IN THE UNITED STATES COURT OF APPEALS FOR … B. OCSLA Prohibits the Agency from Creating its Own Undefined Approval Process for Exploration Plans. 46 IV. BOEM’S APPROVAL OF SHELL’S

Nos. 11-72891 and 11-72943

IN THE UNITED STATES COURT OF APPEALS FOR THE NINTH CIRCUIT

NATIVE VILLAGE OF POINT HOPE; ALASKA WILDERNESS LEAGUE; CENTER FOR BIOLOGICAL DIVERSITY; DEFENDERS OF WILDLIFE;

GREENPEACE, INC.; NATURAL RESOURCES DEFENSE COUNCIL; NATIONAL AUDUBON SOCIETY; NORTHERN ALASKA

ENVIRONMENTAL CENTER; OCEANA; PACIFIC ENVIRONMENT; RESISTING ENVIRONMENTAL DESTRUCTION ON INDIGENOUS LANDS

(REDOIL); SIERRA CLUB; and THE WILDERNESS SOCIETY;

INUPIAT COMMUNITY OF THE ARCTIC SLOPE,

Petitioners,

v.

KENNETH SALAZAR, Secretary of the Interior; and BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION AND ENFORCEMENT,

Respondents,

STATE OF ALASKA and SHELL OFFSHORE INC.,

Respondent-Intervenors.

_________________________________________________

Petition for Review of Department of Interior Decision _________________________________________________

PETITIONERS’ OPENING BRIEF

Holly A. Harris Eric P. Jorgensen EARTHJUSTICE 325 Fourth Street Juneau, AK 99801 T: 907-586-2751

Erik Grafe EARTHJUSTICE 441 W 5th Avenue, Suite 301 Anchorage, AK 99501 T: 907-792-7102

Christopher Winter Tanya Sanerib CRAG LAW CENTER 917 SW Oak Street, Suite 417 Portland, OR 97205 T: 503-525-2725

December 22, 2011

Case: 11-72891 12/22/2011 ID: 8010716 DktEntry: 24 Page: 1 of 95

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CORPORATE DISCLOSURE STATEMENT

Pursuant to Rule 26.1 of the Federal Rules of Appellate Procedure, Native

Village of Point Hope, Alaska Wilderness League, Center for Biological Diversity,

Defenders of Wildlife, Greenpeace, Inc., Natural Resources Defense Council,

National Audubon Society, Northern Alaska Environmental Center, Oceana,

Pacific Environment, Resisting Environmental Destruction On Indigenous Lands

(REDOIL), Sierra Club, The Wilderness Society, and the Inupiat Community of

the Arctic Slope hereby state that none of them has any parent companies,

subsidiaries, or affiliates that have issued shares to the public.


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TABLE OF CONTENTS

TABLE OF AUTHORITIES ..................................................................................... v

INTRODUCTION ..................................................................................................... 1

JURISDICTIONAL STATEMENT .......................................................................... 3

STATEMENT OF ISSUES ....................................................................................... 4

STATEMENT OF THE CASE .................................................................................. 5

STATEMENT OF FACTS ........................................................................................ 6

I. THE BEAUFORT SEA ................................................................................... 7

II. DEEPWATER HORIZON EXPLORATION DRILLING DISASTER ........ 10

III. THE NATIONAL OIL SPILL COMMISSION’S FINDINGS AND RECOMMENDATIONS ............................................................................... 11

A. Oil Spill Prevention and Response ...................................................... 11

B. Arctic Conclusions and Recommendations ........................................ 13

IV. SHELL’S NEW BEAUFORT EXPLORATION PLAN .............................. 14

A. Shell’s Multiple Drilling Proposals ..................................................... 14

B. Content of the Exploration Plan .......................................................... 16

C. The Exploration Plan Relied on an Unapproved Oil Spill Response Plan. ..................................................................................... 17

1. The Old Beaufort Spill Plan was approved before the Deepwater Horizon disaster. ..................................................... 17

2. The New Beaufort Spill Plan has not been approved. .............. 19

D. Shell Proposed a Well Capping and Containment System in the Arctic. .................................................................................................. 20

1. Shell historically rejected well capping in the Arctic. .............. 21


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2. Shell proposed well capping in the Arctic for the first time. ........................................................................................... 23

E. Shell Asserted it Can Drill a Relief Well Faster Than it Can Drill the Actual Exploration Wells. .................................................... 24

V. BOEM’S REVIEW PROCESS REGARDING THE EXPLORATION PLAN ............................................................................................................. 25

A. Lack of an Approved Oil Spill Response Plan. .................................. 25

B. Shell’s Reversal Regarding Well Capping and the Failure to Explain the Containment System. ....................................................... 25

C. Relief Well Drilling May Take Significantly Longer Than Shell’s Estimate. .................................................................................. 27

VI. BOEM CONDITIONALLY APPROVED THE EXPLORATION PLAN ............................................................................................................. 29

VII. PETITIONERS’ INTERESTS ...................................................................... 30

SUMMARY OF ARGUMENT ............................................................................... 33

ARGUMENT ........................................................................................................... 34

I. STANDARD OF REVIEW ........................................................................... 34

II. BOEM VIOLATED OCSLA WHEN IT APPROVED THE EXPLORATION PLAN DESPITE THE FACT SHELL IS RELYING ON AN UNAPPROVED SPILL PLAN. ....................................................... 35

III. BOEM ACTED ARBITRARILY WHEN IT APPROVED THE EXPLORATION PLAN BASED ON A NEW, NOT-YET-DESIGNED WELL CAPPING AND CONTAINMENT SYSTEM THAT SHELL PREVIOUSLY CONCLUDED WAS ILL-SUITED FOR THE ARCTIC. ...................................................................................... 40

A. It was Arbitrary for BOEM to Approve the Exploration Plan Given Shell Provided the Agency No Explanation of the New Well Capping and Containment System. ............................................ 41


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B. OCSLA Prohibits the Agency from Creating its Own Undefined Approval Process for Exploration Plans. .......................... 46

IV. BOEM’S APPROVAL OF SHELL’S ESTIMATE OF A MAXIMUM DURATION BLOWOUT FROM ITS ARCTIC DRILLING OPERATIONS WAS ARBITRARY AND CAPRICIOUS. ......................... 51

V. THE COURT SHOULD VACATE BOEM’S APPROVAL OF THE EXPLORATION PLAN AND REMAND IT TO THE AGENCY FOR FURTHER PROCEEDINGS. ............................................................... 57

CONCLUSION ........................................................................................................ 59


v

TABLE OF AUTHORITIES

CASES

Am. Bioscience, Inc. v. Thompson, 269 F.3d 1077 (D.C. Cir. 2001) .......................................................................... 58

Arrington v. Daniels, 516 F.3d 1106 (9th Cir. 2008) ............................................................................ 35

Bonnichsen v. United States, 367 F.3d 864 (9th Cir. 2004) .............................................................................. 34

Ctr. for Biological Diversity v. Nat’l Highway Traffic Safety Admin., 538 F.3d 1172 (9th Cir. 2008) ............................................................................ 46

Idaho Farm Bureau Fed’n v. Babbitt, 58 F.3d 1392 (9th Cir. 1995) ........................................................................ 58, 59

Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. 463 U.S. 29 (1983) ............................................................................................ 34

Native Ecosystems Council v. United States Forest Serv., 418 F.3d 953 (9th Cir. 2005) .............................................................................. 57

Native Vill. of Point Hope v. Salazar, 378 F. App’x. 747 (9th Cir. 2010) ...................................................................... 14

Native Vill. of Point Hope v. Salazar, 730 F. Supp. 2d 1009 (D. Alaska 2010) ............................................................. 15

Natural Res. Def. Council v. Houston, 146 F.3d 1118 (9th Cir. 1998) ............................................................................ 58

Southeast Alaska Conservation Council v. U.S. Army Corps of Eng’rs, 486 F.3d 638 (9th Cir. 2007) .............................................................................. 58

Tribal Village of Akutan v. Hodel,

869 F.2d 1185 (9th Cir. 1988) ............................................................................ 34

W. Oil and Gas Ass’n v. U.S. Envtl. Protection Agency, 633 F.2d 803 (9th Cir. 1980) .................................................................. 57, 58, 59


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STATUTES

5 U.S.C. § 706(2)(A) ................................................................................................ 34

33 U.S.C. § 1321(a) ................................................................................................. 36

33 U.S.C. § 1321(j) .................................................................................................. 36

43 U.S.C. § 1332(3) ........................................................................................... 56, 57

43 U.S.C. § 1340(c) ....................................................................................... 3, 47, 48

43 U.S.C. § 1347(b) ................................................................................................. 41

43 U.S.C. § 1349(c) ................................................................................. 4, 48, 49, 57

REGULATIONS

30 C.F.R. 250.219(a) ................................................................................................ 38

30 C.F.R. § 250.107(c) ............................................................................. 4, 41, 43, 46

30 C.F.R. § 250.107(d) ............................................................................................ 56

30 C.F.R. § 250.219 ................................................................................................. 16

30 C.F.R. § 250.451(h) ...................................................................................... 21, 52

30 C.F.R. § 254.3 ..................................................................................................... 37

30 C.F.R. § 550.105 ................................................................................................. 42

30 C.F.R. § 550.200 ........................................................................................... 41, 43

30 C.F.R. § 550.202 ................................................................................................. 48

30 C.F.R. §§ 550.211-.228 ....................................................................................... 48

30 C.F.R. § 550.213(d) .................................................................................. 4, 41, 46

30 C.F.R. § 550.213(g) ............................................................................ 5, 51, 52, 57

30 C.F.R. § 550.219 ........................................................................................... 16, 36


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30 C.F.R. § 550.219(a) ....................................................................... 4, 16, 37, 39, 40

30 C.F.R. § 550.233(b) ............................................................................................ 47

FEDERAL REGISTER NOTICES

Executive Order 12777, Implementation of Section 311 of the Federal Water Pollution Control Act of Ocotber 18, 1972, as amended, and the Oil Pollution Control Act of 1990,

56 Fed. Reg. 54,757 (Oct. 18, 1991) .................................................................. 36

Bureau of Safety and Environmental Enforcement and Bureau of Ocean Energy Management, Reorganization of Title 30,

76 Fed. Reg. 64,432 (Oct. 18, 2011) .............................................................. 1, 16


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INTRODUCTION

Oil companies are embarking on a new era of offshore drilling in more

remote and sensitive areas, like the Arctic Ocean, and in deeper water, as in the

Gulf of Mexico. Companies proposing this new type of drilling face some

different challenges in different regions, but the risks posed by untested technology

and uncoordinated response, unfortunately, have become apparent. The

Deepwater Horizon disaster in the Gulf of Mexico illustrates the tragic and

widespread consequences of the Bureau of Ocean Energy Management’s (BOEM)1

decision to approve high-risk drilling plans before requiring oil companies to

demonstrate they can safely and effectively prevent, contain, and respond to an oil

spill.

These petitions challenge BOEM’s decision to approve a plan for Shell

Offshore Inc. (Shell) to drill for oil in the Arctic Ocean’s Beaufort Sea. The Arctic

supports vibrant indigenous subsistence-based cultures and an extraordinary

diversity of species found nowhere else in the world. The Beaufort Sea is also

1 On October 1, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement, formerly the Minerals Management Service, divided into three organizations including, BOEM, which assumed responsibility for the review and approval of exploration drilling plans, and the new Bureau of Safety and Environmental Enforcement (BSEE), which assumed responsibility for the review and approval of oil spill response plans. See 76 Fed. Reg. 64,432 (Oct. 18, 2011); id., 64,438 (BOEM duties); id. 64,434 (BSEE duties). The approval at issue in this case predates the agency reorganization, but, for purposes of convenience, Petitioners refer to the newly formed bureaus throughout this brief.


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remote and often dangerous with 20-foot swells, floating pack ice, and hurricane-

force winds in the summer and early fall and covered by ice the rest of the year.

The challenges presented by the Arctic setting as well as the sensitive balance

between the ecosystem and the subsistence-based culture of the Inupiat people

present unique challenges related to energy development seen nowhere else in

America.

Despite these risks and challenges, BOEM approved Shell’s exploration plan

without critical information related to safety and spill response capabilities, in

violation of the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. §§ 1331–

1356a. Contrary to its own regulations, BOEM approved the exploration plan

despite the fact that Shell is relying on an unapproved oil spill response plan to

support its drilling activities. BOEM ignored, contrary to its regulations, Shell’s

failure to address two fundamental aspects of well control and containment. First,

BOEM acted arbitrarily when it approved the exploration plan, because Shell

failed to explain a new, not-yet-designed well capping and containment system

based on a technology Shell had for years rejected as infeasible and ineffectual for

its Arctic drilling operations. Second, BOEM approved Shell’s blowout scenario

without addressing the conflict between record evidence and Shell’s estimate of the

time required to drill a relief well to stop a blowout, and the resulting potential that

a blowout volume could exceed Shell’s own spill plan and that, for drilling late in


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October, Shell might be prevented from even completing a relief well and stopping

a blowout before winter sets in and the Arctic Ocean freezes.

In the aftermath of the Deepwater Horizon disaster, the consequences of the

government approving a drilling plan without ensuring in advance that the

company can safely and effectively prevent and respond to an oil spill could not be

more apparent. As the National Commission on the BP Deepwater Horizon Oil

Spill cautioned: “Whether we explore for and produce oil and gas” “in such

challenging environs as the Alaskan Arctic,” “and if so, under what conditions,

depends crucially on taking to heart the lessons we learn from the Deepwater

Horizon disaster and the energy policies we put in place.” ER 399. BOEM’s

approval of Shell’s exploration plan in this case is a troubling indication that the

agency has not learned those lessons.

JURISDICTIONAL STATEMENT

These are consolidated petitions for review pursuant to Fed. R. App. P. 15 of

the Secretary of Interior’s approval of an offshore exploratory oil drilling plan

under OCSLA, 43 U.S.C. § 1340(c). Challenges to exploration plans are subject to

judicial review in the court of appeals for the circuit in which the affected state is

located. Id. § 1349(c)(2). The Native Village of Point Hope, Alaska Wilderness

League, Center for Biological Diversity, Defenders of Wildlife, Greenpeace, Inc.,

Natural Resources Defense Council, National Audubon Society, Northern Alaska


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Environmental Center, Oceana, Pacific Environment, Resisting Environmental

Destruction On Indigenous Lands (REDOIL), Sierra Club, and The Wilderness

Society (collectively the Point Hope Petitioners) and the Inupiat Community of the

Arctic Slope (the Inupiat Tribe) (collectively the Petitioners) participated in the

process leading to the decision, are aggrieved by the decision, and filed their

petitions on September 29, 2011 and October 3, 2011, respectively, within 60 days

of the Secretary’s approval of Shell’s exploration plan on August 4, 2011. See 43

U.S.C. § 1349(c)(3); Dkt. 1-2 (No. 11-72891 (Point Hope Petition)); Dkt. 1-2 (No.

11-72943 (Inupiat Tribe Petition)).

STATEMENT OF ISSUES

1. Did BOEM violate OCSLA, 30 C.F.R. § 550.219(a), by approving

Shell’s exploration plan in the absence of a final oil spill response plan approved

pursuant to the Oil Pollution Act of 1990?

2. Did BOEM act arbitrarily and capriciously, under 30 C.F.R. §§

550.213(d) and 250.107(c), by approving Shell’s exploration plan without

requiring Shell to discuss or describe its new well capping and containment

system, which has not been designed, built, or tested, or explaining why the agency

accepted Shell’s assertion that the system will work given that the company

concluded for years that well capping would not be effective in its Arctic drilling

operations?


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3. Did BOEM act arbitrarily and capriciously, under 30 C.F.R. §

550.213(g), by approving Shell’s exploration plan without determining whether

Shell’s blowout scenario, which is unexplained and contrary to evidence in the

administrative record, understates the number of days needed to drill a relief well,

and, therefore, the maximum duration and the total volume of a blowout during

Shell’s drilling activities in the Arctic Ocean’s icy waters?

STATEMENT OF THE CASE

On September 29, 2011, the Point Hope Petitioners filed their petition (No.

11-72891). Dkt. 1-2. On October 7, 2011, Shell and the State of Alaska (the State)

filed motions to intervene. Dkt. Nos. 6; 8-1. Shell also requested assignment of

the Point Hope Petition to the panel that decided Native Village of Point Hope v.

Salazar, Nos. 09-73942, 09-73944, 10-70166, 10-70368. Dkt. No. 6.

On October 3, 2011, the Inupiat Tribe filed its petition (No. 11-72943). On

October 12, 2011, Shell and the State filed motions to intervene. Dkt. Nos. 5; 7-1.

Shell requested assignment of Inupiat Tribe Petition to the panel that decided

Native Village of Point Hope v. Salazar, Nos. 09-73942, 09-73944, 10-70166, 10-

70368. Dkt. No. 5.

On October 17, 2011, the Petitioners and the Federal Respondents filed a

joint motion to consolidate the two petitions, modify the briefing schedule, and

request expedited consideration to allow for a decision on the merits as soon as


6

possible, and prior to the planned commencement of offshore drilling activities on

July 1, 2012. Dkt. No. 13 (No. 11-72891); Dkt. No. 12 (No. 11-72943). Shell and

the State concurred in the motion for consolidation, modification of the briefing

schedule, and expedited consideration. Id.

On October 18, 2011, the panel of A. Kozinski, Chief Judge, C. Bea and S.

Ikuta, Circuit Judges, accepted assignment of the Inupiat Tribe Petition. Dkt. No.

17 (No. 11-72943). The panel also granted the motions to intervene filed by Shell

and the State in that case. Id.

On November 18, 2011, the Court granted the motion to consolidate the two

petitions. Dkt. No. 22 (No. 11-72891). The Court also granted the motions to

intervene filed by Shell and the State in the Point Hope Petition. Id. The Court

granted the joint motion for expedited briefing and argument. Id. The Court

calendared the petitions for oral argument the week of March 19, 2012. Id.

On November 22, 2011, the Court entered an amended order changing the

due date for the answering briefs. Dkt. No. 23.

STATEMENT OF FACTS

This case concerns Shell’s readiness to conduct exploratory oil drilling in the

Arctic Ocean’s Beaufort Sea. Shell proposes to drill two wells at its Sivulliq

prospect and two wells at its Torpedo prospect in the Beaufort Sea. ER 219-220.

Shell’s drilling season extends from July 10 through October 31 of each year. ER


7

219. Shell expects to begin drilling activities in 2012, and will continue in

subsequent summers until it completes the program. Id. Unlike its previous

proposals, Shell plans to conduct simultaneous exploration drilling activities in the

Chukchi Sea with another drilling fleet. See ER 328 (agency staff explaining

“Shell plans to drill in both Beaufort Sea and Chukchi Sea simultaneous [sic] in the

same year using two drilling vessels and separate support vessels and oil spill

response for each activity”).

I. THE BEAUFORT SEA

The Beaufort Sea provides important habitat for thousands of species of

animals, birds, and fish, including endangered and threatened species such as the

bowhead whale, the polar bear, and spectacled and Steller’s eider. See ER 17-26.

Alaska Native communities across the Arctic depend on this biological richness for

their subsistence use of animals such as bowhead whale, seal, fish, and birds. See,

e.g., ER 701-707; ER 709-713; ER 719-721; ER 27-29. As BOEM has explained,

“subsistence (and the relationship between people, land, water, and its resources) is

the expression of cultural identity, and production of subsistence foods is the

activity around which social organization and generational transmission of the

culture occurs.” ER 26.

The Beaufort Sea, however, is also a harsh and challenging environment. In

Barrow, Alaska, the northernmost community in the country, ER 433, there are


8

more than 320 days with temperatures below the freezing point each year. ER 420.

As BOEM acknowledges in its environmental assessment, the Beaufort Sea region

has hurricane-force storms and sea states that produce 20-foot waves during open

water periods. See ER 15-16 (“Frostbite can occur following less than five

minutes of exposure when the wind chill drops as low as minus 90 degrees

Fahrenheit (deg. F) during these storms.”); ER 563-564 (describing sea states in

the Beaufort Sea). Sea ice of varying thickness is present in the Beaufort Sea most

of the year; during approximately three months of the year it is predominantly ice-

free, but it still has floating ice. See generally ER 424-426. According to Shell:

In the vicinity of Shell’s drilling locations, the average duration of open water (defined as 1/10th or less pack ice) is 7.5 weeks, with the most consistent period of continuous open water beginning mid-August and ending with the first complete coverage of new ice in deep water in mid- to late October (based on a review of historical ice charts from 1997 to 2006).

ER 567; see also ER 516-518 (National / Naval Ice Center, Beaufort Sea, Ice

Analysis); ER 220 (providing latitude and longitude for Shell’s drill sites); ER 530

(Shell’s spill response contractor describing “freeze-up median dates October 1-

31”).

A large oil spill in the Beaufort Sea would have significant impacts on

people, mammals, fisheries, birdlife, and the marine ecosystems. See ER 628-670.

For the Alaska Native communities along the Arctic coast, an oil spill also could


9

have significant effects on their culture and way of life, which are heavily

dependent on the sea for subsistence hunting and fishing. See, e.g., ER 671-681;

ER 703-706; ER 712-716.

The Arctic’s sea ice, low visibility, high winds, rough seas, and cold

temperatures “complicate all aspects of a spill response, from stopping a well

blowout to predicting or tracking the movement of an oil spill trapped in sea ice[.]”

ER 475. Spill response technologies face operational limits based on the Arctic’s

wind speed, wave height, ice conditions, and visibility. See ER 115-122, 139-141;

ER 474-499. As a result of these factors, spill response operations can be slowed

or shut down. See ER 120-122; ER 475; ER 500-515 (describing gaps in Arctic oil

spill response).

In addition, there is limited infrastructure in the region. “There are no major

docks or port facilities in Barrow or anywhere on the U.S. Arctic coast[.]” ER 433.

The nearest major port is 1,300 nautical miles from Point Barrow. ER 432. The

nearest U.S. Coast Guard air station is roughly 1000 air miles away and no Coast

Guard vessels reside in the region. ER 112. The U.S. Coast Guard Commandant

Admiral Robert Papp, Jr., recently explained that, with regard to Coast Guard

infrastructure and oil spill response resources, “[t]here is nothing [in the Arctic] to

operate from at present and we’re really starting from ground zero.” ER 277.


10

II. DEEPWATER HORIZON EXPLORATION DRILLING DISASTER

On April 20, 2010, BP’s Deepwater Horizon offshore drilling rig exploded

and caught fire, causing the deaths of 11 people and resulting in a blowout that

spilled roughly 4.9 million gallons of oil into the Gulf of Mexico. ER 338; ER

383. Two days after the explosion and fire, the Deepwater Horizon sank to the

bottom of the ocean. ER 349.

The blowout continued uncontrolled in part because the blowout preventer,

or BOP, did not function properly. In a drilling emergency, the blowout preventer

“is designed to contain pressure within the wellbore and halt an uncontrolled flow

of hydrocarbons to the rig.” ER 352. The blowout preventer “is a stack of

enormous valves that rig crews use both as a drilling tool and as an emergency

safety device. Once it is put in place, everything needed in the well—drilling pipe,

bits, casing, and mud—passes through the BOP.” ER 350. The Deepwater

Horizon’s blowout preventer failed in numerous ways. ER 352-353.

BP, however, “had no available, tested technique to stop a deepwater

blowout other than the lengthy process of drilling a relief well.”2 ER 363. BP

initially tried to use the blowout preventer to stop the flow of oil, but the efforts

were unsuccessful. ER 365-366. As the oil continued to spill, BP designed and

2 A relief well is a second well drilled to depth to intersect the out-of-control well at its source and enable a drilling rig to pump in cement to stop the flow of oil. See ER 360; ER 107 (showing directional drilling for relief well).


11

deployed at least five different well control and containment techniques over the

following months to stop the flowing oil and capture the oil. ER 368-372, 373-

376, 378-383. In the words of one senior government official, BP “hoped for the

best, planned for the best, expected the best” during this process. ER 377. On

September 19, 2010, 152 days after the blowout, the first relief well was completed

and the leaking well was declared dead. ER 385.

III. THE NATIONAL OIL SPILL COMMISSION’S FINDINGS AND RECOMMENDATIONS

Following the Deepwater Horizon, President Barack Obama created the

National Commission on the BP Deepwater Horizon Oil Spill and Offshore

Drilling (the Commission). ER 338. The President charged this “independent,

nonpartisan entity” “to improve the country’s ability to respond to spills, and to

recommend reforms to make offshore energy production safer.” Id. The

Commission released its final report in January 2011. ER 335.

A. Oil Spill Prevention and Response

The Commission concluded that the Deepwater Horizon “blowout was not

the product of a series of aberrational decisions . . . . The missteps were rooted in

systemic failures by industry management (extending beyond BP to contractors

that serve many in the industry), and also by failures of government to provide

effective regulatory oversight of offshore drilling.” ER 354; see also ER 341


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(“Both government and industry failed to anticipate and prevent this catastrophe,

and failed again to be prepared to respond to it.”).

Of its numerous recommendations, the Commission paid specific attention

to the areas of oil spill prevention, containment, response, and planning. ER 393

(“Oil spill response planning and analysis across the government needs to be

overhauled in light of the lessons of the Deepwater Horizon blowout.”). The

Commission concluded: “A new process for reviewing spill response plans is

needed.” Id. The new process “should ensure that all critical information and spill

scenarios are included in the plans, including oil spill containment and control

methods to ensure that operators can deliver the capabilities indicated in their

response plans.” ER 394.

The Commission observed that the “most obvious, immediately

consequential, and plainly frustrating shortcoming of the oil spill response set in

motion by the events of April 20, 2010 was the simple inability—of BP, of the

federal government, or of any other potential intervener—to contain the flow of oil

from the damaged Macondo well.” ER 396. The Commission noted that neither

BOEM nor the U.S. Coast Guard had the expertise or resources to supervise the

well-containment efforts. Id. The Commission cautioned that future “plans should

demonstrate that an operator’s containment technology is immediately deployable

and effective.” ER 397.


13

In the wake of the Deepwater Horizon disaster, BOEM issued Notice to

Lessees No. 2010-N10 (NTL 2010-N10) requiring operators to demonstrate that

they have “access to and can deploy containment resources that would be adequate

to promptly respond to a blowout or other loss of well control.” ER 406; see also

ER 407 (detailing the types and quantities of required surface and subsea

containment equipment).3 The Commission advised that in enforcing NTL 2010-

N10, BOEM “must ensure that operators provide detailed descriptions of their

technology and demonstrate that it is deployable and effective.” ER 397.

B. Arctic Conclusions and Recommendations

During its investigation, the Commission focused heightened attention on

offshore drilling in the Arctic due to the unique risks associated with drilling in

such a remote area. See, e.g., ER 347-347a (“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.”) (internal quotation and

citation omitted); ER 387-388 (recommending changes for “frontier or high-risk

areas—such as the Arctic”).4

3 NTL 2010-N10 applies to “operators conducting operations using subsea blowout preventers (BOPs) or surface BOPs on floating facilities.” ER 406. Shell will be using a floating facility, either the Kulluk or the Discoverer, ER 223-224, and a subsea blowout preventer. ER 236, 231. 4 The Commission defined “frontier areas” as “areas of the [outer continental shelf] that either have never been leased, or have not been leased in many years. It includes the Arctic (Beaufort and Chukchi Seas)[.]” ER 391.


14

The Commission identified “the failure to plan effectively for a large-scale,

difficult-to-contain spill in the deepwater environment or potentially in the Arctic”

as one of the “three critical issues or gaps in the government’s existing response

capacity.” ER 393. “The remoteness and weather of the Arctic frontier create

special challenges in the event of an oil spill. Successful oil-spill response

methods from the Gulf of Mexico, or anywhere else, cannot simply be transferred

to the Arctic.” ER 404.

The Commission warned that Arctic drilling proposals “require the closest

scrutiny, given the potential energy resources and the physical and environmental

challenges of pursuing them safely.” ER 402. The Commission concluded that

“finding and producing . . . oil offshore Arctic Alaska requires the utmost care,

given the special challenges and risks associated with this frontier.” ER 403.

IV. SHELL’S NEW BEAUFORT EXPLORATION PLAN

A. Shell’s Multiple Drilling Proposals

In 2009, BOEM approved Shell’s exploration plan to drill two offshore

wells in the Beaufort Sea during a single season. ER 219. In May 2010, the Court

denied two petitions challenging the approval. Native Vill. of Point Hope v.

Salazar, 378 F. App’x. 747 (9th Cir. 2010). Shell, however, did not drill these

wells during the summer of 2010 because the Secretary of the Interior refused to

allow drilling until BOEM could evaluate the Deepwater Horizon disaster and take


15

steps to limit the potential for a similar failure in the Arctic. See ER 219 (BOEM

“suspended all exploration drilling activities in the Arctic following the Deepwater

Horizon incident.”).

In October 2010, Shell announced it would seek to drill a single well in the

Beaufort in 2011 (and forgo Chukchi drilling due to pending litigation). ER 519-

520; see also Native Vill. of Point Hope v. Salazar, 730 F. Supp. 2d 1009

(D. Alaska 2010). Shell submitted an “update” to its approved Beaufort

exploration plan, seeking permission to drill at the Sivulliq N drill site. ER 219.

By February 2011, as the post-Deepwater Horizon review and permitting processes

were still underway, Shell decided it would not drill in 2011. See id.; ER 328; ER

225 (noting that the Environmental Appeals Board remanded Shell’s air permit).

In May 2011, Shell submitted a further revised exploration plan to drill in

the Beaufort Sea. ER 302. At the same time, Shell submitted a new oil spill

response plan (hereinafter the New Beaufort Spill Plan) to support its proposed


16

exploration drilling.5 ER 228, 234; ER 546-549.6 In June 2011, Shell provided

BOEM a second revised exploration plan for the Beaufort Sea (hereinafter the

Exploration Plan).7 ER 212.

B. Content of the Exploration Plan

Among other changes, the Exploration Plan proposed using a different

drilling unit,8 made the proposal a multi-year drilling plan, and increased the

numbers of wells Shell plans to drill to a total of four. ER 219. In the revised

5 OCSLA requires operators seeking to conduct exploration drilling activities under a regional oil spill response plan to have that plan approved prior to submitting their drilling proposal. See 30 C.F.R. § 550.219(a). On October 1, 2011, 30 C.F.R. § 250.219 moved to 30 C.F.R. § 550.219 to be included under BOEM’s authority, as part of the agency reorganization. See 76 Fed. Reg. at 64,439. Petitioners use the new regulatory citations in this brief, but note that some record documents cite the prior versions. 6 Despite the title page and the signature page, ER 546 is the New Beaufort Spill Plan. See ER 549 (It is a redlined version of the Old Beaufort Spill Plan showing many, but not all, of the changes between the two spill plans.). 7 The Exploration Plan made various technical changes to the version submitted in May. See, e.g., ER 695. 8 Shell reserved the opportunity to use its original drillship, the Discoverer. ER 219, 223. If Shell uses the Discoverer, then it plans to keep the Kulluk in Dutch Harbor, Alaska, to serve as an alternative drilling rig in the event it becomes necessary to drill an emergency relief well. ER 229.


17

proposal, Shell sought to use the conical drilling unit, the Kulluk, id., which was

built in 1983, ER 313, and has not drilled a well in 18 years.9 Id.

BOEM determined that the plan “revisions [were] likely to result in a

significant change to the impacts previously identified” and, as a result, BOEM

“concluded that the revised [exploration plan] [wa]s appropriately subject to the

full procedures pursuant to 30 [C.F.R. §§] 250.231-235.” ER 310; see also ER 220

(Shell acknowledging the same).

C. The Exploration Plan Relied on an Unapproved Oil Spill Response Plan.

The Exploration Plan relies upon the New Beaufort Spill Plan to support

Shell’s proposed exploration drilling. ER 228, 234; ER 546-573. The New

Beaufort Spill Plan revises a spill plan that was developed and approved prior to

the Deepwater Horizon oil spill. ER 226 (Table 2.a-1).

1. The Old Beaufort Spill Plan was approved before the Deepwater Horizon disaster.

In March 2010, BOEM approved Shell’s Beaufort Sea Regional Exploration

Oil Discharge Prevention and Contingency Plan (January 2010) (the Old Beaufort

9 Earlier this year, Shell provided a tour of the Kulluk to various government officials and representatives. ER 312-327. The tour revealed “substantial surface corrosion on the exterior of the Kulluk,” “exterior corrosion on the vessel hull,” and “exterior corrosion on piping, railing, and other rig equipment.” ER 312; see also ER 313 (“The March 1, 2011 tour showed that the Kulluk was not in drill-ready condition and most of the upgrades announced to the press had not been completed.”).


18

Spill Plan). ER 535a; see also ER 531. Approximately one month after the

approval, the Deepwater Horizon blowout occurred. ER 345.

In May 2010, in response to direction from BOEM, Shell provided the

agency “information about additional safety procedures that Shell plan[ned] to

undertake [in the Arctic] in light of [the Deepwater Horizon disaster].” ER 574.

Shell committed to several new safety and oil spill response measures including

changes to Shell’s well control, blowout preventers, remote operating vehicles and

divers, and containment and response equipment and procedures. ER 577-578.

Shell committed to having a “pre-fabricated coffer dam pre-staged in Alaska”10 to

“locate the dome for immediate deployment.” ER 578. Shell stated it would

incorporate these new measures into its plans. ER 577.

In June 2010, BOEM “revised and increased the requirements for [worst

case discharge] scenario calculations through [Notice to Lessees] No. 2010-N06

[(NTL 2010-N06)].” ER 234 (Shell describing the changes). BOEM explained

that “[d]ue to the explosion and sinking of the Deepwater Horizon, the resulting

deaths of 11 people, and changing conditions caused by the blowout of the BP

Macondo prospect well that was being drilled by the Deepwater Horizon, the

10 A coffer dam (also spelled cofferdam) is a dome designed to cover a spilling well; it has a pipe at the top of the dome to channel oil and gas to the surface. ER 367.


19

BOEM requires additional information concerning [oil companies’] planned

activities.” ER 522.

In December 2010, BOEM solicited public comments on the previously

approved Old Beaufort Spill Plan.11 Petitioners provided extensive comments

outlining the inadequacies of the Old Beaufort Spill Plan. See, e.g., ER 115, 121,

124-127, 131, 136, 139. Petitioners specifically criticized Shell’s failure to explain

its new subsea containment system. ER 136 (“In December 2010, groups noted

that Shell is proposing a well capping and containment system that is not

described, built, tested or verified as effective in Arctic conditions.”).

In January 2011, Shell stated publicly that it had “just completed its

selection of a design concept for the system and [] plann[ed] to have fabrication

completed by May 31, 2011, for crew training in June and field deployment in July

[2011] . . . .” ER 330.

In March 2011, Shell admitted its subsea capping and containment system

had not been built. ER 318. Shell explained that it was still being designed. Id.

2. The New Beaufort Spill Plan has not been approved.

In May 2011, Shell submitted the New Beaufort Spill Plan together with the

Exploration Plan. ER 228, 234; ER 546. The New Beaufort Spill Plan “reflects

11 The agency accepted comments “on [the Old Beaufort Spill Plan] and associated information on [the] blowout scenario and containment required under NTL 2010-06.” See http://alaska.boemre.gov/ref/ProjectHistory/Shell_CamdenBF/BF.htm.


20

the inclusion of using either the Kulluk or the Discoverer as the drilling vessel and

updates the [worst case discharge] information and the oil spill response based on

the new [worst case discharge].” ER 234. It attempts to respond to the

government’s heightened scrutiny following the Deepwater Horizon disaster,

including NTL No. 2010-N06. See ER 549; ER 219. The New Beaufort Spill Plan

contemplates a worst case discharge spill of 480,000 barrels (bbl). ER 550

(showing that the Old Beaufort Spill Plan contemplated a worst case discharge

spill of 165,000 bbl). The New Beaufort Spill Plan also incorporates Shell’s new

proposed subsurface control options, including a well capping and containment

system. ER 552-553.

In August 2011, in its environmental assessment for the Exploration Plan,

the agency explained, “[t]he [New Beaufort Spill Plan] is currently being reviewed

given th[e] new information [Shell provided after the Deepwater Horizon] and

appropriate actions will be taken pending the evalutation [sic] of this new

information and how it impacts Shell’s capability to respond to an oil spill event.”

ER 14. To date, BSEE, the bureau now responsible for this review process, still

has not approved the New Beaufort Spill Plan.

D. Shell Proposed a Well Capping and Containment System in the Arctic.

In the Exploration Plan, following direction from BOEM after the

Deepwater Horizon, Shell proposed to use a new capping stack and containment


21

system. ER 237. The proposal reflects a change in Shell’s historical position

regarding the feasibility of such a system and, indeed, the system is still being

designed.

1. Shell historically rejected well capping in the Arctic.

In offshore drilling areas where the ocean floor is subject to extensive ice

gouging and ice keel scouring, companies are required to construct large pits in the

ocean floor, called mudline cellars, to protect the blowout preventer.12 ER 227,

230. Shell’s proposed drill sites are at water depths where the seafloor is subject to

extensive ice gouging and ice keel scouring, ER 230, and, as a result, Shell will

construct mudline cellars as part of its drilling activities. ER 275a (Shell

explaining that its mudline cellars are approximately 24 feet in diameter and 41

feet below the seafloor.); see also ER 221, 226; ER 61 (“relief well BOP would

need to be left in place and consequently exposed to ice gouging and ice keel

scouring”).

According to Shell, “[t]here are three methods of regaining well control once

an incident has escalated to a blowout scenario; implementation of dynamic

surface control measures, well capping, and relief well drilling.” ER 540; ER 602.

12 BOEM regulations require companies to dig a mudline cellar and install their blowout preventer stack in the hole when they are using a subsea blowout preventer system in an ice-scour area. See 30 C.F.R. § 250.451(h). The mudline cellar, also known as a glory hole, must be deep enough to ensure that the top of the blowout preventer stack is below the deepest probable depth that ice will scour the ocean floor. Id.


22

In its previous exploration plan, Shell identified surface control measures and relief

well drilling as the only viable means of achieving well control during its Arctic

exploration activities. ER 591-592 (not proposing well capping); see also ER 594

(Shell explaining in a public meeting: “There is no technology for a containment

sleeve of the type you’re suggesting that can do that without interfering with

[Shell’s] anchoring system. That’s one of the biggest problems.”)

Similarly, Shell explained in its previous oil spill response plans dating back

to 2007 that for Arctic drilling operations “[p]roven technology [for well capping]

is not available.” ER 605. Shell explained: “Well capping is not feasible for

offshore wells from moored vessels with [BOPs] sitting below the mud line in a

well cellar (glory hole)[.]” ER 602; see also ER 606 (According to Shell,

“techniques for performing well capping in mud line cellars constructed on the sea

floor from moored vessels have not been proven. Therefore, well capping would

not be an effective option[.]”); ER 544 (same); ER 604 (same). Last year, Shell

reiterated well capping “is not feasible” for its operations because Shell plans to

use moored vessels with the blowout preventer sitting below the mud line in a well

cellar. ER 540; see also ER 542-543 (“Equipment is not available for wells drilled

from moored vessels.”).


23

2. Shell proposed well capping in the Arctic for the first time.

In May 2011, for the first time in an exploration plan, Shell responded to the

new requirements imposed following the Deepwater Horizon blowout and

proposed to design, build, and use a well capping stack and containment system as

part of its Beaufort exploration activities. See ER 237. In the Exploration Plan,

Shell explained that “[c]ontainment capability in the unlikely event of a blowout in

Camden Bay is provided by a combination of a subsea capping stack . . . and

surface separation equipment on a containment vessel.” Id.

The Exploration Plan acknowledged that the system is still not built, and

stated only that it will have “the following priorities:”

1. Attaching a device or series of devices to the well to affect a seal capable of withstanding the maximum anticipated wellhead pressure (MAWP) and closing the assembly to completely seal the well against further flows (commonly called “capping and killing”);

2. Attaching a device or series of devices to the well and diverting flow to surface vessel(s) equipped for separation and disposal of hydrocarbons (commonly called “capping and diverting”).

ER 237. Shell asserted that it expects the new capping stack system to work in

“conditions found in the Arctic including ice and cold temperatures” and the

equipment “will also be designed for maximum reliability, ease of operation,

flexibility and robustness so it could be used for a variety of blowout situations.”


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Id. The Exploration Plan did not explain why Shell now expects this system to

work in Arctic conditions given its previous contrary conclusions. See id.

E. Shell Asserted it Can Drill a Relief Well Faster Than it Can Drill the Actual Exploration Wells.

In the Exploration Plan, Shell estimated that a well drilled at the Torpedo

prospect will require approximately 44 days, ER 246, and a well drilled at a

Sivulliq prospect will require approximately 34 days. ER 243. For emergency

relief well operations, Shell provided a shorter time frame to drill. Shell asserted it

can drill a relief well at its Torpedo prospect in 25 days, and drill a relief well at its

Sivulliq prospect in 20 days. ER 229; see also ER 274.

The Exploration Plan did not explain the company’s basis for the difference

in drill times, except to say Shell will not construct a mudline cellar for the relief

well. ER 273; see also ER 233 (mudline cellar construction only takes a “few

days”). The Exploration Plan, however, acknowledged that mudline cellars are

required for Beaufort Sea wells to protect wellhead equipment from ice. ER 240.

In the New Beaufort Spill Plan, Shell explains that relief well “[t]echnology

[in the Arctic] may be seasonally limited.” ER 573. According to the plan,

drilling a relief well in light of the Arctic’s seasonal limitations can take “60 to 180

days.” Id.


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V. BOEM’S REVIEW PROCESS REGARDING THE EXPLORATION PLAN

After submission of the Exploration Plan and the New Beaufort Spill Plan,

BOEM solicited public comments and conducted its review of the adequacy of the

Exploration Plan.

A. Lack of an Approved Oil Spill Response Plan.

In May 2011, public commenters explained that “BOEM[] should not deem

[the Exploration Plan] complete until it has reviewed and approved a revised spill

plan.” ER 294; see also 288-290. They explained that Shell’s Old Beaufort Spill

Plan was developed and approved prior to the Deepwater Horizon oil spill and did

not reflect the changes and additional safety and spill response measures required

after the disaster. Id.

In July 2011, Petitioners provided hundreds of pages of comments and

exhibits addressing various inadequacies in the New Beaufort Spill Plan. ER 110-

155; ER 183-88; ER 173-174; ER 156-172. Other stakeholders also provided

extensive comments. See, e.g., ER 30-105; ER 178-182.

B. Shell’s Reversal Regarding Well Capping and the Failure to Explain the Containment System.

BOEM received extensive comments questioning Shell’s readiness to rely

on its proposed well capping and containment system in the Beaufort Sea.

Petitioners and others explained that the system must be designed and built to work

in Arctic conditions. ER 136-138; ER 294-295; ER 194. The North Slope


26

Borough, for example, raised numerous concerns including hydrate formation,13

late season ice conditions, the ability to keep a vessel stable over the blowout

(known as station-keeping), reduced buoyancy, and the availability of trained and

qualified personnel to operate the new system. ER 63-68. The North Slope

Borough noted that Shell failed to provide the agency any engineering drawings or

“technical specifications for the arctic well containment system, including a

description of the system components, capabilities, ratings and throughput capacity

and a comparison to the worst case blowout conditions that may be encountered in

a Camden Bay well blowout[.]” ER 65.

The comments also questioned, in light of the new capping and containment

system, Shell’s assertion that there is no new or unusual technology proposed in

the Exploration Plan. See ER 227; ER 149; ER 294-295. The State of Alaska, for

example, sought “additional details” on the system. ER 180 (observing that “[i]t is

not clear whether [Shell’s well capping and containment equipment] has been used

previously in the Arctic or is based on designs used elsewhere in the Arctic”). The

State of Alaska also asked about “Shell’s progress on having this equipment in

place for the 2012 drilling season.” ER 178.

13 One of Shell’s contractors cautioned that “hydrates can greatly hinder well control operations” and, as a result, “[h]ydrate problems cannot be ignored and might become a major factor in well control.” ER 581.


27

During the agency’s review, BOEM staff questioned Shell’s assertion on this

point in an inquiry to other agency staff:

Do you concur with this statement? Would the containment stack and capping system . . . qualify as new and unusual technology according to the definition in 30 CFR 250.200(b) in that it has not been previously been used extensively in the Alaska region nor has it been used under anticipated operating conditions?

ER 281. The only response indicated that such technology has been used in the

Gulf of Mexico. ER 276; see also ER 269 (Shell explaining it had used the

technology in “other places”).

C. Relief Well Drilling May Take Significantly Longer Than Shell’s Estimate.

Petitioners and other stakeholders challenged Shell’s assertion that it could

drill an emergency relief well faster than the company can drill the original well.

ER 296; ER 166-167; ER 157; ER 164; ER 141-142; ER 193-194, 197; ER 288-

290.14

In the Exploration Plan, Shell identified Wild Well Control as a company

that will provide Shell well control and relief well construction advice. ER 272.

Comments pointed to a Wild Well Control report advising the Canadian

14 In a separate proceeding, BOEM recently evaluated the “operational failures and other constraints that would affect a well-control incident and response in association with the Shell program” for a Chukchi environmental review process. ER 291. The agency concluded it could take 74 days to restore well control if the relief well required an alternative rig. ER 292.


28

Government that drilling a relief well will take longer than the time needed to drill

the original well. See ER 583; ER 61-62. The report cited several considerations

for the additional time: directional drilling results in greater lengths, time needed to

control direction and position of the wellbore, problems with the blownout well,

the relief well might itself suffer the same problematic issues as the original well,

and the limited length of the drilling season.15 ER 583.

During the inter-agency review of BOEM’s environmental assessment, the

National Oceanic and Atmospheric Administration asked BOEM to explain how

quickly Shell could complete its relief well. ER 689 (noting it “[w]ould be helpful

to include industry standards / schedules for relief well setup in the [A]rctic.”).

BOEM responded that this issue was “not part of the proposed action and [wa]s

not, therefore, addressed in the [environmental assessment].” ER 684.

Numerous commenters, including the Inupiat Tribe and the Point Hope

Petitioners, expressed concern that Shell failed to address any of these issues in the

Exploration Plan given the potential importance of the emergency relief well,

especially late in the season when the Arctic is freezing solid. ER 157, 164, 166;

ER 141-143; ER 61-62, 34-36. If a relief well cannot be completed in the Arctic

Ocean “before pack ice encroaches on a drill site, it is possible that a blowout

15 By way of illustration, another oil company projected a potential 60 day timeframe to complete a relief well for a shallow well in the Canadian Beaufort Sea. ER 109.


29

could continue uncontrolled through the eight- to nine-month ice season.” ER 480.

The comments explained that oil left behind over winter can travel considerable

distance either because it is trapped in ice or because it carried by currents under

the pack ice. ER 125-126 (explaining that “[a] scenario developed in the mid-

1980s for the Chukchi Sea estimated that spilled oil trapped in ice could move as

much as 300 to 500 miles”).

VI. BOEM CONDITIONALLY APPROVED THE EXPLORATION PLAN

On August 4, 2011, BOEM conditionally approved the Exploration Plan.

ER 1-3.

In its decision letter, BOEM did not address the lack of approval of the New

Beaufort Spill Plan at the time of the decision. Id.

BOEM acknowledged that Shell’s subsea well capping and containment

system “is currently in the design stage.” ER 3. The agency’s letter required Shell

to provide the agency documentation that the new system is designed for the

“projected worst case discharge conditions for approval by BOEM[].” Id. It also

required Shell to explain its “procedures for deployment, installation and operation

of the system under anticipated environmental conditions, including the potential

presence of sea ice for approval by BOEM[].” Id. Finally, it required Shell to

“conduct a field exercise to demonstrate Shell’s ability to deploy the system.” Id.


30

BOEM did not address Shell’s estimate of the number of days it will take the

company to drill a relief well or the inconsistent record evidence. ER 1-3. The

agency, however, asked Shell to “confirm the final staging location and schedule

for mobilizing the designated relief well rig to the drill site and that response times

for commencement and completion of the relief well are consistent with the

approved [Exploration Plan].” ER 2. BOEM also required Shell, at some later

time, to “document that it has the capability to construct a well cellar if deemed

necessary as part of the relief well planning effort.” Id.

VII. PETITIONERS’ INTERESTS

Petitioners in this case include the Inupiat Tribe, the Native Village of Point

Hope, Resisting Environmental Destruction on Indigenous Lands (REDOIL), a

grassroots network of Alaska Natives, and national and regional conservation

groups.

Members of the Petitioners include residents of the eight separate villages

along the north coast of Alaska, communities that are predominantly Inupiat, and

whose people have relied upon the subsistence harvest of wildlife for thousands of

years. As BOEM has concluded, subsistence practices define the cultural, social

and spiritual values that lie at the heart of the Inupiat heritage:

This close relationship between the spirit of a people, their social organization, and the cultural value of subsistence hunting may be unparalleled when compared with other areas in America where energy-development


31

is taking place. The Inupiat’s continuing strong dependence on subsistence foods, particularly marine mammals and caribou, creates a unique set of potential effects from onshore and offshore oil exploration and development on the social and cultural system.

ER 618. “Subsistence activities are assigned the highest cultural values by the

Inupiat and provide a sense of identity in addition to being an important economic

pursuit.” ER 614.

The bowhead whale is the subsistence resource of primary importance as it

forms the foundation of the Inupiat’s cultural system. ER 614. “Bowhead whale

hunting strengthens family and community ties and the sense of a common Inupiaq

heritage, culture, and way of life. In this way, whale-hunting activities provide

strength, purpose, and unity in the face of rapid change.” ER 615.

The Inupiat Tribe is an Alaska Native tribe created pursuant to the Indian

Reorganization Act of 1934. The Inupiat Tribe’s membership includes all persons

of Inupiat blood residing within the Arctic Slope Borough of Alaska. The tribe

represents the interests of the Inupiat people who since time immemorial have

depended upon the subsistence hunt of marine mammals, fish, birds, and other

wildlife to feed their families and continue their ancient indigenous traditions and

culture. The location of Shell’s drilling is near to or adjacent to important

subsistence hunting grounds, and the Inupiat Tribe acts out of a concern that a


32

potential oil spill could wipe out their subsistence practices in areas affected by a

spill. See ER 708-716.

The Native Village of Point Hope is a federally recognized tribal

government located on the coast of the Chukchi Sea. Village members depend on

the region’s fish, walrus, seals, and bowhead whales for subsistence, which could

be affected by Shell’s drilling operations. See ER 699-707.

REDOIL has members throughout Alaska’s North Slope who rely upon the

Beaufort Sea ecosystem, including the bowhead whale, and potentially affected

terrestrial resources, especially caribou and waterfowl, to sustain their lives

nutritionally and culturally. See ER 717-724; ER 909-918; ER 895-908.

The remaining Petitioners are national and regional conservation groups

dedicated to the appreciation of and preservation of outstanding natural

environments and wildlife populations in the Arctic. These conservation groups

have members in Alaska and nationwide who use and enjoy the resources of the

Beaufort Sea, as well as Alaska’s Arctic coast. See ER 725-908; ER 919-1014.

Petitioners are injured and adversely affected by BOEM’s decision because

their use and enjoyment of these areas will be adversely affected by Shell’s

exploration activities. See generally ER 699-1014.


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SUMMARY OF ARGUMENT

BOEM violated OCSLA in three ways when it conditionally approved the

Exploration Plan all of which reflect the agency’s failure to implement the lessons

of the Deepwater Horizon tragedy to ensure oil spill response readiness before

approving drilling plans. First, OCSLA regulations prohibit the agency from

approving exploration plans in the absence of an approved regional oil spill

response plan. Nonetheless, BOEM approved the Exploration Plan even though

the review of the New Beaufort Spill Plan was, and is, still ongoing. Second,

BOEM acted arbitrarily when it approved the Exploration Plan without requiring

first an adequate description and assessment of a new, not-yet-designed well

capping and containment system, particularly when Shell has for years previously

rejected well capping as ill-suited for its Arctic drilling operations. BOEM

appeared to recognize this flaw in the Exploration Plan, but rather than require it to

be fixed, BOEM allowed Shell to submit information after approval in violation of

OCSLA’s specific provisions. Third, BOEM failed to reconcile Shell’s

unsupported assertions regarding the length of time required to drill a relief well,

maximum duration and total volume of a blowout, with substantial record evidence

to the contrary. As a result, the agency could not properly assess whether the

blowout scenario was consistent with Shell’s oil spill response plan or even

whether Shell could complete a relief well for an October blowout before winter


34

sea ice would halt all response until the following summer. In short, BOEM

violated its own regulations and ignored the critical lessons following the

Deepwater Horizon disaster when it approved the Exploration Plan before it could

determine whether Shell was prepared for an oil spill caused by its exploration

drilling activities.

ARGUMENT

I. STANDARD OF REVIEW

An agency’s action may be set aside if found to be “arbitrary, capricious, an

abuse of discretion, or otherwise not in accordance with law.” 5 U.S.C. §

706(2)(A); see also Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut.

Auto. Ins. Co., 463 U.S. 29, 41 (1983) (quoting statute). “When the arbitrary and

capricious standard is performing that function of assuring factual support, there is

no substantive difference between what it requires and what would be required by

the substantial evidence test.” Bonnichsen v. United States, 367 F.3d 864, 880 n.19

(9th Cir. 2004) (quoting Wileman Bros. & Elliott, Inc. v. Espy, 58 F.3d 1367,

1374–75 (9th Cir. 1995) (internal quotation marks omitted), rev’d on other

grounds, 521 U.S. 457 (1997)).

In performing the duties under OCSLA, the Secretary of the Interior must

articulate a “rational connection between the facts found and the choice made.”

Tribal Village of Akutan v. Hodel, 869 F.2d 1185, 1189 (9th Cir. 1988) (quoting


35

California v. Watt, 683 F.2d 1253, 1269 (9th Cir.1982), rev’d on other grounds,

464 U.S. 312 (1984)). “This is not an empty requirement. Because [the court]

may not substitute [its] own rationales for those of the agency, . . . when an agency

fails to provide an explanation for its actions [the court is] left with no means of

reviewing the reasonableness of that action.” Arrington v. Daniels, 516 F.3d 1106,

1114 (9th Cir. 2008) (citing Burlington Truck Lines, Inc. v. United States, 371 U.S.

156, 169 (1962)).

II. BOEM VIOLATED OCSLA WHEN IT APPROVED THE EXPLORATION PLAN DESPITE THE FACT SHELL IS RELYING ON AN UNAPPROVED SPILL PLAN.

OCSLA regulations require that when an exploration plan relies upon a

regional oil spill response plan that spill plan must be approved before BOEM

approves the exploration plan. Here, BOEM approved the Exploration Plan even

though the New Beaufort Spill Plan, upon which it relies was, and still is,

undergoing review to determine whether it meets spill plan requirements evaluated

in light of the Deepwater Horizon events. As explained below, BOEM’s approval,

therefore, violated OCSLA regulations.

OCSLA regulations and the Oil Pollution Act of 1990 require Shell to have

an oil spill response plan, which, BOEM describes as “a fundamental component

of the proposed exploration drilling program.” ER 14; see also ER 258 (Shell

acknowledging the same). OCSLA regulations link the requirements of


36

exploration plans with the requirements prescribed by the Oil Pollution Act. See

30 C.F.R. § 550.219; 30 C.F.R. Part 254. The Oil Pollution Act requires owners

and operators of offshore facilities to prepare oil spill response plans demonstrating

their ability to “respond[], to the maximum extent practicable, to a worst case

discharge[.]”16 33 U.S.C. § 1321(j)(5)(A)(i). Offshore facilities “may not handle,

store, or transport oil unless” the company’s oil spill “response plan has been

approved by the President” and “the … facility is operating in compliance with the

plan.”17 33 U.S.C § 1321(j)(5)(F)(i)-(ii). As Shell acknowledged in the

Exploration Plan, its oil spill response plan must demonstrate the company’s

“capabilities to entirely prevent, or rapidly and effectively manage, oil spills that

may result from [its] exploratory drilling operations.” ER 258. Thus, the interplay

of the OCSLA regulations, 30 C.F.R. § 550.219, and the Oil Pollution Act is

16 In the case of an offshore facility, the phrase “worst case discharge” means the “largest foreseeable discharge in adverse weather conditions[.]” 33 U.S.C. § 1321(a)(24)(B). 17 By executive order, President George Bush delegated the authority to review and approve response plans for offshore facilities to the Secretary of the Interior. Executive Order 12,777, Implementation of Section 311 of the Federal Water Pollution Control Act of October 18, 1972, as Amended, and the Oil Pollution Act of 1990, 56 Fed. Reg. 54,757, 54,561-62 (Oct. 18, 1991); see also 40 C.F.R. Pt. 112., App. B, Memorandum of Understanding Among the Secretary of the Interior, Secretary of Transportation, and Administrator of the Environmental Protection Agency, Responsibilities, ¶ 3 (The Department of the Interior “retain[ed] jurisdiction over facilities, including pipelines, located seaward of the coastline, except for deepwater ports and associated seaward pipelines[.]”).


37

intended to ensure an oil company is prepared to respond to a “worst case

discharge” caused by its exploration drilling activities.

When a company submits an exploration plan to BOEM, OCSLA

regulations require that it either: (1) be accompanied by a facility-specific oil spill

response plan; or (2) “[r]eference to [the company’s] approved regional [oil spill

response plan[.]”18 30 C.F.R. § 550.219(a)(1)-(2). If a company pursues the

regional plan approach, then its exploration plan (or accompanying materials) must

satisfy various requirements designed to ensure the spill plan is sufficient for the

proposed drilling. See id. § 550.219(a)(2)(i)-(iv). For example, the exploration

plan must calculate the volume of the worst case discharge from the proposed

drilling activities. Id. § 550.219(a)(2)(iv). It must “compar[e] [] the appropriate

worst case discharge scenario in [the] approved regional [oil spill response plan]

with the worst case discharge scenario that could result from [the] proposed

exploration activities[.]” Id. The company must provide a “description of the

worst case discharge scenario that could result from [the] proposed exploration

activities.” Id. § 254(a)(2)(v); see also id. § 254.26(d)-(e) (requiring the company

to describe its response equipment, deployment, personnel, and explain that the

18 BSEE regulations allow companies to prepare oil spill response plans for a single facility or a regional plan that covers a group of facilities within a region. See 30 C.F.R. § 254.3.


38

equipment is “suitable” for the “environmental conditions anticipated” during the

drilling).

Shell did not provide BOEM a facility-specific oil spill response plan. See

ER 546; ER 531; ER 258. Instead, as the agency acknowledged, Shell chose to

rely on a “regional oil-spill-response plan” to support its Beaufort exploratory

drilling operations. ER 14. However, the regional spill plan on which Shell is

relying, ER 228, 234, is still undergoing review.19 ER 14 (BOEM acknowledging

that “[t]he [New Beaufort Spill Plan] is currently being reviewed given th[e] new

information [Shell provided after the Deepwater Horizon] and appropriate actions

will be taken pending the evaluation of this new information and how it impacts

Shell’s capability to respond to an oil spill event”). To date, BSEE still has not

approved the New Beaufort Spill Plan.

The adequacy of oil spill planning and response preparedness has been one

of the critical areas of concern following the Deepwater Horizon disaster. See

supra at 11-14 Before BOEM can decide whether to approve the Exploration Plan,

19 The Exploration Plan refers to the Old Beaufort Spill Plan, ER 226, but that plan was developed and approved prior to the Deepwater Horizon oil spill. See supra at 17-19. Moreover, it is plainly inadequate for Shell’s proposed drilling. For example, the Exploration Plan contemplates a worst case discharge oil spill of 284,040 bbl (30 days times 9,468 bbl), ER 228, but the Old Beaufort Spill Plan only addresses Shell’s ability to respond to 165,000 bbl spill (30 days times 5,500 bbl). ER 535; see also 30 C.F.R. 250.219(a)(2)(iv) (requiring comparison of the worst case discharge in an exploration plan with the worst case discharge in the approved regional oil spill response plan).


39

it must know that a company can respond effectively to an oil spill resulting from

those drilling activities. Here, in light of the Deepwater Horizon disaster, the

agency demanded that Shell revise its worst case discharge, and describe

information about additional safety procedures and spill response measures that

Shell planned to undertake in the Beaufort. See supra at 17-19. Shell prepared the

New Beaufort Spill Plan in an attempt to provide this information and make the

necessary commitments. See, e.g., ER 549-553, 556-557. BSEE, the agency now

responsible for reviewing spill plans, is still considering the substantial, critical

public comments, see supra at 17-19, and evaluating whether Shell provided

adequate information in the New Beaufort Spill Plan, including the company’s

plans for oil spill containment and control methods, to ensure that Shell can deliver

on the capabilities it asserts. See, e.g., ER 110-155, ER 30-105; ER 393. Because

BSEE had not completed its review, and required any necessary revisions at the

time of BOEM’s decision, BOEM could not have known whether the Exploration

Plan is supported by an adequate spill response plan. For example, BSEE may

decide Shell is not equipped to respond to a late season spill in the frozen Arctic.

BOEM should have had such information before deciding to approve Shell’s plan

to conduct drilling activities through the end of October.

OCSLA’s regulations require Shell to support the Exploration Plan with an

“approved regional [oil spill response plan].” 30 C.F.R. § 550.219(a)(2). Shell is


40

relying on its New Beaufort Spill Plan to support its exploration drilling activities.

The New Beaufort Spill Plan, however, is unapproved and, as a result, BOEM

violated 30 C.F.R. § 550.219(a)(2) when it approved the Exploration Plan.

III. BOEM ACTED ARBITRARILY WHEN IT APPROVED THE EXPLORATION PLAN BASED ON A NEW, NOT-YET-DESIGNED WELL CAPPING AND CONTAINMENT SYSTEM THAT SHELL PREVIOUSLY CONCLUDED WAS ILL-SUITED FOR THE ARCTIC.

BOEM approved Shell’s proposal to use a new well capping stack and

containment system as part of its Beaufort exploration activities. ER 237; ER 3.

Well capping technology, however, has never been used in BOEM’s Alaska

Region or in Arctic operating conditions and Shell has consistently asserted it is

not appropriate or safe technology for operations from a moored vessel in the icy

waters of the Arctic. In fact, at the time BOEM acted on Shell’s proposal, Shell

had not even designed, much less built, or tested the capping system. Yet, BOEM

approved the Exploration Plan without resolving this inconsistency, and the agency

even effectively acknowledged Shell failed to provide the required information

about the proposed system. It was arbitrary and capricious for BOEM to approve

the Exploration Plan, given Shell’s reliance on unexplained new technology.

BOEM’s solution to this problem—approve the Exploration Plan in its inadequate

form and allow Shell to backfill the required information at some undefined future

point—violated OCSLA’s plain language.


41

A. It was Arbitrary for BOEM to Approve the Exploration Plan Given Shell Provided the Agency No Explanation of the New Well Capping and Containment System.

BOEM’s regulations require the Exploration Plan to include a “description

and discussion of any new or unusual technology . . . [the company] will use to

carry out [its] proposed exploration activities.” 30 C.F.R. § 550.213(d) (citing 30

C.F.R. § 550.200)). The phrase “new or unusual technology” is defined in 30

C.F.R. § 550.200 as follows:

New or unusual technology means equipment or procedures that:

(1) Have not been used previously or extensively in a BOEM OCS Region;

(2) Have not been used previously under the anticipated operating conditions; or

(3) Have operating characteristics that are outside the performance parameters established by this part.

Id. OCSLA also requires the “use of the best available and safest technologies

which the Secretary determines to be economically feasible, wherever failure of

equipment would have a significant effect on safety, health, or the environment[.]”

43 U.S.C. § 1347(b); see also 30 C.F.R. § 250.107(c) (requiring Shell to “use the

best available and safest technology (BAST) whenever practical on all exploration,

development, and production operations”). The phrase “best available and safest

technology” means the “best available and safest technologies that the Director

determines to be economically feasible wherever failure of equipment would have


42

a significant effect on safety, health, or the environment.” 30 C.F.R. § 550.105.

BOEM’s decision to approve the Exploration Plan based on a new, and as of yet

still-to-be-designed, capping and containment system fails to meet these standards.

After the Deepwater Horizon, Shell proposed a new subsea containment

system as one of its primary methods for responding to well blowout during its

Arctic drilling exploration activities. ER 578; ER 237. Shell had never proposed a

capping and containment system in its previous Arctic proposals. See, e.g., ER

591-593; ER 540. Yet, in the Exploration Plan, Shell stated: “There is no new or

unusual technology proposed.” ER 227.

In fact, this capping stack and containment is new both in Alaska and in

Arctic drilling operations from a moored vessel with the blowout preventer in a

mudline cellar. As Shell admitted elsewhere in the Exploration Plan, this

technology has never been used in BOEM’s Alaska OCS Region or in the Arctic.

ER 269 (Shell responding to community concerns by stating it “ha[s] used this

equipment in many other places”). The State of Alaska inquired on this point in its

comments: “It is not clear from the discussion whether [Shell’s well capping and

containment equipment] has been used previously in the Arctic or is based on

designs used elsewhere in the Arctic.” ER 178; see also ER 298, 294-295; ER

136. In an inquiry to colleagues, BOEM staff also questioned Shell’s assertion that

it was not new or unusual technology. See supra at 25-26. The only response to


43

this inquiry came from agency staff in the Gulf of Mexico, noting the technology

was used there. ER 276. In short, Shell is relying on a system that has never been

used in Alaska or under Arctic operating conditions and, as a result, the well

capping and containment system qualifies as “new or unusual technology” under

30 C.F.R. § 550.200(1) and § 550.200(2). Because this technology has not been

used previously, Shell was required by regulation to provide a description of the

technology, but, as discussed below, this information is not provided in the

Exploration Plan as the new equipment was still in the design phase.

The agency’s failure to reconcile Shell’s assertions regarding this technology

is important because until recently Shell has consistently over a period of years

rejected a well capping system as infeasible for its Arctic drilling operations and,

as a result, not the “best available and safest technology.” See 30 C.F.R. §

250.107(c); ER 604-605 (Shell’s “best available and safest technology” analysis

concluding that “well capping is “[n]ot applicable, [to its Arctic operations], since

proven technology is not available”); ER 602; ER 540, 542-543 (Shell concluding

the same in 2010). According to Shell, “[w]ell capping is not feasible for offshore

wells from moored vessels with [blowout prevention equipment] sitting below the

mud line in a well cellar (glory hole)[.]” ER 602; ER 540 (same). Shell explained

that “well capping in mud-line cellars constructed on the sea floor from moored

vessels [has] not been proven.” ER 606; ER 544 (same). Shell told the agency


44

repeatedly that “well capping would not be an effective option for regaining well

control while operating from a moored vessel.” ER 606; ER 544 (same). Just last

year, Shell concluded well capping is “is not feasible” for its operations because

Shell plans to use moored vessels with the blowout preventer sitting below the mud

line in a well cellar. ER 540.

Shell’s unexplained shift to this new technology also is inconsistent with the

New Beaufort Spill Plan, submitted with the Exploration Plan, which continues to

rule out well capping in the Arctic. ER 570 (“Well capping is not feasible for

offshore wells from moored vessels with BOP[] sitting below the mud line in a

well cellar (glory hole)[.]”). Shell concludes: “[Well capping] [e]quipment is not

available for wells drilled from moored vessels.” ER 572. Seven different times,

Shell restates the conclusion: “[p]roven [well capping] technology is not

available.” ER 572-573.

The Exploration Plan does not explain or justify Shell’s decision to reverse

course as to its assertions about the feasibility of well capping in an Arctic drilling

operation from a moored vessel. The only explanation in the Exploration Plan is

that Shell intends to “[a]ttach[] a device or series of devices to the well . . . and

clos[e] the assembly to completely seal the well against further flows.” ER 237.

After Shell seals the well, it will “[a]ttach[] a device or series of devices to the well

and divert[] flow to surface vessel(s)[.]” Id. Stated more directly, Shell simply


45

asserts that a new yet-to-be-designed and untested system will stop a blowout.

Shell also assumes the new system will work in “conditions found in the Arctic

including ice and cold temperatures,” but the Exploration Plan did not explain why

Shell now expects this system to work in Arctic conditions after concluding for

years that well capping would not work. See ER 237. Substantial public

comments to the agency reiterated the importance of the missing design and

explanation. See supra at 25-26.

Shell has been promising a new subsea containment system for more than a

year and half now. See ER 578. Time and again, Shell has committed to having

the system designed and built, only to miss its own deadlines. See ER 330 (Shell

stating publicly in January 2011 it had “completed its selection of a design concept

for the system and [] plan[ed] to have fabrication completed by May 31, 2011, for

crew training in June and field deployment in July [2011].”); ER 318 (Shell

admitting in March 2011 that the system was still being designed); ER 309

(exploration plan submitted in May 2011 contending the system was “being

assembled”); ER 237 (revised version of the Exploration Plan submitted in July

2011 contending the same). In fact, as of August 2011, when BOEM approved the

Exploration Plan, the agency acknowledged that the system “is currently in the

design stage.” See ER 3.


46

In the face of Shell’s prior conclusions about well capping, comments in the

record about the many unresolved issues, and Shell’s continuing failure to

complete and explain its design, it was arbitrary and capricious for the agency to

approve the Exploration Plan. There is nothing in the record that provides the

description or explanation of the new well capping system required for “new or

unusual technology” in Alaska’s Arctic conditions, under 30 C.F.R. § 550.213(d),

or that provides a basis for the conclusion that it now constitutes “best available

and safest technology,” under 30 C.F.R. § 250.107(c). See Ctr. for Biological

Diversity v. Nat’l Highway Traffic Safety Admin., 538 F.3d 1172, 1193 (9th Cir.

2008) (“The reviewing court may not supply a reasoned basis for the agency’s

action that the agency itself has not given.”) (quotation marks and citation

omitted). The agency apparently recognized Shell’s failure to comply with

OCSLA’s regulations because the agency conditioned its approval of the

Exploration Plan on Shell providing the agency critical information about its new

capping and containment system at some undefined point in the future. See ER 3.

As explained below, however, this fails to comply with the process established by

Congress for the review and approval of exploration plans.

B. OCSLA Prohibits the Agency from Creating its Own Undefined Approval Process for Exploration Plans.

Under OCSLA, Congress gave BOEM three options after it reviews an

exploration plan. The agency can: reject the plan; approve the plan “as submitted;”


47

or require modifications to meet OCSLA’s requirements and approve the re-

submitted plan “as . . . modified.” See 43 U.S.C § 1340(c)(1). In this case, BOEM

pursued none of these courses and, instead, created its own undefined process

called a “conditional approval.” BOEM did not comply with 43 U.S.C §

1340(c)(1) and, as a result, the “conditional approval” is unlawful.

An exploration plan “shall be approved by the Secretary if he finds that such

plan is consistent with the provisions of [OCSLA], [the] regulations prescribed

under [OCSLA]” and the provisions of the company’s lease. 43 U.S.C §

1340(c)(1). If the exploration plan is not consistent, then “[t]he Secretary shall

require such modifications of such plan as are necessary to achieve such

consistency.” Id. If the agency requires an exploration plan to be modified, then

the company must make the changes and resubmit the plan for consideration. See

30 C.F.R. § 550.233(b)(2); id. § 550.234(a). The Secretary must then either

approve the exploration plan, “as submitted or modified, within thirty days of its

submission” or disapprove the plan. 43 U.S.C. § 1340(c)(1). In other words, the

statute and the regulations contemplate one approval decision – either as submitted

originally or after modified and resubmitted.

An exploration plan must contain the elements required by OCSLA and its

regulations before it can be approved. “An exploration plan submitted under

[OCSLA] shall include, in the degree of detail which the Secretary may by


48

regulation require[,] . . . a description of equipment to be used for such

activities[.]” 43 U.S.C. § 1340(c)(3)(B). Pursuant to this requirement of OCSLA,

the agency’s regulations further require specific information that must be included

in the exploration plan and the standards by which the agency evaluates the plan’s

compliance with the statute. See 30 C.F.R. §§ 550.211-.228, .202. As explained

above, this information includes details regarding oil spill prevention, response,

and containment that is lacking in the Exploration Plan, including the capping and

containment system Shell fails to describe or explain. See, e.g., id.

§§ 550.219(a)(2)(iv)-(v), 254.26(d)-(e), 550.213(d), 550.105, 250.107(c). Thus,

the statute and regulations make clear that certain critical information, including

information about the new proposed capping and containment system at issue here,

must be a part of, or submitted with, the exploration plan itself, and that a plan can

only be approved once all the required elements are provided.

The importance of a single comprehensive decision is also clear from

Congress’ requirement for expedited judicial review of exploration plan approvals.

Congress intended that challenges to the adequacy of an exploration plan,

following the agency’s conclusion that the plan contains all the required elements,

would be pursued in one expedited proceeding. 43 U.S.C. § 1349(c)(2)

(establishing judicial review of “[a]ny action of the Secretary to approve, require

modification of, or disapprove any exploration plan”). Congress provided that the


49

challenge must be brought in the Courts of Appeal. Id. Congress also outlined the

requirements for public participation prior to the challenge and that the challenge

must be pursued within 60 days of the approval. Id. § 1349(c)(3). This sort of

singular, expedited appellate review process is consistent with Congress’ expressed

intent to require a single decision on the adequacy of an exploration plan.

BOEM made a decision here that avoids this carefully defined OCSLA

process. It approved the Exploration Plan, but on fundamental spill preparedness

elements required by the statute and the regulations, the agency allowed Shell to

submit information later in time. The agency approved the plan before requiring

Shell to provide documentation explaining why the capping and containment

system will be sufficient for the worst case discharge from its drilling proposal or

explain Shell’s plans for “deployment, installation and operation of the system

under anticipated environmental conditions, including the potential presence of sea

ice[.]” ER 3. All of this information will be subject to future review and approval

by BOEM at an unspecified point in time. Id. BOEM did not define deadlines, did

not provide for public input as to the adequacy of the new measures Shell decides

to adopt, and gave no indication whether the company would be required to amend

the Exploration Plan or whether BOEM would make a new or revised plan

approval decision that would then be subject to judicial review. This open-ended

process BOEM created fails to meet the requirements of the law and regulations to


50

ensure the Exploration Plan meets BOEM regulations prior to approval and

judicial review.

BOEM’s multi-stage approval is not only inconsistent with the process

Congress established to govern exploration plans, it also ignores the lessons the

agency should have learned after the Deepwater Horizon. The critical lesson

following the Deepwater Horizon disaster is that BOEM must test the veracity of

the assertions oil companies make regarding oil spill response and containment,

including assertions regarding the efficacy of the technology, before it approves an

exploration plan. See ER 406 (BOEM requiring operators to demonstrate that they

have “access to and can deploy containment resources that would be adequate to

promptly respond to a blowout or other loss of well control.”); ER 394

(Commission cautioning BOEM to “ensure that operators can deliver the

capabilities indicated”); ER 397 (BOEM “must ensure that operators provide

detailed descriptions of their technology and demonstrate that it is deployable and

effective.”).

The Exploration Plan Shell submitted did not include the information

required by OCSLA and its implementing regulations, so the agency was obligated

to require Shell to modify the Exploration Plan and resubmit it for consideration

“as submitted.” BOEM violated OCSLA by instead conditionally approving the

Exploration Plan.


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IV. BOEM’S APPROVAL OF SHELL’S ESTIMATE OF A MAXIMUM DURATION BLOWOUT FROM ITS ARCTIC DRILLING OPERATIONS WAS ARBITRARY AND CAPRICIOUS.

OCSLA regulations require exploration plans to describe a blowout

scenario, including the maximum duration of a potential blowout, and estimate the

time required to drill a relief well. 30 C.F.R § 550.213(g). In the Exploration

Plan, Shell asserted it will be able to drill a relief well to stop a blowout faster than

the evidence in the record suggests is feasible, but the agency failed to reconcile

the differences or the consequences of understating the total volume of oil that

could spill during a potential blowout. This failure has important potential

consequences. If relief well drilling takes longer than Shell’s unsupported

estimate, the spill volume could exceed Shell’s oil spill plan. Moreover, because

the Exploration Plan permits drilling through October, it could mean the Arctic

Ocean will have frozen over before a relief well can be completed, resulting in a

blowout flowing unrelentingly until the following summer. BOEM, therefore,

acted arbitrarily in approving the Exploration Plan without addressing this issue,

because Shell’s own assertions are not explained and contradict evidence in the

record.

Exploration plans must describe a blowout scenario from the proposed

drilling activities. 30 C.F.R. § 550.213(g). More specifically, exploration plans

must provide the following information:


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A scenario for the potential blowout of the proposed well in [the exploration plan] that [the company] expect[s] will have the highest volume of liquid hydrocarbons. Include the estimated flow rate, total volume, and maximum duration of the potential blowout. . . . Estimate the time it would take to drill a relief well.

Id.

In the Exploration Plan, Shell estimates it could take 44 days to drill its

Torpedo wells and 34 days to drill its Sivulliq wells. See ER 246; ER 243. Yet,

for its emergency relief well operations, Shell estimates it will take only 25 days to

drill a relief well at its Torpedo prospect, and only 20 days to drill a relief well at

its Sivulliq prospect. ER 229; see also ER 274.

As an initial matter, Shell failed to provide the agency any rational

explanation for why it expects to drill a relief well so much faster. The

Exploration Plan’s only explanation is that Shell will not construct a mudline cellar

for the relief well. See ER 273. BOEM regulations require companies to dig a

mudline cellar and install their blowout preventer stack in the hole when they are

using a subsea blowout preventer system in an ice-scour area.20 See 30 C.F.R. §

250.451(h). Thus, the “maximum duration” blowout scenario should have

20 In its conditional approval letter, the agency stated it is requiring Shell to “document that it has the capability to construct a well cellar if deemed necessary as part of the relief well planning.” ER 2.


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included the time needed to construct the mudline cellar during the relief well

operations.21

Shell’s estimate, moreover, conflicts with evidence in the record that drilling

a relief well takes longer than Shell asserted in the Exploration Plan. In the New

Beaufort Spill Plan, for example, Shell explains that relief well “[t]echnology [in

the Arctic] may be seasonally limited, leading to durations of 60 to 180 days.” ER

573.

Moreover, the record includes a recent report from Shell’s well control and

relief well contractor, Wild Well Control, which advised the Canadian Government

that drilling a relief well in Arctic conditions takes even longer than the time

needed to drill the original well. ER 583; ER 272. The report explained that “[a]

number of factors will cause the relief well to take longer to drill than the blowout

well, such as the need to directionally drill the relief well.”22 ER 583 (identifying

the factors and noting that “drilling the relief well could be more risky than drilling

the original well”). Shell’s discussion of the time needed to complete a relief well

in the Exploration Plan’s blowout scenario did not assess these considerations or

21 In 2009, the agency concluded it would take between 7-10 days construct a mudline cellar for one of Shell sites. ER 7. Even if one includes those additional days to Shell’s relief well estimates, the company still contended it could drill a relief well faster than its original well. 22 See ER 107 (showing directional drilling for relief well).


54

the consequences of a late season spill in the Arctic’s icy conditions. See ER 228-

229.

A report in the record commissioned by Pew Environment Group’s U.S.

Arctic Program reached similar conclusions regarding the problems of timing. “In

August 2009, the Montara platform . . . experienced a blowout during exploratory

drilling in the East Timor Sea, Australia.” ER 447. “[T]he Montara relief well

required 10 weeks to complete[.]” Id. It also explained that it “took several

months to mobilize a rig and drill the relief well in a gas well blowout” in Cook

Inlet, Alaska. ER 479-480 (explaining that the blowout occurred in December

1987, but the relief well was not completed until June 1988).

In another record document, Chevron, in a presentation to a U.S. Department

of Energy / Norway Arctic Workshop, described a potential 60-day timetable to

complete a relief well for a shallow well in the Canadian Beaufort Sea. ER 109.

In explaining the length of time, Chevron explained that a late season relief well

“will take place largely in darkness” and “growing ice thicknesses.”23 ER 108.

Finally, in May 2011, BOEM evaluated the “operational failures and other

constraints that would affect a well-control incident and response in association

with the Shell program” for a Chukchi environmental review process. ER 291. In

23 Shell will confront the same challenges. See, e.g., ER 562 (zero hours of daylight in December); ER 565-569 (describing seasonal ice conditions).


55

its own analysis, the agency concluded well control might take 74 days based on an

alternative rig drilling a relief well. ER 292.

The agency never reconciled the substantial evidence in the record that runs

contrary to Shell’s relief well estimate. The agency’s failure to grapple with

Shell’s estimate of the time it takes to drill a relief well and the “maximum

duration” blowout has important implications. For example, variations in the relief

well timing could lead to a spill larger than contemplated by Shell’s oil spill plans.

If there is a blowout and Shell has to move the Kulluk from Dutch Harbor to drill

the relief well, ER 229, Shell estimated it will take 18 days to tow the Kulluk to the

Beaufort. Id. Even assuming it only takes Shell the same amount of time to drill a

relief well as it takes to drill the original well, though other record evidence

suggests it could take much longer, completing the relief well could take 62 days.

ER 274, 246 (44 days (drilling estimate for actual Torpedo well) plus 18 days

(transit time from Dutch Harbor)). Shell’s total spill volume over the course of 62

days likely would exceed 587,000 bbl. See ER 228 (9,468 barrels of oil per day

over 62 days). This volume substantially exceeds the expectations of the New

Beaufort Spill Plan, which only contemplates a worst case discharge of 480,000

bbl. ER 550. Evidence in the record indicates the volume could be even larger,24

24 Based on the agency’s estimate of 74 total days to achieve well control, Shell’s “maximum duration” blowout could exceed 700,000 bbl. See ER 292.


56

but the example illustrates the importance of the agency’s failure to grapple with

these issues.

The agency’s failure to address relief well timing also is important given the

Arctic conditions in which Shell will be operating. If a blowout occurs in October,

based on the relief well scenarios described above, Shell might not complete its

relief well before late December or early January (or even later), but by this time,

the Arctic Ocean is frozen.25 There is nothing in the record to suggest Shell can

complete a relief well under such conditions. If a relief well cannot be completed

in the Arctic Ocean “before pack ice encroaches on a drill site, it is possible that a

blowout could continue uncontrolled through the eight- to nine-month ice season.”

ER 480. The agency’s failure to address Shell’s unsubstantiated relief well

projections thus implicates Shell’s ability to complete a relief well before the

Arctic Ocean freezes over, and raises serious questions about whether Shell’s

operations can be conducted in a safe and responsible fashion through the end of

October as the Exploration Plan contemplated. See 43 U.S.C. § 1332(3); 30 C.F.R.

§ 250.107(d)(1).

25 See ER 567; ER 259 (Shell explaining that “[t]he majority of the Beaufort Sea is covered with sea ice for most of November through July.”); ER 530 (Shell’s spill response contractor describing “freeze-up median dates October 1-31”); ER 572 (“Lack of year-round access to some locations (e.g., offshore Beaufort) limits application [of a relief well] to the open-water season.”).


57

In short, there is no analysis in the record to support the agency’s decision to

accept Shell’s blowout scenario based on the estimate of the time it will take to

drill a relief well. See Native Ecosystems Council v. United States Forest Serv.,

418 F.3d 953, 960 (9th Cir. 2005) (“To have not acted in an arbitrary and

capricious manner, the agency must present a ‘rational connection between the

facts found and the conclusions made.’ ”) (quoting Nat’l Wildlife Fed’n v. United

States Army Corps of Eng’rs, 384 F.3d 1163, 1170 (9th Cir. 2004)). In light of the

evidence to the contrary, BOEM acted arbitrarily in approving the Exploration

Plan without requiring Shell to reconcile such a fundamental assumption regarding

the “maximum duration” blowout caused during Shell’s exploration activities in

the Beaufort Sea. See 30 C.F.R. § 550.213(g).

V. THE COURT SHOULD VACATE BOEM’S APPROVAL OF THE EXPLORATION PLAN AND REMAND IT TO THE AGENCY FOR FURTHER PROCEEDINGS.

As explained above, BOEM’s approval of the Exploration Plan violates

OCSLA. OCSLA specifically empowers the Court to vacate an unlawful order or

decision. See 43 U.S.C. § 1349(c)(6) (stating that courts may “vacate” a decision

to approve an exploration plan). Vacatur also advances OCSLA’s mandate by

ensuring “orderly” offshore development “subject to environmental safeguards,”

43 U.S.C. § 1332(3); see also W. Oil and Gas Ass’n v. U.S. Envtl. Protection

Agency, 633 F.2d 803, 813 (9th Cir. 1980) (“relief for agency procedural error


58

should be a strict reconstruction of procedural rights”). Accordingly, the Court

should vacate the approval and remand to the agency with direction to comply with

the statute’s requirements regarding oil spill prevention and readiness.

Additionally, the normal remedy under the Administrative Procedure Act for

an unlawful agency action is to set aside the agency’s action. See Natural Res.

Def. Council v. Houston, 146 F.3d 1118, 1129 (9th Cir. 1998) (citing 5 U.S.C. §

706(2)); Idaho Farm Bureau Fed’n v. Babbitt, 58 F.3d 1392, 1405 (9th Cir. 1995)

(“Ordinarily when a regulation is not promulgated in compliance with the APA,

the regulation is invalid.”); Am. Bioscience, Inc. v. Thompson, 269 F.3d 1077, 1084

(D.C. Cir. 2001) (where a plaintiff “prevails on its APA claim, it is entitled to relief

under that statute, which normally will be a vacatur of the agency’s order”);

Southeast Alaska Conservation Council v. U.S. Army Corps of Eng’rs, 486 F.3d

638, 654-55 (9th Cir. 2007) (the “normal remedy” for an unlawful agency action is

to “vacate the agency’s action and remand to the agency to act in compliance with

its statutory obligations”) (quotation marks and citation omitted), rev’d on other

grounds, 557 U.S. 261 (2009); W. Oil and Gas Ass’n, 633 F.2d at 813 (describing

the circumstances under which an unlawful agency determination will be left in

place during remand as “unusual”). Because BOEM approved the exploration plan

even though it did not meet OCSLA requirements, the Court should vacate the

approval.


59

Although the Court retains discretion to remand without vacatur where

vacatur would threaten harm to the environment, Idaho Farm Bureau Fed’n, 58

F.3d at 1406, or thwart the objective of the statute at issue, W. Oil and Gas Ass’n,

633 F.2d at 813, no departure from the normal rule is warranted in this instance.

Vacatur here would avoid harm to the environment, and to Petitioners’ and their

members’ use of the Beaufort Seas for subsistence, scientific, recreational, and

spiritual purposes. See ER 699-1014; ER 1015-1046; ER 453-591; ER 628-681.

CONCLUSION

For all the reasons stated above, Petitioners respectfully request that this

Court vacate BOEM’s approval of Shell’s Exploration Plan pending the agency’s

compliance with the law.


60

Respectfully submitted this 22nd day of December, 2011.

s/ Holly A. Harris

Holly A. Harris Eric P. Jorgensen Erik Grafe EARTHJUSTICE Attorneys for Petitioners, Native Village of Point Hope, et al., Petition No. 11-72891 s/ Christopher Winter

Christopher Winter Tanya Sanerib CRAG LAW CENTER Attorneys for Petitioner Inupiat Community of the Arctic Slope, Petition No. 11-72943


61

CERTIFICATE OF COMPLIANCE PURSUANT TO FED. R. APP. P. 32(a)(7)

1. This brief complies with the type-volume limitation of Fed. R. App. P.

32(a)(7)(B) because this brief contains 13,850 words, excluding the parts of the

brief exempted by Fed. R. App. P. 32(a)(7)(B)(iii).

2. This brief complies with the typeface requirements of Fed. R. App. P.

32(a)(5) and the type style requirements of Fed. R. App. P. 32(a)(6) because this

brief has been prepared in a proportionally spaced typeface using Microsoft Word

2010 in 14 point Times New Roman.


s/ Holly A. Harris

Holly A. Harris Eric P. Jorgensen Erik Grafe EARTHJUSTICE Attorneys for Petitioners, Native Village of Point Hope, et al., Petition No. 11-72891 Christopher Winter Tanya Sanerib CRAG LAW CENTER Attorneys for Petitioner Inupiat Community of the Arctic Slope, Petition No. 11-72943


62

STATEMENT OF RELATED CASES

Pursuant to Ninth Circuit Rule 28-2.6, Native Village of Point Hope; Alaska

Wilderness League; Center for Biological Diversity; Defenders of Wildlife;

Greenpeace, Inc.; Natural Resources Defense Council; National Audubon Society;

Northern Alaska Environmental Center; Oceana; Pacific Environment; Resisting

Environmental Destruction On Indigenous Lands (REDOIL); Sierra Club; The

Wilderness Society; and the Inupiat Community of the Arctic Slope state all the

related cases have been consolidated.


63

CERTIFICATE OF SERVICE

I hereby certify that on December 22, 2011, I electronically filed the

foregoing PETITIONERS’ OPENING BRIEF with the Clerk of the Court for the

United States Court of Appeals for the Ninth Circuit using the appellate CM/ECF

system.

Participants in the case who are registered CM/ECF users will be served by

the appellate CM/ECF system.

I also certify that on December 22, 2011, four (4) copies of PETITIONERS’

EXCERPTS OF RECORD were sent by Express Mail to the Clerk of the Court,

U.S. Court of Appeals for the Ninth Circuit, P.O. Box 193939, 95 Seventh Street,

San Francisco, CA 94119-3939. One (1) copy was served by Express Mail on

each of the following:

David C. Shilton Appellate Section Environment & Natural Resources Div. U.S. DEPARTMENT OF JUSTICE P.O. Box 23795, L’Enfant Station Washington, DC 20026-3795

Kathleen M. Sullivan William B. Adams QUINN EMANUEL URQUHART & SULLIVAN, LLP 51 Madison Avenue, 22nd Flr. New York, NY 10010

Kyle W. Parker CROWELL & MORING, LLP 1029 W. 3rd Avenue, Ste. 402 Anchorage, AK 99501

Rebecca Kruse STATE OF ALASKA 1031 W. 4th Avenue, Ste. 200 Anchorage, AK 99501


64


s/ Holly A. Harris

Holly A. Harris Eric P. Jorgensen Erik Grafe EARTHJUSTICE Attorneys for Petitioners, Native Village of Point Hope, et al., Petition No. 11-72891 Christopher Winter Tanya Sanerib CRAG LAW CENTER Attorneys for Petitioner Inupiat Community of the Arctic Slope, Petition No. 11-72943


[Colored Page in Printed Brief]


i

ADDENDUM

STATUTES Page(s) Administrative Procedures Act (APA), 5 U.S.C. § 706

A1

Clean Water Act (CWA) 33 U.S.C. § 1321

A2-A3

Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. § 1332

A4

OCSLA, 43 U.S.C. § 1340 A5-A6 OCSLA, 43 U.S.C. § 1347 A7 OCSLA, 43 U.S.C. § 1349 A8

REGULATIONS OCSLA Regulations, 30 C.F.R. § 250.107 A9 OCSLA Regulations, 30 C.F.R. § 250.451 A10 OCSLA Regulations, 30 C.F.R. § 254.3 A11-A12 OCSLA Regulations, 30 C.F.R. § 550.105 A13 OCSLA Regulations, 30 C.F.R. § 550.200 A14-A15 OCSLA Regulations, 30 C.F.R. § 550.202 A16 OCSLA Regulations, 30 C.F.R. § 550.213 A17 OCSLA Regulations, 30 C.F.R. § 550.219 A18-A19 OCSLA Regulations, 30 C.F.R. § 550.233 A20-A21


Administrative Procedures Act

5 U.S.C.A. § 706

§ 706. Scope of review

To the extent necessary to decision and when presented, the reviewing court shall decide all relevant questions of law, interpret constitutional and statutory provisions, and determine the meaning or applicability of the terms of an agency action. The reviewing court shall--

. . .

(2) hold unlawful and set aside agency action, findings, and conclusions found to be--

(A) arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law;

. . .

In making the foregoing determinations, the court shall review the whole record or those parts of it cited by a party, and due account shall be taken of the rule of prejudicial error.

A1


Clean Water Act

33 U.S.C.A. § 1321

§ 1321. Oil and hazardous substance liability

Effective: July 11, 2006

(a) Definitions

For the purpose of this section, the term--

. . .

(11) “offshore facility” means any facility of any kind located in, on, or under, any of the navigable waters of the United States, and any facility of any kind which is subject to the jurisdiction of the United States and is located in, on, or under any other waters, other than a vessel or a public vessel;

(24) “worst case discharge” means--

. . .

(B) in the case of an offshore facility or onshore facility, the largest foreseeable discharge in adverse weather conditions;

. . .

(j) National Response System

. . .

(5) Tank vessel, nontank vessel, and facility response plans

(A)(i) The President shall issue regulations which require an owner or operator of a tank vessel or facility described in subparagraph (C) to prepare and submit to the President a plan for responding, to the maximum extent practicable, to a worst case discharge, and to a substantial threat of such a discharge, of oil or a hazardous substance.

. . .

(ii) The President shall also issue regulations which require an owner or operator of a nontank vessel to prepare and submit to the President a plan for responding, to the maximum extent practicable, to a worst case discharge, and to a substantial threat of such a discharge, of oil.

A2


. . .

(C) The tank vessels, nontank vessels, and facilities referred to in subparagraphs (A) and (B) are the following:

. . .

(iii) An offshore facility.

. . .

(F) A tank vessel, nontank vessel, offshore facility, or onshore facility required to prepare a response plan under this subsection may not handle, store, or transport oil unless--

(i) in the case of a tank vessel, nontank vessel, offshore facility, or onshore facility for which a response plan is reviewed by the President under subparagraph (E), the plan has been approved by the President; and

(ii) the vessel or facility is operating in compliance with the plan.

. . .

A3


Outer Continental Shelf Lands Act

43 U.S.C.A. § 1332

Congressional declaration of policy

It is hereby declared to be the policy of the United States that—

. . .

(3) the outer Continental Shelf is a vital national resource reserve held by the Federal Government for the public, which should be made available for expeditious and orderly development, subject to environmental safeguards, in a manner which is consistent withthe maintenance of competition and other national needs;

. . .

A4



43 U.S.C.A. § 1340

§ 1340. Geological and geophysical explorations

. . .

(c) Plan approval; State concurrence; plan provisions

(1) Except as otherwise provided in this subchapter, prior to commencing exploration pursuant to any oil and gas lease issued or maintained under this subchapter, the holder thereof shall submit an exploration plan to the Secretary for approval. Such plan may apply to more than one lease held by a lessee in any one region of the outer Continental Shelf, or by a group of lessees acting under a unitization, pooling, or drilling agreement, and shall be approved by the Secretary if he finds that such plan is consistent with the provisions of this subchapter, regulations prescribed under this subchapter, including regulations prescribed by the Secretary pursuant to paragraph (8) of section 1334(a) of this title, and the provisions of such lease. The Secretary shall require such modifications of such plan as are necessary to achieve such consistency. The Secretary shall approve such plan, as submitted or modified, within thirty days of its submission, except that the Secretary shall disapprove such plan if he determines that (A) any proposed activity under such plan would result in any condition described in section 1334(a)(2)(A)(i) of this title, and (B) such proposed activity cannot be modified to avoid such condition. If the Secretary disapproves a plan under the preceding sentence, he may, subject to section 1334(a)(2)(B) of this title, cancel such lease and the lessee shall be entitled to compensation in accordance with the regulations prescribed under section 1334(a)(2)(C)(i) or (ii) of this title.

(2) The Secretary shall not grant any license or permit for any activity described in detail in an exploration plan and affecting any land use or water use in the coastal zone of a State with a coastal zone management program approved pursuant to section 1455 of Title 16, unless the State concurs or is conclusively presumed to concur with the consistency certification accompanying such plan pursuant to section 1456(c)(3)(B)(i) or (ii) of Title 16, or the Secretary of Commerce makes the finding authorized by section 1456(c)(3)(B)(iii) of Title 16.

(3) An exploration plan submitted under this subsection shall include, in the degree of detail which the Secretary may by regulation require--

A5


(A) a schedule of anticipated exploration activities to be undertaken;

(B) a description of equipment to be used for such activities;

(C) the general location of each well to be drilled; and

(D) such other information deemed pertinent by the Secretary.

(4) The Secretary may, by regulation, require that such plan be accompanied by a general statement of development and production intentions which shall be for planning purposes only and which shall not be binding on any party.

. . .

A6



43 U.S.C.A. § 1347

§ 1347. Safety and health regulations

. . .

(b) Use of best available and safest economically feasible technologies

In exercising their respective responsibilities for the artificial islands, installations, and other devices referred to in section 1333(a)(1) of this title, the Secretary, and the Secretary of the Department in which the Coast Guard is operating, shall require, on all new drilling and production operations and, wherever practicable, on existing operations, the use of the best available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies.

. . .

A7



43 U.S.C.A. § 1349

§ 1349. Citizens suits, jurisdiction and judicial review

. . .

(c) Review of Secretary’s approval of leasing program; review of approval, modification or disapproval of exploration or production plan; persons who may seek review; scope of review; certiorari to Supreme Court

. . .

(2) Any action of the Secretary to approve, require modification of, or disapprove any exploration plan or any development and production plan under this subchapter shall be subject to judicial review only in a United States court of appeals for a circuit in which an affected State is located.

(3) The judicial review specified in paragraphs (1) and (2) of this subsection shall be available only to a person who (A) participated in the administrative proceedings related to the actions specified in such paragraphs, (B) is adversely affected or aggrieved by such action, (C) files a petition for review of the Secretary’s action within sixty days after the date of such action, and (D) promptly transmits copies of the petition to the Secretary and to the Attorney General.

. . .

(6) The court of appeals conducting a proceeding pursuant to this subsection shall consider the matter under review solely on the record made before the Secretary. The findings of the Secretary, if supported by substantial evidence on the record considered as a whole, shall be conclusive. The court may affirm, vacate, or modify any order or decision or may remand the proceedings to the Secretary for such further action as it may direct.

. . .

A8


Oil and Gas and Sulphur Operations in the Outer Continental Shelf Subpart A. General

Performance Standards

30 C.F.R. § 250.107

What must I do to protect health, safety, property, and the environment?

Effective: October 1, 2011

. . .

(c) You must use the best available and safest technology (BAST) whenever practical on all exploration, development, and production operations. In general, we consider your compliance with BSEE regulations to be the use of BAST.

(d) The Director may require additional measures to ensure the use of BAST:

(1) To avoid the failure of equipment that would have a significant effect on safety, health, or the environment;

. . .

A9


Oil and Gas and Sulphur Operations in the Outer Continental Shelf Subpart D. Oil and Gas Drilling Operations

Blowout Preventer (BOP) System Requirements

30 C.F.R. § 250.451

What must I do in certain situations involving BOP equipment or systems?


The table in this section describes actions that lessees must take when certain situations occur with BOP systems during drilling activities.

If you encounter the following situation: Then you must . . .

. . .(h) Use a subsea BOP system in an ice-scour area,

Install the BOP stack in a glory hole. The glory hole must be deep enough to ensure that the top of the stack is below the deepest probable ice-scour depth.

. . .

A10


Oil–Spill Response Requirements for Facilities Located Seaward of the Coast Line

Subpart A. General

30 C.F.R. § 254.3

May I cover more than one facility in my response plan?


(a) Your response plan may be for a single lease or facility or a group of leases or facilities. All the leases or facilities in your plan must have the same owner or operator (including affiliates) and must be located in the same BSEE Region (see definition of Regional Response Plan in § 254.6).

(b) Regional Response Plans must address all the elements required for a response plan in Subpart B, Oil Spill Response Plans for Outer Continental Shelf Facilities, or Subpart D, Oil Spill Response Requirements for Facilities Located in State Waters Seaward of the Coast Line, as appropriate.

(c) When developing a Regional Response Plan, you may group leases or facilities subject to the approval of the Regional Supervisor for the purposes of:

(1) Calculating response times;

(2) Determining quantities of response equipment;

(3) Conducting oil-spill trajectory analyses;

(4) Determining worst case discharge scenarios; and

(5) Identifying areas of special economic and environmental importance that may be impacted and the strategies for their protection.

A11


(d) The Regional Supervisor may specify how to address the elements of a Regional Response Plan. The Regional Supervisor also may require that Regional Response Plans contain additional information if necessary for compliance with appropriate laws and regulations.

A12


Oil and Gas and Sulphur Operations in the Outer Continental Shelf Subpart A. General

Authority and Definition of Terms

30 C.F.R. § 550.105

Definitions.


Terms used in this part will have the meanings given in the Act and as defined in this section:

. . .

Best available and safest technology (BAST) means the best available and safest technologies that the Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment.

. . .

Regional Director means the BOEM officer with responsibility and authority for a Region within BOEM.

Regional Supervisor means the BOEM officer with responsibility and authority for operations or other designated program functions within a BOEM Region.

. . .

You means a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-use and easement.

A13


Oil and Gas and Sulphur Operations in the Outer Continental Shelf Subpart B. Plans and Information

General Information

30 C.F.R. § 550.200

Definitions.


Acronyms and terms used in this subpart have the following meanings:

(a) Acronyms used frequently in this subpart are listed alphabetically below:

BOEM means Bureau of Ocean Energy Management.

BSEE means Bureau of Safety and Environmental Enforcement.

. . .

EP means Exploration Plan.

. . .

NTL means Notice to Lessees and Operators.

OCS means Outer Continental Shelf.

(b) Terms used in this subpart are listed alphabetically below:

. . .

Modification means a change required by the Regional Supervisor to an EP, DPP, or DOCD (see § 550.233(b)(2) and § 550.270(b)(2)) that is pending before BOEM for a decision because the OCS plan is inconsistent with applicable requirements.

A14


New or unusual technology means equipment or procedures that:

(1) Have not been used previously or extensively in a BOEM OCS Region;

(2) Have not been used previously under the anticipated operating conditions; or

(3) Have operating characteristics that are outside the performance parameters established by this part.

. . .

Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes you make to an OCS plan that BOEM has disapproved (see §§ 550.234(b), 550.272(a), and 550.273(b)).

Revised OCS plan means an EP, DPP, or DOCD that proposes changes to an approved OCS plan, such as those in the location of a well or platform, type of drilling unit, or location of the onshore support base (see § 550.283(a)).

. . .

A15



General Information

30 C.F.R. § 550.202

What criteria must the Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD)

meet?


Your EP, DPP, or DOCD must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that:

(a) Conforms to the Outer Continental Shelf Lands Act as amended (Act), applicable implementing regulations, lease provisions and stipulations, and other Federal laws;

(b) Is safe;

(c) Conforms to sound conservation practices and protects the rights of the lessor;

(d) Does not unreasonably interfere with other uses of the OCS, including those involved with National security or defense; and

(e) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.

A16



Contents of Exploration Plans (Ep)

30 C.F.R. § 550.213

What general information must accompany the EP?


The following general information must accompany your EP:

. . .

(d) New or unusual technology. A description and discussion of any new or unusual technology (see definition under § 550.200) you will use to carry out your proposed exploration activities. In the public information copies of your EP, you may exclude any proprietary information from this description. In that case, include a brief discussion of the general subject matter of the omitted information. If you will not use any new or unusual technology to carry out your proposed exploration activities, include a statement so indicating.

. . .

(g) Blowout scenario. A scenario for the potential blowout of the proposed well in your EP that you expect will have the highest volume of liquid hydrocarbons. Include the estimated flow rate, total volume, and maximum duration of the potential blowout. Also, discuss the potential for the well to bridge over, the likelihood for surface intervention to stop the blowout, the availability of a rig to drill a relief well, and rig package constraints. Estimate the time it would take to drill a relief well.

. . .

A17



Contents of Exploration Plans (Ep)

30 C.F.R. § 550.219

What oil and hazardous substance spills information must accompany the EP?


The following information regarding potential spills of oil (see definition under 30 CFR 254.6) and hazardous substances (see definition under 40 CFR part 116) as applicable, must accompany your EP:

(a) Oil spill response planning. The material required under paragraph (a)(1) or (a)(2) of this section:

(1) An Oil Spill Response Plan (OSRP) for the facilities you will use to conduct your exploration activities prepared according to the requirements of 30 CFR part 254, subpart B; or

(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to include:

(i) A discussion of your regional OSRP;

(ii) The location of your primary oil spill equipment base and staging area;

(iii) The name(s) of your oil spill removal organization(s) for both equipment and personnel;

(iv) The calculated volume of your worst case discharge scenario (see 30 CFR 254.26(a)), and a comparison of the appropriate worst case discharge scenario in your approved regional OSRP with the worst case discharge scenario that could result from your proposed exploration activities; and

(v) A description of the worst case discharge scenario that could result from your proposed exploration activities (see 30 CFR 254.26(b), (c), (d), and (e)).

A18


(b) Modeling report. If you model a potential oil or hazardous substance spill in developing your EP, a modeling report or the modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.

A19



Review and Decision Process for the Ep

30 C.F.R. § 550.233

What decisions will BOEM make on the EP and within what timeframe?


. . .

(b) BOEM decision. By the deadline in paragraph (a) of this section, the Regional Supervisor will take one of the following actions:

The regional If . . . And then . . .supervisor will . . .

(1) Approve your EP, It complies with all applicable requirements,

The Regional Supervisor will notify you in writing of the decision and may require you to meet certain conditions, including those to provide monitoring information.

(2) Require you to modify your proposed EP,

The Regional Supervisor finds that it is inconsistent with the lease, the Act, the regulations prescribed under the Act, or other Federal laws,

The Regional Supervisor will notify you in writing of the decision and describe the modifications you must make to your proposed EP to ensure it complies with all applicable requirements.

(3) Disapprove your EP, Your proposed activities would probably cause serious harm or damage to life (including fish or other aquatic life); property; any mineral (in areas leased or not leased); the National

(i) The Regional Supervisor will notify you in writing of the decision and describe the reason(s) for disapproving your EP.

A20


security or defense; or the marine, coastal, or human environment; and you cannot modify your proposed activities to avoid such condition(s),

A21


Documents

IN THE UNITED STATES COURT OF APPEALS FOR … B. OCSLA Prohibits the Agency from Creating its Own Undefined Approval Process for Exploration Plans. 46 IV. BOEM’S APPROVAL OF SHELL’S