and shale gas require a lot of water. It sets up a collision course for the West.”
In communities from Wyoming to Texas, thousands of trucks now rumble down rural roads, carrying the huge amounts of water — 2 million to 4 million gallons per well — needed to free oil and natural gas from shales by blasting them with high-pressure fluids. In places such as North Dakota, which receives modest amounts of rainfall, local residents and conservationists worry that the energy boom will deplete aquifers.
And the explosion in development of these unconventional fossil fuels raises a troubling question at the national level: At a time when the country should be embracing a renewable energy revolution, it is hurtling in the opposite direction, developing on a massive scale sources of energy that cause considerably more environmental harm than conventional oil and gas drilling.
Highway 12 is a crucial supply route for this burgeoning industry, with fossil fuel companies using the road to reach a good portion of the West’s new oil and gas domain that lies to the north and south of the highway. The companies transport equipment 900 miles north to Alberta, Canada, where they are spending $15 billion annually to develop the region’s tar sands, now the single largest source of oil imports to the U.S. and the fastest-growing source of CO2 emissions in Canada, according to the Pembina Institute, a Canadian environmental think tank.
In North Dakota — which has become the fourth-largest oil-producing state in the country, with an estimated 100 million barrels being pulled out of deep shales this year and where 1,000 wells will be drilled in 2010 — Highway 12 crosses the $5 billion, 2,151-mile Keystone Pipeline. It is the centerpiece of a $31 billion network of major transport lines either planned or under construction to carry oil from the middle part of the continent to refineries in Texas, Oklahoma, and Illinois that are being modernized and expanded at a cost of more than $20 billion. In all, according to company reports and state economic development offices, the oil industry is spending nearly $100 billion annually in the U.S. to perpetuate the fossil fuel era.
Oil industry executives say their investments are consistent with the national goal of producing more energy to increase security. Oil companies are also profiting handsomely from the exploitation of these unconventional sources of oil and natural gas. The stakes became clear earlier this year, when ExxonMobil paid $41 billion to buy XTO Energy, a major player in unconventional fuels production, especially natural gas.
Last year, in a much-disputed draft environmental impact statement that summarized the need for the new Keystone-XL pipeline — which will transport oil from Alberta’s tar sands to U.S. refineries — the U.S. Department of State tacitly backed the new energy boom. “The increasing demand for crude oil in the U.S. cannot be entirely met by efforts to conserve use of refined petroleum products or the increased use of renewable energy,” the department said. “As crude oil demand increases, the overall domestic supplies of crude oil are declining.” The department’s analysts added that without the pipeline and the new supplies of oil it would carry, the country “would remain dependent upon unstable foreign oil supplies from the Mideast, Africa, Mexico, and South America.”
One of the flashpoints is occurring in northern Idaho and eastern Montana, where oil companies want to use Highway 12 to dispatch the largest convoy of oversized trucks ever assembled to Alberta’s tar sands and elsewhere. The trucks, nearly as long as football fields and so wide they cover both lanes of the highway, haul refining and processing equipment that weighs hundreds of tons and is as tall as a mansion.
ConocoPhilips was granted a road permit in Idaho last month to haul four Korean-built oversized oil-processing units from Lewiston, Idaho, where The Bakken Shale may contain 4 billion barrels of oil and trillions of cubic feet of natural gas. they were offloaded from Columbia River barges, to the company’s expanding refinery in Billings, Montana. Earlier this month, Idaho Second District Judge John Bradbury revoked the permit, asserting that the state did not adequately assess the hazards of the shipment, particularly the consequences of an accident involving one of the immense processing units blocking the highway. Local officials in Montana are considering similar legal action.
The court judgment in Idaho, which is set for an appeal on Oct. 1, could have significant ramifications for ExxonMobil Canada, which wants to make 207 oversize hauls next year along Highway 12. Exxon’s trucks will carry even larger Korean-built units to be assembled into a new tar sands oil processing plant in Alberta. The company says it must use Highway 12 because the loads are too big to fit under bridges along interstate highways or rail lines.
Despite opposition, the oil and gas industry is undeterred. The Bakken Shale that lies 10,000 feet beneath a 200,000 square mile expanse of North Dakota, Montana, and Saskatchewan is said by the U.S. Geological Survey to contain more than 4 billion barrels of oil and trillions of cubic feet of natural gas. Oil industry geologists say there is much more than that in the Bakken, and in a second oil-rich shale reserve, the Three Forks, that lies below it.
Spurred by the Bakken riches, energy companies are now spending tens of millions of dollars to lease mineral rights in Wyoming and Colorado and are drilling exploratory wells in the Niobrara Shale, which sprawls beneath both states.
“It just almost boggles the mind,” Lynn Helms, director of the North Dakota Department of Mineral Resources, told a veterans group in Minot on Sept. 2. “It is not like the traditional oil and gas play.”
A 2006 study by the Department of Energy that looked at rising energy demand and diminishing freshwater supplies found that the collision between the two was occurring most violently in the fastest-growing parts of the country that also happened to have the scarcest water ‘The oil industry can find water elsewhere,’ said one North Dakota wildlife official. resources — California, the Southwest, the Rocky Mountain states, and the Upper Great Plains.
It takes 2.5 to 6.5 gallons of water to extract and refine one gallon of tar sands oil, which is four times more water than it takes to produce oil from conventional reserves, according to a 2009 study by Argonne National Laboratory.
Moreover, producing tar sands oil, according to the Natural Resources Defense Council, generates as much as three times as many greenhouse gases per barrel as conventional oil production.
Extracting unconventional fossil fuel reserves like the Bakken formation uses a lot of water because getting to the oil and natural gas requires rupturing the deep shale to create open spaces and crevices through which the oil and gas can flow. The pulverizing process, called hydraulic fracturing or “fracking,” involves sinking drill bits two miles deep and then turning them to move horizontally through the shale. An armada of tank trucks hauls several million gallons of water to each well site, where pumps shoot it down the well at such super high pressure — 8,000 pounds per square inch — that the rock splits.
The practice is risky. Earlier this month, an oil well undergoing fracking near Kildeer, N.D. ruptured. The blowout leaked 100,000 gallons of fracturing fluid and crude oil before being plugged two days later.
Fracking has caused contamination of surface and groundwater in other states and harmed drinking water in some communities, according to a number of reports from local environmental organizations. The energy boom has also filled state coffers. In North Dakota, where the oil and gas rush has drawn more than 7,000 laborers migrating into the state, the unemployment rate has dropped to 3.6 percent, the nation’s lowest. When North Dakota’s budget cycle ended in June, the state reported an $800 million surplus.