More Precious than Oil?
Westerners have long observed that the region is short on water. The Colorado River Compact of 1922 made the traditional lament a mathematical truth by apportioning the river between upper and lower basins based on data from some of the wettest years ever recorded.
Using flow rates from 1905 onward, the negotiators of the Colorado River Compact calculated the average flow of the river to be 16.4 million acre feet and agreed to split 15 million acre feet evenly between the upper and lower basin, divided at Lee Ferry at the head of the Grand Canyon, 10 miles from the Utah border in northern Arizona. The upper basin states of Colorado, Wyoming, Utah, and New Mexico agreed to deliver at least 75 million acre feet to Lee Ferry during every 10-year period. This formula (as opposed to requiring 7.5 million feet every year) leaves some wiggle room for the upper basin to adjust how much it delivers year to year in accordance with the river's flow, but it ultimately gives the lower basin states of Arizona, Nevada, and California a priority claim to their full share.
However, in the years since the agreement was reached, the river's flow has fluctuated widely, and often it has not met the levels assumed by the compact's architects. In December 2007, prompted by a tenacious drought that has kept river flows low since 2000, the compact states collaborated with the Bureau of Reclamation in the Department of Interior to agree upon new guidelines to follow in such times of shortage. The new supplementary agreement helps water managers plan drought strategies with greater certainty by specifying the order and timing in which states will take reductions of their water supply. It also creates provisions for increasing coordination and conservation throughout the system, essential aspects of effective water management as population and demands upon the system continue to grow throughout this arid region.48
A Potential Dealbreaker
Historically, problems from the overestimation of the river's annual average flow have been postponed, because the upper basin states have used much less than their share. But this is changing as growing numbers of coastal Americans relocate to the Rocky Mountains and to the desert Southwest, especially to swelling cities like Phoenix, Tucson, Las Vegas, Denver, and Salt Lake. These booming population centers are now laying claim to their share of the river, considerably reducing the margin of surplus in the system that Southern California had been soaking up. In fact, in 2003 Secretary of the Interior Gale Norton ordered California to relinquish 800,000 acre-feet it had grown accustomed to using because the water rightfully belonged to the upper basin states.49
Today, more than ever before, a variety of competing industrial, municipal, agricultural, tribal, and environmental interests in 7 states as well as Mexico battle over every acre foot of water in the Colorado River system. Farmers and ranchers, recreational anglers and whitewater rafters, and residents of major metropolitan areas, not to mention endangered fish species and the other members of the region's intricate ecosystem, rely on adequate flows and water quality in the Colorado and its tributaries. Water is a potential dealbreaker for any extraction process that requires too much or poses too great a risk of groundwater contamination.
At the outset, water for an oil shale industry will likely come out of local sources such as the White River, which runs along the northern edge of the Piceance Basin and into the heart of the Uintah Basin. Operators may also tap the Colorado River running to the south of both basins, and Shell recently made a claim farther afield on unappropriated waters in the Yampa River to the north. Companies have obtained water most often by purchasing senior water rights from established users. They might also claim unallotted water in the system (if they can find some, as Shell did in the Yampa's spring runoff flows), or theoretically they might bring water to the area from outside the Colorado River Basin (a tricky engineering and legal maneuver that Exxon briefly proposed during the previous boom).
Of the 3 companies with RD&D leases in Colorado, Chevron maintains the largest claim to existing water rights on the Western Slope as a result of its involvement in the earlier booms, but Shell has been actively purchasing them and making claims in recent years. Both trail ExxonMobil, which owns the most water rights of any energy company in Shale Country. According to a report from Western Resource Advocates (WRA), an environmental law center that conducted a survey of water rights in Shale Country, 6 energy companies have filed for a total of 7.2 million acre-feet of water rights on the Colorado and White Rivers. The amount equals nearly the entire Upper Basin allotment under the 1922 Colorado River Compact, although it is not credible to suggest that all of these rights would be developed at the same time.
Shell disputes some of the WRA report's methodology and conclusions about how much water has been claimed for oil shale, but the company does not deny that a future oil shale industry will require significant amounts of water. Shell contends that maintaining a broad water rights portfolio is the best way to provide the flexibility needed to avoid impinging on other users, but users with junior rights - including many cities along Colorado's populous Front Range that rely on water drawn from the other side of the Continental Divide - are nervous that large scale oil development will make it more difficult to attain the water they count on.50
No one is yet sure how much water a commercial-scale industry using a next-generation in situ process will require, but the engineers and scientists working on it are confident that they can do a good bit better than their predecessors. The traditional mining and retort methods planned and tested in the last boom require tremendous quantities of water for dust control, scrubbing off-gasses, hydrogenation, evaporative cooling, disposal, cooling and compaction of spent shale, revegetation of spent shale, and other uses in the production process. Estimates made during the previous boom range between roughly 2 and 5 barrels of water for each barrel of oil produced from shale. In situ recovery methods promise to consume less water because the disposal, cooling, compaction, and revegetation of spent shale would be unnecessary (although other stages of an in situ process might need considerable volumes). The best current estimates for in situ water requirements are between 1 and 3 barrels of water for each barrel of oil (with some companies like AMSO and Chevron promising to use even less), but it will not be clear exactly how much water they will need until operations are ready to be scaled up to larger operating dimensions.51
The new generation of in situ processes that energy companies are studying and testing in Shale Country today - ambitious technologies that significantly reduce the amount of water required to produce a barrel of oil, and even allow Chevron to envision being what it calls a net producer of water - have to be more economical with water than their predecessors because they are being designed under greater constrictions.52 Water demand is rising with population throughout the Colorado River system, leaving a smaller and smaller portion available for new industries. The manifold impacts of increased water usage for an oil shale industry near the headwaters will ripple downstream through the entire basin, reducing hydroelectric power generation, sharpening the effects of drought, requiring more water storage facilities, and impairing the already fragile fisheries. Prized species such as the Colorado River cutthroat trout and endangered fish such as the humpback chub, bonytail, Colorado pikeminnow and razorback sucker stand to lose substantial portions of their habitats and populations from reduced instream flows.53
How Much Is Left?
Complicating any predictions about water in the Colorado River basin is the latest global warming forecast, which calls for earlier and faster snowmelts and even drier summers throughout the West in the coming century. The specter of climate change combined with booming population growth throughout the basin introduces myriad uncertainties into discussions of how much water will be available for industry and other users in the future.
Under such indeterminate conditions, planning is a tricky proposition at best. Some studies suggest that, with the addition of more reservoir storage on the system, the Colorado River system contains enough water to support the region's population growth and an oil shale industry in coming decades. In its Final PEIS, the BLM concluded that there was water still available in the Colorado River system to support oil shale development in the three Upper Basin states that constitute Shale Country. Some advocates specifically point to the 800,000 acre-feet of water relinquished by California as enough to supply the industry. Other equally confident analyses predict severe shortfalls that may dry up key reservoirs such Lake Mead and Lake Powell in a little over a decade, leaving the parched region unable to support even current inhabitants, much less a growing populace or new water-intensive industries.
In Colorado, no less an authority than Eric Kuhn, the General Manager for the Colorado River Conservation District, cannot be more precise than this: "Colorado has either a lot of water to develop - upwards of another million acre-feet - or Colorado may already be at or above full development of its Colorado River supplies at certain periods." And the situation changes from year to year as river flows rise and fall, leading the BLM to note that just because water is available under the allocation formula of the Colorado River Compact, "this calculation does not imply that the water is readily or physically available." In fact, by the time they produced the Final PEIS, the agency had backed away from some of its more confident earlier claims about the availability of water for oil shale development. Seeking to put a number on just how little might be left, Eric Kuhn has suggested that the river may have only 150,000 acre-feet left to reliably give in Colorado, far below the figure of 1.5 million acre-feet commonly cited by state officials.54
In addition to intensifying questions about the finite quantity of water available in the basin, oil shale operations - both traditional mining and surface retorting methods and, to a lesser extent, in situ methods - pose a number of challenges to water quality. Depending on the extraction process and technology, oil shale production may produce quantities of saline water large enough to impair the quality of local surface water. Retorting produces water with high levels of pH capable of dissolving and thereby introducing into the environment toxic metals such as arsenic and selenium. Carbonate salts are also a common byproduct of oil shale retorting processes, but their environmental impact may be minimal if left in the ground and isolated from ground water systems.55 However, these threats depend upon - and vary in response to - local geographic and hydrologic conditions and the exact extraction processes used. And, as we mentioned earlier, every in situ method currently in development seeks to minimize threats to groundwater, albeit through some very divergent methods.
The number and degree of challenges to water quality presented by new in situ processes are still largely in the speculative realm. A number of key questions around water await answers as the RD&D process begins. How much water will production require? Is it available? In the heavily appropriated Colorado River system, who (if anyone) loses water if industry gains it? Can creating freeze walls or controlled fracture zones control groundwater contamination and maintain water quality? And in such a thirsty region, what should operators do with the water pumped out of the extraction zone (a problem that has confounded operators in other energy fields)?
Answers to these questions are, according to a 2005 RAND analysis, still a number of years away, raising the prospect that, unless policymakers dramatically slow down the commercial leasing program outlined in the 2005 Energy Policy Act, the first commercial-scale operations may be permitted and built without this information.56