SANTA BARBARA OIL SPILL

¶Oil from a ruptured well surrounds a platform six miles off the coast of Santa Barbara. The 1969 spill, an estimated 100,000 barrels, was the largest in U.S. waters prior to 2010. Some 30 miles of shoreline were fouled, and thousands of birds died along with fish, dolphins, and sea lions. The incident drew public outcry and triggered environmental-protection legislation. Today, Platform A-21 is still operating.

¶Associated Press the largest offshore drilling accident in American waters until the Macondo blowout. It generated intense opposition to offshore oil in California, but the fallout also reverberated nationally, setting the stage for the passage of the National Environmental Policy Act (NEPA), a symbol of the growing strength of the national environmental movement, as well as a host of other increasingly demanding environmental protection laws throughout the 1970s (See Chapter 3).29

¶Offshore operators suddenly faced a potentially hostile political and regulatory climate. Ten days after the accident, Secretary of the Interior Walter Hickel, with the support of President Richard Nixon, issued a moratorium on all drilling and production in California waters. In April, Secretary Hickel completed a preliminary assessment of the leases affected by the moratorium and allowed 5 of the 72 lessees to resume drilling or production. In August, the Interior Department issued completely revised outer continental shelf Orders 1–7—the first update since the orders were established—with more specific requirements about company plans and equipment for prevention of pollution and blowouts. It also issued new Orders 8 and 9 on the installation and operations of platforms and pipelines. These were the first rules in which the department claimed authority to prohibit leasing in areas of the continental shelf where environmental risks were too high.30

¶The industry protested the new outer continental shelf regulations, but calamities in the Gulf undermined its case. In February 1970, Chevron's Platform C in Main Pass Block 41 blew out and caught fire. The spill forced a postponement of a federal lease sale, damaged

wildlife, and drew a $31.5 million suit against the company by Louisiana oyster fishermen and a $70 million suit from shrimp fishermen. Chevron was also fined $1 million for failing to maintain storm chokes and other required safety devices—the first prosecution under the 1953 Outer Continental Shelf Lands Act. The Justice Department also obtained judgments against other major oil and gas companies for similar violations. Then, in December, Shell suffered a major blowout on its Platform B in the Bay Marchand area, killing four men and seriously burning and injuring 37 others. Investigators attributed the accident to human error resulting from several simultaneous operations being performed without clear directions about responsibility. It took 136 days to bring 11 wild wells under control, at a cost of $30 million. The failure or leaking of subsurface-controlled storm chokes contributed to the size of the conflagration.31

In the wake of these disasters, the government further strengthened its regulatory program. The Interior Department again revised and expanded outer continental shelf orders to mandate new requirements: surface-controlled storm chokes; the testing of safety devices prior to and in use; more careful control of drilling and casing operations; prior approval of plans and equipment for exploration and development drilling; and updated practices and procedures for installing and operating platforms. To enforce the new regulations, the U.S. Geological Survey tripled its force of inspectors and engineers, ceased using industry-furnished transportation for inspections, and introduced a more systematic < inspection program based on newly developed criteria.32

In response, the Offshore Operators Committee and the industry's Offshore Safety and Anti-Pollution Equipment Committee worked closely with the U.S. Geological Survey both in advising changes in the outer continental shelf orders and in promptly drafting a new set of American Petroleum Institute (API) "recommended practice" guidance documents for the selection, installation, and testing of safety devices, as well as for platform design. The major offshore operators revamped personnel training for offshore operations, and they formed an organization called Clean Gulf Associates to upgrade oil-spill handling capabilities.33 Certifying agencies issued new standards and guidelines for mobile drilling.34 In addition, the industry's annual Offshore Technology Conference, first held in 1969, became an important forum for publishing and sharing technical information that led to safer designs and operations.35

The industry's safety record in the Gulf improved significantly after the new regulations and practices were introduced: the reported incidence and rate of fatalities and injuries decreased, as did the rate of fires and explosions.36 During the 1970s and 1980s, the frequency of blowouts did not decline significantly, but there was a sharp drop in the number of catastrophic blowouts, and fewer casualties and fatalities were associated with them.37

Design and equipment problems were steadily being solved. But reducing accidents caused by human error, poor safety management, or simultaneous operations continued to be a vexing challenge.

¶Constrained Expansion

¶As new regulations brought more caution to offshore oil development, countervailing forces emerged to speed it up. Domestic oil supply could not keep up with demand. In the postwar period, Americans' consumption of petroleum—largely for operating automobiles—climbed dramatically, rising steadily from 243 gallons of motor gasoline per capita in 1950 to 463 gallons per capita in 1979.38

¶U.S. oil production peaked, however, in 1970. Along with the OPEC oil embargo of 1973 and consequent skyrocketing price of oil products, this event spurred the quest to develop new offshore reserves. With crude oil prices tripling to $10 per barrel, oil companies could justify more expensive offshore drilling and development. Under the mandate of "Project Independence," the Nixon Administration announced a dramatic increase in the pace of leasing in the Gulf and a resumption of sales off the Atlantic, Pacific, and Alaskan coasts. At the March 1974 federal lease sale of offshore Louisiana acreage, the industry spent a record $2.17 billion in cash bonuses for leases covering 522,000 acres, including a few tracts ranging beyond 1,000-foot depths.39

¶The First Deepwater Play In June 1975, Shell made a monumental discovery on one of those new leases. Shell geophysicists had employed an innovative seismic technique called "bright spot" to lead drillers to an attractive prospect, code-named Cognac, in 1,000 feet of water in the Mississippi Canyon, not far from the mouth of the great river. The drilling uncovered an estimated 100-million-barrel reserve.40 Cognac pioneered other discoveries in what would come to be known as the "Flex Trend," an area in the Gulf that reaches just beyond the edge of the continental shelf, where there is a flex in the seafloor. The Flex Trend would be the world's first true oil play in 1,000-foot water depths, the modern definition of "deepwater."41

¶When Shell purchased its leases, it did not yet have a design concept for deepwater production. Barges were not big enough to launch a 1,025-foot steel jacket in one piece. Therefore, adapting Exxon's precedent—the company installed its Hondo jacket in 850 feet of water in the Santa Barbara channel in 1976—Shell chose to build the Cognac structure in three pieces and assemble them vertically in place. The complex, nerve-wracking installation inflated total development costs to nearly $800 million. But Cognac was both a technical and commercial success. It won the American Society of Civil Engineers 1980 award for "Outstanding Civil Engineering Achievement," the first ever received by an oil company. Production commenced in 1979, just as the supply shock caused by the Iranian Revolution drove the price of oil to nearly $40 per barrel.42

¶Along with Hondo and major developments in the North Sea pioneered by Phillips, Conoco, and BP, Cognac paved the way for truly enormous offshore engineering-construction projects. In 1976, Brown & Root and J. Ray McDermott opened giant new construction yards at Harbor Island, near Corpus Christi Bay, to accommodate the assembly and load-out of deepwater structures. In these yards, they built jackets lighter and cheaper

than Cognac and launched them in single pieces. In the late 1970s, Brown & Root built a 700-foot structure for Chevron's Garden Banks field, and a 650-foot jacket for Atlantic Richfield. In 1980–1981, McDermott built two platforms for Union Oil in the 1,000-foot waters of the East Breaks area,¹⁰⁰¹⁰⁰ Ibid., 37–38. Tetrahedron, Inc., Reliability of Blowout Preventers Tested Under Fourteen and Seven Days Time Interval: Study Report, Submitted to Minerals Management Service, Department of the Interior, MMS Technology Assessment & Research Project 253, "Blowout Preventer Study" (December 20, 1996), http://www.boemre.gov/tarprojects/253/ AA.PDF.; Blowout Preventer (BOP) Testing Requirements for Drilling and Completion Operations, 63 Fed. Reg. 29,604 (June 1, 1998). Internal BP document (BP-HZN-MBI 21415). "Shell 'Ignored Accident Warning.'"Show full note miles south of Galveston. During 1979–1983, Brown & Root built and installed a novel "guyed tower" for Exxon in 1,000 feet of water just southwest of Cognac.43

Even as rising oil prices and declining onshore production in the late 1970s spurred them on, Gulf oil operators encountered economic and geological constraints. Bonus bids soared beyond the estimated value of the oil that might be discovered and produced: the September 1980 sale in New Orleans, for example, brought in $2.8 billion in cash bonuses, shattering all previous records. During the 1970s, the bonus paid per barrel of oil equivalent discovered by the largest producing companies increased four- to five-fold, undermining the economics of deepwater.44 Furthermore, initial production rates from some of the early producing wells in the Flex Trend proved disappointing. Many industry exploration managers came to believe that after 25 years of development, only lean prospects remained in the Gulf. The best hope for increasing national reserves, they concluded, was from other parts of the U.S. outer continental shelf.45

¶Beyond the Shelf

Rising lease bonuses still did not deter major companies (such as Chevron, Exxon, Mobil, and Amoco), along with some of the larger independents (such as Pennzoil, Union, and Tenneco), from drilling and developing fields in the deepwater Flex Trend. But discoveries could not offset overall production declines in the Gulf. Oil production on the shelf had peaked at just above 1 million barrels per day in 1972; by 1978, it had fallen below 800,000 barrels per day. Because discoveries in the Flex Trend play were relatively small, with fairly low flow rates, most Gulf oil and gas still came from shallow water, despite declining overall production there. In 1970, the average production-weighted depth of oil extracted from the Gulf was just 100 feet, and by 1980 it was still less than 200 feet.46 Many managers had concluded that there would never be economic developments more than 60 miles from shore. Other experts became convinced that significant oil-bearing sands would never be found beyond the continental shelf. "But what conventional wisdom really tells you," as one Shell geophysicist explained, "is that you just don't know what you don't know."47

At just that time, some scientists from industry and academia had begun to piece together a regional picture of the geology deep underneath the Gulf by combining information from cores with a regional seismic survey shot out into deepwater. This picture showed that massive salt pillars, or diapirs, had squeezed up from the mother layer of salt deposited beginning 165 million years ago, when the Gulf of Mexico was slowly forming. As the diapirs pinched up, sandstone overlaying the salt slowly subsided, forming cup-shaped "mini-basins" featuring different kinds of configurations for trapping oil. These sandstone formations were named "turbidites" (they had been deposited when ancient underwater

¶rivers, called turbidity currents, channeled huge volumes of sediment onto the continental margin). The structural anomalies in these mini-basins looked similar to productive features on the shelf, but the spotty seismic coverage allowed for only speculative knowledge of their potential, at best. Shell, always the leader in Gulf frontier exploration, had drilled a number of wells in similar rocks along the margin of the continental shelf. Turbidites in deepwater were potentially much larger, less faulted, and might have prolific flow rates. At least in theory, they would require fewer wells, making them more attractive as economically exploitable reservoirs of oil.48

¶During 1978–1980, hoping to test its theories about the regional geology, Shell nominated deepwater tracts for auction. But no other companies seconded its nominations, so the government never selected the tracts for sales.49 Then, in 1982, the Interior Department announced a new system of area-wide offshore leasing. This policy put into play entire planning areas (e.g., the central Gulf of Mexico) up to 50 million acres, rather than rationing tracts through a tedious nomination and selection process. Companies could bid on any tract they wanted in a lease sale for a given planning area, thus giving them access to far more extensive offshore acreage at significantly less cost.50

¶Strong political opposition to area-wide leasing by some coastal states and environmental organizations stymied its effective use in other parts of the nation (see Chapter 3), but not in the Gulf, where oil companies had long operated. Established infrastructure and abundant geological information there could be put to more flexible use under a more open system. Oil companies responded to area-wide leasing by bidding aggressively for attractive blocks on the continental shelf, while making a number of speculative bids on acreage ranging into 3,000-foot depths beyond the edge of the shelf. The May 25, 1983 sale harvested a record $3.47 billion in high bonus bids. All told, in seven lease sales held from 1983 to 1985, the Interior Department, through the newly formed Minerals Management Service (see Chapter 3), leased 2,653 tracts, more than had been leased in all the federal sales since 1962 combined. About 600 of these tracts lay in deepwater beyond 1,000 feet.51

¶In the next central Gulf area-wide sale, in April 1984, many different operators jumped in to compete for deepwater tracts. This prompted Shell to move quickly in deploying the Shell America, a $45 million custom-designed, state-of-the-art seismic vessel that provided company geophysicists with high-quality, proprietary seismic data. Armed with these data and other intelligence gained from drilling its 1983 leases, Shell dominated the May 1985 sale, winning 86 of 108 tracts on which it bid, in water depths ranging to 6,000 feet. For

Shell, pushing deeper was an imperative for its operations in the United States, as onshore reserves continued to decline. "Exploration has been called a poker game," explained one Shell official. "But there's more to it than that. In this game, we don't have chips or coins or dollar bills that can change hands over and over again. We're dealing with a declining resource base, and every barrel we find is never going to be found again."53

¶The Era of Uncertainty

The long cycles of oil exploration and development do not always align well with the shorter cycles of the economy. Just as Shell bet heavily on deepwater, the severe recession in 1981 further depressed falling oil demand. For the first time in 34 years, U.S. oil consumption hit a plateau and began declining.54 The now "forgotten victory" of energy conservation and efficiency measures passed in the mid-1970s, in response to historically high oil prices, reversed the long trend of an increasingly petroleum-intense U.S. economy. During 1985–1986, oil prices collapsed to $10 per barrel, as international producers saturated the global market with crude.55

Expensive Gulf development projects were canceled or shelved. Construction of mobile drilling vessels and other kinds of offshore-servicing equipment fell sharply. Unemployed oilfield workers transitioned into new trades, or migrated from southern Louisiana in search of better opportunities. This human and capital flight marked the beginning of what one scholar called "the inevitable disassembly of the offshore system and its onshore support network for the Gulf of Mexico."56

The offshore projects that went forward faced intimidating challenges. Shell drilled some dry holes costing more than $10 million apiece. Development stretched the limits of technological and financial resources. To produce oil from the Bullwinkle field, the company installed in 1988 a $500 million fixed platform,¹⁶²¹⁶² Testimony of Steve Bertone, 48. There is a dispute as to whether BP personnel called back to shore that evening to discuss the data observed during the negative-pressure test. The Commission staff has to date seen no direct evidence of such a call. The staff 's inves- tigation is ongoing. Testimony of James Ellis, Institute of Nuclear Power Operations, Hearing before the National Commission, August 25, 2010.Show full note stories high—taller than Chicago's Sears Tower (now the Willis Tower), the tallest building in the world at the time. The Bullwinkle platform was the largest and last conventional jacket of its kind. The scale and costs of constructing anything bigger were simply prohibitive.57

Moving deeper would require alternative production methods: subsea wells, tension-leg platforms, or floating systems. Operators had put subsea wells to use in the North Sea, but they were still extremely expensive. The tension-leg platform was an innovative concept consisting of a production facility situated on a floating hull held in place by long tendons that kept the hull from bobbing like a cork but allowed some degree of side-to-side motion. In 1984, Conoco installed the first full-scale design of this type in the North Sea, in 485 feet of water, and in 1989 the company placed its Jolliet mini-tension-leg platform in 1,760 feet of water in the Gulf.58 But tension-leg platforms would have to be scaled up for major projects in deepwater. In 1987–1988, Placid Oil developed a field in 1,500 feet of water with a floating production facility converted from a semisubmersible drilling vessel. But Placid soon abandoned the development, sold the semisubmersible, and sought bankruptcy protection.59

¶Deep Sea Monsters

¶DER SPIEGEL 19/2010

¶The deepwater costs were matched by the safety and environmental risks. In 1985, an Office of Technology Assessment study of Arctic and deepwater oil drilling highlighted the "special safety risks" of "harsh environments and remote locations." It identified "a need for new approaches to preventing work-related injuries and fatalities in coping with new hazards in the hostile Arctic and deepwater frontiers." It also presciently warned of the glaring deficiencies in safety oversight offshore, observing that "there is no regulatory requirement for the submission of integrated safety plans which address technical, managerial, and other aspects of offshore safety operations."60

¶Setbacks in the Arctic As the study indicated, deepwater was not the only frontier that captured the industry's interest. In the 1980s, companies also had their sights set on the Arctic region, then thought to have the highest resource potential in the United States. Since the 1960s, major firms had produced oil from Alaska's Kenai Peninsula and Cook Inlet. In 1977, the massive onshore Prudhoe Bay field on the North Slope started pumping oil through the Trans- Alaska Pipeline. Many explorers expected to find the next great oil frontier to the north of Prudhoe Bay, in the Bering, Beaufort, and Chukchi Seas. Although the industry lost a contentious struggle to gain access to the Bering Sea's Bristol Bay, home to the world's largest commercial salmon fishery, they did win the right to lease and drill in the Beaufort and Chukchi Seas.61

Everywhere operators drilled offshore Alaska, however, they came up empty. Either they found no source rocks or the deposits they did find were not large enough at that time to turn a profit in the Arctic's forbidding environment. After a costly dry hole at a prospect called Mukluk in the Beaufort Sea and some futile efforts to explore in the Chukchi Sea, the industry temporarily lost its craving for the Arctic. The public-relations fallout from the Exxon Valdez oil spill in 1989, which resulted in congressional and presidential moratoriums on leasing in Bristol Bay, contributed to the industry's suspended interest in offshore Alaska.62

Renewed Focus on the Gulf of Mexico The mid-1980s collapse in oil prices also ruined many companies' appetite for further leasing in the deepwater Gulf of Mexico. But Shell and others chose to take a longer-term view—a decision reinforced by the failures in Alaska. Additional reinforcement came in 1987, when the Minerals Management Service reduced the minimum bid for deepwater tracts from $900,000 to $150,000—enabling companies to lock up entire basins for 10 years for only a couple million dollars.63 During the next five years, despite flat oil and gas prices, the industry acquired 1,500 tracts in deepwater.64

Shell's December 1989 announcement of a major discovery at a prospect called Auger, located in the Garden Banks area 136 miles off the Louisiana coast, spurred further interest. Two years earlier, Global Marine's new, giant semisubmersible, the Zane Barnes, struck oil for Shell after drilling through 2,860 feet of water and another 16,500 feet beneath the seafloor. Shell kept the discovery quiet as it delineated the extent of the field, <

which turned out to contain an estimated 220 million barrels of oil equivalent, the company's third-largest offshore discovery in the Gulf. Underpinning Shell's decision to go forward with Auger was the discovery of relatively high flow rates from the turbidite sands at Bullwinkle, where engineers found they could open the wells to 3,500 barrels per day (three times the rate considered good for a well on shallower parts of the Gulf continental shelf). If Auger had similar flow rates, the field could be profitably developed, even in water more than twice as deep as Bullwinkle's. Few people knew that Auger was only one of a number of Shell deepwater discoveries.65

As the company formulated an ambitious strategy to launch a series of major platforms, a gloomy economic outlook tempered Shell's euphoria over the Auger discovery and production breakthrough at Bullwinkle. The projected cost of developing Auger exceeded $1 billion. In appraising the next prospect, code-named Mars, Shell's exploration managers looked for ways to save money and offload some of the financial risk; accordingly, in 1988, they brought in British Petroleum (BP) as a partner with a 28.5 percent interest in the project.66

At the time, Mars seemed like a risky endeavor, with low probability for a major discovery. Furthermore, BP posed little threat. The company had been kicked out of Iran and Nigeria in 1979 and was struggling with a bloated management structure, poorly performing global assets, and uninspired leadership. Shell viewed BP as merely a banker.67

¶All that changed in 1989, when Sonat's Discoverer Seven Seas drilled into Mars. The field, located due south of the mouth of the Mississippi, lay in nearly 3,000 feet of water. The discovery well encountered multiple oil- and gas-bearing layers stacked on top of each other over several hundred meters. Mars was more than twice the size of Auger—the largest field discovered in the Gulf in 25 years. For Shell, Mars promised a big payoff for large bets on deepwater leases. For the industry, Mars confirmed the Mini-Basin trend in the Gulf as a bona fide play. For BP, Mars allowed the company's managers, engineers, and scientists to go to school on Shell's deepwater technology. Perhaps just as importantly, according to BP's chief in the United States, "Mars saved BP from bankruptcy."68

¶During the next several years, major oil companies—and even more significantly, contractors in the offshore service industry—propelled the evolution of technology in innovative new directions. The 1970s revolution in digital, three-dimensional (3-D) seismic imaging, pioneered by Geophysical Services Inc. (GSI), and the 1980s move to computer workstations, which enabled faster processing of the data generated in such surveys, combined to enhance dramatically the industry's accuracy in locating wells for field development—a critical factor when drilling a single well in deepwater could cost as much as $50 million. Beyond development drilling, 3-D seismic imaging boosted the success of wildcat discovery wells from less than 30 percent to 60 or 70 percent. As the major companies began to divest from older producing properties in favor of new deepwater prospects, smaller firms purchased older properties and redeveloped them with significant reserve additions using 3-D seismic imaging. In all, 3-D seismic imaging effectively tripled or even quadrupled the estimated amount of oil and gas reserves in the Gulf of Mexico.69

¶Drilling and subsea engineering advanced in similar fashion. Drilling contractors developed a new generation of vessels that took drilling from 5,000 to 10,000 feet of water, and from 20,000 to 30,000 feet of sub-seafloor depth. New directional drilling techniques, made possible by "downhole steerable motors," allowed engineers to maneuver a well from vertical to horizontal to achieve greater accuracy and more fully exploit reservoirs. Drillers also found ways to obtain information from deep inside wells, using "measurements- while-drilling" tools and sensors that provided position, temperature, pressure, and porosity data while the borehole was being drilled. Improvements in marine risers using lightweight composite materials and tensioners, along with new methods for preventing oil from cooling and clogging in deepwater pipelines, enabled the industry to make long tiebacks between subsea wells and production facilities. To support subsea installation and operations, the industry turned to sophisticated remote-operated vehicles mounted with TV cameras and umbilical tethers containing fiber-optic wire for the transmission of vivid images.70

¶Even as the major operators pushed into deepwater, they outsourced more of the research and development (R&D) of new technologies. The bust of the 1980s had driven the exploration and production companies to decrease internal R&D and adopt policies of buying expertise as needed, rather than cultivating it from within. R&D investments in oil exploration and production by the major companies declined from nearly $1.3 billion in 1982 to $600 million by 1996. According to a National Petroleum Council study, "This 'buy versus build' strategy resulted in a significant reduction in the number of

skilled people within operating companies who understood technology development and deployment."71 Service companies (Schlumberger, Halliburton, Baker Hughes, and Oceaneering) became the major source of technology development. An illustration of this trend was the Texaco-initiated "Deep Star" consortium, established in 1992, through which offshore operators funded contractor-generated R&D.72

Rapid technological advances in the early 1990s did not immediately translate into more economically feasible practices. Cost overruns, delays, and strained relationships with contractors plagued the fabrication and installation of Shell's giant tension-leg platform for Auger, the industry's bellwether deepwater project. Further, Shell discovered that crude oil from the Auger field was sour (containing sulfur, which had to be separated out at the refinery) and thus had to be discounted. The company's only salvation on the project depended on Auger's wells flowing at a higher rate than Bullwinkle's.73

Auger Pays Off Fortunately for Shell and the offshore industry, the wells did not disappoint. In the spring of 1994, Shell began to bring in wells at Auger that flowed at more than 10,000 barrels per day. Even with oil prices at $20 per barrel or less, deepwater now promised handsome profits. The Auger wells confirmed the reservoir model for turbidites in deepwater and even exceeded Shell's most optimistic estimates. Engineers designed Auger to handle 42,000 barrels of oil (and 100 million cubic feet of gas) per day from 24 wells, but by July the first three wells were already producing 30,000 barrels per day. "Debottlenecking" efforts eventually raised Auger's capacity to 105,000 barrels of oil and 420 million cubic feet of gas per day by the late 1990s.74

Auger's prodigious output also made subsea completions (with the wellhead located on the ocean floor rather than on a surface production platform) economic in the Gulf, as they had been in the North Sea. With tension-leg platforms like Auger, subsea completions became important as a component of an early production system or as a remote subsea development. Large fields or clusters of smaller fields, which otherwise would not justify the expense of multiple or larger platforms, could thus be profitably developed.75

Auger's many blessings came at a cost to Shell and the environment. Expanding production at Auger was extremely challenging. At the start of production in April 1994, Shell continuously flared or vented between one and six million cubic feet of natural gas per day, without the required federal permission. The flaring and venting continued for more than four years until the Minerals Management Service announced it had discovered this violation as well as Shell's failure to record and report the releases. In a 2003 civil settlement, Shell agreed to pay $49 million, an amount equivalent to the value of about two weeks of production from Auger. If the company was chastened after having to admit to these serious violations, Shell management also must have been tempted to look at this charge as an incidental cost of doing business in the deepwater Gulf.⁷⁶⁷⁶ Ibid., 283. Oil and Gas and Sulphur Operations in the Outer Continental Shelf, 56 Fed. Reg. 30,400 (July 2, 1991). Testimony of Daun Winslow, Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 219;