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Focus W UTAH

a sa t c h Fr o n t

October 2011

A Publication of The Enterprise - Utah’s Business Journal

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Oil, Gas & Energy .

INSIDE

Shale drilling creates jobs and boosts domestic energy production, but critics raise groundwater concerns and other issues. Page 2 “Gasland” documentary misportrays hydraulic fracking. Page 3 Questar actively pursuing plans to increase the availability of natural gas filling stations along the interstate corridors. Page 4 Utah rich in oil shale; commercial production still uncertain. Page 6 Questar CEO Ron Jibson says the coming decades will be favorable for the gas utility and its customers, with stable returns projected for investors and low energy bills projected for consumers. Page 8 Federal regulations could hinder Utah’s ability to tap energy resources Page 10


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Utah Focus, October 2011

Hydraulic fracturing — a primer Shale drilling creates jobs and boosts domestic energy production, but critics raise groundwater concerns and other issues

are not found in underground caverns. Instead, they are found in the pore spaces of underground rocks. To produce oil or gas, an operator drills a well to an underground rock formation that the operator Hydraulic fracturing is a prohopes contains oil or gas, so cess that makes it feasible to prothat those substances can duce oil and natural gas from cerflow to the well from the tain underground rock formations surrounding rock and then that contain those substances tightup the wellbore to the surly bound within the rock’s strucface. To get to the well, the ture. The oil and gas activity made oil or gas flows through the possible by hydraulic fracturing rock itself by moving from creates jobs, reduces this country’s one pore space to the next, dependence on imported energy, through interconnections and yields large quantities of natubetween the pores. ral gas, the cleanest-burning of all Keith Hall A rock through which fossil fuels. But many people have such fluids flow easily has also expressed environmental conhigh “permeability.” But if cerns, including a fear that hydraulic frac- the interconnections between pores are too turing might cause contamination of narrow and too few in number, the rock groundwater. will have low permeability and oil or gas What is Hydraulic Fracturing and Why will not flow through it very easily. If the is it Used? permeability of the rock formation is low In nature, oil and natural gas generally enough, it will not be economical to pro-

duce oil or gas from the formation with conventional methods. But production from a low permeability formation might become economical if the well’s operator could create cracks or fractures in the rock so that oil or gas could flow through the fractures instead of flowing only through interconnections between pores. The process of creating such fractures is called “fracturing.” Well operators first began fracturing wells in the 1860s, only a short time after the first oil well was drilled in Pennsylvania in 1859. The earliest method of fracturing was explosive fracturing. A well operator would lower an explosive charge — called a “torpedo” — into a well, then detonate it. The explosion would fracture the surrounding rock, and often would result in a significantly higher rate of production than before the fracturing. In the late 1940s, hydraulic fracturing was developed. In hydraulic fracturing, the operator pumps water into a rock forma-

tion at extremely high pressure. The high pressure causes the rock to fracture, and water moves into the fractures, forcing the fractures to open slightly. To prevent the fractures from closing when the highpressure water is withdrawn, companies use “proppants” to prop open the fractures. Proppants are small particles — typically sand, though small ceramic particles or sintered bauxite sometimes are used. The proppants are mixed into the fracturing water before it is pumped into the formation that will be fractured. As the water moves into fractures, it carries proppants along with it. When the water is removed at the end of the fracturing process, the proppants stay behind, preventing the fractures from closing. For oil or gas to travel through the fractures, it must travel through the proppant particles, but this is not a problem because the proppants have high permeability. Typically, about 99.5 percent of the fracturing fluid will consist of water and proppants, but operators also add various other substances, including biocides to inhibit microbial growth and corrosion inhibitors to protect the well’s piping. They also add other chemicals to assist the hydraulic fracturing process in other ways. Authorities estimate that hydraulic fracturing has been used in more than a million wells since the process was commercially developed in the late 1940s. In addition to being used in low permeability rock formations, hydraulic fracturing also is used in coalbeds to facilitate the production of coalbed methane. Hydraulic fracturing has received substantial publicity in recent years relating to its use in production of oil and natural gas from shale, a type of rock that often contains oil or gas, but which has extremely low permeability. For years after hydraulic fracturing was developed, it remained uneconomical to produce oil or gas from shale formations. This changed when operators learned to use improved fracturing techniques and to combine fracturing with the use of horizontal drilling. Horizontal Drilling vs. Vertical Drilling In traditional drilling, a well is drilled more or less vertically downward. When the target formation is reached, drilling continues for some distance into the target formation. The operator then uses a special tool to create perforations in a portion of the wellbore that is within the target formation. Oil or gas can then flow into the well through the perforations. The longer the length of perforated pipe, the faster oil or gas can flow into the well, but with vertical drilling the length of pipe that can be perforated is limited by the vertical height of the target rock formation. On the other hand, a formation that may be only a couple of hundred feet or less in height might extend horizontally for miles. Horizontal drilling takes advantage of this fact. In horizontal drilling, the operator drills vertically downward toward the target formation, then turns the drill bit to drill in a horizontal direction. The drilling might then proceed horizontally for a see PRIMER page 7


Utah Focus, October 2011

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The truth about fracking Hydraulic fracturing, more commonly est accusations that imply a connection referred to in the industry as “fracking” or between negative health/environmental “fracing,” is a method for creating frac- effects and the process of fracking. tures in geologic formations with low per- In two of the documentary’s signature meability located thousands of feet below moments, landowners in Colorado actually the surface of the earth to allow more oil ignite the water coming out of their houseand natural gas to be removed from a well hold taps. The film leaves the viewer with than would otherwise be obtained from a the false impression that the ignited tap typical drilling and well completion pro- water is the result of hydraulic fracturing cess. In effect, fracking increasof natural gas wells in the area. es a well’s exposure to the The film conveniently omits geologic formation, allowing any discussion of the differfor greater production from the ences between thermogenic well. The simple truth is that methane, which is the gas the majority of oil and natural sought by drillers that is located gas wells drilled in this country in rock formations thousands of do not produce at sufficient feet below the surface, and biorates to be economical without genic surface methane, which the use of fracking. Although is naturally created by decomthe practice of fracking is not posing organic material and A. John Davis new and, in fact, has been used commonly seeps into fresh since the 1940s, fracking has water aquifers and may result been the latest target of an attack in the contamination of drinkbrought by environmental ing water wells. In fact, the groups seeking to delay or halt Colorado Oil and Gas oil and natural gas development Conservation Commission in this country. (COGCC) released a formal The supposed dangers surdocument criticizing the film’s rounding the practice of frackdepiction of the events. In its ing have been recently placed in opening paragraph, the COGCC the media spotlight by a number stated: of sources. For example, frack “[T]he documentary ing was featured in the 2010 “Gasland” has attracted wide Ryan R. Jibson pseudo-documentary attention. Among other things, “Gasland,” was the topic of a it alleges that the hydraulic recent “60 Minutes” news spefracturing of oil and gas wells cial highlighting alleged dangers related to has contaminated nearby water-wells with fracking, was the topic of a PBS special, methane in a number of states including and has been the subject of numerous Colorado. Because an informed public Internet videos making unfounded accusa- debate on hydraulic fracturing depends on tions about its potential harmful effects on accurate information, the [COGCC] would the environment. These media outlets like to correct several errors in the film’s appear to be more interested in a sensation- portrayal of the Colorado incidents.” alist depiction of this common and neces- The COGCC goes on to explain the sary oilfield practice than educating the differences between biogenic surface public on the truth about fracking. The methane and the much deeper thermogenic truth is this: The technique has been used methane extracted during natural gas for decades, it is safe, is carefully regulated development. With respect to the specific by environmental laws and regulations, landowners featured in the film, the and is absolutely pivotal for current and COGCC had previously investigated the future development of the vast oil and complaints of contamination and had deternatural gas resources in the United States. mined that the water-wells in question Depictions of individuals lighting their contained naturally-occurring biogenic tap water on fire may create the initial surface methane that was not attributable knee-jerk reaction that they are meant to to oil and gas development in the area. create, but are merely scare tactics that are Further, the COGCC’s investigations were apparently meant to mislead the general made, and its conclusions documented, public about the actual causes for such long before the filming of “Gasland.” events, causes unrelated to fracking itself Lastly, the COGCC points out that its or in most cases natural gas development. director, Dave Neslin, offered to speak The 2010 pseudo-documentary, “Gasland” with the film’s producer, Josh Fox, on has received a great deal of attention, and camera during the filming of the documenhas been the primary basis for the recent tary to discuss any alleged instances of media condemnation of fracking. The film contamination. Unfortunately, Fox is an attempt by its creator to inflame the declined to interview Neslin. general public against hydraulic fracking The COGCC has not been alone in its and the oil and gas industry in general by criticisms of the film. Organizations such alleging hidden dangers associated with as America’s Natural Gas Alliance and the the process of fracking. It insinuates that Barnett Shale Energy Education Council there is some vast conspiracy led by the have been bringing the film’s many falseenergy industry seeking to continue a prac- hoods to light. As stated in an interview tice replete with alleged health and envi- with the Philadelphia Inquirer, even the ronmental risks. It is shocking, however, Secretary of the Pennsylvania Department that an Oscar-nominated documentary of Environmental Protection dismissed could be riddled with such unfounded and “Gasland” as “fundamentally dishonest” misleading claims, and make such dishon- and “a deliberately false presentation for

Graphic reproduced courtesy of the American Petroleum Institute. dramatic effect,” and accused the film’s producer of being a “propagandist.” In order to understand the truth about fracking, and in order to understand its pivotal role in the development of our vast oil and natural gas reserves, one must first understand the fracking process. One must also understand that fracking is a proven technology used safely in more than a million wells in this country throughout the last six decades, and that the technology continues to improve. The process begins with the initial drilling of a wellbore. In most cases, this requires the operator to drill approximately 5,000 to 15,000 feet below the surface to reach the targeted geologic formation which has trapped the oil or natural gas. As shown in the attached figure 1 of a horizontal well, once the operator has achieved the appropriate depth, the drill bit is turned horizontally to travel within the target formation. Layers of steel casing and cement liners are then placed in the wellbore for the purposes of protecting any existing groundwater sources, preventing a caving of the well, confining oil and gas to the wellbore, and for circulating drilling fluids. With the aid of advanced computer modeling in fracture design, the operator is then able to predict the potential fractures, and avoid a fracture job extending into an unintended zone. Once the computer modeling is complete, and the protective casing and cement are in place, the operator injects the fracturing fluid, which is comprised of water, sand or small ceramic beads (referred to as “proppants”), and

other chemicals (approximately 0.5 percent) that aid in the process. Using a sophisticated control center, the operator increases the hydraulic pressure on the specific target formation until the pressure is high enough that the formation fractures, creating small cracks. The fracturing fluid is then drained, leaving the proppants in the cracks to allow the oil or gas to flow to the wellbore and be extracted. As the well is brought into production, the majority of the fracturing fluid is recovered and either recycled for future use or disposed of in accordance with the federal Clean Water Act and the Safe Drinking Water Act. As for the fracturing fluid that remains in the ground, it is confined by literally thousands of feet of impenetrable rock layers that act as a barrier to prevent both the fracturing fluid or the oil or natural gas from contaminating underground water sources. The notion that fracturing fluids are able to travel upwards thousands of feet, through multiple layers of rock, to contaminate water sources has been proven false by studies performed by both the Environmental Protection Agency (EPA) and the Ground Water Protection Council (GWPC). In 2004, the EPA conducted a study that assessed the potential for contamination of underground sources of drinking water from the injection of fracking fluids into wells. The study focused on the fracking of coal-bed methane wells, wells which are typically much shallower and in closer proximity to groundwater see TRUTH page 5


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Utah Focus, October 2011

Questar hopes to expand CNG availability By Andrew Haley The Enterprise This summer, Jeremy Asay, a writer of instructional films for teachers, drove his F-250 extended cab pickup truck with three passengers, two mountain bikes and an enthusiast’s supply of camping and rock climbing gear from Salt Lake City to Grants Pass, Ore. by way of Winnemucca. The four passengers split the cost of gas. The total: $90, just over $20 per person. Asay drives a retired duel-fuel Idaho state government fleet vehicle equipped with separate tanks for compressed natural gas (CNG) and gasoline. Gasoline is good for getting up to speed and for driving offroad, but at cruising speeds natural gas works just as well and at a fraction of the cost. Though CNG fueling stations are scarce (Assay travels with a binder full of station info printed off of MapQuest and sometimes makes detours to refuel) they are increasingly easier to find. “My V8 truck gets better mileage than almost any sedan on the road. And I pay only $1.20 a gallon,” Asay said. “I love it. It will take me just about anywhere in the state of Utah I want to go. With both tanks full I can go 600 miles without refueling. And it has fewer emissions than almost any sedan on the road.” Carl Galbraith, director of business development at Questar, said the utility company is actively pursuing plans to increase the availability of natural gas filling stations along the interstate corridors, especially for freight-hauling tractor trailers. The company anticipates Cummingsbuilt heavy-duty semis equipped to run off a 70/30 natural gas/diesel blend will roll off the factory floor in late 2012 to early 2013 and wants to be prepared to lead the market in natural gas vehicle (NGV) fueling solutions. So far, the natural gas provider operates 29 natural gas stations, mostly along the I-15 corridor, with two Wyoming stations along I-80 in Rock Springs and Evanston. “I think you’ll see in the next 18 to 24 months some big announcements,” Galbraith said. The current crop of stations are designed for personal commuter vehicles and are operated by Questar Gas, the utility company that is a wholly owned subsidiary of Questar. As a utility, Questar Gas is regulated by the Utah Public Service

Commission (PSC), which sets the rate of return the company can profit from its sales of natural gas. According to Galbraith, if the technology pans out and Questar finds itself in the large-scale business of fueling interstate freight haulers, the current business model wouldn’t fit. “If we were to go outside our jurisdiction, we would form a new, unregulated company. We would keep the Questar name. We would like to brand ourselves,” he said. Galbraith said Questar is intent on avoiding competition with truck stops and has no plans to go into the business of selling Red Bull, microwavable pizzas and hot showers. Instead, a hypothetical Questar gas station company would partner with existing truck stops to add fueling islands equipped with natural gas pumps. Development would occur slowly, with the potential to grow nationwide, Galbraith said. “We’d start on a regional basis, maybe

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in the five Western states. There’s a fairly high upfront investment,” he said. Once initial capitalization costs are met, however, natural gas fuel sales are quickly magnified by the economy of scale provided by the large number of trucks in shipping companies’ fleets and the long distances they cover. Galbraith said he estimates that in the near future, allocating for a slight rise in bearishly low natural gas prices, the profit margins on the unregulated retail of natural gas for heavy-duty vehicles will approach current margins for the sale of diesel. Still, when applied to potential savings, the economy of scale works to the advantage of freight company owners as well. “[Trucking companies] would save a lot,” Galbraith said. “Swift turns over a million gallons a day. If you save a penny a gallon you’re saving $100,000 a day. If you save 50 cents … the numbers add up really fast.” While Questar may soon find itself in the business of fueling interstate trucking, Galbraith said the company does not plan on expanding its operations for commuter vehicles beyond its existing 29 stations in the Intermountain West. “We feel that we’ve got placement that works now. Is it convenient? Not really. It will never get to the point where there’s one on every corner,” he said. Galbraith said that Questar will look at “pockets of inconvenience” within the current commuter natural gas vehicle (NGV) system, and may add a station or two to alleviate that inconvenience, but the company has determined that the commuter NGV market is not worth developing further at present. Part of that decision lies in the current crop of CNG stations falling under the purview of Questar Gas, the profits of which are regulated. Part lies in the high capitalization costs of building

new commuter CNG stations, which Galbraith estimated at between $800,000 and $1 million each for an investment with a relatively modest rate of return. Another problem for CNG profitability is visibility. Without his binder full of maps and CNG fueling information, Asay would be hard-pressed to find one of the minimalist, stripped down stations that look something like the gas stations you might expect to see in “Star Wars.” They often service municipal bus fleets and are located in undeveloped or industrial parts of town, in distinctly non-commercial looking locales, meaning that until word of mouth or MapQuest lures customers, new CNG stations turn a meager profit. “The first few years are pretty lean. [Profitability] really is volume dependent,” Galbraith said. Despite the hurdles, Questar Gas has seen an increase in CNG sales. Galbraith said this year’s sales at its commuter vehicle CNG stations are up 12 percent over last year and growing. With the cost of filling up a mid-sized sedan with low octane gasoline topping $50 — and no sign of dropping — you don’t have to look far to figure out why Utah’s drivers are increasingly opting for a more economical fuel. Could switching America’s cars and trucks to natural gas, which for decades has been used almost exclusively for heating homes, water heaters and scrambled eggs, deplete the supply and hasten the arrival of a natural gas crunch much like the oil crunch that is driving up gasoline prices? Galbraith said no. “We have a 100-year supply at current consumption levels and that number is constantly going up,” he said. “Today it’s really undervalued. If we’re talking about it running out for our kids, or our kids’ kids, that’s simply not going to happen.”


Utah Focus, October 2011

TRUTH from page 3

than conventional oil and gas wells and unconventional shale oil and gas wells Even dealing with shallower coal-bed methane wells, the EPA found no confirmed cases of groundwater contamination being linked to the injection of fracking fluid into nearby wells or subsequent underground movement of fracking fluids. The 2009 GWPC study made similar findings; again, finding no instance of groundwater contamination from fracking. Further, the studies performed by the EPA and the GWPC demonstrate the effectiveness of current federal and state laws and regulations meant to protect groundwater resources potentially affected by fracking — regulations that govern every stage of the drilling process, including initial permitting, well construction, well production, wastewater disposal, and reclamation of the oil or gas well. The simple truth is that fracking is safe, and if oil and natural gas development is carried out by responsible operators who comply with federal and state regulations, there is very little risk of adverse environmental effects. However, surface spills, improper wastewater disposal, poorly constructed well casing and cement jobs or improperly abandoned production wells, will always pose some risk to groundwater sources, but the fracking process is not the culprit in these circumstances. According to estimates by the Energy Information Administration, the United States contains 2,552 trillion cubic feet of potential natural gas reserves. This is enough gas to supply the United States for approximately 110 years. As for oil reserves, with the ever-increasing commercial viability of oil shale development, again due to advancements in fracking, the Green River Formation alone, located within Utah, Colorado and Wyoming, contains the equivalent of six trillion barrels of oil. Of these six trillion barrels of oil, the Department of Energy estimates that 1.38 trillion barrels are potentially recoverable. To put that into perspective, 1.3 trillion barrels of oil is equivalent to more than five times the oil reserves of Saudi Arabia. The strategic and economic importance of this resource cannot be overstated. Reducing our country’s dependence on foreign sources of energy has been a stated objective of both Republican and Democratic Presidents since the Nixon administration. The film “Gasland,” and the negative messages presented by media outlets that have come in its wake, fail to tell the true story of hydraulic fracturing, and fail to accurately portray its safeness. Further, the media outlets fail to properly portray the critical role that fracking plays in the current and future development of oil and natural gas. To put it bluntly, elimination of fracking would eliminate the industry’s ability to economically develop the vast oil and natural gas reserves in this country, would eliminate tens of thousands of jobs nationwide, and would bring to a halt any progress towards energy independence in the U.S. The idea that fracking could be

banned, and that oil and natural gas development could return to the status quo, is a misguided idea — fracking is the status quo. To ban fracking would ban any meaningful future development of this country’s oil and gas resources, a fact that opponents of fracking know all too well. Both A. John Davis and Ryan R. Jibson are attorneys in the Salt Lake City office of Holland & Hart. Davis focuses his practice on energy and natural resources law, with an emphasis in oil and gas, mining, public land, and geothermal energy. He can be reached at (801) 799-5887. Jibson concentrates his practice on commercial litigation, with an emphasis on litigation involving public lands management, oil and gas development, mining operations, and general corporate matters. He can be reached at (801) 799-5967.

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Utah Focus, October 2011

Utah rich in oil shale; commercial production still uncertain By Andrew Haley The Enterprise According to University of Utah researchers, between 1.5 trillion and 1.8 trillion barrels of oil lie trapped in a wide swath of oil shale hundreds of feet below remote portions of Utah, Wyoming and Colorado. In a 2007 report prepared for the U.S. Department of Energy, the university’s Institute for Clean and Secure Energy (ICSE) said that a five-county region of Eastern Utah and Western Colorado containing the Piceance and Uinta Basins is likely to become the epicenter for a transformative oil shale industry born of new technologies and rising global demand for oil. The report said oil shale deposits in Duchesne and Uintah Counties in Utah, and Moffat, Rio Blanco and Garfield Counties in Colorado, are similar in size to Canadian oil sand deposits that have become an important part of that country’s economy. On Oct. 17, Utah Lt. Gov. Greg Bell will discuss the potential of Utah oil shale development in a keynote address given at the 31st Oil Shale Symposium at the Colorado School of Mines in Golden, Colorado. “Part of what makes Utah a great place for families and business is our affordable energy,” Bell said. “Gov. Herbert and I have made it a priority to ensure continued access to energy resources. I will be discussing the 10-year Strategic Energy Plan that Gov. Herbert and I

released last March,  and particularly the unprecedented oil shale resources that may be commercially produced in Utah.” Oil shale is a fine-grained sedimentary rock bound together by an organic compound called kerogen. Kerogen, the fossilized remains of ancient algae, can be converted into oil with the application of heat. Oil shale extraction technology is similar to that used in oil sands operations in Western Canada, where geologists estimate approximately 1.7 trillion barrels of oil remain to be exploited. “Oil sand is oil that is past its prime. Oil shale is oil that hasn’t reached its prime,” said Jennifer Spinti, an associate research professor of chemical engineering at the ICSE. Spinti organized this year’s annual University of Utah Unconventional Fuel Conference, held in May, which examined the challenges of developing Utah’s oil shale and oil sands. While the scale of potential oil shale production is staggering, so are the hurdles that must be cleared to sufficiently capitalize any future operations while satisfying environmental regulations, she said. Because the majority of Utah and Colorado oil shale lies on federal land, potential oil shale production must navigate federal as well as state bureaucracies. “The Piceance Basin and Uinta Basin are the two most productive oil shale zones in the USA,” Spinti said. “Despite their abundance, these fuels are difficult to pro-

duce due to technical, economical and regulatory challenges, and there is no current commercial production.” That is about to change. In April, Estonian energy company Enefit, which has produced the bulk of Estonia’s domes-

tic energy from oil shale for more than a century, acquired the White River oil shale mine near Bonanza, Utah, and has already begun initial capitalization to develop a see SHALE page 11

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Utah Focus, October 2011

PRIMER from page 2

mile or so within the target formation, providing a long horizontal “leg” that can be perforated. The Benefits — Economic, National Security, and Environmental Hydraulic fracturing makes it feasible to produce oil and gas from shale and other low-permeability formations from which production would not be feasible in the absence of fracturing. Such production and the activity associated with it are beneficial for several reasons. First, the activity has substantial economic benefits. Economists have estimated that shale gas development has created more than 200,000 jobs — direct and indirect — in the United States. Some of the new jobs are in the oil and gas industry itself, while other jobs are with companies that supply products, materials or services to the oil and gas industry. These include companies that mine the sand or manufacture the ceramic particles used as proppants; transport water, sand, and equipment to drilling sites; manufacture the high-pressure pumps used in fracturing; operate pipelines; perform construction; and operate the hotels, restaurants and caterers that house and feed workers. State and local government benefit from increased tax revenue, and sometimes mineral royalty revenue. In northwest Louisiana, where the Haynesville Shale is located, some local governments have seen their sales tax revenue double over the course of a few years, enabling those governments to pay cash for the construction of numerous capital improvements, even while state and local governments elsewhere are struggling. State and local governments in other areas, including Texas, Pennsylvania, and North Dakota, also have benefitted. Second, the increased production of oil and gas bolster our national security by reducing our country’s dependence on imported oil and gas, some of which comes from areas that are politically unstable or nations that are hostile to the United States. Third, hydraulic fracturing can have environmental benefits because it is often used to facilitate production of natural gas, which is the cleanest-burning of all fossil fuels. For a given amount of energy production, the combustion of natural gas produces only half as much carbon dioxide as coal, and about one-third less than oil. The combustion of natural gas also produces smaller amounts of other pollutants. The Biggest Concern — Drinking Water People have expressed various concerns about hydraulic fracturing, with the most frequently expressed concern being a fear that hydraulic fracturing might cause contamination of underground sources of drinking water. Supporters of fracturing argue that fracturing will not cause contamination because the formations being fractured typically are located thousands of feet below drinking water aquifers, and the fractures created by the fracturing process will not travel anywhere near that far. Indeed, even many critics of fracturing agree that the fracturing process itself is

unlikely to cause contamination. If contamination occurred, it most likely would be the result of a well construction failure — such as improper casing or cementing — that allowed fluids to travel up the side of the well from a deeper formation that contains oil or gas to a shallower formation that contains a source of drinking water. Proponents of fracturing note that, with respect to the possibility of a casing or cementing failure, a hydraulically fractured well is no different than oil or gas wells that are not hydraulically fractured, but which pass through a shallow water aquifer on the way to a deeper formations. Further, millions of such wells have been drilled, and contamination problems rarely occur. Nevertheless, fears still exist. The main regulations that protect against such contamination are state regulations. Each

University, expressed a concern. They note that, when fracturing is complete, the high pressure of the formation being fractured is allowed to push the fracking water back to the surface, where such “flowback” water is recovered. As it flows up the well, the flowback water is accompanied by significant quantities of natural gas. If that gas is vented, as it sometimes has been, the venting of the natural gas could have an adverse impact on air quality. Regulators have begun to address this concern. A couple of states have implemented regulations to prevent the venting of natural gas that accompanies flowback, requiring that the gas be recovered in most cases and flared in others. Further, the EPA recently published proposed regulations to prohibit such venting. Another concern is water consumption. The hydraulic fracturing of a horizon-

Hydraulic fracturing is used to facilitate the production of oil or natural gas from low permeability formations. The process has received significant attention recently in relation to its use in shale formations. The oil and gas activity made feasible by hydraulic fracturing creates hundreds of thousands of jobs, bolsters national security by decreasing our dependence on imported energy, and even can have environmental benefits because hydraulic fracturing often is used to produce natural gas, the cleanest burning of all fossil fuels. But skeptics raise several environmental concerns, including a fear that hydraulic fracturing can threaten underground sources of drinking water. state with oil and gas activity requires a company to obtain a permit for drilling a well, and each state has regulations that impose standards for the construction, casing and cementing of wells. The main federal law that protects underground sources of drinking water, the Safe Drinking Water Act (SDWA), does not apply to the hydraulic fracturing process itself, so long as diesel is not used in the fracturing fluid (and usually it is not used). And, for the most part the SDWA has not been used to regulate fracturing even when diesel is used in the fracturing fluid. Other Concerns Several other concerns exist. One concern relates to the temporary inconveniences that arise during the drilling process. During drilling, the area around a well-site can experience increased traffic, as well as noise, dust and bright lighting that is used to facilitate around-the-clock drilling. Some states and local governments have responded with regulations to address these issues. Another concern is air quality. Hydraulic fracturing can have a positive effect on air quality because it often is used to produce natural gas, by far the cleanest burning of all fossil fuels. But people, including researchers from Cornell

tal well typically uses a few million gallons of water. That amount is not very large compared to many industrial and agricultural uses, but in areas where water supplies already are short, finding water for use in fracturing may present a problem. Some states have implemented, or are considering, implementing water use regulations. Another is the disposal of flowback water, which contains fracturing additives, as well as substances that dissolve into the water from the formation being fractured. Such substances can include metals and naturally occurring radioactive materials. In many parts of the country, underground injection wells provide a safe means for the disposal of flowback. But in some areas, such as Pennsylvania, there are not many underground injection control wells, and there sometimes has been controversy regarding whether some existing wastewater treatment plants will adequately treat the flowback. This prompted an order from the Pennsylvania Department of Environmental Protection that flowback not be sent to certain treatment plants. Well operators have been putting an increasing emphasis on recycling as much flowback as possible, using it to supply a portion of the water for future fracturing jobs. There are limits to the ability to recycle, but to the extent operators can

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recycle flowback the recycling has two benefits —  it reduces the supply of new water needed and it reduces disposal volumes. The disposal of flowback — whether by underground injection or by treatment and discharge — is regulated by the federal Clean Water Act. Some people have expressed concerns about actual or potential spills of fracturing fluids, but fracturing additives are not any different than other potentially hazardous substances with respect to the possibility of spills. Each state has regulations regarding the prevention, containment and control of spills of hazardous or potentially hazardous substances. A final area of controversy concerns disclosure of the chemicals used in fracturing. Traditionally, many of the companies that perform hydraulic fracturing kept the composition of their fracturing fluid confidential in order to protect any competitive advantage they gain through experience and research. But in response to public concerns, some companies have begun making voluntary disclosures, sometimes on their own websites and sometimes on the website FracFocus. Also, several states have enacted regulations requiring such disclosure, with some limited protection for additives that a company can demonstrate constitute a trade secret (trade secret status is a more exclusive status than normal business confidentiality). In addition, some companies have responded to public concerns by developing fracturing additives that are composed entirely or mostly of substances that qualify as food additives. Conclusion Hydraulic fracturing is used to facilitate the production of oil or natural gas from low permeability formations. The process has received significant attention recently in relation to its use in shale formations. The oil and gas activity made feasible by hydraulic fracturing creates hundreds of thousands of jobs, bolsters national security by decreasing our dependence on imported energy, and even can have environmental benefits because hydraulic fracturing often is used to produce natural gas, the cleanest burning of all fossil fuels. But skeptics raise several environmental concerns, including a fear that hydraulic fracturing can threaten underground sources of drinking water. The use of hydraulic fracturing appears likely to continue, but regulations, which already have strengthened, likely will be strengthened further to address environmental concerns. Keith  B. Hall is a member of the law firm Stone Pigman Walther Wittmann LLC in New Orleans, where his primary areas of practice are oil and gas law, commercial litigation, environmental law and toxic tort litigation. He serves as chair of the New Orleans Bar Association’s Oil and Gas Section, as a member of the Louisiana Mineral Law Institute’s Advisory Council, and as a member of the Advisory Council for the Louisiana State Bar Association’s Environmental Law Section. Hall teaches Introduction to Mineral Law as an adjunct professor at Loyola University School of Law in New Orleans. He authors “Recent Developments in Mineral Law” for the bimonthly Louisiana Bar Journal, and also authors a blog, the Oil and Gas Law Brief.


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Utah Focus, October 2011

Questar CEO says company’s future is strong By Andrew Haley The Enterprise Questar CEO Ron Jibson says the coming decades will be favorable for the gas utility and its customers, with stable returns projected for investors and low energy bills projected for consumers. A superabundance of natural gas in Utah and neighboring states will allow Questar to continue to provide Utahns with low-cost heating and cooking fuel, and, over time, will begin to replace coal and gasoline as mainstream fuels in power plants and vehicles. New and ongoing pipeline capitalization projects will help the utility company continue to deliver the low-carbon, inexpensive fuel to local customers and the national market. “The outlook for natural gas is very positive,” Jibson said. “Our monthly customer satisfaction ratings are our highest ever in the last two years,” he said. “Over 90 percent of our customers rate us as very favorable or

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favorable. We’ve been able to find ways to lower people’s bills and yet remain successful as a company.” As a vertically integrated company, the gas giant is able to provide Utah customers with natural gas at very low prices because of a unique arrangement it has with natural gas supplier and Questar subsidiary Wexpro. Since 1981, Wexpro has sold natural gas from wells it drills in Utah, Wyoming and Colorado to Questar at cost. Questar Pipeline in turn delivers the flammable gas to Questar Gas, the distribution arm of the company. “We handle everything from well to burner,” Jibson said. “Wexpro provides gas to Utah at cost of service. Because of that we’ve been able to deliver gas at well below market cost, resulting in $751 million in savings for our customers,” he said. “We have a lot of assets left for Wexpro to develop, which means very low cost.” Until recently, Questar maintained an

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(E&P) company under the Questar umbrella and was spun off as a separate, independent company in July 2010. According to Jibson, the decision to divest QEP came after considerable debate about the investment profile Questar wished to show its current and prospective shareholders. Jibson said investors were uncertain whether they were investing in a volatile E&P company with potentially high profits but considerable exposure, or a secure utility investment with stable but relatively unspectacular returns. “Were we an E&P company or a regulated company? It allows us to clean up our stories on both sides a little bit,” Jibson said. The loss of QEP does not mean Questar has written itself out of the natural gas exploration and production business. According to Jibson, Wexpro continues to provide Questar with approximately half of the natural gas it uses. According to its website, “Wexpro  has over 900 risked locations yet to drill on acreage defined by the 1981 Wexpro Agreement — over $1.4 billion of potential future investment providing attractive cost of service through low finding and development costs.” Wexpro operates in the Greater Green River, Vermillion and Uinta Basins in Wyoming, Colorado and Utah. “We’re getting very good production from those wells. We’re able to get more molecules out of the ground than we ever have before,” Jibson said. Increased supply is helping to stabilize natural gas prices, which were destabilized by the global economic downturn. Jibson said Utahns can expect low gas bills for the foreseeable future. Questar projects natural gas prices to remain low, even as oil prices have continued to climb during the ongoing economic doldrums. “We saw a lot of volatility in natural gas prices. I personally think, looking forward, those natural gas prices are not going to be as volatile as in the past,” Jibson said. “Traditionally, you always saw natural gas and oil tracking pretty close together. What we’re seeing right now is totally different. We anticipate, going forward, to have very low natural see QUESTAR next page


Utah Focus, October 2011

QUESTAR from previous page

gas costs. Not only the lowest in the country, but very low. There’s not going to be the volatility we’ve seen in the past.” Paradoxically, natural gas providers tend to thrive in a poor economy, Jibson said. “Because natural gas prices are so low, we haven’t seen a large decrease in consumption, like those behaviors which we see in times when prices are high: people only heating some rooms or keeping the thermostat low. Tough times only promote [natural gas use] more,” he said. And because it is a regulated utility, Questar’s profits, while capped, are in some measures guaranteed. The company recently led efforts to change the tariff rates, which determine its returns, from rates based on production to rates based on conservation. The change meant that Questar was financially rewarded for taking steps to improve the efficiency of its operations. “We don’t have to sell a lot of volume of natural gas in order to stay successful as a company,” Jibson said. With the future in mind, Questar is expanding the carrying capacity of its pipeline system, a giant network shaped like an H turned on its side, that delivers gas from wells in remote locations across Utah, Colorado and Wyoming to points east and west. The company is currently undertaking the fourth phase of its expansion of mainline 104, a 24-inch diameter segment completing the pipeline between Goshen and Fiddler, the southern bar of the H. The new line increases the capacity of the Goshen-Fiddler pipeline to 166 decatherms of natural gas per day, though 144 of those decatherms are already contracted. “Essentially what Questar has done in the last five years is double that southern system. We’re very strategic in the Rockies,” Jibson said. Apart from meeting increases in consumer demand for heating and cooking fuel, Questar stands to gain from its increased supply capacity as Utah’s demand for electricity continues to climb at a time when coal power, the state’s traditional method for electricity generation, faces severe setbacks. Legal challenges from national environmental groups like the Sierra Club, and a recent U.S. Supreme Court decision labeling carbon dioxide a pollutant, and thus subject to restrictions under the Clean Air Act (CAA), have halted construction of new coal fired power plants in the United States. The court’s ruling, in Massachusetts v. Environmental Protection Agency, remanded the case to the EPA, obliging the agency, a part of the executive branch, to spearhead the federal government’s handling of the carbon issue, which has increased the acrimony felt towards the EPA by the nation’s energy companies and raised concerns about the feasibility of regulating carbon markets via the CAA. Limitations on domestic coal consumption have driven a massive increase in exports of U.S. coal to developing markets in South America and Asia, where continued economic expansion, despite the global economic downturn’s effect on the

U.S. and European economies, has led to voracious coal consumption that has helped provide inexpensive electricity for new homes and factories, albeit at a high environmental cost. In Utah, where existing coal plants provide the lion’s share of the state’s electricity, the state’s vast wealth of low-sulfur, bituminous coal has long provided an abundant and low-cost source of electricity generation. But with environmental fetters hobbling the coal industry, future electricity generation in the state may rely on natural gas, the state’s other abundant energy resource. Besides its abundance and low cost, natural gas is a smart choice as a replacement fuel for coal because the costs of converting an existing coal-fired plant to a natural gas-fired plant are far lower than the costs of building new power plants. Furthermore, as concerns about global warming have spurred on the search for a replacement for coal in electricity generation, natural gas has in many ways replaced nuclear power, which in the wake of the

Fukushima disaster in Japan has become a political albatross, as the low-carbon alternative of choice. Existing green energy technologies, like wind and solar, are prohibitively expensive for generating the large amounts of electricity required to power cities and factories. According to the Western Energy Alliance, of existing electricity generating technologies, natural gas alone meets the requirements of an abundant, low-cost, low-carbon energy source. “We’re certainly in a nice position to [replace coal with natural gas plants.] Right now the cost of natural gas is very competitive with coal,” Jibson said. “You’re just not going to see a lot of coal plants being built. But in Utah you’ve got a 1.7 percent increase in power demand per year. You’ve got to meet that demand. It’s a good time to do it, because of low costs. Plus you get to keep the air clean while doing it. Natural gas has substantially lower carbon than coal. “We certainly promote all forms of energy but we think it’s got to be market-

driven. Right now the cost of wind and solar is a lot higher than natural gas for power generation. I think most of the coal plants, as they reach the end of their lives, will be converting to natural gas plants.” High oil prices and worries about carbon emissions are also attracting national interest in expanding the use of natural gas vehicles (NGVs). Questar currently operates 29 compressed natural gas (CNG) stations, mostly clustered along the I-15 corridor, and plans on developing a system of natural gas fueling stations at existing truck stops in the West to supply natural gas fueled tractor-trailers currently in production (see related story, page 4). Questar’s investment in NGV infrastructure has attracted international attention; the government of Ireland, which is considering converting the entirety of its vehicles to NGVs, invited Jibson to speak in Dublin on the subject. “We’re regarded as leading the development of natural gas vehicles across the nation,” Jibson said. “Not just nationally, but internationally, Utah is on the map.”

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Utah Focus, October 2011

Federal regulations could hinder Utah’s ability to tap energy resources By Andrew Haley The Enterprise Utah and its neighboring states possess more oil and natural gas than the Middle East, Venezuela, Nigeria and Russia combined, according to the Western Energy Alliance (WEA). In its Blueprint for Western Energy Prosperity, published in July, the nonprofit trade association, which represents more than 400 oil and gas companies, said, “technological advancement has opened the door to a century’s worth of new oil and natural gas in the West,” but federal interference threatens to slow, or even prohibit, tapping the hugely lucrative resources. In Utah, the WEA projects the oil and gas industry will create 5,700 new jobs and over $100 million in new severance tax revenues by 2020. “The good news is that Utah is part of increasing the West’s oil and gas development over the next 10 years,” said Kathleen Sgamma, WEA’s director of government

affairs. Leading the boom in Utah is natural gas, which increasingly is seen as a potential replacement for coal and gasoline in the fueling of power plants and vehicles. Rotting organisms in seas that once lapped against the southern and eastern slopes of the Uinta Mountains produced oceans of flammable gasses trapped below, and often within, thousands of feet of sedimentary rock. Technological innovations have led to the discovery of new pockets of those gasses and have allowed companies to drill for and extract them in ways industry experts never thought possible. The remains of those shallow, warmwater seas, much like today’s Caribbean, can be found in dry, low-lying basins in Wyoming and along the Utah-Colorado border. Natural gas plays in those basins, particularly in the Uinta and Green River Basins, have skyrocketed in the previous few years and are projected to continue growing for the foreseeable future. Among its sister states, Utah stands to reap a sig-

nificant portion of the profits derived from harnessing the resource. “Once described as a bridge fuel, the competitive advantages of natural gas render the bridge label obsolete. As the only energy source that is simultaneously abundant, affordable and clean, natural gas is an energy resource destination in the 21st Century, not a bridge,” the WEA wrote in its Blueprint. However, current and proposed federal regulations and lawsuits brought by government regulators and environmental groups hamper productivity and could potentially prevent accessing natural gas altogether, the WEA wrote. Much of the newly available natural gas in Utah, Colorado and Wyoming is made so by the use of hydraulic fracturing, or fracking, which has become controversial since the anti-fracking documentary film “Gasland” brought public attention to the issue. (See related stories pages 2 and 3). Several cities and states have proposed fracking bans and there is significant interest in

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Washington, D.C. to bring fracking regulation to the federal level One industry insider said the federal regulation of fracking would invariably follow standards implemented by New York, based on the potential environmental impact of fracking on New York’s unique geography. Applying environmental regulations designed to protect Manhattan’s water supply to the sparsely populated regions of Eastern Utah and Northwestern Colorado, where in addition to being mostly uninhabited, the geography is completely different to that of the eastern seaboard, made no sense, he said. Regulating fracking at the state level permitted a much more nuanced approach that allowed states like Utah to tailor their environmental regulations to fit the particulars of places like the Uinta Basin. The WEA’s Blueprint calls for a freeze on new federal regulations, which it labeled “haphazard.” It recommends the streamlining of bureaucratic hurdles some see as obfuscatory and redundant, the creation of “measures to limit litigation” and the rejection of “legislative and administrative efforts to take jurisdiction for regulating hydraulic fracturing away from the states.” Additionally, it calls for the leveling of the energy playing field by eliminating or amending fuel subsidies and tax incentives that promote the use of some fuels and electricity generating technologies over others, often at the expense of natural gas. Since more than 60 percent of the state lies on federal land, the tightening of federal regulations would have an undue effect on Utah, Sgamma said. Defining the limit of federal authority over state sovereignty has a long and contentious history and resisting federal authority is a touchstone of the conservative movement. The political stalemate in Congress has meant many federal issues, such as determining the federal government’s stance on greenhouse gas emissions, have been settled by federal court rulings on legal battles between various litigants and entities within the executive branch. Given strong support for oil and gas development among Western governors and legislators from both parties, the prospect of bringing about a federal fracking ban through legislation is remote. Instead, an outright ban or the imposition of new federal regulations would likely originate within the executive branch and be enforced by the EPA, or another federal body within the executive branch, something that would almost certainly bring about legal challenges. If political resistance to fracking continues, the fate of the practice will likely be decided as a states’ rights issue in the federal courts. While dismissive of the role of federal regulators, the WEA is not against all government. It has said state governments are playing a “leading role” in the exploitation of domestic oil and gas. In its Blueprint it praised the Utah Legislature’s approach to spurring growth in the market for vehicles operating on compressed natural gas (CNG).


Utah Focus, October 2011

SHALE from page 6

massive mining and processing facility. Enefit expects commercial production at its White River facility to begin in 2017, with oil reaching the Utah market in 20192020. Enefit will ramp up its production capabilities in two phases, reaching a total production capacity of 50,000 barrels per day around 2024, more than doubling the state’s current production levels. It plans to transport the synthetic crude upgraded from mined shale at its onsite processing facilities to Salt Lake City via pipeline. From there, Enefit will distribute its oil by train to domestic markets further afield. “They’re certainly moving forward and pumping money into the project,” Spinti said. Enefit’s White River operation involves what is called ex situ production. In ex situ production, oil shale is brought to the earth’s surface either by strip mining or underground mining. The shale is then carefully heated in an enormous cooker, called a retort, until its kerogen transforms into oil. In the 1970s, a boom in oil shale development proved highly unprofitable because of fluctuations in global oil prices and staggering labor and capital costs. Today’s high oil prices, and diminishing global supplies, have lured developers back to the industry and led to innovative technologies that lower production costs. In Colorado’s Piceance Basin, Shell has developed an in situ process that heats oil shale deposits underground and pumps out the resulting oil using traditional technology. Utah-based Red Leaf Resources has proposed a third method, which combines ex situ and in situ processes by burying extracted shale in an enormous clay-lined pit and heating the de facto retort with in situ technologies. Red Leaf claims the modified in situ or eco-shale process uses far less water than other oil shale upgrading technologies, which can be burdensome in arid, rural communities. The company is currently navigating the regulatory process and if it receives the green light, Red Leaf expects to produce nearly 10,000 barrels per day. The combined 60,000 barrels per day Red Leaf and Enefit expect to produce are only the tip of the oil shale iceberg. The ICSE report said, “the oil shale deposits in Colorado and Utah can support a large industry should technical and economic difficulties be resolved. Various studies and planning documents have forecast an industry producing up to several million [barrels of oil per day.] Obviously, the development of an oil shale industry producing millions of barrels of oil per day would cause significant changes in the area’s economy.” According to the report, an oil shale industry producing 100,000 barrels per day would create 12,500 oil shale jobs in the five-county area, with an additional 25,000 to 30,000 jobs created by the businesses that would feed, transport, house, care for and entertain oil workers earning projected

salaries nearly double area averages. All in all, the report said the five sparsely-populated counties would see a population increase of between 43,000 and 52,000 people. Similar population booms followed development of oil sands in Alberta, Canada, causing tremendous growing pains for rural counties whose hospitals, schools, police, sanitation services and roads were rapidly rendered insufficient to accommodate the influx of workers and residents and whose low tax bases did not permit a timely expansion of needed services. Separate studies conducted by the Department of Energy and the Rand Corp. anticipate the development of a domestic oil shale industry producing between two million and three million barrels per day, much of it originating in the Uinta and Piceance Basins in Utah and Colorado. The magnitude of such an industry would radically reshape not only the remote counties of Eastern Utah, but the entire state itself, as Utah and Colorado would come to rival, if not surpass, California, Texas and Alaska as the centers of the country’s oil

supply. While calling the development of oil shale “highly likely,” the report said, “oil shale commercialization faces major obstacles. Those obstacles include the high initial capital investment, the possible instability of world crude oil prices, the lack of a clearly defined federal oil shale development policy, and environmental considerations.” In Colorado, Shell has already run into problems with its state-of-the-art in situ technology, Spinti said. Shell’s process pumps steam into deep holes bored into strata contained within a protective ice wall and slowly converts shale to oil over several years, she said. The profit margin for such an operation requires a careful balancing of the amount of energy (usually in the form of natural gas) required to freeze the ice wall and heat the subterranean kerogen, and the amount of energy extracted and sold (in the form of synthetic crude). “Shell’s property is sitting between two aquifers. The problem is if you have a lot of water around, you end up heating the

11

water and not the rock. And there’s the issue of potential contamination,” Spinti said. “The Uinta Basin doesn’t have the same water problem. The oil shale zone is not collocated with the aquifer. The Piceance has a much bigger pay zone than the Uinta. Colorado is more lucrative, but there’s this water problem.” Spinti said Shell, the industry leader in in situ processing, had never publicly released its Piceance oil shale figures, nor has it begun commercial production. While rival oil companies like Chevron have developed their own in situ innovations, none of them have yet to bring oil shale to market. “There are companies that claim they have technologies that can produce it at today’s oil prices, but there are no commercial operations,” Spinti said. “Why is that? The companies’ argument is that uncertainty brought about by an unfriendly administration deters investment, and that once the rules are in play [they] will line up investors. The other side of it is they’re blowing smoke.”

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