Safely Transporting Hazardous Liquids and Gases in a Changing U.S. Energy Landscape (2018)

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2 The Domestic Energy Revolution Dramatic changes have been taking place in U.S. energy supply and demand over the past decade. While their specific impacts on the transportation sector are discussed later in the report, this chapter provides background on the major developments in the oil, natural gas, and ethanol markets that spawned these impacts. The chapter begins with an overview of cir- cumstances before 2009 when energy producers using hydraulic fracturing and horizontal drilling technologies started extracting increasingly larger quantities of oil and gas from the country’s interior at about the same time that federal policies were spurring growth in the production and use of ethanol as a motor fuel. The implications on domestic crude oil, natural gas, and ethanol markets since these transformative developments are then described. Most data in the chapter are for the period 2005 to 2015 and 2016. When the chapter was written in early 2017, it was by no means clear that the country’s energy landscape had reached a semblance of a steady state. Domestic oil markets are tied to global oil markets that have been histori- cally volatile and rattled by technological developments, as exemplified by the transformative effects of hydraulic fracturing and horizontal drilling. Government policies also matter and are prone to change. The desirability of federal and state efforts to promote ethanol fuel, for example, continues to be the subject of policy debate. Furthermore, the demand for transportation is often described as being “derived” from the demand for other goods and services. Accordingly, suppliers of pipeline, rail, barge, and other transporta- tion services must remain ready to serve an energy sector that, as demon- strated over the past decade, can undergo dramatic and unpredicted changes. 14

THE DOMESTIC ENERGY REVOLUTION 15 HISTORICAL PERSPECTIVE By the turn of the century, it was already the conventional view that domestic production of oil and natural gas would continue to decline and be outpaced by growth in demand to necessitate greater reliance on energy imports. Any other view would have seemed implausible in light of decades of stable or declining domestic oil and gas production and expanding con- sumer demand for these energy supplies. Between 1985 and 2005, U.S. pro- duction of crude oil fell by about 40 percent, while the trend in natural gas production was essentially flat.1 To meet the country’s increasing demand for gasoline, diesel, and other refined products, the importation of crude oil was continually growing. By 2005, the United States was importing 10 mil- lion barrels of oil per day2 while producing only 5 million barrels.3 Over the same period, U.S. production of natural gas increased slightly from about 16 trillion to 18 trillion cubic feet per year.4 However, to meet growing de- mand, these gas supplies were increasingly supplemented by imports from Canada.5 Flattening domestic production contributed to rising natural gas prices and to uncertainty about the future availability of key gas-derived compounds such as ethane and butane. The U.S. petrochemical manufactur- ers that relied on this hydrocarbon feedstock were facing increasing prices so as to make investing in domestic manufacturing capacity less attractive.6 Over the course of decades, the growth in energy imports had come to shape the country’s energy transportation system. Tanker ships bringing crude oil from overseas offloaded at coastal refineries and terminals, where a network of transmission pipelines moved the commodity to inland refiner- ies. In the case of natural gas, pipeline systems were built to accommodate Canadian imports. By 2005, large investments were being contemplated for specialized port facilities to handle imports of liquefied natural gas (LNG) by tanker ship to meet supply shortfalls. Indeed, many energy analysts were 1 U.S. Energy Information Administration, “U.S. Field Production of Crude Oil,” Petro- leum & Other Liquids, accessed September 14, 2017, https://www.eia.gov/dnav/pet/hist/ LeafHandler.ashx?n=pet&s=mcrfpus2&f=m. 2 U.S. Energy Information Administration, “Annual Energy Outlook” (Washington, D.C., January 7, 2017), https://www.eia.gov/outlooks/aeo. 3 U.S. Energy Information Administration, “U.S. Field Production of Crude Oil.” 4 U.S. Energy Information Administration, “U.S. Dry Natural Gas Production,” Natural Gas, accessed September 14, 2017, https://www.eia.gov/dnav/ng/hist/n9070us2a.htm. 5 U.S. Energy Information Administration, “U.S. Natural Gas Imports and Exports: Issues and Trends 2005,” February 2007, https://www.eia.gov/naturalgas/importsexports/annual/ archives/2007/ngimpexp05.pdf. Canadian gas exports to the United States grew from 1 tril- lion cubic feet in 1985 to about 3.5 trillion cubic feet in 2005; https://www.eia.gov/naturalgas/ importsexports/annual/archives/2007/ngimpexp05.pdf. 6 Alexander H. Tullo, “Petrochemicals: A North American Recovery Was Elusive in 2003, but Producers Hope They Will Make Some Progress in 2004,” Chemical & Engineering News, March 15, 2004, http://pubs.acs.org/cen/coverstory/8211/print/8211petrochemicals.html.

16 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES predicting that imports of LNG would meet about 20 percent of the coun- try’s natural gas demand by 2020.7,8 Meanwhile, concern over the country’s growing dependence on oil imports had led federal and state policy makers to strengthen incentives for the production and use of corn-based ethanol. While these efforts had yielded only modest national impacts on the de- mand for ethanol by the early 2000s, they were leading to more truck and rail movements of this fuel in the corn-growing states of the Midwest.9 The waning of domestic oil and gas supplies and their replacement by imports and alternatives such as ethanol remained the dominant narrative as late as 2011, even as many casual observers were beginning to take notice of contrary developments in the field. It was around this time that The New York Times, CNN, and other news media began reporting that rural communities across eastern Montana, western North Dakota, Oklahoma, Pennsylvania, and western Texas had become oil and gas boomtowns, ex- periencing burgeoning demand for workers, housing, equipment, materials, transportation, and public services.10 Their observations coincided with market evidence of increasingly larger supplies of oil and gas originating in these regions—a development that signaled the prospect of the United States not only becoming less dependent on imports but potentially a net exporter of oil and gas in the years ahead.11,12 The U.S. Energy Information Administration (EIA) reported in 2014 that domestic natural gas production was nearing an all-time high.13 Hav- ing issued a forecast in 2006 that oil imports would account for two-thirds 7 Liquefied natural gas is natural gas that has been cooled to a liquid state at –160 degrees Celsius. Liquefaction reduces its volume more than 600 times, making it more practical for storage and transportation by ship. 8 National Petroleum Council, Balancing Natural Gas Policy—Fueling the Demands of a Growing Economy, vol. 1, Summary of Findings and Recommendations (Washington, D.C.: National Petroleum Council, 2003), http://www.npc.org/reports/NG_Volume_1.pdf. 9 U.S. Energy Information Administration, “Increasing Ethanol Use Has Reduced the Aver- age Energy Content of Retail Motor Gasoline,” Today in Energy, October 27, 2014, https:// www.eia.gov/todayinenergy/detail.cfm?id=18551. Biofuel’s share of the motor fuel supply had reached barely 3 percent by the early 2000s. 10 Monica Davey, “North Dakota Has Jobs Aplenty, but Little Housing,” The New York Times, April 20, 2010, http://www.nytimes.com/2010/04/21/us/21ndakota.html. 11 Blake Ellis, “Six-Figure Salaries, but Homeless,” CNNMoney, October 26, 2011, http:// money.cnn.com/2011/10/21/pf/america_boomtown_housing/index.htm. 12 Robert J. Samuelson, “The U.S. May Become Energy-Independent after All,” The Washington Post, November 14, 2012, https://www.washingtonpost.com/blogs/post- partisan/post/the-us-may- become-energy-independent-after-all/2012/11/14/ef8624e4-2e7d-11e2-89d4-040c9330702a_blog. html?utm_term=.7ce9e5011e50. 13 U.S. Energy Information Administration, “U.S. Weekly Supply Estimates,” Petroleum & Other Liquids, accessed September 14, 2017, https://www.eia.gov/dnav/pet/pet_sum_sndw_ dcus_nus_w.htm.

THE DOMESTIC ENERGY REVOLUTION 17 of U.S. oil consumption during the next decade,14 EIA was issuing updated forecasts that domestic oil production would surpass imports for the first time in 30 years.15 Meanwhile, even as domestic gas and crude oil supplies were surging, production of ethanol was also on the rise, as policies insti- tuted in the 2000s to mandate the greatly increased use of biofuel had taken effect. The 350 million barrels of ethanol produced in 2015 were nearly four times higher than volumes produced 10 years earlier, and nearly equal to 10 percent of the country’s total gasoline sales.16 It is difficult to overstate the extent to which U.S. energy markets had been transformed in a few short years, or to exaggerate how this transformation caught energy analysts by surprise. In retrospect, the trans- formation’s central causes are now clear—the most important being the widespread exploitation of new drilling technologies and methods that enabled economic recovery of oil and gas from the country’s many basins of porous rock (e.g., shale and other types of mudstone) (see Figure 2-1). In the case of ethanol, of course, the cause of its marked growth was an increasingly ambitious federal policy to increase the use of biofuels.17 The impact of this energy transformation was felt well beyond U.S. oil and gas markets. The population of North Dakota grew by 13 percent between 2010 and 2015 as hydraulic fracturing activity ramped up.18 The counties of northern Pennsylvania, site of the Marcellus basin, became new employment centers in a region that had been slowly recovering from high unemployment during the Great Recession.19 In the rural mudstone basins of Kansas, Oklahoma, and northern Texas, many new oil and gas jobs were being created. Meanwhile, to meet ethanol supply mandates, more and more of the country’s corn crop (up to 40 percent) was being devoted to the production of this fuel, which had become an important source of employment in the rural counties of Illinois, Indiana, Iowa, and 14 U.S. Energy Information Administration, “Annual Energy Outlook 2006.” Table A1. 15 U.S. Energy Information Administration, “U.S. Weekly Supply Estimates.” 16 U.S. Energy Information Administration, “Monthly Energy Review: Table 10.3 Fuel Ethanol Overview,” n.d., http://www.eia.gov/totalenergy/data/monthly/query/mer_data_excel. asp?table=T10.03. 17 The standards are intended to comply with the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. 18 “North Dakota Population Could Top 1 Million by 2040,” The Bismarck Tribune, Janu- ary 19, 2016, http://bismarcktribune.com/news/state-and-regional/north-dakota-population- could-top-million-by/article_d4f75d95-669e-5dc3-8bc8-453cd1b65390.html. 19 Jennifer Cruz, Peter W. Smith, and Sara Stanley, “The Marcellus Shale Gas Boom in Pennsylvania: Employment and Wage Trends,” U.S. Bureau of Labor Statistics Monthly Labor Review, February 2014, https://www.bls.gov/opub/mlr/2014/article/the-marcellus-shale-gas- boom-in-pennsylvania.htm.

18 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES Nebraska.20 This rapid growth in jobs and income boosted state and local tax revenues, but also placed new demands on public infrastructure and services.21 Roads in rural counties that were once remote and lightly trav- eled were suffering from traffic congestion and damage caused by trucks carrying equipment and materials to and from production sites.22 In the same way that these economic, social, and environmental ef- fects had not been anticipated, operators of transportation systems did not foresee how they would be affected by the speed and magnitude of the changes taking place in domestic energy markets. The increasing supplies of 20 U.S. Department of Agriculture, “U.S. Bioenergy Statistics,” Economic Research Service, accessed September 15, 2017, https://www.ers.usda.gov/data-products/chart-gallery/detail. aspx?chartId=40078. 21 Daniel Raimi and Richard G. Newell, “Shale Public Finance Local Revenues and Costs Associated with Oil and Gas Development” (Duke University Energy Initiative), accessed Sep- tember 15, 2017, https://energy.duke.edu/sites/default/files/attachments/Shale%20Public%20 Finance%20Local%20Revenues%20and%20Costs%20Issue%20Brief%20Final.pdf. 22 Ana Campoy, “Drilling Strains Rural Roads,” The Wall Street Journal, July 26, 2012, https://www.wsj.com/articles/SB10000872396390444840104577551223860569402. FIGURE 2-1 Major U.S. shale and other mudstone basins with reservoirs of oil and gas, 2011. SOURCE: U.S. Energy Information Administration, “Review of Emerging Re- sources: U.S. Shale Gas and Shale Oil Plays,” Analysis & Projections, July 8, 2011, https://www.eia.gov/analysis/studies/usshalegas. 2-1

THE DOMESTIC ENERGY REVOLUTION 19 crude oil, natural gas, and ethanol had an immediate impact on the trans- portation sector because of the need for more take-away capacity. How- ever, the origins of this supply had limited transportation options because they were located far from traditional production regions. For instance, by 2015, Pennsylvania had become the second largest domestic producer among states of natural gas,23 North Dakota ranked second in domestic oil production,24 and top ethanol-producing states, such as Iowa, Nebraska, and South Dakota, had become the main suppliers of nearly 10 percent of the country’s finished gasoline.25,26 A decade earlier, these states had origi- nated a negligible share of the country’s liquid and gas energy, and thus had accounted for a commensurately small percentage of the country’s energy transportation infrastructure. The domestic energy revolution not only created new energy transporta- tion routes, but it also disrupted traditional routings. For example, as more natural gas was produced in western Pennsylvania, there was an increase in demand for local and regional pipeline capacity to serve electric utili- ties and gas distribution systems located in the nearby communities of the Northeast. In turn, demand waned for gas that was once imported to the region in long-haul pipeline systems originating in the Gulf Coast and Rocky Mountain regions.27,28 Similarly, as new pipeline take-away capacity was added in North Dakota to transport oil from the Bakken fields to refineries in the Midwest, the long-haul pipelines that had been configured to supply these refineries with oil from Gulf Coast terminals were becoming idle.29,30 23 U.S. Energy Information Administration, “Rankings: Natural Gas Marketed Production, 2015,” Pennsylvania State Profile and Energy Estimates, accessed September 15, 2017, https:// www.eia.gov/state/rankings/?sid=PA#series/47. 24 U.S. Energy Information Administration, “Rankings: Crude Oil Production, May 2017,” U.S. States Profiles and Energy Estimates, accessed September 15, 2017, https://www.eia.gov/ state/rankings/?sid=US#/series/46. 25 State of Nebraska, “Ethanol Facilities’ Capacity by State,” accessed September 15, 2017, http://www.neo.ne.gov/statshtml/121.htm. 26 U.S. Energy Information Administration, “Energy Use for Transportation,” Use of Energy in the United States Explained, accessed September 15, 2017, https://www.eia.gov/ Energyexplained/?page=us_energy_transportation. 27 Brendan Gibbons, “In Northeast Pa., Gas and Power March Together,” Marcellus.Com, August 17, 2015, http://marcellus.com/news/id/127517/in-northeast-pa-gas-and-power-march- together. 28 Bradley Kramer, “Rockies Express Pipeline Gets a Second Chance,” North American Oil & Gas Pipelines, February 25, 2014, http://napipelines.com/resurexion. 29 Kristen Hays, “Marathon CEO: Capline Pipeline Reversal Likely When Oil Prices Re- cover,” Reuters, April 28, 2016, https://www.reuters.com/article/us-marathon-pete-capline/ marathon-ceo-capline-pipeline-reversal-likely-when-oil-prices-recover-idUSKCN0XP2QS. 30 Sandy Fielden, “Diamonds Are Forever—but Northbound Capline Crude Flows May Be Living on Borrowed Time,” RBN Energy, September 1, 2014, https://rbnenergy.com/ diamonds-are-forever-but-northbound-capline-crude-flows-may-be-living-on-borrowed-time.

20 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES To provide background for the review of the impacts of the domestic energy revolution on the country’s long-haul modes of transportation in Chapter 3, additional detail follows on specific developments in the domes- tic oil, natural gas, and ethanol markets. Developments in oil markets are discussed first and in greater detail because they have had major reverbera- tions across three modes—pipelines, railroads, and barges. DEVELOPMENTS IN CRUDE OIL MARKETS The main use of crude oil is to power transportation. When refined into gasoline, diesel, bunker fuel, and jet fuel, crude oil is the source of more than 95 percent of the energy used for transportation. Other uses include home heating fuel, feedstock for petrochemical plants, and the production of waxes, lubricants, and asphalt. Most of the country’s refinery capacity is located near populated areas, which have high demand for gasoline and other refined products, as well as good connections with pipeline and marine transportation systems that can provide access to oil supplies and markets for refined products (see Figure 2-2). About 47 percent of the country’s refinery capacity is located on the Gulf Coast, which has a high concentration of petrochemical plants, proximity to onshore and offshore oil fields, and a dense network of pipe- lines and waterways.31 Other major refinery centers are located in the Great Lakes region (13 percent of refining capacity); California (11 percent); Kansas, Oklahoma, and inland Texas (9 percent); and the mid-Atlantic Coast (7 percent). The locations of U.S. refinery capacity have been fairly stable for decades, as most new capacity additions since the 1970s have been confined mainly to traditional refinery centers. Like the geography of oil refineries, the geography of crude oil pro- duction had been stable for many years, as production fields were concen- trated in a handful of states—mainly Alaska, California, Oklahoma, and Texas—and offshore in the Gulf of Mexico. By the early 2000s, however, production from Alaska’s North Slope and California was declining, and increasing volumes of crude oil were being imported from Canada, Mexico, and Venezuela. Much of this imported crude was dense and high in sulfur content—or “heavy” and “sour.” Refineries along the Gulf Coast, and some on the Great Lakes, invested in special equipment to process these heavy and sour crude oils, which could be obtained at lower prices than the lower-density, lower-sulfur “light” and “sweet” oils that are generally produced in Alaska and Texas. Lacking the specialized equipment to pro- 31 U.S. Energy Information Administration, “Louisiana Gulf Coast Refinery Utilization and Capacity,” Petroleum & Other Liquids, accessed September 15, 2017, https://www.eia.gov/ dnav/pet/pet_pnp_unc_dcu_r3c_m.htm.

THE DOMESTIC ENERGY REVOLUTION 21 2-2 FIGURE 2-2 Location of U.S. oil refinery capacity, 2012. SOURCE: U.S. Energy Information Administration, “Much of the Country’s Re- finery Capacity Is Concentrated Along the Gulf Coast,” Today in Energy, July 19, 2012, https://www.eia.gov/todayinenergy/detail.php?id=7170. cess heavy and sour crudes, most refineries on the Atlantic Coast and, to a lesser extent, the Pacific Coast, as well as many in the Midwest, obtained increasingly larger amounts of their crude oil from tankers importing lighter grades from overseas. Before 2010, the location of domestic oil production was even more geographically concentrated than the country’s refinery capacity. This is no longer the case. As oil production in California and Alaska has de- clined, production in the middle of the country has grown (see Table 2-1). Trends in production from basins that use hydraulic fracturing are shown in Figure 2-3. In 2005, these basins produced less than 5 percent of domestic crude oil. In 2015, four of these basins—Eagle Ford and Permian (mostly in Texas), Bakken (mostly in North Dakota), and Niobrara-Codell (mostly in Colorado and Wyoming)—accounted for more than 40 percent of U.S. oil production. During this period, North Dakota went from being a negligible oil producer to the second-highest among states after Texas, while production from Colorado, New Mexico, and Wyoming more than doubled (see Figure 2-4).

22 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES TABLE 2-1 Top Crude-Oil-Producing States, 2005 and 2015 2005 2015 State Barrels per Day (Thousands) State Barrels per Day (Thousands) Texas 1,076 Texas 3,462 Alaska 864 North Dakota 1,177 California 631 California 551 Louisiana 206 Alaska 483 Oklahoma 168 Oklahoma 432 New Mexico 167 New Mexico 402 Wyoming 142 Colorado 346 North Dakota 98 Wyoming 237 Kansas 92 Louisiana 172 Montana 90 Kansas 125 SOURCE: EIA. 2-3 FIGURE 2-3 Trends in oil production from U.S. mudstone basins, 2005–2016. SOURCE: U.S. Energy Information Administration, “Where Our Natural Gas Comes From,” Natural Gas Explained, accessed September 15, 2017, https://www. eia.gov/energyexplained/index.cfm?page=natural_gas_where.

THE DOMESTIC ENERGY REVOLUTION 23 FIGURE 2-4 U.S. states experiencing largest changes in crude oil production, 2005–2015. SOURCE: EIA, “Crude Oil Production,” Petroleum & Other Liquids, March 31, 2017, https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm. Not only did the development of the country’s mudstone basins change the oil supply landscape, it also affected the flow of crude oil grades across the continent. Whereas heavy, sour oil imports from Canada had been a main source of growth in North American supplies until the mid- 2000s, the oil extracted using hydraulic fracturing consisted of lighter, sweeter grades. As a result, the geographically stable base of refineries, whose oil-processing investments were made on the basis of past trends in crude oil supplies, was facing a dramatic change in both the location of producing regions and the grades and prices of oil available in the market. Although many of the Gulf Coast and Great Lakes refineries that had in- vested in the equipment needed to process heavy crudes were not natural customers for this lighter, sweeter crude, several refineries on the Atlantic and Pacific coasts were candidates. If properly incentivized by price dif- ferentials, they could use this oil instead of more expensive imports from overseas and from the dwindling supply of light oil from Alaska. Faced with this mixture of refinery interest, many of the new produc- ing regions, such as North Dakota, had limited connectivity to the large pipeline networks that could efficiently move the crude oil to meet demand. Limited pipeline take-away capacity had been stretched thin by growing 2-4 -500 0 500 1,000 1,500 2,000 2,500 3,000 3,500 UT OH CA WY NM OK CO AK ND TX Change in barrels per day (thousands), 2005 and 2015 2005 2015 Difference

24 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES production volumes spurred by sharply rising world oil prices from 2009 to 2011.32 As pipeline transportation and storage bottlenecks formed across the Great Plains and Upper Midwest, the oil supply surplus depressed oil prices in the middle of the country. At times during 2012, the surplus led to Bakken crude oil selling for $10 to $25 less per barrel than the West Texas Intermediate (WTI) benchmark rate (see Figure 2-5). Price differentials of this magnitude created powerful incentives for refineries to seek alterna- tive transportation means to obtaining these less expensive, bottlenecked supplies. During 2010 and 2011, the nation’s freight railroads had been expe- riencing steady increases in crude oil traffic. By 2012, when the pipeline bottle necks were at their peak, the number of carloads of crude oil was nearly 10 times higher than in 2010.33 During the same period, barge operators were investing heavily in new tank barges to accommodate the growing volume of domestic crude oil being shipped. Not only did the country’s extensive freight rail and barge networks reach deep into the new oil-producing regions, they could move shipments in directions not served by pipelines. For refineries that process light crude oil, the decision to ship by rail or by barge was a simple matter of economics. The decision rested on the lower end price of acquiring the bottlenecked oil when shipped by rail or by barge than that of oil supplies received by other means, such as tanker imports from overseas. At a time when oil prices were highly volatile and the long-term pros- pects of profitable production from hydraulic fracturing remained uncer- tain, an advantage of rail and barge service was flexibility for shippers. However, as a longer-term means of transportation, rail and barge pre- sented some difficult investment choices. The tank car and barge fleet would need to be expanded, and bulk loading and offloading facilities would need to be built. These investments would need to be made with an eye toward the eventual ability of competing pipelines to expand their networks and for the price differentials between domestic and imported crude oil to remain sufficiently attractive to make rail equipment and infrastructure investments pay off. Indeed, from June 2014 to January 2016, U.S. oil prices declined by 69 percent, from $114 to $35 per barrel.34 In the years since bottleneck conditions emerged in 2012, the oil supply surpluses in the Midwest had been cleared, in part because of the use of rail and barge transportation. 32 From January 2009 to April 2011, the benchmark price of West Texas Intermediate (WTI) oil increased from $42 to $113 per barrel. 33 Association of American Railroads, “U.S. Rail Crude Oil Traffic,” accessed September 15, 2017, https://www.aar.org/BackgroundPapers/US%20Rail%20Crude%20Oil%20Traffic.pdf. 34 U.S. Energy Information Administration, “Europe Brent Spot Price FOB,” Petroleum & Other Liquids, accessed September 15, 2017, https://www.eia.gov/dnav/pet/hist/LeafHandler. ashx?n=PET&s=RBRTE&f=D.

THE DOMESTIC ENERGY REVOLUTION 25 FIGURE 2-5 Average difference in price from WTI benchmark, Bakken crude oil, January 2012–March 2013. SOURCE: EIA, “Bakken Crude Oil Price Differential to WTI Narrows Over Last 14 Months,” Today in Energy, March 19, 2013, https://www.eia.gov/todayinenergy/ detail.php?id=10431. Having peaked in 2014, crude-by-rail traffic was down 20 percent in 2015. Figure 2-6 shows graphically how the once-rail-dependent Bakken fields had become pipeline accessible by 2016. When this report was being prepared in early 2017, the future of crude by rail was dimming as pipeline companies expanded their networks to offer more scale economies in crude oil transportation. Nevertheless, rail and barge transportation were holding onto some of their advantages by offering producers additional routing options, especially for moving short- term supply surpluses and serving newly developed, lower-volume basins. Perhaps the most one can predict at this juncture is that these two modes will continue to account for a meaningful portion of the country’s crude oil traffic, but at levels substantially lower than in recent years. DEVELOPMENTS IN ETHANOL MARKETS Ethanol has been distilled and denatured for mixing with gasoline for decades. Traditionally, “gasohol” blends were used mainly by motorists in corn-growing states of the Midwest. The oil supply shocks of the 1970s prompted the federal government and several states to introduce policies aimed at increasing fuel ethanol supplies in support of U.S. farmers and to reduce reliance on imported oil. These policies included federal and state ex- emptions of ethanol from motor fuel excise taxes, blending and production tax credits, producer loan guarantees, and research grants. In the years that

26 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES FIGURE 2-6 Crude oil transportation by rail and by pipelines from the Williston Basin’s Bakken play. NOTE: Mb/d = thousands of barrels per day. SOURCE: E. R. Braziel, presentation to committee. 2-6 followed, federal and state mandates for the reformulation of gasoline to improve air quality eventually led to the widespread adoption of ethanol as a fuel oxygenate, which displaced methyl tertiary-butyl ether. Consequently, demand for the biofuel gradually increased during the 1980s, as ethanol was being transported to more markets outside the Midwest. Nevertheless, by the late 1990s, ethanol remained a niche fuel, produced in quantities equivalent to only about 1 or 2 percent of the country’s total gasoline supply. Since the early 2000s, public policy has continued to play an important role in spurring ethanol demand and supply. The most important policy development has been the Renewable Fuel Standard (RFS), established by the U.S. Congress in the Energy Policy Act of 2005. The legislation requires minimum volumes of biofuels to be used each year in the motor vehicle fuel supply. The first RFS called for at least 4 billion gallons of biofuel to be used in 2006, rising to 7.5 billion gallons by 2012. The Energy Independence and Security Act of 2007 greatly increased the mandated volumes and ex- tended the compliance period through 2022. This new standard required the annual use of 9 billion gallons of biofuel in 2008, rising to 36 billion gallons in 2022.35 35 The 36 billion gallons were supposed to consist of at least 16 billion gallons made from cellulosic biofuels, followed by an eventual cap of 15 billion gallons of corn-based ethanol.

THE DOMESTIC ENERGY REVOLUTION 27 Figure 2-7 shows how ethanol volumes increased sharply after passage of the first RFS in 2005 and the second RFS in 2007. Fuel ethanol is now consumed in all 50 states, and total ethanol production was nearly 5 times higher in 2015 than in 2005. Ethanol’s share of gasoline sales reached 9.8 percent in 2014.36 The U.S. Environmental Protection Agency (EPA) proposed RFS requirements for 2017 that would increase conventional renewable fuel volumes (mostly corn ethanol) to 14.8 billion gallons.37 Although this level would represent an increase of 300 million gallons over 2016 volumes, it is 200 million gallons less than required by the 2007 law. By mandating the use of ethanol in the U.S. gasoline supply, RFS turned fuel ethanol into a widely shipped commodity. Because it takes about 20 pounds of corn to produce 1 gallon of ethanol (weighing about 6.5 pounds), it makes economic sense for distillation plants to be located near cornfields to reduce raw material transportation costs and make eco- nomic use of distillation byproducts, such as the distillers’ dried grain used 36 U.S. Energy Information Administration, “Corn Ethanol Yields Continue to Improve,” Today in Energy, May 13, 2015, https://www.eia.gov/todayinenergy/detail.php?id=21212. 37 U.S. Environmental Protection Agency, “Proposed Renewable Fuel Standards for 2017, and the Biomass-Based Diesel Volume for 2018,” Renewable Fuel Standard Program, May 17, 2016, https://www.epa.gov/renewable-fuel-standard-program/proposed-renewable- fuel- standards-2017-and-biomass-based-diesel. FIGURE 2-7 Annual U.S. ethanol production, 1980–2015. SOURCE: Renewable Fuels Association. 2-7

28 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES in livestock feed.38 Ethanol distilleries have therefore remained centered in a handful of corn-growing Midwestern states, led by Illinois, Indiana, Iowa, Minnesota, and Nebraska (see Figure 2-8). The distilled and de- natured product is then transported on long-distance routes—mostly by rail— radiating out from the Midwest to gasoline distribution and blending centers located near motorist demand. In 2015, the top five states in etha- nol consumption were California, Texas, Florida, New York, and Ohio.39 As discussed more in the next chapter, about 70 percent of the country’s ethanol production moves by rail, mostly in trains consisting of 60 to 120 tank cars, each holding about 30,000 gallons (1.8 to 3.6 million gallons per train). Because of the limited number of ethanol plants located near rivers, barges transport only about 10 percent of the volume produced, typically in 2-barge tows that hold 2.5 million gallons. Very little ethanol is shipped by pipeline, in part because of the fuel’s propensity to attract water, which can corrode the steel in pipelines. Another reason for the limited movement 38 Renewable Fuels Association, “2016 Ethanol Industry Outlook: Fueling a High Octane Future” (Washington, D.C., 2016), http://www.ethanolrfa.org/wp-content/uploads/2016/02/ RFA_2016_full_final.pdf. 39 U.S. Energy Information Administration, “Table F4: Fuel Ethanol Consumption Esti- mates, 2015,” U.S. States Profiles and Energy Estimates, accessed September 19, 2017, https:// www.eia.gov/state/seds/data.php?incfile=/state/seds/sep_fuel/html/fuel_use_en.html. FIGURE 2-8 Fuel ethanol production facilities in 2016, by state. SOURCE: Renewable Fuels Association. 2-8

THE DOMESTIC ENERGY REVOLUTION 29 by pipeline is that the ethanol industry is fairly dispersed such that signifi- cant infrastructure investments would be required to consolidate traffic to achieve the quantities needed for pipeline transportation. DEVELOPMENTS IN NATURAL GAS MARKETS Natural gas is a mixture of several hydrocarbon gases. Although its main constituent is methane, it can also contain ethane, propane, and butane, as well as other gases such as carbon dioxide, oxygen, and hydrogen sulfide. Once flared off as an unwanted side-product of oil extraction, natural gas now accounts for about 30 percent of U.S. energy consumption (see Fig- ure 2-9). More than half of U.S. homes use natural gas as their main heating source.40 Natural gas is also used to produce electricity in about 30 percent of the country’s power plants and it is an important heating fuel for numer- ous manufacturing processes, including steel, glass, and paper production.41 The hydrocarbons in natural gas are also used as chemical feedstocks in the manufacture of plastics and other organic chemicals. 40 U.S. Energy Information Administration, “Everywhere But Northeast, Fewer Homes Choose Natural Gas as Heating Fuel,” Today in Energy, September 25, 2014, https://www. eia.gov/todayinenergy/detail.php?id=18131. 41 U.S. Energy Information Administration, “What Is U.S. Electricity Generation by Energy Source?,” Frequently Asked Questions, accessed September 19, 2017, https://www.eia.gov/ tools/faqs/faq.php?id=427&t=3. FIGURE 2-9 Historical trends and projections in U.S. energy consumption, by fuel source. SOURCE: EIA, “Annual Energy Outlook 2017,” 9. 2-9 Quadrillion British thermal units

30 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES When extracted from the well, raw natural gas is often described as being “dry” or “wet.” Dry gas consists almost entirely of the light molecule methane, whereas wet gas contains more of the heavier hydrocarbons, such as ethane, propane, and butane. These heavier hydrocarbons are referred to as natural gas liquids (NGLs; EIA uses the term hydrocarbon gas liquids) and can be separated from the gas stream. Their separation from methane, or dry gas, usually takes place near the production site at gas-processing facilities. The methane is then transported under pressure by transmission pipelines directly to large industrial users, power plants, and gas distribution systems. The NGL stream is usually transported by pipeline to fractionator plants that separate the stream into its constituent compounds, or “purity products.” In the case of propane and butane, they are usually compressed into a liquefied form (liquefied petroleum gas, or LPG) and transported by pressure pipeline, barge, and railroad tank car to large industrial users or by tank truck, tank container, and cylinder for use by homeowners and other consumers. Ethane, the lightest and most volatile of the main NGL compounds, is mainly used as a petrochemical feedstock. Because of the need to transport it under pressures too high for safe and economical movement by tank barge, tank car, and tank truck, ethane is domestically transported by pipeline only, usually from fractionators to storage terminals and then to industrial users. Having been turned into a major energy source and petrochemical feedstock, natural gas supplies in the United States were no longer viewed as being overabundant by the end of the 20th century. In its Annual Energy Outlook for 2008, EIA observed that most of the country’s major conven- tional gas reserves had been discovered. Indeed, the combination of increas- ing demand and limited growth in domestic production had contributed to a fivefold increase in natural gas prices from the late 1990s to 2008.42 By that time, large investments were being contemplated for LNG import facilities, as most analysts expected natural gas prices to continue to rise be- cause of growing demand and lagging domestic supplies. In its 2008 report, EIA predicted that U.S. production would grow only incremental for the next 20 years, aided only by small additions from offshore fields, Alaska, and unconventional sources such as sandstone and shale.43 EIA’s 2008 forecast would not stand the test of time. Just 4 years later, in its Annual Energy Outlook for 2012, the agency predicted the country 42 U.S. Energy Information Administration, “Henry Hub Natural Gas Spot Price,” Natural Gas, accessed September 19, 2017, https://www.eia.gov/dnav/ng/hist/rngwhhdm.htm. 43 U.S. Energy Information Administration, “Annual Energy Outlook 2008 with Projections to 2030” (Washington, D.C., June 2008), 77, https://www.eia.gov/outlooks/archive/aeo08/ pdf/0383(2008).pdf.

THE DOMESTIC ENERGY REVOLUTION 31 would be a net exporter of natural gas by 2035.44 In its Annual Energy Outlook for 2016, the agency predicted that the United States would become a net exporter of natural gas by 2018.45 As was the case with domestic crude oil production, energy analysts did not foresee the dramatic impact that development of the country’s shale and other mudstone basins would have on domestic gas production. As shown in Figure 2-10, output from hydraulic fracturing sources grew to make up nearly half of the U.S. dry natural gas production by 2014, driven by especially large volumes recovered from the Marcellus Basin in Pennsylvania and West Virginia. Just a few years earlier, these states had accounted for a negligible share of natural gas production, and the Northeast was generally viewed as “gas 44 U.S. Energy Information Administration, “Annual Energy Outlook 2012 with Pro- jections to 2035” (Washington, D.C., June 2012), 74, https://www.eia.gov/outlooks/aeo/ pdf/0383(2012).pdf. 45 U.S. Energy Information Administration, “Most Natural Gas Production Growth Is Ex- pected to Come from Shale Gas and Tight Oil Plays,” Today in Energy, June 7, 2016, https:// www.eia.gov/todayinenergy/detail.php?id=26552#. FIGURE 2-10 Trends in U.S. natural gas production volumes by basin, 2000–2014. SOURCE: EIA. 2-10

32 SAFELY TRANSPORTING HAZARDOUS LIQUIDS AND GASES starved” due to its distance from domestic supplies and limited access to cross-country gas transmission pipelines. Because they are co-produced with natural gas, NGLs were similarly forecasted to experience declining supplies during the early 2000s. When the hydraulic fracturing boom began around 2008, dry natural gas prices were at an all-time high, creating incentives for the development of fields that produced more dry gas than wet gas. Interest in dry gas was par- ticularly strong in the Marcellus Basin, which had access to natural gas pipelines but not substantial NGL pipeline and processing capacity. Most of the country’s NGL pipelines and fractionators are located in Texas and Louisiana, close to conventional gas fields and petrochemical centers that demand ethane and other NGLs. However, by 2009, the large influx of dry natural gas from hydraulic fracturing contributed to sharp decreases in the commodity’s price. Under these circumstances, producers began to place greater value on basins that produced wet gas in order to recover the NGL streams that could be sold separately and had not experienced the same precipitous declines in price. The growth in wet gas production has led to investments in gas- processing capacity in the Northeast, as well as investments in fraction- ation capacity, so that some of the purity products, especially propane and butanes, can be separated locally and sold in regional markets (see Figure 2-11). Currently, the supply of NGLs from the Marcellus and Utica Basins exceeds demand in the Northeast, particularly for ethane, whose main market continues to be the petrochemical industry centered in the Gulf Coast states. In 2014, the United States switched from being a net importer of ethane to a net exporter after the opening of two new ethane pipelines that transport methane from North Dakota and Pennsylvania to Canada.46 The future market for the NGLs produced from hydraulic fracturing will therefore depend on many factors, including market prices, export demand, changes in the size and location of the petrochemical in- dustry, and transportation options. In the next chapter, more discussion is given to the development of NGL transportation capacity. 46 U.S. Energy Information Administration, “Ethane Production Expected to Increase as Petrochemical Consumption and Exports Expand,” Today in Energy, April 1, 2016, https:// www.eia.gov/todayinenergy/detail.php?id=25632.

THE DOMESTIC ENERGY REVOLUTION 33 FIGURE 2-11 Natural gas field plant production of NGLs in and near the Marcel- lus and Utica Basins. SOURCE: EIA, “Appalachian No. 1 Natural Gas Plant Field Production,” Petro- leum & Other Liquids, April 28, 2017, https://www.eia.gov/dnav/pet/pet_pnp_gp_ dc_rap_mbblpd_m.htm. 2-11 0 25 50 75 100 125 150 175 200 225 250 275 300 Barrels per day (thousands) Natural Gasoline Ethane Propane Normal Butane Isobutane