1

Final Regulatory Impact Analysis for the Final Rule on

Increased Safety Measures for Energy Development on the 

Outer Continental Shelf

RIN 1014-AA02

Bureau of Safety and Environmental 

Enforcement

March 7, 2012
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Table of Contents

EXECUTIVE SUMMARY ................................................................................................ 5

INTRODUCTION AND NEED FOR FEDERAL ACTION ................................................ 9

Investigative Reports ................................................................................................... 9

Need for Well Control and Voluntary Measures......................................................... 10

HISTORICAL INFORMATION ABOUT BLOWOUTS................................................... 12

Shallow Water Drilling Activity .................................................................................... 12

Deepwater Drilling Activity .......................................................................................... 13

Baseline Size and Duration of a Catastrophic Deepwater Blowout Spill ............................. 13

EXISTING AND NEW REGULATORY PROVISIONS .................................................. 14

Benefit-Cost Approach............................................................................................... 20

BASELINE ASSUMPTIONS IN THE BENEFIT-COST ANALYSIS.............................. 22

Baseline Estimates of Future Deepwater Drilling Activity ................................................ 22

Shallow Water Drilling Activity ................................................................................... 24

Baseline Chance of Another Deepwater Blowout Spill .............................................. 24

COMPLIANCE COSTS FOR THIS REGULATION....................................................... 25

Seafloor Function Testing of ROV Intervention and Deadman Systems - Drilling ..... 26

Seafloor Function Testing of ROV Intervention and Deadman Systems –

Workover/Completions/Abandonment................................................................... 28

Testing the Subsea BOP between Development Wells and 

Workover/Completions/Abandonment on a Single Project..................................... 29

Negative Pressure Tests ........................................................................................... 29

Installation of Dual Barriers........................................................................................ 30

Professional Engineer Certification for Well Design................................................... 31

Retrieval and Testing of a BOP Stack After a Well Control Situation......................... 32

Third Party Verification of Shear Ram Capability....................................................... 32

Paperwork Costs ....................................................................................................... 33

Summary of Annual Recurring Costs......................................................................... 34

Compliance Cost Changes between IFR and Final Rule ....................................... 35

Voluntary Measures by Industry ................................................................................ 36

AVOIDED PRIVATE-SOCIAL COSTS ......................................................................... 37

Damage to Drilling Rig............................................................................................... 37

Well Containment and Plugging ................................................................................ 38

Hydrocarbon Losses.................................................................................................. 38

Fines and Criminal Penalties ..................................................................................... 39

Summary of Avoided Private-Social Costs ................................................................ 39

AVOIDED EXTERNAL-SOCIAL COSTS...................................................................... 40

Conceptual Approach ................................................................................................ 41

Valuing Natural Resource Damages.......................................................................... 42

Caveats and Assumptions ..................................................................................... 47

Relationship between Natural Resource Damages and Spill Size and Type of Oil 

Spilled ................................................................................................................... 47

Valuing Commercial Fishery Losses.......................................................................... 48
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Data Availability...................................................................................................... 48

Background....................................................................................................................48

Revenues .......................................................................................................................51

Operating Costs .............................................................................................................55

Closures.........................................................................................................................58

Valuing Lost Recreation............................................................................................. 60

Recreational Fishing .............................................................................................. 61

Beach Recreation................................................................................................... 62

Oil Spill Response and Damage Assessment Costs ................................................. 64

Avoided Costs Associated with Reduced Loss of Life and Nonfatal Injuries ............. 66

Value of Statistical Life........................................................................................... 66

VSL Value Used in Offshore Safety Regulation..............................................................69

Nonfatal Injuries .............................................................................................................69

Other Health Effects .................................................................................................. 69

Avoided Costs Associated with Other Activities Linked Economically to Avoiding an 

Oil Spill.................................................................................................................. 70

Summary – Avoided External-Social Costs ............................................................... 71

TOTAL ESTIMATED AVOIDED SOCIAL COSTS (BENEFITS) .................................. 72

SCENARIO ANALYSIS ................................................................................................ 72

Baseline Scenario...................................................................................................... 74

Sensitivity of Compliance Costs ................................................................................ 74

Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a 

Catastrophic Blowout Spill ..................................................................................... 75

Sensitivity of Number of Deepwater Wells Drilled per Year (25% lower) ............... 76

Scenario Analysis Summary...................................................................................... 77

Alternatives................................................................................................................ 78

Small Business Alternatives................................................................................... 79

CONCLUSION .............................................................................................................. 79

Appendix A Final Regulatory Flexibility Act Analysis, RIN 1014-AA02 .................. 81

Supplementary Information ........................................................................................... 81

Breakout of Small and Large Companies Operating on the OCS.............................. 84

Deepwater ................................................................................................................. 84

Shallow water ............................................................................................................ 85

Summary of Large and Small Company OCS Activity ............................................... 85

Alternative 1, Different Compliance Requirements for Small Entities ........................ 90

Alternative 2, Testing Requirements.......................................................................... 90

Alternative 3, Paperwork Consolidation ..................................................................... 91

Alternative 4, Use Performance Rather than Design Standards................................ 91

Alternative 5, Exemptions from Rule Requirements .................................................. 92

Appendix B Natural Resource Damage Data ............................................................ 94

Appendix C Well Data ................................................................................................. 97

Appendix D Definitions............................................................................................. 100

Appendix E References ........................................................................................... 102

Appendix F Voluntary Industry Measures Review ................................................ 106
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EXECUTIVE SUMMARY

This document describes the regulatory impact analysis (RIA) conducted for the final rule, RIN 

1014-AA02, Increased Safety Measures, Drilling Operations on the Outer Continental Shelf 

(OCS). On October 14, 2010 BSEE’ predecessor agency published an Interim Final Rule (75 FR 

63346) as RIN 1010 AD68 addressing certain recommendations from the Safety Measures 

Report, and soliciting public comment on the Interim Final Rule. The Interim Final Rule was 

effective immediately, with a 60-day comment period. The Final Rule will modify, in part, 

provisions of the Interim Final Rule based on comments received, however many of the 

provisions adopted October 14, 2010, are retained without change. The resulting changes from 

the draft benefit cost analysis published with the interim final rule (IFR) are minor and are 

mostly found in the compliance cost estimates for the final rulemaking. Because of regulatory 

changes in the final rule, revised cost assumptions and estimated drilling activity, the estimated 

annual compliance costs is reduced to $131 million from $183 million in the IFR. 

Various events around the world as well as the US over the years demonstrate that catastrophic 

oil spills can and do occur. The costs associated with such spills can be enormous. As a matter 

of policy, BSEE has decided that any reasonable measures to reduce the risks of another 

catastrophic spill occurring on the OCS should be put in place and enforced. The requirements 

included in this rulemaking are such measures. They were identified in the May 27, 2010 report, 

Increased Safety Measures for Energy Development on the Outer Continental Shelf, for which 

the recommendations were peer-reviewed by seven experts identified by the National Academy 

of Engineering, or identified by industry or academic experts in materials presented to BSEE as 

part of the public forums and information gathering. Also on September 14, 2011 BSEE’s 

predecessor agency published the final joint investigation report on the causes of the Deepwater 

Horizon incident, which included multiple regulatory recommendations. Upon review of the 

report recommendations, BSEE decided to include in the interim final rule only those 

recommendations that are appropriate for change without public comment (i.e. updating 

definitions and clarifications). The remainder of the report recommendations will be addressed 

through future rulemakings subject to public comment procedures.

While the estimated costs of this rulemaking, as reflected in the compliance costs of the 

enumerated requirements of approximately $131 million per year are based on updated BSEE 

estimates from surveys of public and industry sources, quantification of the benefits is uncertain. 

The benefits are represented by the avoided costs of a catastrophic spill, which are estimated 

under the stipulated scenario as being $16.3 billion per spill avoided. These regulations will 

reduce the likelihood of another blowout and associated spill, but the risk reduction associated 

with the specific provisions of this rulemaking cannot be quantified because there are many 
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complex factors that affect the risk of a blowout event. As noted by the Secretary of the Interior 

in his July 12, 2010 decision memo suspending certain drilling activities, drilling accidents can 

have a profound, devastating impact on the economic and environmental health of a region. The 

measures codified in this rule will reduce the likelihood of such an event in the future, at a cost 

that is not prohibitive, and therefore this rulemaking is justified.

The purpose of a benefit-cost analysis is to provide policy makers and others with detailed 

information on the economic consequences of the regulatory requirements. The benefit-cost

analysis for this rule was conducted using a scenario analysis. This analysis considers a 

regulation designed to reduce the likelihood of a catastrophic oil spill. The costs are the 

compliance costs of imposed regulation. If another catastrophic oil spill is prevented, the 

benefits are the avoided costs associated with a catastrophic oil spill (e.g., reduction in expected 

natural resource damages owing to the reduction in likelihood of failure).

Avoided cost is an approximation of the “true” benefits of avoiding a catastrophic oil spill. A 

benefits transfer approach is used to estimate the avoided costs. The benefits transfer method 

estimates economic values by transferring existing benefit calculations from studies already 

completed for another location or issue to the case at hand. Accordingly, none of the avoided 

costs used in this analysis of hypothetical catastrophic spills rely upon, or should be taken to 

represent, our estimate for the DWH event commencing on April 20, 2010.

Three new requirements account for most of the compliance costs imposed by this regulation. 

These are (1) use of dual barriers in the final casing string to prevent hydrocarbon flow in the 

event of cement failure, (2) application of negative pressure tests to the production casing string

for wells drilled with a subsea BOP, and (3) testing time for the ROV to close BOP rams after 

the BOP has been installed on the sea floor. BSEE estimates that these three requirements will 

impose compliance costs of approximately $118 million per year, representing 91 percent of the 

total annual compliance costs of $131million associated with this rulemaking. These cost 

estimates were developed based on public data sources, prior experience and confidential 

information provided by several offshore operators and drilling companies. The $131 million 

estimated annual compliance costs are 29 percent less than the $183 million cost estimate for the 

interim final rule, largely reflecting a reduced estimate of the time it takes to conduct an ROV 

function test when the BOP is on the seafloor and lower negative pressure test costs resulting 

from relaxed testing requirements in the final rule relative to the IFR. These reduced costs are 

partly offset by the costs associated with a revision that precludes use of a float valve to meet the 

criteria for a second mechanical barrier and by inclusion of paperwork costs omitted from the 

estimates in the interim final rule.
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On the benefit side, the avoided costs for a representative deepwater blowout resulting in a 

catastrophic oil spill are estimated to be about $16.3 billion (in 2010 dollars).

1

 Most of this 

amount derives from detailed cleanup estimates developed by the Department of the Interior 

Office of Policy Analysis using damage costs per barrel measures found in historical spill data 

(from all sources including pipeline, tanker, and shallow water as well as deepwater wells) and 

from aggregate damage measures contained in the legal settlement documents for past spills 

applied to a catastrophic deepwater spill of hypothetical size. The rest of this avoided cost 

amount represents the private costs for blowout containment operations. In sum, three 

components account for nearly the entire avoided spill cost total: (1) natural resource damage to 

habitat and creatures, 2) infrastructure salvage and cleanup operations of areas soiled by oil, and 

(3) containment and well-plugging actions plus lost hydrocarbons.

We believe that the compliance cost estimates are closer to the actual cost than those used in the 

IFR because of the information gathered since deepwater drilling resumed in the GOM in the 

Spring of 2011. On the benefit side, the total avoided cost estimate of $16.3 billion (representing 

a measure of expected benefits for avoiding a future catastrophic oil spill) has not been revised. 

The true magnitude of an avoided spill is highly uncertain because of the limited historical data 

upon which to judge the cost of failure, the disparity between the damages associated with spills 

of different sizes, locations, and season of occurrence, and owing to the fact that the measure 

employed reflects only those outlays that we have been able to calculate based primarily upon 

data derived from past oil spills. Possible avoided losses from human health effects or reduced 

property values have not been quantified in this analysis. Moreover, the likelihood of a future 

blow out leading to a catastrophic oil spill is difficult to quantify because of limited historical 

data on catastrophic offshore blowouts.

 

1 We note that the estimates of avoided damages contained in this document, while a useful tool for the purpose of 

this benefit-cost exercise, are not relevant in calculating damages for any particular oil spill, including the DWH

spill. Although the hypothetical spill discussed in this document is similar in volumetric magnitude to estimations 

of the amount of oil released as a result of the DWH event, damages are highly specific to a particular event, and 

depend on a multitude of complex and interacting factors. This report addresses a hypothetical Gulf of Mexico spill 

that is not intended to correspond to any real event, and whose characteristics have been designed to permit 

modeling and analysis, rather than being designed to reflect to the facts of a specific event or set of events. This 

document is also not able to incorporate scientific data relating to the specific circumstances of a particular spill or 

to any other specific spill, among other limitations of the model and analysis applied in this report. Moreover, the 

nature of the economic analysis contained in this document, and the space limitations of this document, have 

required that a number of potential factors be excluded from the scope of the analysis, or have entailed other 

changes. Additionally, the estimate of potential costs avoided used in this analysis do not reflect an assessment or 

quantification of the costs of injury or fatality resulting from the DWH event. As such, the damage and cost 

estimates presented herein should not be considered reliable monetary assessments associated with the DWH event. 

This document is only intended to provide a cost-benefit analysis for a defined regulatory purpose, and is not 

intended to be used, and should not be used, for any other purpose or in any other situation. In particular, estimates 

contained in this report are not intended to be used, nor are of any relevance, in litigation relating to damages 

resulting from the DWH spill or any other spill.
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Based on the occurrence of only a single catastrophic blowout, the number of GOM deepwater 

wells drilled historically (4,123), and the forecasted future drilling activity in the GOM (160 

deepwater wells per year), we estimate the baseline risk of a catastrophic blowout to be about 

once every 26 years. Combining the baseline likelihood of occurrence with the cost of a 

representative spill implies that the expected annualized damage cost absent this regulation is 

$631 million ($16.3 billion once in 26 years, equally likely in any 1 year). To balance the $131

million annual cost imposed by these regulations with the expected benefits, the reliability of the 

well control system needs to improve by 21 percent ($131 million / $631 million). We have 

found no studies that evaluate the degree of actual improvement that could be expected from 

dual barriers, negative pressure tests, and a seafloor ROV function test and no additional 

information was provided during the public comment period. However, based upon the blowout 

risk reduction that would be achieved primarily from the three most critical safety provisions 

required by the Interim Final Rule and the Final Rule, it is reasonable to conclude that this 

rulemaking will reduce the risk for a catastrophic blowout spill event at least enough such that 

benefits will justify the costs estimated to be imposed by the regulation, or, at a minimum, 21 

percent. 
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INTRODUCTION AND NEED FOR FEDERAL ACTION

Investigative Reports

The final rule amends drilling regulations related to well control in response to recommendations 

in the Increased Safety Measures Report (Safety Measures Report) that DOI sent to the President 

on May 27, 2010.

2

 This regulation will affect all lessees and operators undertaking drilling 

operations on the OCS. The Safety Measures Report identified four items for emergency 

rulemaking:

(1) Develop secondary control system requirements;

(2) Establish new blind-shear ram redundancy requirements;

(3) Establish new deepwater well control procedure requirements; and

(4) Adopt safety case requirements for floating drilling operations on the OCS.

The provisions of this final rule address items 1) secondary control system requirements and 3) 

deepwater well control procedure requirements. The rule does not include 2) new blind-shear 

ram redundancy requirements and 4) safety case requirements for floating drilling operations.

These and other items in the Safety Measures Report require further study by industry and the 

Department of Interior to determine their efficiency and effectiveness. Measures considered 

beneficial will be proposed for future notice and comment rulemaking.

The Joint Investigation Team (JIT) report conducted by BSEE and the United States 

Coast Guard into the rig operations, and subsequent explosion, fire and sinking of the 

Mobile Offshore Drilling Unit (MODU) Deepwater Horizon made several 

recommendations consistent with the regulatory provisions in this rule.3 This final rule 

only includes the recommendations from the JIT report that are within the scope of this 

rulemaking. The only changes made to this rulemaking from the JIT recommendations 

involve updating certain definitions and adding clarifications including that a dual float 

valve by its self is not considered a mechanical barrier. Other JIT report 

recommendations will be addressed in other future rulemakings and will be available for 

public comment.

The report by the Presidential Oil Spill Commission recommended the Department of the 

Interior should require offshore operators seeking its approval of proposed well design to 

 

2

Increased Safety Measures for Energy Development on the Outer Continental Shelf, May 27, 2010, available 

at: http://www.doi.gov/deepwaterhorizon/loader.cfm?csModule=security/getfile&PageID=33598; Joint 

3

BOEMRE/USCG Report Regarding the Causes of the April 20, 2010 Macondo Well Blowout, available at: 

http://www.boemre.gov/pdfs/maps/DWHFINAL.pdf
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demonstrate that wells are designed to mitigate risks to well integrity during post-blowout

containment efforts.4

This final rule requires additional testing for the BOP stacks on the seafloor and 

professional engineering certification of well design. It does not require subsea BOP 

stacks to be fitted with additional controls and sensors beyond the existing dual blue and 

yellow control pods. Similar to the regulatory recommendations in other reports, 

appropriate Oil Spill Commission recommendations will be addressed through future 

rulemakings. 

Need for Well Control and Voluntary Measures

In general, procedures for maintaining or regaining well control can be divided into primary and 

secondary measures. Primary measures include items such as the use of drilling mud, casing and 

cementing to keep the well under control. These requirements will strengthen primary well 

control barriers thereby reducing the likelihood that secondary barriers, like the BOPs, will be 

needed. Secondary measures include the BOP stack and its redundant control devices to seal the 

well and prevent environmental or safety impacts in the case of a blowout event. The final rule 

also requires increased testing of secondary measures including a check of remotely operated 

vehicle (ROV) intervention capability and deadman switch on the seafloor to better assure 

backstop activation of the subsea BOP, should the need arise. These requirements provide 

greater protections against a catastrophic blowout event. Effective secondary measures eliminate 

or reduce the urgency of completing a relief well to stanch the flow of oil after a blowout.

The Secretary of the Interior (Secretary) has the duty to ensure that operations on the Outer 

Continental Shelf (OCS) are managed in a safe manner, under the authority of the OCS Lands 

Act (OCSLA). Section 21(b) of the OCS Lands Act provides guidance on the discharge of this 

duty as follows.

the Secretary . . . 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.

 

4 Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Part III, 

Lessons Learned: Industry, Government, Energy Policy 

http://www.oilspillcommission.gov/sites/default/files/documents/FinalReportPartIII.pdf, p. 275.
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The BSEE and BOEM carry out this duty through regulations, inspection of OCS oil and 

gas operations, the terms and conditions of leases and conditions of exploration and 

development plan approval. Although current regulations extensively address shallow 

and deepwater drilling operations, the DWH event and related investigations revealed 

that those regulations insufficiently protect the environment and those conducting 

operations on the OCS under certain situations.

There are other rationales for this regulation. The first relates to the uncertainty associated with 

actual damages and related magnitude of liability for those damages, and how that uncertainty 

may adversely influence operator behavior. Another rationale relates to information 

asymmetries. The regulatory regime in effect before promulgation of the interim final rule, 

wherein certain information did not come to the attention of regulators until after the event, 

perhaps provided too little information to regulators regarding the effectiveness of safe operating 

incentives embodied in the then existing regulatory regime. A more prescriptive regime, such as 

that contained in the interim final rule and the final rule, could assist in this regard by providing 

society with greater transparency and assurance that safety measures on all operations perform as 

expected. Lastly, because of statutory liability limits and the potential to avoid liability by 

declaring bankruptcy, offshore operators may take certain risks and cost-cutting actions absent 

explicit federal requirements relating to safety and the environment.

The regulatory changes published in these new drilling regulations are designed to reduce both 

the frequency of a catastrophic spill and the severity of its impact (through a shorter period of 

discharge). The frequency of deepwater well control events (blowouts) that could lead to a spill 

does not appear to have changed materially over time. Historic data shows that blowout 

frequencies on the OCS have stabilized at about 1 for every 275 deepwater wells over the last 

several decades (see the Baseline, Section - Chance of another Spill for a more in-depth 

discussion). Thus, while a greater number of deepwater wells are being drilled in ever deeper 

water depths, this history indicates that normal evolution of deepwater practices may not have

materially reduced the chance of a blowout event. Moreover, a blowout may pose more 

problems in deepwater where drilling a relief well is likely to take longer. Hence prescriptive

regulations are being instituted to increase the control measures that will manage and contain a 

blowout event with a greater degree of reliability.

We recognize that liability implications and increased insurance costs may compel changes by 

drilling companies independent of these regulations. Accordingly, BSEE’s predecessor agency 

(BOEMRE) commissioned an outside assessment of the voluntary measures proposed by Joint 

Industry Task Forces (JITFs) in May, 2010 as compared to these regulations. (See Appendix F). 

While the lessons learned or other measures have not been fully implemented, an assessment of 
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existing JITF proposals serve as guidance on how much of the additional costs industry may

incur are not really imposed by the new regulations. Joint Industry Task Force draft 

recommendations include use of mechanical barriers and negative pressure tests which happen to 

account for a substantial share of the compliance costs we attribute to the final rule. We did not 

adjust for these potential voluntary actions, so for this reason our compliance cost estimate may 

be higher than the actual costs imposed by this rule. 

While voluntary measures by industry may result in some of the same changes, the federal 

government has an obligation to protect offshore workers, the environment and our economic 

interests with regulations that make critical changes in systems legally enforceable. The

catastrophic failure of the primary and secondary barriers on the Macondo well (the location of 

the DWH blowout) supports federal regulations intended to reduce the identified risks. 

HISTORICAL INFORMATION ABOUT BLOWOUTS

The “no action” baseline is the recent Gulf of Mexico deepwater oil and gas activity levels and 

the historical rate of events up to and including the April 20, 2010 DWH blowout. The DWH

spill is the first U.S. Gulf of Mexico catastrophic deepwater blowout spill. 

Shallow Water Drilling Activity

While well control incidents actually occur more frequently in shallow water, the consequences 

and spill damage resulting from a blowout tends to be less than in deep water due to the 

generally lower reservoir pressure, the greater prevalence of gas rather than oil, and the presence 

of more accessible surface BOPs with diverters. From 1990-2010 BSEE has recorded 6 GOM 

shallow water well control incidents resulting in a spill of hydrocarbons. The total volume 

spilled is estimated to be 132 barrels of oil or condensate over these last two decades. If we go 

back another 20 years to 1970, we add another 6 spills for total hydrocarbon spill volume of 

138.5 barrels from 12 blowout events over the last 40 years in the GOM. Since 1970 there have 

been 32,339 shallow water wells drilled in the GOM and since 1990 there have been 13,675 

shallow water wells drilled. Over this period there have been several major revisions to the 

drilling regulations and some of these regulatory changes have specifically addressed drilling 

risks in shallow water. 

While minimal drilling activity has occurred in the Alaska program areas, spill frequencies are 

expected to be lower than the Gulf of Mexico. This result excludes consequences. The study 

supporting this conclusion (Bercha 2008) uses different spill sizes and probabilities than used in 

this analysis for a catastrophic spill event, but the conclusion remains. Because the 
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overwhelming share of historical OCS wells and future shallow water drilling is expected to be 

in the GOM, this analysis relies on historical GOM data.

Approximately 81 percent of the compliance costs for this regulation fall on deepwater wells. 

Thus, in our analysis the baseline chance of another spill and the calculation of avoided costs

focus exclusively on a scenario in which hypothetical catastrophic deepwater blowout events 

may occur randomly at some periodic rate based on the historical evidence.

Deepwater Drilling Activity

BSEE obtained these historical data on deepwater drilling from its Technical Information 

Management System database. There have been 4,123 wells spudded between 1973 and mid2010 not counting bypasses in water depths of at least 500 feet. 

There have been 20 OCS deepwater blowouts in the history of the program with 3 resulting in a 

spill during drilling operations. Only one deepwater blowout has resulted in a spill of a 

catastrophic size. The other two deepwater blowout spills were estimated to be 11 and 200 

barrels of crude/condensate spilled. 

The 20 deepwater blowouts average one blowout for about every 200 deepwater wells drilled on 

the OCS. The average number of wells between blowouts increased until about 1990 but has 

since leveled off at about one for every 275 deepwater wells.

Baseline Size and Duration of a Catastrophic Deepwater Blowout Spill

Since the baseline for this regulatory analysis is the world at the time of the DWH spill and 

without these regulations, we are using an estimate of spill volume similar to the government 

volumetric estimate of the DWH event. Estimates of potential natural resource damages and 

other avoided costs are based upon this blowout spill volume but in all other respects are derived 

from information not specific to this spill. 

The baseline size and duration of the catastrophic spill used in this analysis is taken from the 

National Incident Command’s (“NIC”) updated estimate of August 2, 2010 of the DWH spill. 

The scientific team charged by the NIC with determining flow rate concluded that 53,000 barrels 

of oil per day were leaking from the well immediately before closure by the capping stack on 

July 15, 2010. Measurements and modeling showed that, as a result of depletion of the reservoir, 

the daily flow rate decreased over the 87 days prior to the capping of the well; the scientific team 

estimated at the beginning of the spill, the flow rate was 62,000 barrels per day. BSEE is using 

the estimate of 53,000 barrels a day for 90 days as the figure upon which to base the estimated 

avoided costs for this regulatory analysis. While a catastrophic deepwater spill may have a 

higher flow rate in a worst-case scenario, the 53,000 barrels a day for 90 days is a reasonable 
14

proxy for regulatory cost-benefit analysis purposes. This scenario results in an oil spill of 4.77

million barrels.

This 4.77 million barrel estimate is also consistent with the Central Planning Area Gulf of 

Mexico Sale 216/222 SEIS.

5

 It is approximately the mid-point of a potential catastrophic

deepwater GOM spill event. The range for a catastrophic spill event is assumed to be between 

2.7 and 7.2 million barrels. The 216/222 SEIS catastrophic spill event assumptions are excerpted 

below.

3.1.3.2. Deep Water

For the purposes of this analysis, an uncontrolled flow rate of 30,000-60,000 barrels per 

day is assumed for a catastrophic blowout in deep water. This flow rate is based on the 

assumption in Section 3.1.3, well test results, and the maximum expected flow rate of the 

2010 Deepwater Horizon blowout, which occurred in deep water. Therefore, total 

volume of oil spilled is estimated to be 2.7-7.2 million barrels over 3-4 months. In 

addition, deepwater drilling rigs hold a large amount of diesel fuel (10,000-20,000 

barrels). Therefore, it is assumed that any remaining diesel fuel from a sunken drilling 

rig would also leak and add to the spill.

EXISTING AND NEW REGULATORY PROVISIONS

This final rulemaking revises selected sections of 30 CFR 250 subparts D, E, F and Q as related 

to the drilling of new wells. As in most benefit-cost analysis studies a full compliance scenario 

is assumed and analyzed for the baseline and new regulatory requirements. We expect only a 

portion of the proposed changes in Subpart D will add material capital or operating costs (some 

of which will be significant) to the drilling of new OCS wells.

6

 Table 1 compares the existing 30 

CFR 250 Subpart D provisions with the new provisions. As demonstrated since the publication 

of the IFR these requirements can be implemented immediately using existing equipment and 

established practices. Those changes that will impose significant costs include:

1. Seafloor function testing of ROV intervention and deadman systems; 250.449(j) and (k), 

250.516(d) and 250.616(h).

2. Negative pressure testing of the final casing string for wells drilled with a subsea BOP; 

250.423(c).

3. Installation of dual barriers for the final casing string; 250.420(b).

 

5

OCS EIS/EA BOEMRE 2011-027 http://www.gomr.boemre.gov/PDFs/2011/2011-027.pdf

6

Identical costly new requirements for subsea function testing of ROV intervention during drill operations (Subpart 

D) also apply to well completion (Subpart E) and workover (Subpart F) operations.
15

4. Professional engineer certification that the well design is appropriate for expected well 

bore conditions; 250.420(a).

5. Retrieval and testing of BOP after a shear ram has been activated in a well control 

situation; 250.451(i).

6. Third party verification that the shear rams will shear drill pipe under maximum 

anticipated pressure; 250.416(e)

7. Additional record keeping and other paperwork required by the regulations.
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Table 1 - 30 CFR 250 Subpart D Provisions

EMERGENCY SUBPART D/E/F/Q FINAL RULE PROVISIONS

Regulation Summary Existing Regulatory 

Provisions (before 

IFR

New Regulatory Provisions (final 

rule)

Cost

30 CFR 

§250.415(f)

Evaluate best 

practices in 

API RP 65-

Part 2

- No evaluation 

required

- Requires the operator to evaluate 

the best practices according to API 

RP 65-Part 2 and submit a written 

description for the evaluation. 

- No meaningful 

cost

- Written description must include 

the mechanical barriers and 

cementing practices the operator 

will use for each casing string.

- API RP 65 Part 2 addresses 

cementing practices and factors 

affecting cementing success.

30 CFR 

§250.416(d),

§250.1705

Submittal of 

schematics of 

all control 

systems for 

BOP stack

- Schematic of BOP 

system showing inside 

diameter of BOP stack, 

number and type of 

preventers, location of 

choke and kill lines

- Schematics of all control 

systems, including primary 

controls, secondary controls, and 

pods for the BOP system must be 

submitted.

- No meaningful 

cost

- Location of the controls must be 

included

30 CFR 

§250.416(e), 

§250.1712(g)

Independent 

third party 

verification 

to ensure 

blind-shear 

rams are 

capable of 

cutting the 

drill pipe 

used

- Information that the 

blind-shear ram is 

capable of shearing the

pipe

- Verification that the blind-shear 

rams installed in the BOP stack are 

capable of shearing the drill pipe

or tubing in the hole under 

maximum anticipated surface 

pressure.

- Independent third 

party certification 

will require a small 

cost per well

- No independent third 

party certification 

required

- Independent third party must be a 

technical classification society or 

an API licensed manufacturing, 

inspection, certification firm, or 

licensed professional engineering 

firm.

- Will add moderate 

costs

30 CFR 

§250.418(i)

Submit 

qualifications 

of 

independent 

third parties 

with APD

- No independent third 

party certification 

required

- Description of qualifications in 

accordance with §250.416 (e)

- No meaningful 

cost
17

30 CFR 

§250.420(a)(

6), 

§250.1712(g)

Professional 

Engineer 

certification

of well 

casing and 

cementing 

program

- No PE certification

required - Certify the casing cementing 

design is appropriate for the 

purpose it was intended under 

expected wellbore conditions

- Small cost per well 

if performed by an 

independent third 

party

- No cost if PE 

certification is done 

in house

- Assumed that some 

majors would verify 

in-house; smaller 

operators will use 

third party

30 CFR 

§250.420(b)(

3)

Dual barriers - No requirement - Operator must install dual 

barriers including one mechanical 

barrier in each annular flow path.

- Installation of dual 

barriers and the 

increased drilling 

depth required to 

install the 

mechanical barrier is 

estimated to be on 

average 12 hours.

- Will add 

significant costs to 

regulation.

30 CFR 

§250.423(b)(

2)

Pressure test 

on the casing 

seal 

assembly

- Perform a pressure 

test on all casing 

strings (except 

drive/structural) 

according to 250.423 

(a)

- Additional pressure test for the 

intermediate and production casing 

strings on the casing seal assembly 

to ensure proper installation of the 

casing in the subsea wellhead.

- Pressure tests are 

already required, no 

extra equipment 

time

- No requirement to 

ensure proper 

installation of the 

casing in the subsea 

wellhead

- Each pressure test 

only takes a few 

minutes

- No meaningful 

cost
18

30 CFR 

§250.423(c)

Negative 

pressure test

- No negative pressure 

test required

- Perform a negative pressure test 

to ensure proper installation of the 

final casing string or liner and 

prior to unlatching the BOP for all 

wells drilled with a subsea BOP.

- Negative pressure 

test will take 3 hours

for each required 

string of casing

- Will result in 

significant costs for 

the regulation

30 CFR 

§250.428

If operator 

receives

indication of 

inadequate 

cement job, 

conduct

further tests.

- No specific 

evaluation required

Operator must: run a temperature 

survey, run a cement evaluation 

log; or use a combination of these 

techniques.

- These tests would 

normally be

conducted by a 

prudent operator. 

This regulation will 

not add additional 

costs.

30 CFR 

§250.442(e)

Maintain 

ROV and a 

trained crew

- ROVs used for visual 

inspection every 3 

days; 250.446(b)

- Required to maintain an ROV 

and trained crew on each floating 

rig on a continuous basis.

- All rigs are 

assumed to have an 

ROV on board. This 

regulation will not 

add additional costs.

- ROV must be capable of shutting 

in the well during emergency 

situations

- Regulation does 

not require a timed 

test, therefore 

current ROVs will 

be capable of 

performing all 

required functions.

30 CFR 

§250.442(f)

Provide an 

autoshear 

and deadman 

system for 

dynamically 

positioned 

rigs

- No 

autoshear/deadman 

system requirement

- All dynamically positioned rigs 

must have an autoshear and 

deadman system

- Industry standard 

for dynamically 

positioned rigs is to 

have autoshear/

deadman systems

- No meaningful 

cost

30 CFR 

§250.442(g)

Barriers on 

BOP control 

panels to 

prevent 

accidental 

disconnect 

functions

- No two-handed 

requirement

- Incorporate enable buttons on 

control panels to ensure twohanded operations for all critical 

functions.

- No meaningful 

cost

30 CFR 

§250.442(h)

Label subsea 

BOP control 

panel

- No labeling 

requirement

- Clearly label all control panels, 

such as hydraulic control panels 

and ROV interface on the BOP

- No meaningful 

cost
19

30 CFR 

§250.442(i)

Develop 

management 

system for 

BOP

- No management 

requirement

- Develop and use a management 

system for operating the BOP 

system

- No meaningful 

cost

- Written procedures for operating 

the BOP stack and LMRP

- Minimum knowledge 

requirements for personnel 

authorized to operate and maintain 

critical BOP components

30 CFR 

§250.442(j)

Training for 

BOP 

equipment

- No training 

requirement

- Train BOP personnel in 

deepwater well control theory and 

practice in accordance with 30 

CFR 250, Subpart O

- No meaningful 

cost

30 CFR 

§250.446(a),

§250.1708(a)

Document 

maintenance 

and 

inspections 

to BOP 

system

- No documentation 

requirement

- BOP maintenance and 

inspections must meet or exceed 

provisions of Section 17.10 and 

18.10 Inspections; 17.11 and 

18.11, Maintenance; 17.12 and 

18.12 Quality Management in API 

RP 53

- No meaningful 

cost
20

30 CFR 

§250.449(j),

§250.516(d), 

§250.616(h),

§250.1707(h)

Subsea 

function test 

for ROV 

intervention 

on a subsea 

BOP stack

Additional 

stump testing 

requirements

- No initial test on the 

seafloor

- All ROV intervention functions 

must be tested during the stump 

test and one set of rams during the 

initial test on the seafloor.

- Initial test on the 

seafloor is not 

industry standard

and is estimated to 

take about 2 hours.

- Stump test BOP stack - ROV hot stabs must be function 

tested and capable of actuating at 

least 1 set of pipe rams, 1 set of 

blind-shear rams and unlatching 

the LMRP

- No meaningful 

cost since stump 

tests can be 

conducted topside 

prior to BOP 

deployment.

- Operator must examine all 

surface and subsea well control 

equipment to ensure that it is 

properly maintained and capable of 

shutting in the well during 

emergency operations

- Will add 

significant costs to 

well drilling, 

workover, 

abandonment and 

completion 

operations 

30 CFR 

§250.449(k),

§250.516(d), 

§250.616(h),

§250.1707(h)

Autoshear/

Deadman 

function test

- No required function 

test

- The autoshear and deadman 

systems must be function tested 

during the stump test and the 

deadman tested on the seafloor.

The deadman test is 

estimated to take 

about 2 hours on 

average.

30 CFR 

§250.451(i)

Emergency 

activation of 

blind or 

casing shear 

rams

- No required action - If the blind-shear or casing shear 

rams are activated in a well control 

situation, the BOP must be 

retrieved and fully inspected and 

tested

- Emergency 

situation only, will 

incur significant loss 

of rig time when 

activated

30 CFR 

§250.456(j),

§250.514(d),

§250.614(d),

§250.1709

Displacement 

of kill-weight 

fluid from 

the wellbore

- No required action Submit APM, with reasons for 

displacing the kill-weight drilling 

fluid and provide procedures 

describing how the fluids will 

safely displace. 

- No meaningful 

cost

Benefit-Cost Approach

The purpose of this regulatory impact analysis is to meet the requirements of Executive Order 

12866 (Regulatory Planning and Review) and OMB Circular A-4 by providing policy makers 

and others with detailed information on the consequences of the regulatory requirements. This is 

a significant rule because of the policy implications and estimated annual costs of more than 

$100 million. 

A benefit-cost analysis requires estimating the net benefits associated with the rule. Net 

economic benefits are total benefits less total costs. The benefits from this rulemaking include 
21

the reduced potential for catastrophic deepwater blowouts and resulting damage as a 

consequence of stricter well control requirements. Costs include compliance costs associated 

with the specific provisions of the rule, such as wider use of best well design practices, extra 

testing and certification requirements, along with any additional administrative costs anticipated 

as a result of the rule.

A benefit-cost analysis is different from an economic impact analysis. The effects measured in a 

benefit-cost analysis reflect direct first-order real resource market outcomes, such as more 

abundant or higher valued outputs and the accompanying enhancement of consumer utility, 

along with the costs imposed by the regulatory action as expressed in terms of the market value 

of the scarce factors of production needed to comply with the rulemaking. In contrast, while an 

economic impact analysis could include these output measures as well, it tends to focus upon 

broad macroeconomic measures, such as national income, employment, wages, and revenue 

transfers, among others, as they may be relate to specific industries and geographical locations 

associated with the regulatory requirements. Anecdotal economic impact information is 

provided for commercial fisheries impacts consistent with the avoided cost estimate for this 

analysis.

The approach used in this benefit-cost report utilizes consumer surplus measures to estimate 

avoided-cost impacts on recreation, and producer surplus measures to estimate avoided-cost 

impacts on industry, i.e., the benefits of the regulatory action, rather than measuring these 

benefits from disparate economic considerations such as lost wages and employment in affected 

industries (hotels, restaurants, charter fishing boats, etc.). Estimated output impacts do not 

account for the value of the increased environmental benefits (or reduction in potential 

environmental damages) that accrue to individuals, as part of consumer surplus. 

In the case of this rule, we have not been able to quantify the precise extent to which the 

new safety measures required by this rulemaking can be expected to reduce the chance of 

another catastrophic oil spill. A study by Det Norske Veritas for the Canadian National 

Energy Board titled Beaufort Sea Drilling Risk Study dated March 11, 2010 used a fault 

tree analysis methodology to develop estimates of the change in the probability of a 

blowout associated with several secondary well control measures like enhancements to 

the BOP. We have not discovered sufficient data that would allow adapting that 

methodology to the change in the probability of blowout associated with the enhanced 

primary well control measures in this rulemaking. Nor have we found other studies that 

evaluate the degree of improvement that could be expected from enhanced barriers, 

pressure tests, and a seafloor ROV function check.
22

The preamble to the interim rule requested comments on the availability of appropriate 

well design reliability studies. Commenters did not cite any applicable reliability studies.

BASELINE ASSUMPTIONS IN THE BENEFIT-COST ANALYSIS

The baseline for this rulemaking is the world without these new regulations. The “no action” 

baseline is the recent Gulf of Mexico deepwater oil and gas activity levels and the historical rate 

of events up to and including the April 20, 2010 DWH blowout. The DWH spill is the first U.S. 

Gulf of Mexico catastrophic deepwater blowout spill. While there have been other OCS spills 

and blowouts, the requirements in this rule are primarily focused on deepwater and designed to 

prevent or more quickly control deepwater blowouts. Estimates of potential natural resource 

damages are based on a spill volume similar to the government estimate of the DWH blowout 

spill volume but in all other respects are derived from information not specific to this spill. 

Estimates are also consistent with projections of future GOM deepwater drilling activity7. 

We estimated the baseline rates of deepwater blowouts, injuries, fatalities and spills directly from 

historical data. This baseline assumes that industry has not voluntarily implemented additional 

safety and protection measures as a result of the lessons learned from the DWH spill. This 

assumption may overstate likely future blowout chances under existing regulations since industry 

can be expected to implement some new safety measures on its own. Because of this uncertainty 

about many of these changes, difficulty of quantifying them and the time limitations under which 

analysis was conducted for this rulemaking, we did not adjust the baseline for any voluntary 

measures.

Baseline Estimates of Future Deepwater Drilling Activity

The key drilling input for this benefit-cost analysis is the future number of GOM deepwater 

wells. BSEE projected average deepwater drilling activity for 2011 – 2030 in the Central and 

Western GOM using 6 different methods and then calculated the 20-year average to determine a 

reasonable drilling projection. The component projections were based on recent trends in 

 

7 The damage and loss estimates in this analysis are purely hypothetical and do not provide values applicable to the 

DWH event. They are not pertinent to the DWH event because they rely on dollar per barrel factors derived from a 

number of earlier spills. These dollar measures vary widely across the different spills in the sample set so the 

average is not relevant to any actual spill. The exception is for well containment costs cited directly by BP and 

extrapolated to a hypothetical GOM deepwater catastrophic blowout event postulated in this analysis. Otherwise, 

there is insufficient information available at this time to determine the magnitude of the costs that could have been 

avoided, including natural resource damages, from the DWH event. Moreover, the estimate of potential costs 

avoided used in this analysis do not reflect an assessment or quantification of the costs of injury or fatality resulting 

from the DWH event. As such, the damage and cost estimates presented herein should not be considered reliable 

monetary assessments associated with the DWH event.
23

drilling, leasing, aggregate production forecasts and other available data. Using these 

techniques we estimated there will be an average of 160 deepwater wells drilled annually over 

the next 20 years.

However, going forward this pace of deepwater drilling activity may be optimistic even if 

drilling regulations did not change. The main reason is that a larger share of future deepwater 

wells will be deeper (25,000 to 36,000 feet as opposed to under 22,000 feet in the recent past) 

requiring more time to drill and complete. Together with the new safety regime8, operators may 

average fewer wells drilled each year. In the section titled Sensitivity of Number of Deepwater 

Wells Drilled per Year (25% lower) we estimate the benefits/costs under an alternative scenario 

of 120 deepwater wells per year.

The drilling of 160 deepwater wells per year is used to estimate the expected interval before 

another catastrophic blowout similar to the DWH. This projection was divided into 112 wells 

drilled from floating rigs and 48 from rigs on deepwater production platforms. The recent 

historical annual well count is shown in Figure 1.

9

Figure 1 - Historical Deepwater Wells (Greater than 500 feet)

 

8 Under the new safety regime, deepwater drilling permits require more complex analyses by both operators of 

deepwater leases and BSEE prior to approval. These complex reviews include determination and verification of 

worst case discharge and planned blowout scenarios (included in revised plans) for potential blowouts, submittal and 

review of containment plans (including well screening tool) for potential blowouts, review of blowout preventer 

(BOP) diagrams and shearing capabilities, and review of certifications of casing and cement analyses proposed for 

the wells.

9 All counts of wells exclude bypasses which are often included in other BSEE counts of spudded wells. These 

counts also exclude well completion and workover operations which involve re-entering a wellbore and redeploying of BOPs and ROVs. The count includes sidetracks.

DW Wells >500 ft (historical)

0

50

100

150

200

250

300

19941995199619971998199920002001200220032004200520062007200820092010

Year

Wells

DW Wells >500 ft
24

Shallow Water Drilling Activity

While the greatest cost imposed by this regulation will affect deepwater drilling activities using 

MODUs, new regulatory testing and casing requirements apply to wells drilled both in shallow 

water and deep water. Future regulatory compliance costs for shallow water wells are estimated 

using the 2009 GOM shallow water drilling activity rate of 186 wells a year and the additional 

costs imposed on shallow wells by this regulation.

Baseline Chance of Another Deepwater Blowout Spill

The baseline chance of another catastrophic deepwater blowout spill uses only deepwater 

drilling, blowout and spill data on the U.S. federal OCS. BSEE has obtained this historical data 

from its Technical Information Management System database. There have been 4,123 wells 

spudded between 1973 and mid-2010 not counting bypasses in water depths of at least 500 feet. 

There have been 20 OCS deepwater blowouts in the history of the program with 3 resulting in a 

spill during drilling operations. Only one deepwater blowout has resulted in a spill of a 

catastrophic size. The other two deepwater blowout spills were estimated to be 11 and 200 

barrels of crude/condensate spilled. 

The 20 deepwater blowouts average one blowout for about every 200 deepwater wells drilled on 

the OCS. The average number of wells between blowouts increased until about 1990 but has 

since leveled off at about one for every 275 deepwater wells.

Using the estimated 160 new deepwater wells that will be drilled annually, we estimate a 

catastrophic blowout spill under current regulations and practices to be 1 in 4,123 wells. This 

implies a baseline major spill once every 26 years under current deepwater drilling rates. A 

sensitivity analysis was conducted on this baseline probability assumption. The results of that 

analysis can be found in the section titled Scenario Analysis.

Uncertainties

Available data on drilling system reliability do not allow computation of the blowout risk 

reduction associated with the specific provisions in this rulemaking. Future long term studies 

should be conducted to assess the likely effectiveness of these and other increased safety 

measures, using statistical analysis of historic information on existing well configurations and 

testing practices. Cross-sectional data that are now collected but not captured in the BSEE TIMS 

data base may enable studies that assess how requirements for subsea ROV and deadman testing, 

use of negative pressure tests, dual barriers in the final casing string, along with the remaining 

items required in this rulemaking, could improve well control performance. 
25

We can expect the risk and impact of a deepwater catastrophic blowout will be lessened by other 

factors not specifically addressed in this analysis. Industry and government reaction to the DWH

spill has added experience that will improve the human factors of planning and response. The 

technology used to mitigate spill effects before a relief well is completed is currently deployed 

and on stand-by in case of a blowout and subsea BOP failure. While these are significant 

advances, the nature and impact of these changes are not easily quantifiable and are not included 

in the benefit-cost baseline.

Another area for further inquiry involves determining the impact and cost of a catastrophic 

deepwater oil spill. Ongoing studies will be helpful to more fully record the effects of a 

catastrophic deepwater blowout on the natural and human environments in the Gulf of Mexico. 

One ongoing BOEM study is titled Simulation Modeling of Ocean Circulation and Oil Spills in 

the Gulf of Mexico (GM110-2). Universities and consultants are conducting environmental 

studies of the Gulf of Mexico and the impact of the DWH event over the next decade. We also 

note that the basis for our damage estimates relies on dollar per barrel factors derived from 

historic near-shore spills which may not be the best analogies for a future deepwater spill far 

from land. If future estimates of the individual cost elements of a hypothetical deepwater spill 

imply that the resulting social costs vary significantly from our hypothetical $16.3 billion benefit 

estimate (discussed below), then the future analysis should be adjusted to reflect the new 

estimate.

COMPLIANCE COSTS FOR THIS REGULATION

This section addresses the main compliance costs resulting from this regulation. The compliance 

costs fall primarily on lessees and operators operating on the federal OCS because the rule raises 

drilling costs for each new deepwater well and shallow water well on the OCS. These new 

requirements add mechanical barriers to well design requirements and time for testing several 

features during drilling operations. BSEE estimates that each year the seven activities discussed 

in this section will add $131 million to the cost of operations on the OCS. For purposes of 

calculating annual costs associated with this rulemaking, we assume that in an average year 

operators will drill 160 deepwater wells and 186 shallow wells on the federal OCS as well as 

complete 36 workover, completion and abandonment operations using a subsea BOP. 
26

Seafloor Function Testing of ROV Intervention and Deadman Systems 

- Drilling 

Current regulations at 30 CFR 250.449(b) require a stump test of the subsea BOP system. In a 

stump test, the subsea BOP system is placed on a simulated wellhead (the stump) on the rig 

designated area. The BOP system is tested on the stump to ensure the BOP is functioning 

properly. New sections §250.449(j), §250.516(d), §250.616(h) and §250.1707(h) require that all 

ROV intervention functions on the subsea BOP stack must be tested during the stump test and 

one set of rams must be tested by an ROV on the seafloor. New sections §250.449(k), 

§250.516(d), §250.616(h) and §250.1707(h) require that the autoshear and deadman systems be 

function tested during the stump test, and the deadman system tested during the initial test on the 

seafloor. The initial test on the seafloor is performed as soon as the BOP is attached to the subsea 

wellhead. This section provides the calculations for drilling subsea ROV testing compliance 

costs. The following section provides the calculations for workovers, completions and 

abandonment operations.

BSEE assumes it is an industry standard to have ROVs on board. Regulation 250.446(b) 

requires that all subsea BOPs and marine risers must be visually inspected every 3 days; ROVs 

are the industry standard for meeting this requirement, therefore we reasonably assume all rigs 

have ROVs. BSEE also assumes dynamically positioned rigs have autoshear/deadman systems. 

BSEE has data showing that all dynamically positioned rigs being used in the Gulf of Mexico 

employ an autoshear/deadman system. Therefore, it is assumed to be industry standard for all 

dynamically positioned rigs to have an autoshear/deadman system.

These new requirements will provide a higher probability that a well will be secured in an 

emergency situation and prevent a possible loss of well control. Autoshear and deadman control 

systems activate during an accidental disconnect or loss of power respectively. The ROV test

requirement will ensure that the dedicated ROV has the capacity to close a BOP ram on the sea 

floor using its pump or an available accumulator bank. The deadman test on the seafloor verifies 

that the BOP closes automatically if both hydraulic pressure and electrical communication are 

lost with the rig.

BSEE’s predecessor agency conducted a survey to investigate the potential impact of subsea 

ROV testing. Several drilling contractors, lease operators and equipment manufacturers were 

asked: “How long would it take to function test the ROV to verify that the ROV could be used to 

close one set of blind-shear rams, one set of pipe rams, and disconnect the LMRP?” Results 

averaged about 24 hours of lost rig time to perform these subsea tests. 
27

However, the regulation only requires one set of rams and the deadman system to be tested on 

the seafloor; not two rams (one pipe ram/one blind-shear ram) nor disconnecting the LMRP. The 

24 hour survey average in the IFR was an overestimate based on the final regulations. Since the 

publication of the interim final rule in October, 2010, BSEE has had the opportunity to observe 

stump tests and subsea tests required by this rulemaking. The testing of one set of rams on the 

seafloor is estimated to add about 2 hours on average to the testing time. The deadman system 

seafloor tests are estimated to take 2 additional hours. The total additional time for the subsea 

tests is estimated to be about 4 hours on average.10 The estimate of 4 hours is a reduction from 

the 24 hours used for the interim final rule analysis. The regulatory provision will not affect 

platform rigs or shallow wells since they do not use subsea BOPs.

Multiplying the number of estimated deepwater MODU wells each year (112) by the weighted 

average day rate ($916,622) by 4/24 hours yields a total estimated compliance cost for this 

provision of $17.1 million. This is one-sixth the cost estimated in the analysis for the interim 

final rule. Table 2 reports the number of the various kinds of deepwater drilling rigs operating in 

the Gulf of Mexico and the rig (day) rates used to calculate the cost of the extra 4 hours added to 

drill time. The rig rate was taken from RIGZONE and increased (loaded) to reflect the assumed 

cost of the assorted support contractors on the rig whose services are not covered in the day rate. 

The loaded day rate is appropriate because BOP and other tests cannot be scheduled with 

accuracy so they occur in the middle of the drilling operations. The subsea BOP is not lowered 

to the seafloor until after the surface casings are set (maybe 10-30 days into the drilling) when 

the increased down-hole pressure and risks for gas kicks and blowouts are possible. Most 

deepwater wells are drilled more than 100 miles offshore and contractors and supplies that 

contribute to the loading of the day rate are contracted for the duration of the drilling operation. 

Part of the reason that crews stay on the rig for 2 weeks at a time is that round trips to shore are 

expensive, so “unloading” and “reloading” for part of a day is likely to cost more than 

maintaining capability at the ready. Additionally, delays and problems occur frequently during 

drilling operations and it is standard practice to maintain the contractor and company capability 

available to resume operations as soon as the problem is resolved. 

 

10 The ROV stump test components are not considered because they are not expected to significantly increase testing 

time. Some operators simulate the hydraulic flow of an ROV to perform the stump test on the BOP stack, while 

others use an actual ROV to stump test the BOP stack; this regulation removes the option of simulating hydraulic 

flow and requires the use of an ROV during the stump test.
28

Table 2 –Rig Counts, Day Rates, and Annual Drill Rates

Rig Type Number of Rigs Loaded Day Rate Wells Drilled/Year

Drillship 11 $1,000,000 33

Deep Semisubmersible 21 $923,953 63

Low Semisubmersible 4 $715,792 16

MODU Total or Weighted 

Average

36 $916,622 112

Platform (deepwater) 10 $400,000 48

Shallow water n/a $200,000 186

Seafloor Function Testing of ROV Intervention and Deadman Systems 

– Workover/Completions/Abandonment

As is the case with drilling operations, regulations in place before the IFR did not require subsea 

ROV function testing of the BOP during workover completions, or abandonment operations. 

New sections 250.516(d), 250.616(h) and §250.1707(h) require testing of ROV intervention 

functions and the autoshear/deadman systems during the stump test, and a function test of at least 

one set of rams and the deadman system during the initial test on the seafloor. These sections

extend the requirements added to deepwater drilling operations (discussed in the previous 

section) to well completion operations, workover and abandonment operations using a subsea 

BOP stack. Successful exploratory wells are typically temporarily abandoned until additional 

equipment is installed to produce the reservoir. When the operator is preparing to produce the 

well it is often completed using a different rig or redeployment of the original rig. This testing 

time for completion operations is estimated to also be 4 hours. This is in addition to the 4 hours 

testing time discussed in the previous section for selected wells. BSEE estimates that on average 

each year there will be 12 completions, 12 workovers and 12 abandonments each year employing 

a subsea BOP. Using a weighted average of MODU day rates (Table 2), 36 (12 workovers [plus] 

12 completions [plus] 12 abandonments) redeployments of a BOP will cost $5.5 million. This is 

one-third of the cost estimated in the interim final rule analysis. This compliance cost reduction 

is the result of the testing time being reduced to 4 hours from 24 hours while being partially 

offset by the revised counts of workovers/completions and the addition of the 12 annual 

abandonment subsea BOP tests not counted in the interim final rule.
29

Testing the Subsea BOP between Development Wells and 

Workover/Completions/Abandonment on a Single Project

BSEE past history, practice and custom was that departures were routinely but not always 

granted when an Operator wished to move a subsea BOP between wells on the same project 

without pulling the BOP to the surface for a visual inspection and stump test. Comments on the 

IFR claimed that the compliance cost for rulemaking was greatly underestimated. Commenters 

claimed the cost to pull a BOP for a visual inspection is underestimated and the real cost of 

pulling a subsea BOP for a visual inspection would result in a $5 - $15 million opportunity cost.

BSEE’s termination of the practice allowing Operators to “hop” a subsea BOP between wells on 

the same development project is not the result of this regulation, but rather BSEE’s cessation of 

the practice of granting departures to existing regulations (30 CFR 250.446). BSEE 

acknowledges the opportunity cost to pull a subsea BOP for the full suite of inspections may 

range between 5 -14 days. BSEE estimates that this practice may have applied up to 50 wells or 

workover/completions/abandonments using a MODU each year. If an average of 7 days is added 

to the time required to drill or complete these 50 wells, the increased cost would be

approximately $320.8 million (50 wells x 7 days x $916,622/day). This is a significant cost to 

deepwater Operators, but it is not a cost directly applicable to this rulemaking.11 It is the result 

of a tighter regulatory environment through the BSEE practice of no longer granting departures 

for the regulatory requirement to pull the subsea BOP stack between each well on a project.

Negative Pressure Tests

Section 30 CFR 250.423 currently requires a positive pressure test for each string of casing, 

except for the drive or structural casing string. This test confirms that fluid from the casing 

string is not flowing into the formation. In the IFR, section §250.423(c) required that a negative

pressure test be conducted for all intermediate and production casing strings for wells drilled 

with a subsea BOP. The final rule §250.423(c) only requires that the negative pressure test be 

conducted on the final casing before the subsea BOP is removed or if the BOP is to be removed 

during drilling operations.

The negative pressure test will reveal whether gas or fluid from outside the casing is flowing into 

the well and ensures that the casing and cement provide a seal. Maintenance of pressure under 

both tests ensures proper casing installation and the integrity of the casing and cement. While 

some companies routinely conduct negative pressure tests on casing strings as a best practice, we 

do not have the data to determine the frequency at which this occurs, so we assume all negative 

pressure testing is a new cost imposed by this regulation. Based on typical industry procedures, 

we estimate each new negative pressure test will take approximately 3 hours. 

 

11 We discuss this cost, not because it results from this final rule, but because commenters raised the issue.
30

Three hours is equivalent to 0.125 days. Using the weighted average of the MODU day rates 

(Table 2) 0.125 days times 1 casing string times 112 MODU wells yields an annual additional 

costs in deepwater for this test of $12.8 million. The estimated duration for an average negative 

pressure test was doubled from 90 minutes used in the interim rule to 3 hours based upon 

improved estimates of the time it takes both to create and then hold the low pressure state. The 

negative pressure test requirement for wells drilled with a surface BOP was removed from the 

final rule. Therefore compliance costs no longer include estimated costs of negative pressure 

tests for deepwater wells drilled from a platform or for shallow water wells. Additionally, the 

number of casing strings subject to the negative pressure test has been reduced substantially from 

the requirements in IFR. The IFR required that the negative pressure test be conducted on all 

intermediate and production casing strings. We previously estimated, on average, a deepwater 

well required 5 negative pressure tests and a shallow water well 3 tests. The final rule only 

requires a single negative pressure test for deepwater wells drilled with a subsea BOP. This 

change results in a significantly lower compliance cost for this regulation as shown in Table 5.

Installation of Dual Barriers

Regulations before the issuance of the IFR did not require the installation of dual barriers

although this requirement could be considered the use of best available and safety technology 

(BAST) per § 250.107(d). For this analysis the requirement is considered new because the 

government had not previously specified this technology in the regulations. New regulatory 

section § 250.420(b)(3) requires the operator install dual barriers including cement barriers for 

the final casing string. This second mechanical barrier prevents hydrocarbon flow in the event of 

cement failure at the bottom of the well. The operator must document the installation of the dual 

barriers and submit this documentation to BSEE in the End-of-Operations Report (Form BSEE0125). These new requirements will ensure that the best casing and cementing design will be 

used for a specific well. 

The IFR allowed dual barriers which could include one float valve. We estimated that all wells 

will require a second mechanical barrier and that the installation time would be 30 minutes and 

an equipment cost of $20,000. This yielded an IFR annual compliance cost estimate of $10.3 

million for all OCS wells. 

The regulatory provision for mechanical barriers in § 250.420(b)(3) has been changed from the 

IFR and now requires the second barrier must be mechanical. BSEE no longer considers a float 

valve to be a mechanical barrier meeting the requirement of this provision. The result of this 

change is that the compliance cost estimate for this requirement at § 250.420(b)(3) increases 
31

significantly. The provision may add anywhere from 4 to 24 hours of drilling/rig time to all new 

OCS wells.

A well may require 4 or more hours (depending on the drilling depth) of additional drilling time 

to extend the well the 50 feet deeper necessary to install the mechanical barrier and the 

corresponding additional cement necessary to ensure integrity of the mechanical barrier. An 

alternative to drilling the well 50 feet deeper is to wait until after the primary cement job hardens 

and install the mechanical plug above the wiper plug. This requires tripping the drill string in 

and out to install the mechanical barrier and re-cementing. BSEE estimates that if the operator 

must trip in and out of the hole to install a bridge plug and reconnect, it will require 

approximately 24 or more hours of additional rig time. For this regulation we are estimating that 

installing two mechanical plugs will add, on average, 12 hours to the drilling time of all 

deepwater and shallow water OCS wells.

For all wells we estimate that requiring a mechanical barrier and cement will cost about $10,000 

in equipment and cement; this is a reduction from the $20,000 estimate used in the IFR. This 

yields $1.12 million for deepwater MODU wells, $0.48 million for deepwater platform wells and 

$1.86 million for shallow water wells.

The average additional drilling time of 12 hours (1⁄2 of a day) per OCS well using the day rates 

from Table 2 is estimated to cost:

 $51.33 million (1⁄2 * $916,622 * 112 wells) for deepwater MODU wells,

 $ 9.60 million (1⁄2 * $400,000 * 48 wells) for deepwater platform wells, and

 $18.60 million (1⁄2 * $200,000 * 186) for shallow water wells.

The combined compliance cost ($millions) of the equipment and additional drilling time is 

estimated to be: ($1.12 + $51.33) + ($0.48 + $9.60) + ($1.86 + $18.60) = $83.0 million for this 

regulatory provision. This § 250.420(b)(3) change between the IFR and the final rule increases 

the compliance cost for this regulatory provision as shown in Table 5.

Professional Engineer Certification for Well Design

Regulation 30 CFR 250.420(a) in place before the IFR specified well casing and cementing 

requirements but did not require certification by a Professional Engineer although certification 

could be considered the use of best available safety technology (BAST) per § 250.107(d). New 

regulatory section §250.420 (a)(6) requires that well casing and cementing specifications must be 

certified by a Professional Engineer. The Professional Engineer will certify that the well casing 

and cementing design is appropriate for the purpose for which it is intended under expected 

wellbore conditions. This certification will add assurance that the appropriate design is used for 
32

the well thus decreasing the likelihood of a well failure during a blowout. Many of the larger

companies probably will certify the well design using in-house expertise for little or no extra 

cost. Other companies will hire a third-party professional engineering firm. Since a majority of 

leases are owned by large entities, BSEE assumes that at most 50% of future wells will incur an 

additional cost for a third party professional engineer certification of the well design. The 

assumption for shallow water wells is changed from the IFR where we assumed that all wells 

would incur the cost of an external PE certification. The percentage of shallow water wells using 

external PE services is now estimated to be the same as deepwater wells. Based on an informal 

survey of drilling contractors and lease operators, BSEE estimates that the external certifications 

will cost about $22,500 each.

For MODU wells, those parameters yield $1.26 million (112 times 50% times $0.0225 million), 

for platform wells $0.54 million, and for shallow water wells $2.09 million.

Retrieval and Testing of a BOP Stack After a Well Control Situation

Regulations in place before the IFR did not specifically address BOP inspection following use of 

the blind-shear ram or casing shear ram, although a prudent operator would tend to conduct such 

an inspection to confirm the reliability of the BOPs. Surface inspection following shear ram 

activation may not have been conducted by the entire industry absent a more specific regulatory 

requirement; therefore this analysis considers the surface inspection to be a new cost. New 

regulation §250.451(i) requires that if a blind-shear ram or casing shear ram is activated in a well 

control situation where the pipe is sheared, the BOP stack must be retrieved, fully inspected and 

tested. This provision will ensure the integrity of the BOP and that the BOP will still function 

and hold pressure after the event. This activity, when triggered, will add about 13 days to 

drilling time. According to a Det Norske Veritas study12, out of 5,611 deepwater wells, there 

were 12 situations where either the blind-shear or casing shear ram was activated; this implies 

one activation for every 515 wells drilled. With 112 wells drilled per year from drillships or 

semisubmersibles; one can expect 0.22 (112/515) relevant activities per year for costing 

purposes. At the day rates quoted in Table 2, 13 days times a 22% annual chance of occurrence 

yields $2.61 million expected annual compliance cost for this provision.

Third Party Verification of Shear Ram Capability

Before promulgation of the IFR, 30 CFR 250.416(e) required submission of information showing 

that BOP blind-shear rams are capable of cutting through the drill pipe in the hole under 

maximum anticipated conditions. The IFR and the final rule modifies this earlier regulation to 

require a BOP verification of shear ram capability by an independent third party. The 

independent third party provides an objective assessment that the blind-shear rams can cut any 

 

12 Det Norske Veritas. Beaufort Sea Drilling Risk Study. March 11, 2010.
33

drill pipe (including workstring and tubing) in the hole if the shear rams are functioning properly. 

This confirmation will be required for both subsea and surface BOPs, thereby adding a small cost 

to each well drilled. While the requirement to demonstrate shear ram capability is not new, 

independent verification and submission of that verification is a new provision; therefore this 

analysis considers the independent verification to be a new cost. Based on in-house expert 

judgment, we assume this will add $3,250 to the cost of each well. Applied to 346 wells per 

year, this yields a compliance cost estimate of $1.1245 million for this provision. 

Paperwork Costs

Paperwork burden costs were not fully incorporated into the benefit-cost analysis for the interim 

final rule. This final rule analysis adds recordkeeping and other paperwork costs from the PRA 

(Paperwork Reduction Act) burden to the compliance costs for the regulation. Rather than repeat 

the PRA analysis by listing individual regulatory citations, the aggregate paperwork costs from 

that analysis are summarized in a single line in Table 4. This cost includes both the paperwork 

burden included in the IFR (75 FR 63368) and also includes the paperwork burden added in this 

final rule. Because the IFR was effective immediately, the paperwork burden summarized in the 

IFR (75 FR 63368) is already approved by OMB and is not included in this final rule.

The estimate of annual responses for the paperwork costs in the IFR PRA table (75 FR 63368) 

differs slightly from the estimates used in this RIA analysis. This difference is the result of 

different methods used to estimate future drilling activity. Generally the paperwork burden 

estimates a 3-year historical average of responses or actions. This RIA estimates drilling activity 

using both historical activity and forecast scenarios. For example in this rulemaking the 

paperwork burden analysis number of deepwater MODU wells drilled is 110 versus 112 used in 

this RIA analysis. The differences are minor and are not considered to have a material impact on 

the compliance cost estimates.

The estimated total annual burden hours includes both the burden hours from the IFR (75 FR 

63368, OMB Control Number 1014-0014) of 44,731 burden hours and the additional burden 

hours included in the final rule (5,347 hours). The paperwork costs are estimated using the total 

annual burden hours and the average respondent cost of $92*/hour (rounded). This cost is 

broken out in the below table using the Bureau of Labor Statistics data for the Houston, TX 

area. See BLS website: http://www.bls.gov/bls/wages.htm. The total paperwork burden for this 

rulemaking is estimated to be $4.6 million (50,078 hours x $92hr = $ 4,607,176).
34

Table 3 – Hourly Salary Rate for Industry

Position Level Hourly Pay 

rate ($/hour 

estimate)

Hourly rate 

including benefits 

(1.4** x $/hour)

Percent of time 

spent on 

collection

Weighted 

Average 

($/hour)

Secretaries and 

Administrative 

assistants

6 $21 $29 10% $3

Management*** 13 $64 $90 40% $36

Petroleum Engineers 

/Geologists

All 

Workers

$68 $95 50% $48

Supv. Engineer 15 $68 $95 5% $5

Weighted Average ($/hour): $92

* Note that this BLS source reflects their last update from December 2009.

** A multiplier of 1.4 (as implied by BLS news release USDL 11-1718, December 7, 2011 (see 

http://www.bls.gov/news.release/ecec.nr0.htm)) was added for benefits. 

*** This position is closest representative to Regulatory Specialist.

Summary of Annual Recurring Costs

Table 4 summarizes the cost estimates for these recurring cost categories for three subgroups of 

wells affected by the new regulations.
35

Table 4 – Estimated Recurring Cost Summary

Regulation Recurring Costs: MODU 

Wells 

(112/yr)

Fixed 

Platforms 

(48/yr)

Shallow 

Wells 

(186/yr)

Cost 

Shares

Total 

($MM)

Total 

($MM)

Total 

($MM)

250.449(j)(k)

Subsea BOP and ROV function 

testing (drilling) 17.1 0.0 0.0 13%

250.516(d)(8), 

250.616(h)(1)

§250.1707(h)

Subsea ROV function testing 

(completions/workover/abandonment) 

Total of 36 instances. 5.5 0.0 0.0 4%

250.423(c)

Test casing strings for proper 

installation (negative pressure test) 12.8 0.0 0.0 10%

250.420(b)(3)

Installation of dual mechanical 

barriers 52.5 10.1 20.5 63%

250.420(a)(6) PE certification for well design 1.3 0.5 2.1 3%

250.451(i)

Retrieval and Testing of a BOP Stack 

After a Well Control Situation

2.6 0.0 0.0 2%

250.416(e)

Independent third party shear ram 

verification 0.4 0.2 0.6 1%

All

Paperwork Costs taken from PRA 

tables in IFR & Final Rule. 2.5 0.4 1.7 4%

Estimated Cost per year: 94.6 11.2 24.8 $ 130.7 

Estimated Cost per well: 0.85 0.23 0.13

The regulations impact well costs differently depending on the category of drilling rig and type 

of well being drilled. As can be observed in Table 4, deepwater wells drilled by platform rigs

and shallow wells drilled by jackups will incur lower incremental costs, primarily because they 

use surface BOPs while wells drilled by MODU’s (drillships and semisubmersibles) will incur 

the greater incremental cost due to the new subsea BOP and dual barrier requirements. 

Compliance Cost Changes between IFR and Final Rule

The reasons for the compliance cost changes between the IFR and the final rule vary from 

regulatory changes to revised BSEE counts and rig time. The following table provides a side-byside comparison between the IFR compliance costs and those in this final rule.
36

Table 5 – Compliance Cost Comparison between IFR and Final Rule

Annual Recurring Costs IFR 

($millions)

Final Rule 

($millions)

Compliance Cost Change between IFR and Final 

Rule

Subsea ROV function testing 

(drilling)

102.7 17.1 Estimated time was reduced. BSEE over estimated 

the time required for the subsea tests.

Subsea ROV function testing 

(completions/workover/abandonme

nts)

15.5 5.5 Estimated time was reduced. BSEE over estimated

the time required for the subsea tests. Count of 

abandonment operations added to revised count of 

workover/completions.

Test casing strings for proper 

installation (negative pressure test)

45.1 12.8 Regulation was changed and the count of actions is 

reduced. BSEE no longer requires a negative 

pressure test on all intermediate casing strings, but 

only on the final casing before the subsea BOP is 

removed.

Installation of dual mechanical 

barriers

10.3 83.0 Regulation was changed. A float valve no longer 

meets the definition of a second mechanical barrier. 

The estimated time to install the second mechanical 

barrier increased to 12 hours.

PE certification for well design 6.0 3.9 Cost estimate reduced because the large companies 

drilling in shallow water are now assumed to have 

Professional PE available for in-house certification.

Retrieval and Testing of a BOP 

Stack After a Well Control 

Situation

2.6 2.6 No change.

Independent third party shear 

verification

1.2 1.2 No change.

Paperwork Costs taken from PRA 

tables in IFR & Final Rule.

0.0 4.6 Paperwork costs were not included in the IFR 

benefit-cost analysis, but are added to the 

compliance cost for the final rule.

Total: 183.4 130.7

Voluntary Measures by Industry

Some part of the roughly $131 million in annual compliance cost total may not be rightfully 

assigned to the regulation as industry is undertaking a number of steps following the DWH event 

that may overlap those in this regulation. An independent analysis by Industrial Economics Inc.

for the IFR (See Appendix F) indicates overlap exists for the second barrier and negative 

pressure test provisions. However, these actions by industry are voluntary and, as such, not 

subject to enforcement. For these reasons, we have not adjusted the compliance cost estimate to 

account for these new potential actions, but acknowledge that our cost estimate may overstate 

compliance costs.
37

AVOIDED PRIVATE-SOCIAL COSTS

The objective of this section is to describe the avoided private-social costs resulting from a 

catastrophic oil spill in the Gulf of Mexico. Private-social costs as defined in this analysis are 

the costs incurred by the lessees and operator contractors based on the actual property loss and 

containment costs emerging from a catastrophic blowout on their rig and OCS lease. The 

avoided private-social costs include damage to the drilling rig, costs for containment and 

plugging of the blowout well and the value of hydrocarbons lost as a result of a blowout spill. 

Costs for clean-up of spilled oil are considered external-social costs in this analysis since they 

are incurred off the lease and are focused on mitigating the external costs to society from a 

catastrophic blowout event. Estimates of external-social costs are provided in the section on 

Avoided External-Social Costs. The combination of private-social costs and external-social 

costs equal the avoided social costs in this analysis.

Damage to Drilling Rig

A catastrophic deepwater blowout event can cause serious damage to or even destroy the

MODU. Recently delivered floating deepwater semisubmersible drilling rigs reportedly cost 

about $560 million and a drillship $750 million. In addition to the DWH event where the drilling 

rig sank, there is only one other deepwater blowout event with rig damage and fatalities. This 

blowout occurred on September, 1984 in Green Canyon, Conoco (Zapata Lexington Drilling 

Rig). Salient points of that event include:

 There were deaths, serious injuries and damage to the drilling rig.

 While the blowout bridged (i.e., closed off on its own by cave-in or material falling in 

the well bore) and did not spill oil, the explosion did cause $15 million of damage to the 

drilling rig.

We use only these two deepwater blowout events to estimate the avoided costs for drilling rig 

damage because even in serious blowout events there are redundant systems designed to protect 

the rig and its workers, including disconnect of the lower marine riser package (LMRP).

For a prospective catastrophic blowout event, BSEE is assuming the value of a rig is $650 

million, which is the approximate midpoint of the new construction cost of a deepwater 

semisubmersible rig ($560 million)13 and the cost of a new drillship ($750 million)14. We take 

 

13 May 4, 2010, The replacement cost of the Deepwater Horizon is estimated at $560 million.

http://www.nytimes.com/gwire/2010/05/04/04greenwire-warnings-on-backup-systems-for-oil-rigs-sounde30452.html
38

this as the expected loss if the rig is destroyed. Additionally, we assume there is an equal 

likelihood of damaging but not sinking the rig, with resulting damage estimated at $26 million 

($15m in 1984$ from the Zapata Lexington rig accident, inflated to 2010$). The calculation 

used to estimate the expected damage/loss of the drilling rig per catastrophic spill event is ($26m 

+ $650m) / 2) = $338 million.

Well Containment and Plugging

This analysis uses containment and well plugging costs for a deepwater well blowout 

extrapolated from the amount provided by the North America BP Investor Relations desk on July 

23, 2010 for the DWH event. In a phone call, BP stated the company had spent a total of $4.3 

billion through July 22, 2010 which is approximately 90 days after the explosion. Of the $4.3 

billion, $200 million had been spent on the two relief wells and $900 million on other source 

control efforts (e.g., failed ROV intervention efforts, containment structures, etc.). BSEE

assumes that while the oil will flow for 90 days in the baseline (pre-regulation) case, the 

containment and well plugging efforts will extend to 120 days. The $1.1 billion ($200m + 

$900m) for the first 90 days extrapolated to 120 days yields $1.467 billion per catastrophic 

spill event. 

While BP has now paid out more than this figure for its DWH well containment and plugging, 

BSEE is not increasing our estimate for this analysis. Both the Marine Well Containment 

Company and Helix well containment system are operational.15 In the unlikely chance of 

another significant blowout event, specialized equipment has become available and response 

time to stem the flow from the well is anticipated to be reduced. Cognizant that every situation 

and event is different, the $1.467 billion estimate remains.

Hydrocarbon Losses 

In addition to the well containment efforts, private-social costs include the market value of the 

lost oil and gas as a result of an uncontrolled blowout event. BSEE assumes that a deepwater 

well that has suffered an uncontrolled blowout would flow 53,000 barrels of oil a day for 90 

days. This equates to 4.77 million barrels of oil spilled16. While some oil may be captured 

through various skimming systems, the overwhelming majority of captured oil is likely to be 

flared or disposed of as waste rather than sold into the market. Moreover, for our purposes we 

can ignore the relatively modest size of the hypothetical extraction costs of the lost oil. 

 

14 Total capital costs to be incurred for the construction of the drillship are estimated to be $750 million 

http://www.redorbit.com/news/business/1446859/transocean_inc_announces_agreement_to_acquire_newbuild_ultra

deepwater_drillship_under/index.html

15 The cost to stand-up and maintain the MWCC and Helix systems is a significant regulatory cost to industry. 

However it is not a specific compliance cost of this regulation and is not otherwise considered in this analysis. 

16 See footnote number 1 and page 12 for cautions about this estimate.
39

Accordingly, assuming a market oil price of $70/barrel, the value of lost crude oil is estimated to 

be $334 million. 

In the deepwater Gulf of Mexico oil averages 80 percent and natural gas the other 20 percent of 

hydrocarbon production on a BOE basis. If the oil spilled is 4.77 million barrels, associated 

natural gas would be another 1.19 million BOE or 6.92 million MMBtu, implying a total of 5.96 

million BOE is lost 17. For computing the value of lost natural gas, BSEE estimates a market 

value of $4.00/MMBtu for a total lost value of almost $28 million.

Fines and Criminal Penalties

A number of statutes, including the Clean Water Act (33 U.S.C. 1321(b)(7)), and the Outer 

Continental Shelf Lands Act (43 U.S.C. 1350) provide for fines against the parties responsible 

for an oil spill or for violations related to an oil spill. In the context of benefit-cost analysis, 

fines and other penalties not specifically for natural resource damages or other social costs 

incurred by society are considered “transfer payments.” These transfer payments simply move 

funds from the responsible party to the government. Transfer payments do not involve real 

resource costs and are therefore excluded from the avoided benefit-cost estimate for this 

rulemaking.

Summary of Avoided Private-Social Costs

Table 6 summarizes the avoided private costs estimated for this analysis, stated in 2010 dollars. 

These estimates have not changed from the IFR. Note that only about one-sixth of the private 

cost total is from lost hydrocarbon values which the lessees would have realized had the spill not 

occurred.

 

17 5.8 MMBtu per BOE.
40

Table 6 - Summary of Estimated Avoided Private-Social Costs

Private-Social Cost Estimated Value

Damage/loss of Drilling Rig 338,000,000

Well Containment, 120 days 1,466,666,667

Lost Crude Oil, 4.77 million barrels 333,900,000

Lost Natural Gas, 6.92 million MMBtu 27,666,000

Total: $2,166,232,667

AVOIDED EXTERNAL-SOCIAL COSTS

This section evaluates (in quantitative terms where possible) the avoided natural resource and 

cleanup costs, categorized as external-social costs, from a major oil spill in the deepwater Gulf of 

Mexico (GOM). The results from the avoided external-social costs estimated in this section are 

combined with the estimated private-social costs summarized in the table above to provide the 

estimate ($16.3 billion) of avoided social costs (benefits) used in this analysis. External-Social

costs associated with oil spills may include loss of property value, natural resource damages, 

health effects, litigation costs, non-use values, loss of consumer surplus from recreational users, 

loss of producer surplus from commercial fishing or shell-fishing businesses, welfare effects 

associated with price changes in seafood markets, operational disruptions at marinas, commercial 

ports, or Naval facilities, temporary or permanent displacements of families or businesses, and 

reduction of supply of water for certain industrial purposes.18

The main categories of external-social costs considered in this section of the analysis include 

 Natural resource damages;

 Lost recreational values;

 Lost commercial fishery production; and 

 Oil spill response (cleanup) and damage assessment costs. 

The avoided external-social cost estimate focuses on these categories of avoided social costs 

because information appropriate to a benefit-cost analysis is readily available to estimate their 

magnitude from studies and historical data. Recall that costs for the containment and the killing 

of an uncontrollably flowing well, damage to drilling equipment from a blowout, and lost 

hydrocarbons have already been discussed in the section on External-Private Costs. 

 

18 Water of a certain quality is required for various industrial uses, power generation, and desalination. There are 

nineteen thermoelectric plants on the Gulf coast (Florida, Mississippi and Texas). There is a Gulf-water fed 

desalination plant located in Tampa Bay, and one planned for San Antonio.
41

Three main factors affect the economic value of the avoided external-social costs of an oil spill: 

the spill’s location, the time of year it occurs, and the type of oil spilled. Spill location and 

timing affect all categories of costs. Spills near locations with sensitive biota, significant fishery 

resources or recreational areas, or in locations where the oil could easily spread to such locations 

will have relatively greater costs. Little is known about the short- and long-term impacts of 

deepwater oil spills on the water column or deepwater biota. Timing also has situation-specific 

effects. A spill occurring near bird habitats during nesting or breeding season might be 

associated with greater natural resource damages, while a spill occurring near a shrimp fishery 

during harvesting season would be associated with larger fishery-related costs.

The specific type of oil affects the amount of cleanup needed and the amount of natural resource 

damages incurred. Light oils naturally dissipate and evaporate quickly—requiring minimal 

cleanup—but are highly toxic and create severe environmental impacts. Heavy oils do not 

evaporate, and therefore may require intensive structural and shoreline cleanup. While they are 

less toxic than light oils, heavy oils can harm waterfowl and fur-bearing mammals through 

coating and ingestion. Each spill’s cost reflects the particular mix of these factors, and no factor 

is clearly predictive of the outcome. 

Conceptual Approach

Typically, the external-social cost of damages to natural resources, fisheries and recreational 

areas is evaluated after a spill has occurred and subsequent to the completion of response 

activities. This evaluation includes collecting data that allow assessing the nature and extent of 

the damages (both spatially and over time) to all of the impacted resources relative to the prespill baseline and then, where possible, monetizing the damages using economic techniques 

designed to value resources that are not typically bought and sold in markets. In concept, 

damages include use and non-use values, for example, both the value of a trip to the beach now 

and the value of being able to take such a trip in the future.

For the proposed regulation, this level of information is not readily available. Baseline 

information such as the number, timing, duration, and location of potential spills during the 

period of analysis are not known. In addition, while baseline projections for the number of 

future deepwater wells drilled are assumed for this benefit-cost analysis, it is not possible to 

forecast the timing, magnitude, duration, and trajectory of future spills. This introduces a 

considerable degree of uncertainty into estimates of the value of the avoided costs associated 

with the proposed regulation. The analysis addresses this uncertainty by providing a range of 

values associated with different categories of avoided costs, and reporting averages or most 

likely values to determine point estimates for calculations.
42

Given the limited information available to evaluate the avoided natural resource costs, the 

technique used in this analysis falls into the category of “benefit transfer.” This technique can be 

implemented in a variety of ways, ranging from simply transferring values from sufficiently 

similar studies, to adapting willingness-to-pay functions for new site-specific changes in 

environmental conditions, prices, and other values. In situations where time or resources do not 

permit extensive data collection or primary research, benefit transfer may be an appropriate 

technique for evaluating the magnitude of economic benefits. There are many caveats that 

accompany use of this approach, the most important perhaps being the extent to which the study 

site/situation is similar to the study from which the values are to be transferred. 

As discussed in the Baseline section of this analysis, BSEE estimated the probability of a 

catastrophic spill based on the history of deepwater blowout events and the resulting spills on the 

Federal outer continental shelf (OCS).

The BSEE estimates that about 160 new deepwater wells will be drilled annually over the next 

several decades. BOEMRE also assumes that the baseline scenario includes one catastrophic 

deepwater spill every 26 years, with the probability of a spill in any given year during the period 

of analysis being 3.85%. In this analysis, the hypothetical spill is assumed to be 4.77 million 

barrels of oil. The analysis does not assume a specific grade of crude oil for future spills, 

although oil from a deepwater GOM blowout would likely be a sour light crude typical in the 

GOM. The type of oil spilled affects spill dispersion and clean-up costs.

Valuing Natural Resource Damages

The avoided costs for natural resource damages depend on the particular circumstances 

associated with an oil spill. Natural resource damages from prior oil spills (excluding the DWH 

spill) were used to inform the cost-benefit analysis of this rulemaking. We collected information 

on coastal oil spills that were responded to under the authority of the Oil Pollution Act, including 

the natural resource damage settlements associated with these events. For the purposes of this 

benefit-cost analysis, the values contained in the legal settlement documents represent the best 

source of available information on the monetary value of the natural resource damages 

associated with coastal oil spills. Settlement amounts reflect compromises based on factors other 

than the actual amount of damages, such as litigation risk with respect to legal issues in the case 

or the ability of parties to support protracted, complex litigation. Further, although this 

information is useful for the purpose of a benefit-cost analysis, it should not be relied on to 

determine the amount of natural resource damages associated with any particular oil spill, 

including the DWH spill. 
43

The dataset includes 62 coastal spills, none of which occurred a significant distance offshore. 

While vessel-related spills have previously occurred offshore, primarily in foreign waters, there 

is little information available on the associated natural resource damages. Similarly, little 

information is available on natural resource damages associated with blowouts occurring in 

foreign waters. Information on the spills contained in the data set is summarized in Figure 2

through Figure 5 and in the Appendix. 

 Figure 2 shows a histogram of the per-barrel response costs in the dataset, with the 

majority of spills below $10,000/bbl, and a large number below $10/bbl;

 Figure 3 shows a histogram of the per-barrel restoration and assessment costs in the 

dataset, with the majority of spills below $10,000/bbl, and a large number below 

$1,000/bbl;

 Figure 4 shows a histogram of the total spill costs in the dataset, with the majority of 

spills below $10 million, and a large number below $1 million;

 Figure 5 shows a histogram of claims requested and claims paid out by the U.S. Coast 

Guard from the National Pollution Trust Fund. The majority of these are below $10,000 

per claim; many are below $1,000 per claim.

Figure 2. Distribution of Dataset Spills by Response Costs per Barrel ($2009)
44

Figure 3. Distribution of Spills, by NRD + Assessment Cost per Barrel ($2009)

Figure 4. Distribution of Spills, by Total Spill Costs ($2009)
45

Figure 5. Oil Spill Liability Trust Fund Claims Requested and Paid (Sep 1972-Feb 2010)

The 62-spill dataset is characterized by a wide range of volumes spilled (24 to 262,000 barrels) 

as well as a wide range of per-barrel natural resource damages ($7 to $76,000 per barrel).19 The 

vast majority of the spills were 10,000 barrels or less. As stated, this data set does not include 

the DWH spill. For the 62 spills, the average monetary value of the natural resource damages 

(including assessment costs) was about $3,700 per barrel, the median spill was about $850 per 

barrel, and the standard deviation was about $11,300 per barrel. The per-barrel damage values 

are related to both spill size and type of hydrocarbon. 

Of the 62 spills, 10 spills occurred in the Gulf region. Natural resource damages (including 

assessment costs) for the Gulf spills range from $49 to $1,287 per barrel (in 2010 dollars), with 

an average of $456, per barrel, a median of $244 per barrel, and a standard deviation of $470 per 

barrel. For this analysis of a hypothetical catastrophic oil spill, we selected seven Gulf spills that 

appear most germane. Summary information on these seven spills is reported in Table 5. The 

average damages across these spills were $604/bbl, which is used as a conservative estimate for 

our avoided cost calculations. The Ocean 255 spill was highest-damage Gulf spill prior to April 

2010, and the only non-crude oil spill in the Gulf data.

Although the hydrocarbons spilled in the Ocean 255 spill were fuel oil, rather than crude, the 

resources impacted were typical of some of the marine resources throughout the Gulf that could 

be affected by a catastrophic spill: sea turtles, mangroves, sea grasses, oyster beds, and beaches. 

These impacts suggest that the Ocean 255 spill may be a good representation of a future large 

 

19 The upper end of the range of natural resource damages is given by the M/T Command oil spill in San Francisco 

Bay in 1998. Spills occurring in or near northern California are associated with some of the largest dollar-per-barrel 

damages.
46

spill. As discussed below, while the model used for this analysis appears to predict natural 

resource damage costs for smaller spills reasonably well, this model may have poor predictive 

capability for the NRD costs of catastrophic spills.

Table 7 Seven Gulf Coast Spills: Natural Resource Damages

Event Volume 

spilled 

(bbls)

NRD+Assessement 

Costs $/bbl $2010

Injured Resources

OCEAN 255/B155/BALSA 37 Spill8,619 1,287 366 birds, 2117 sea turtles, 

5.5 acres mangroves, 255 

acres seagrasses, 0.85 acres 

salt marshes, 0.22 acres 

oyster beds, 20 linear miles 

seawalls, surface waters, 

1.34 acres bottom 

sediments and 39,827 cubic 

yards of oiled sands (13 

linear miles)

Blake IV and Greenhill 

Petroleum Corp. Well 25

2,905 1,122 Intertidal marshes, marine 

and estuarine fish, bottom 

dwelling species, birds, 

sediments

Equinox Cockrell-Moran 

#176 well

1,500 891 1,221 acres saltmarshes, 

Birds/Wildlife, 12 acres 

mangroves, 21 acres 

subtidal sediments, 

recreational activities

Chevron BLDSU #5, West 

Bay Field

262 346 200 Acres Fresh Water 

Marsh Vegetation, 

Birds/Wildlife

Ocean Energy/Devon 

Energy North Pass Storage 

Facility

300 424 120 acres freshwater marsh

Texaco Pipeline Company 

Lake Barre oil spill

6,548 109 4,237 acres of marshes, 

7,465 finfish and shellfish, 

333 birds, 

M/VWestchester 13,095 49 Oiled shoreline and surface 

waters; lost recreational use 

of the Mississippi River.

Average per Event 604
47

Caveats and Assumptions

The analysis includes the following caveats and assumptions:

 The estimate of natural resource damages from the table above, while a useful tool for the 

purpose of this cost-benefit exercise, is not relevant in calculating damages for any 

particular oil spill, including the DWH spill.

 For the purposes of this exercise, it is assumed that the average natural resource damage 

value for Gulf cases per barrel spilled, equal to $604 from the table above, is a reasonable 

approximation of the value of avoided natural resource damages for a spill significantly 

larger than the cases contained in the dataset of natural resource damage cases. It is 

worth noting, however, that a future catastrophic spill could result in a significantly 

higher natural resource damage value per barrel spilled, depending on the circumstances. 

In the Exxon Valdez oil spill, which resulted in a release of 261,905 barrels of oil, natural 

resource damages plus assessment costs averaged $5,005 per barrel (2009 dollars). See 

Appendix B.

 Total damages for a given hypothetical event are a linear function of the amount spilled.

 The average damage value is not adjusted to account for distance to shore, evaporation, 

degradation, dispersion, containment, etc. It is assumed that reported natural resource 

damage values already incorporate these effects.

 The injured resources for the cases in the dataset are similar to the resources potentially 

damaged from a large Gulf spill in the future. 

 This analysis translates estimated avoided costs into dollar-per-barrel values. This metric 

is useful because barrels are a common measure of spill volume. However, the wide 

variation in social spill costs across events is noted. In short, the damages ultimately 

depend on the characteristics of an individual spill as noted earlier in the reference to the 

Exxon Valdez spill.

Relationship between Natural Resource Damages and Spill Size and 

Type of Oil Spilled

Similar to previous analysis by Dunford and Freeman (2001), a statistical model was developed 

to explain the factors that affect the monetary value of natural resource damages in the oil spill 

data set. The regression analysis used the log of natural resource damage and assessment costs 

(in $/barrel) as the dependent variable. Independent (explanatory) variables included the type of 

oil spilled (with dummy variables included for crude, diesel and gasoline), a time trend, the log 

of the volume of oil spilled (in barrels), and a dummy variable indicating if the oil spill occurred 

in California. The regression results explain a reasonable amount of variation in the sample; 

however, the predictive ability of the model appears to be better for small size spills. The model 

is able to predict costs for smaller spills in the sample reasonably well, although predictions of 

larger spills in the sample result in smaller values than expected. Based on the historic spill data 
48

available, the model appears to have poor predictive capability for the NRD costs of catastrophic 

spills. 

Valuing Commercial Fishery Losses

Commercial fishing as an industry must be differentiated from other types of fishing, such as 

recreation, “subsistence” consumption, or informal sale. One approach to calculating 

commercial fishing profits20 requires tallying revenue earned by industry operators, and 

subtracting operating costs. Operating costs include labor costs, such as wages for harvesting 

and processing; and non-labor costs such as fuel and supplies.

The commercial fishing industry includes various species of aquatic life (shrimp, crabs, oysters, 

finfish) and types of economic activity (fishermen, processors/cleaners, dealers, marinas, support 

facilities). Impacts to the industry from an oil spill can be expected to affect all sectors of the 

industry. 

Economic damages related to an oil spill can result from:

 Fishery closures, when fishermen must either shift to different areas or not fish at all;

 Fish population impacts that result in lower catch rates, different target species, or 

changes in fishing methods; and 

 Market price changes, for example due to public reluctance to consume fish from the 

region.

This approach for assessing damages related to an oil spill requires identifying changes in catch 

rates, prices, fishing areas, and methods employed.

Data Availability

Background

The Gulf States include, from West to East, Texas, Louisiana, Mississippi, Alabama and Florida. 

The region’s shrimp landings are the nation’s largest: 188.3 million pounds, for 73 percent of the 

national total (Fisheries of the United States 2008). The region landed approximately 30 percent 

of the total blue crabs for the nation (48.7 million pounds) in 2008. The Gulf region leads the 

nation in the production of oysters, some 67 percent of the nation’s total. 

Gulf fishery total landings (in pounds) and the revenues from those landings have tended to fall 

over the past decade, as shown in Figure 6. Fluctuations in prices do not appear to contribute to 

the decline in revenues. For the top ten commercial species, which together account for over 96 

 

20 We use producers’ profits as a proxy for producer surplus.
49

percent of annual harvests, prices show no steady downward trend in Figure 7, while landings of 

all species show moderate declines in Figure 8.

Figure 6 Gulf State Landings and Revenue, 1999-2008 (2009$)

Note: Data include landings for Florida’s Gulf coast and Atlantic coast.

Source: NMFS Fisheries Economics of the United States 2008.

Figure 7 Average Annual Price per Pound (2009$)

Source: NMFS Fisheries Economics of the United States 2008.

Finfish & Other (lbs), 

1999, 1,638

Finfish & Other (lbs), 

2000, 1,397 Finfish & Other (lbs), 

2001, 1,254

Finfish & Other (lbs), 

2002, 1,377 Finfish & Other (lbs), 

2003, 1,229 Finfish & Other (lbs), 

2004, 1,110

Finfish & Other (lbs), 

2005, 888

Finfish & Other (lbs), 

2006, 975

Finfish & Other (lbs), 

2007, 1,071

2008, 993 Shellfish (2009$), 

1999, 828

Shellfish (2009$), 

2000, 1,017

Shellfish (2009$), 

2001, 780 Shellfish (2009$), 

2002, 641

Shellfish (2009$), 

2003, 614

Shellfish (2009$), 

2004, 601

Shellfish (2009$), 

2005, 555

Shellfish (2009$), 

2006, 593

Shellfish (2009$), 

2007, 565 2008, 511 Shellfish (lbs), 1999, 

367

Shellfish (lbs), 2000, 

398

Shellfish (lbs), 2001, 

359

Shellfish (lbs), 2002, 

351

Shellfish (lbs), 2003, 

367

Shellfish (lbs), 2004, 

365

Shellfish (lbs), 2005, 

310

Shellfish (lbs), 2006, 

387

Shellfish (lbs), 2007, 

333

Shellfish (lbs), 2008, 

281

Finfish & Other 

(2009$), 1999, 228

Finfish & Other 

(2009$), 2000, 223

Finfish & Other 

(2009$), 2001, 200

Finfish & Other 

(2009$), 2002, 177

Finfish & Other 

(2009$), 2003, 163

Finfish & Other 

(2009$), 2004, 164

Finfish & Other 

(2009$), 2005, 135

Finfish & Other 

(2009$), 2006, 145

Finfish & Other 

(2009$), 2007, 151 (2009$), 2008, 145

Finfish & Other (lbs)

Shellfish (2009$)

Shellfish (lbs)

Finfish & Other (2009$)

$ 0

$ 2

$4

$6

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

2009$ per Lb

Crab, Stone

Tunas

Snapper, Red

Oyster

Groupers

Shrimp

Crawfish

Crab, Blue

Mullets

Menhaden
50

Figure 8 Gulf State Landings, 1999-2008 (mmlbs)

Notes: Data include landings for Florida’s Gulf coast and Atlantic coast.

Crawfish landings for 2000 totaled 393,000 lbs. 

Source: NMFS Fisheries Economics of the United States 2008.

Datasets were more readily available for commercial shrimp fishing than for other Gulf fisheries. 

The domestic shrimp industry has been in decline since the 1980s and may not be a good 

indicator of the overall commercial fishing industry in the Gulf. Louisiana accounts for about 

50% of Gulf Coast shrimp landings. By 2007 resident shrimping licenses in Louisiana had fallen 

to less than one-third of their 1989 value, as shown in Figure 9.

1

1 0

100

1,000

1 0,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Landings (Million Lbs)

Menhaden

Shrimp

Crab, Blue

Oyster

Mullets

Groupers

Crab, Stone

Snapper, Red

Tunas

Crawfish
51

Figure 9 Resident Louisiana Shrimping Licenses (Trawl, Butterfly Net, and Skimmer Net) 

Source: Louisiana Department of Wildlife and Fisheries

Revenues

In calculating producer surplus, we estimated gross revenues using the gross value of landings, 

multiplying pounds of fish landed by the wholesale price for that fish. The National Oceanic and 

Atmospheric Administration (NOAA) provides summary data on the value of commercial 

fisheries in the Gulf of Mexico, as shown in Table 8. 
52

Table 8 Gulf of Mexico Commercial Fisheries Data, 2008

Texas Louisiana Mississippi Alabama West 

Florida

Total

Shrimp

Volume (million lbs) 63.9 89.0 8.6 17.2 9.9 188.5

Value (million $) 157.1 130.3 17.1 38.4 23.3 366.3

Crabs (Blue crabs)

Volume (million lbs) 2.3 39.8 0.5 1.8 2.6 47.3

Value (million $) 2.6 31.1 1.0 1.5 3.3 38.7

Oysters

Volume (million lbs) 2.7 12.6 2.6 0.7 2.4 20.4

Value (million $) 8.8 38.2 6.9 0.1 5.3 59.5

Finfish (and other)

Volume (million lbs) 3.7 759.3 190.2 5.4 34.7 993.4

Value (million $) 7.7 64.0 19.2 4.1 50.5 145.6

Source: NOAA Fisheries Economics of the U.S.

These data were accessed on-line at 

http://www.st.nmfs.noaa.gov/st5/publication/fisheries_economics_2008.html#

NOAA’s National Marine Fisheries Service (NMFS) data on weights and values of landings 

exhibit strong seasonality: Figure 10 and Figure 11 show a pronounced peak in each State’s 

landings during one or two summer months each year; Figure 12 and Figure 13 show revenues 

by State during the summer months. This seasonality indicates that the timing of closures and 

population impacts should be considered in an analysis of oil spill damages. The seasonality is 

also rather stable, 21 suggesting that reasonable future monthly harvest values might be inferred 

from the data. We used the early summer months which correspond to the high revenue season 

for convenience rather than employing more sophisticated assumptions to reflect the seasonality. 

This choice deviates from our usual practice of using conservative assumptions to generate 

avoided social costs, but the values involved are so small relative to other social costs that further 

efforts in this regard do not appear warranted.

 

21 Within-month coefficients of variation for May, June, July and August are below 0.45 for all five Gulf States over 

1997 through 2008, and below 0.37 outside of Mississippi. The variation is lower still (outside of Mississippi) for 

2002 through 2008: below 0.26 for all months.
53

Figure 10 Monthly Commercial Fishery Landings (Texas, West Florida, Alabama)

Figure 11 Monthly Commercial Fishery Landings (Louisiana, Mississippi)

0

5

1 0

1 5

2 0

2 5

Million lb

Texas

Florida, West

Alabama

0

5 0

100

150

200

250

300

350

Million lb

Louisiana

Mississippi
54

Figure 12 Summer Commercial Fishery Landing Revenues (West Florida, Mississippi, Alabama)

Figure 13 Summer Commercial Fishery Landing Values (Louisiana, Texas)

Baseline monthly landings values were estimated separately for each month of 2010 by sorting 

the 2002-2008 data by month, and finding the monthly trend for each State using ordinary least 

squares. These values are reported in Table 9.

$0

$5

$1 0

$1 5

$2 0

Million (2009$)

Florida, West

Mississippi

Alabama

$ 0

$2 0

$4 0

$6 0

$8 0

Million (2009$)

Louisiana

Texas
55

Table 9 Estimated 2010 Baseline Values for Gulf State Commercial Fisheries ($ millions, trend 2002-2008)

Texas Louisiana Mississippi Alabama West

Florida

May $12.0 $29.8 $0.9 $2.5 $8.5

June $11.7 $43.6 $6.5 $7.6 $7.2

July $23.2 $29.3 $6.6 $6.4 $5.8

Operating Costs

Liese et al. (2009) performed a cash-flow analysis based on a sample of Gulf commercial 

shrimpers. They found the average net revenue (before taxes) for a gulf shrimping operation was 

$2,654, with a 95% confidence interval spanning -$4,138 to +$9,446. This wide confidence 

interval, which includes zero, suggests that while the average vessel may be earning positive net 

revenues, there are at least some vessels that are earning negative net revenues. This was 

observed in spite of the fact that “the effective economic environment actually improved 

somewhat from 2006 as shrimp prices increased proportionally more than fuel prices. However, 

with the liquidity constraint implied by a negative cash flow and following many marginal years, 

it seems the average vessel simply did not have the ability to exploit this improvement and had to 

cut its overall effort (Liese et al. 2009).

Travis and Griffin (2004) had predicted the improvement noted by Liese in a simulation that 

assumed that variable costs as a percentage of revenues would fall for Gulf commercial 

shrimping. Their assumptions are given in Table 10.

Table 10 Gulf Commercial Shrimping Costs as a Percentage of Revenues (simulated)

2002 2007 2010-2018 

(lowest-cost 

period)

Large Vessels

(at least 60 feet 

long)

98% 78% 75%

Small Vessels

(<60 feet long)

114% 96% 93%

Liese’s 2007 survey results can be used to make some inferences about how the Gulf fleet is 

divided between “large” and “small” vessels. They found 12% of the fleet was less than 50 feet 

long, and 56% of the fleet was more than 75 feet long. For the 31% of the sample that was 50 to 

75 feet long, the average length was 65 feet. We assume that vessels are evenly distributed by 

size within this category, so that half the vessels (16 percent of the fleet) are longer than 65 feet. 

Of the 16% of vessels that are 50 to 65 feet long, two-thirds of the vessels are 50 to 60 feet long, 

and one-third of the vessels are 60 to 65 feet long. Tallying the proportions below 60 feet 
56

indicates that 23 percent of the fleet consists of “small” vessels (by Travis and Griffin’s 

definition), while 77% of the fleet consists of “large” vessels. These results are summarized in 

Table 11, where the same approach is used to apportion the total fleet shrimp landings and 

landings revenue.

Table 11 Gulf Shrimping Fleet: Large and Small Vessels

Categories from Liese et al. (2009) Categories from 

Travis and Griffin 

(2004)

< 50 feet 50 feet to 

60 feet

60 feet to 

65 feet

65 feet to 

75 feet

> 75 feet < 60 feet >= 60 

feet

% of 

Fleet 

Vessels

12% 10% 5% 16% 56% 23% 77%

% of 

Fleet 

Shrimp 

Landings

4% 10% 5% 15% 66% 14% 86%

% of 

Fleet 

Landings 

Revenue

3% 9% 5% 14% 69% 12% 87%

*A small percentage (0.2 percent) of the landings revenue is from non-shrimp landings.

As shown in Table 11, the smallest vessels in Liese’s survey (those less than 50 feet long) form a 

disproportionately small part of the industry: these vessels make up 12% of the fleet, but bring in 

only 4% of the landings, and receive only 3% of the landings revenue. In part this is due to the 

lower price that they receive for shrimp ($2.40 per pound versus the fleet average of $3.00). 

Likewise, the largest vessels form a disproportionately large part of the industry. Vessels over 

75 feet long make up 56% of the fleet, but bring in 66% of the landings, and receive 69% of the 

landings revenue. We preserve this imbalance when we switch to the 60-foot designation for 

“large” vessels. 

The proportions of Gulf commercial shrimp landing revenues going to large and small vessels is 

combined with the baseline revenue projections in Table 9 to determine the contribution of each 

vessel class to baseline revenues for the entire commercial fishing industry (see Table 12). We 

then apply the assumptions from Travis and Griffin (2004) about variable costs as a percentage 

of revenues to determine baseline profits accruing to each vessel class (see Table 13). Finally, in 
57

Table 14 the results for large and small vessels are summed together to find the 2010 baseline for 

total industry profits by month.

 

Table 12 Large and Small Vessel Contributions to Gulf Commercial Fishing Revenues (2009$ millions)

Vessels Texas Louisiana Mississippi Alabama West 

Florida

May Fleet $12.0 $29.8 $0.9 $2.5 $8.5

Large $9.2 $22.9 $0.7 $1.9 $6.5

Small $2.8 $6.9 $0.2 $0.6 $2.0

June Fleet $11.7 $43.6 $6.5 $7.6 $7.2

Large $9.0 $33.6 $5.0 $5.9 $5.5

Small $2.7 $10.0 $1.5 $1.7 $1.7

July Fleet $23.2 $29.3 $6.6 $6.4 $5.8

Large $17.9 $22.6 $5.1 $4.9 $4.5

Small $5.3 $6.7 $1.5 $1.5 $1.3

Table 13 Estimated Baseline Profits for 2010: Large and Small Gulf Commercial Fishing Vessels (2009$ 

millions)

Vessels Texas Louisiana Mississippi Alabama West 

Florida

May Large $2.3 $5.7 $0.2 $0.5 $1.6 

Small $0.2 $0.5 $0.0 $0.0 $0.1 

June Large $2.3 $8.4 $1.3 $1.5 $1.4 

Small $0.2 $0.7 $0.1 $0.1 $0.1 

July Large $4.5 $5.6 $1.3 $1.2 $1.1 

Small $0.4 $0.5 $0.1 $0.1 $0.1 

The calculations presented in Table 13 assume that all Gulf commercial fishing operations have 

similar cost structures, namely that variable costs average 75% of revenues for large vessels, or 

93% for small vessels. This is a conservative estimate: commercial shrimping is a high-cost 

industry, and other types of fishing are likely to have lower costs. Applying this percentage to 

the 2010 baseline revenues from Table 9 gives the 2010 baseline profits in Table 14.

If labor used in commercial fishing is not easily redeployed to alternatives, i.e., it does not have 

an opportunity cost, then this lost labor would also be included as an avoided social cost. We did 

not attempt to include estimates of this effect since the entire lost fishing and recreation item is 

such a small fraction of the total avoided cost estimate. Even counting all lost fishing revenue 

adds only one percent to our total avoided cost estimate. 
58

Table 14 Estimated Baseline Profits for 2010: Gulf Coast Commercial Fisheries (2009$ millions)

Texas Louisiana Mississippi Alabama West 

Florida

May $2.5 $6.2 $0.2 $0.5 $1.8 

June $2.4 $9.1 $1.4 $1.6 $1.5 

July $4.8 $6.1 $1.4 $1.3 $1.2 

August $6.9 $7.4 $1.0 $1.8 $2.5 

Closures

Gulf fishery closures in the Federal Exclusive Economic Zone (EEZ) are tracked over time in 

Table 15. As of July 21, 2010, about a third of Federal waters in the central Gulf were closed, 

while Texas had not experienced any closures, and shrimping season in the western Gulf opened 

as usual on July 15.22 The eastern edge of the Gulf has also remained open, and Florida has 

closed only about 20 miles of the coastline near Pensacola.23 All of Alabama State coastal 

waters (outside of Mobile Bay) have been closed to commercial fishing since June 24, though 

some shrimping and catch-and-release fishing are allowed.24 On July 20, Mississippi State 

coastal waters re-opened to live-bait shrimping and catch-and-release fishing.25 As of July 5, 

about half of Louisiana oyster harvest areas were closed, as was about half of the Louisiana 

coastline (from Oyster Bayou to the Mississippi border) for commercial fishing. A smaller set of 

areas was closed to recreational fishing.26 

 

22 Texas data were taken from the Texas Parks and Wildlife Department website “BP Oil Spill in the Gulf of 

Mexico” at http://www.tpwd.state.tx.us/site/emergency/oil_spill/.

23 Florida closure data were taken from a Florida Fish and Wildlife Conservation Commission press release dated 

June 13, 2010.

24 Alabama closure data were taken from an Alabama Department of Conservation and Natural Resources press 

release dated June 28, 2010.

25 Mississippi closure data were taken from a Mississippi Department of Environmental Quality/Department of 

Marine Resources news release dated July 19, 2010.

26 Louisiana closure data were taken from the Interactive Closure Maps on the website of the Louisiana Department 

of Wildlife and Fisheries (LDWF) at http://www.wlf.louisiana.gov/oilspill/map/.
59

Table 15 2010 Gulf Fishery Closures in Federal Exclusive Economic Zone (EEZ)

Closure Date

(2010)

Percent Coverage

of Gulf EEZ 

Days Closure

was in Effect

Effective Days of

Full EEZ Closure

2-May 2.8% 5 0.1

7-May 4.5% 4 0.2

11-May 6.6% 1 0.1

12-May 7.3% 2 0.1

14-May 8.0% 3 0.2

17-May 10.0% 1 0.1

18-May 18.9% 3 0.6

21-May 19.8% 4 0.8

25-May 22.4% 3 0.7

28-May 25.1% 3 0.8

31-May 25.6% 1 0.3

May 2010 Subtotal 3.9

1-Jun 31.4% 1 0.3

2-Jun 36.6% 2 0.7

4-Jun 32.3% 1 0.3

5-Jun 32.5% 2 0.7

7-Jun 32.3% 9 2.9

16-Jun 33.4% 5 1.7

21-Jun 35.9% 2 0.7

23-Jun 32.5% 5 1.6

28-Jun 33.2% 6 2.0

June 2010 Subtotal 10.9

4-Jul 33.5% 8 2.7

12-Jul 34.8% 1 0.3

13-Jul 34.7% 10 3.5

23-Jul 23.8% 8 1.9

July 2010 Subtotal 8.4

May-July 

2010

Total 23.2

source: http://sero.nmfs.noaa.gov/ClosureSizeandPercentCoverage.htm

We applied the “effective days of full EEZ closure” by month to the profits for Louisiana, 

Alabama and Mississippi. This approach relies on the assumption that landings, costs and vessel 

classes are evenly distributed throughout a State’s waters and the adjacent portion of the EEZ. 

We are also assuming that the timing for landings is seasonally fixed, so that applying extra 

effort ahead of the spill could, but did not shift profits to that particular point in time.
60

Table 16 Estimated Gulf State Profits Lost to Closures

Days of 

Closure

Days in 

Month

2010 Baseline Profits 

(LA, MS, AL), millions 

(2009$)

Lost profits, 

millions 

(2009$)

May 3.9 31 $6.9 $0.9

June 10.9 30 $12.0 $4.4

July 7.7 31 $8.8 $2.2

Total $27.8 $7.5

A total of $7.5 million in lost profits due to a spill of 4.8 million barrels is equivalent to $1.56 

per barrel.

Valuing Lost Recreation

Recreation activities are often affected when oil spills result in contamination of coastal or ocean 

resources. These damages can result in value losses to consumers who either are unable or 

choose not to participate in a given recreation activity due to the contamination or do participate 

but have a lower quality experience than if there was no contamination. In order to arrive at a 

value of lost recreation, estimates must be obtained for the number of recreation trips (or days) 

lost per barrel of oil spilled and the average value for a particular type of recreation trip.

Economists use consumer surplus, or the difference between what an individual is willing to pay 

for a good and what they actually pay for it, to arrive at these recreation values. Since market 

price data is lacking for the value of recreational activities, these values are inferred from 

consumer behavior (such as the costs incurred to travel to the recreation site) or from individual 

stated preferences about their willingness to pay for the resource. Ideally, survey-based data 

would be collected from individuals to obtain information about the value that they place on the 

resource in a particular geographic location and the value loss incurred from an oil spill. 

However, when it is not feasible to undertake an original study to obtain these values, the benefit 

transfer approach is often used. Benefit transfer is a method that applies values obtained from 

previous studies to a new situation where primary data has not been collected.

In this section, benefit transfer is used to produce estimates of the value of lost recreation 

associated with a catastrophic oil spill event in the Gulf of Mexico for recreational fishing and 

beach recreation. Other recreational activities such as scuba diving, snorkeling and boating are 

likely to be affected as well but estimates for those activities are not included in this analysis due 
61

to lack of information about the impacts and potential overlap among activities. In order to 

arrive at an estimate of the impact of a catastrophic oil spill, several assumptions are required 

about the size, duration and location of the spill. In this analysis, the spill is assumed to result 

from a catastrophic blowout event in the GOM. In addition, this analysis does not account for 

the substitution of less desirable or more costly recreation sites for those that are affected by the 

spill. 

Recreational Fishing

In order to estimate the value of lost recreational fishing trips, historic data on the total number 

of trips is first required. Historic data from the NOAA Marine Recreational Fishing Statistics 

Survey (MRFSS) for the Gulf Coast Region including Alabama, Mississippi, Louisiana, and 

Western Florida (data for Texas was not available) was used to arrive at an estimate of number 

of trips over a three month period including May, June and July (Wave 3 and half of Wave 4 in 

the MRFSS data set). These totals were not adjusted to reflect non- offshore fishing since such 

adjustments would be arbitrary and the overall cost of this element is small, relative to the much 

larger social cost estimate. Using a five-year average from 2005-2009, an estimate of 7,667,567 

recreational fishing trips was obtained (Table 17). 

Table 17 Average Number of Trips (May-July) (2005-2009)

Area Number of Trips

Alabama 572,907

West Florida 4,576,280

Louisiana 1,455,094

Mississippi 384,055

Federal EEZ 679,261

Total 7,667,597

Source: NOAA Marine Recreational 

Fishing Statistics Survey

The number of effective days of full closure (see Table 15) was then applied to the average 

number of trips per day for each month to estimate the number of trips lost during the period of 

closure. Effective days of closure for the Federal EEZ were also applied to each of the States 

due to lack of specific data on State water closures. This is likely to result in an underestimate 

for Alabama, Mississippi and Louisiana, and an overestimate for Florida. In addition, this 

estimate does not account for certain areas that re-opened to catch-and-release recreational 

fishing after initial closures. It should also be noted that these estimates do not explicitly account 

for the availability of substitute fishing destinations, or the differences in behavior of local versus 

out of state fishermen (local fishermen may be less likely to find a suitable substitute if 

recreational fishing is affected throughout the region). If suitable substitutes are available, it is 
62

likely that the decrease in number of trips would be smaller than if fewer substitutes are 

available.

Benefit transfer was then used to value the lost recreational fishing trips. Consumer surplus 

estimates (in dollars per activity day) were obtained from previous non-market valuation studies 

of recreational fishing in the Gulf Coast region. All values were converted to current (2010) 

dollars, and an average value of $54.48/day was obtained from the 7 studies considered. This 

value was multiplied by the number of trips lost for State waters in each state and the Federal 

EEZ to arrive at total estimated consumer surplus over the three-month period. The total 

recreation value lost over the period is estimated to be $111.8 million. In this catastrophic spill 

scenario, we assume the impacts discussed result from a spill of 4.8 million barrels. Dividing the 

recreation value lost by the number of barrels spilled gives a value loss of $23.43 per barrel.

Beach Recreation

Historic data on the annual number of visitor days for beach recreation in the Gulf Coast States 

was obtained from the 2000 National Survey of Recreation in the Environment (NSRE) 

conducted by the U.S. Forest Service and NOAA. In order to estimate the number of visitor days 

in May, June and July, the monthly visitation data from Gulf Islands National Seashore (located 

in MS and FL) was used to estimate the percentage of visitation during this three month period 

(48%) and this percentage was applied to the annual state visitation data. For the State of 

Florida, information from Murley et al. (2005) was used to estimate the percentage of beach 

recreation visits that occur on the western coast (25.7%). The estimated recreation days in each 

state during the period are shown in Table 18. 

Table 18. Estimated Number of Recreation Days (May-July)

State Recreation Days

Alabama 5,683,200 

West Florida 21,853,224 

Louisiana 1,939,200 

Mississippi 4,161,600 

Texas 16,910,400 

Total 50,547,624

Ideally, in order to estimate the number of recreation days lost, actual visitation data would be 

collected from beach surveys or over flight surveys during the affected period and compared to 

average visitation levels for that time of year. In the absence of actual visitor counts, certain 

assumptions must be made to estimate the recreation days lost. In this case, the percentage of 

oiled shoreline in each state as of July 22, 2010 was used to approximate the percentage of 
63

recreation days in each state that were affected (12% in AL, 2% in FL, 5% in LA, 30% in MS 

and 0% in TX). This is likely to be an underestimate for much of the area because the total 

shoreline used to calculate the percentage of area affected includes areas that are not used for 

beach recreation.

Although most beaches along the Gulf Coast may remain open after a deepwater catastrophic oil 

spill, decreased visitation and a reduction in quality experience for those that still participate in 

beach recreation are likely to occur. In this analysis, we assume that all beaches remain open, 

with a decrease in recreation days of 20% compared to historic levels. We also assume that 

remaining visitors experience a loss in consumer surplus due to decreased quality of the 

recreation activity. We assume a 20% loss in quality for each recreation day affected, following 

Chapman and Hanemann (2001). 

Consumer surplus values for beach recreation per activity day were obtained from 8 studies 

conducted in the Gulf Coast region. All values were converted to current (2010) dollars and 

averaged to obtain a value of $88.47 per activity day. This value was then multiplied by the 

number of recreation days in each state to arrive at a total consumer surplus value for beach 

recreation during the three month period. Using these values, we estimate a loss in the value of 

beach recreation of $75.5 million over the period, or $15.82 per barrel for a spill of 4.8 million 

barrels. It should be noted that these estimates do not explicitly account for the availability of 

substitute beach sites, or the differences in behavior of local versus out of state visitors. If 

suitable substitutes are available, it is likely that the decrease in consumer surplus would be 

smaller than if fewer substitutes are available.

As with the commercial fishing analysis, we used selected characteristics of the BP spill as a 

proxy for a future catastrophic spill simply for analytical convenience. These factors include the 

closure periods and time of year. The minor size of the recreational fishing and beach use values 

relative to the total social cost estimate did not justify devoting further effort to refining the spill 

circumstances such as randomizing time of year or adjusting for fishing trip substitution.
64

Table 19. Recreation Studies

Recreational Fishing

Year State Reference

1991-1992 Florida (Tampa Bay) Greene et al., 1997

1991 Gulf of Mexico Gillig et al., 2000

1991 Florida Leeworthy, 1990

1992 Florida Bell et al., 1982

1999 Louisiana Bergstrom et al., 2004

1990 Florida Bell, 1992

1988 Florida McConnell and Strand, 1994

Beach Recreation

Year State Reference

1996 Florida (Keys and Key West) Leeworthy and Bowker, 1997

1984 Florida Bell and Leeworthy, 1986

1984 Florida Bell and Leeworthy, 1986

2008 Texas (Padre Island Nat. Seashore) Parsons et al., 2009

1990 Florida (Clearwater Beach) Leeworthy and Wiley, 1994

1990 Florida (Honeymoon Island State Park) Leeworthy and Wiley, 1995

1984 Florida Bell and Leeworthy, 1990

1988 Florida (John Pennekamp State Park) Leeworthy (1991)

Oil Spill Response and Damage Assessment Costs

Response or removal expenditures include rescue and rehabilitation of personnel and wildlife, 

salvage of infrastructure, cleanup of oil from aquatic and terrestrial areas, and hearings and 

investigations into causes of a spill. Removal costs include the equipment used in the 

response—skimmers to pull oil from the water, booms to contain the oil, airplanes for aerial 

observation or dispersant application—as well as salaries, travel and lodging costs for 

responders. Response expenditures can be incurred by: Federal, State, Tribal governments; 

industry; non-governmental organizations; private companies; and foreign entities. Response 

costs exclude the wellhead containment costs to secure and kill the uncontrolled flow from a well 

blowout. Although technically “response costs” under the Oil Pollution Act (OPA), those

containment costs are considered private-social costs for this analysis and covered in the section 

on Avoided Private-Social Costs. Damage assessment costs can include costs associated with 

data collection and analysis required to evaluate the impacts of the spill relative to pre spill 

conditions.

In a 2003 report to Congress, (Informing Regulatory Decisions: 2003 Report to Congress on the 

Costs and Benefits of Federal Regulations and Unfunded Mandates on State, Local, and Tribal 
65

Entities), OMB considered benefits of vessel response plans and double-hull vessels by valuing 

avoided spills at $2,000 per barrel, noting that “This is double the sum of the most likely 

estimates of environmental damages plus cleanup costs contained in a published journal article.”

Estimates of response costs can also be found in the literature. Table 20 presents estimates in 

current dollars of oil spill cleanup costs by oil type; Table 21 presents estimates by kilometer of 

shoreline oiled; Table 22 presents estimates by proximity to shore. Table 23 presents 

information by spill volume.27

Table 20 Cost of Spills by Fuel Type

Oil Type US Spills (2010 

$/bbl)

No. 2 diesel 

fuel 

638

Light crude 554

No. 4 fuel Data not available

No. 5 fuel 1,539

Crude 2,570

Heavy crude 3,733

No. 6 fuel 3,198

Per-unit cleanup costs by degree of 

shoreline oiling

Source: Etkin, June 2000.

Table 21 Cost of Spills by Length of Shoreline Oiled

Shoreline 

Length

Oiled US 

Spills 

(2010 $/bbl)

0-1 km 468

2-5 km 1,060

8-15 km 1,866

20-90 km 2,684

100 km 4,832

500 km 9,197

 

27 Etkin, D. June 2000. Worldwide Analysis of Marine Oil Spill Cleanup Cost Factors. Presented at Arctic and 

Marine Oil Spill Program Technical Seminar; Etkin, D. 2001. Comparative Methodologies for Estimating on Water 

Response Costs for Marine Oil Spills, International Oil Spill Conference.
66

Table 22 Cost of Spills by Location

Location US Spills 

(2010 

$/bbl)

In-port 6,033

Nearshore 4,437

Offshore 1,217

Source: Etkin, 2001.

Table 23 Oil Spill Response Costs by Spill Volume

Spill Volume 

(bbls)

Total Cost 

($2010)

$ per bbl 

($2010)

240 203,803 856

2,400 2,072,094 870

12,000 10,953,217 920

120,000 46,885,858 394

240,000 90,476,930 380

Source: Etkin, 2001.

For the purposes of the benefit-cost analysis it is assumed that one third of the response efforts 

occur nearshore and two-thirds offshore. The weighted average of the near- and offshore 

response cost estimates presented above is $2,300 per bbl.

Avoided Costs Associated with Reduced Loss of Life and Nonfatal 

Injuries

There have been 20 blowouts from deepwater wells, with 2 resulting in injuries or fatalities. 

Those two events are a 1984 blowout with 4 fatalities and 3 injuries and the 2010 BP-Deepwater 

Horizon explosion and resulting spill with 11 fatalities and 17 injuries. For purposes of 

estimating costs avoided from reduce loss of life and injuries, the following uses the average 

fatalities and injuries for these 2 cases as values for a hypothetical catastrophic deepwater 

blowout.

Value of Statistical Life

The proposed regulation, because it is anticipated to reduce the probability of catastrophic 

blowout events, is likely to reduce the risk of premature death of rig workers. The oil and gas 

extraction industry is characterized by a relatively small percentage of the Nation’s workforce 

and a higher fatality rate than most other industries. Approximately 161,600 workers were 

employed in oil and gas extraction occupations in 2008 (Bureau of Labor Statistics 2010). The 
67

fatality rate for oil and gas extraction workers is high compared to many other industries, with a 

rate of 23.4 fatalities per 100,000 full-time equivalent workers (Table 24).

Table 24 Selected Fatal Occupational Injury Rates by Industry, 2008

Industry Fatality Rate 

(per 100,000 Full-Time 

Equivalent Workers)

Agriculture, forestry, fishing, and 

hunting

30.4

Oil and gas extraction 23.9

Transportation and warehousing 14.9

Construction 9.7

Protective service occupations 

(includes protective service occupations 

such as fire fighters, law enforcement)

9.1

Manufacturing 2.5

Management, professional, and related 

occupations

1.6

Finance, insurance, real estate and 

leasing

1.1

Source: Bureau of Labor Statistics, 2010.

The benefits of occupational risk reduction are usually measured using the concept of “value of 

statistical life” (VSL). The VSL concept is based on individual willingness to pay for reductions 

in small risks of premature death and not on the present value of future earnings. In concept, the 

VSL is the measurement of the sum of society’s willingness to pay (WTP) for one unit of fatal 

risk reduction, which is society’s willingness to pay for reducing each individual’s risk by a 

small amount. 

VSL estimates are derived from aggregated estimates of individual values for small changes in 

mortality risks. For the analysis of benefits, mortality risks can generally be classified across the 

characteristics of the affected population and the characteristics of the risk itself. These factors 

should be addressed in any analysis that transfers values from one study to a new policy context. 

The literature on VSL identifies the following factors that affect risk perceptions that could be 

considered in selecting and adjusting any VSL values:

 Voluntary/involuntary;

 Ordinary/catastrophic;
68

 Delayed/immediate;

 Natural/man-made;

 Old/new;

 Controllable/uncontrollable;

 Necessary/unnecessary; and

 Occasional/continuous.

Whether adjustments are made to the VSL value depends on a variety of factors, including the 

extent to which such adjustments could be made on a systematic and defensible basis. To date 

there has been a lack of consensus on the merits of using a single VSL for all situations versus 

adjusting the VSL estimates to reflect the specific rule context. 

Income has been found to have a clear and measurable effect on the VSL: as income increases, 

WTP for risk reductions usually increases. While this effect could be measured both crosssectionally (across individuals or subpopulations) and longitudinally (over time), most studies 

are cross-sectional. However, using different VSL estimates for individuals with different 

incomes is controversial and has raised issues about the equitable treatment of richer and poorer 

segments of the population in policy decisions (Robinson, 2007). Some recent studies only 

consider samples from extremely dangerous jobs, such as police officers. Workers in these jobs 

may have different risk preferences and face risks much higher than those evaluated in typical 

environmental policy contexts (Kochi, 2006). Other recent research has examined how VSL 

varies with age, how it varies between males and females, and how worker heterogeneity may 

impact VSL.

A large number of estimates of VSL exist in the academic literature. This literature involves 

either explicit or implicit valuation of fatality risks, and generally involves the use of estimates of 

VSL from studies on wage compensation for occupational hazards, on consumer product 

purchase and use decisions, or from an emerging literature using stated preference approaches. 

Values reported have varied over time, geographic location, and worker heterogeneity. VSL 

estimates from under $1 million to around $3 million that were used to assess policies in the 

early 1980s have now been replaced by estimates as high as $9 million (Viscusi, 2010). A 

substantial majority of the resulting estimates of VSL vary from roughly $1 million to $10 

million per statistical life. The literature based on estimates using U.S. labor market data 

typically shows a VSL in the range of $4 million to $9 million. 

EPA recommends that the central estimate of $7.4 million ($2006), updated to the base year of 

the analysis, be used in all benefits analyses that seek to quantify mortality risk reduction 

benefits regardless of the age, income, or other population characteristics of the affected 

population. This approach was vetted and endorsed by the Agency when the 2000 Guidelines for 
69

Preparing Economic Analyses were drafted. A recent report of the EPA’s Science Advisory 

Board (SAB) concluded that the available literature does not support adjustments of VSL for 

most factors. However, the panel did support adjustments to reflect changes in income (EPA 

allows the adjustment of VSL based on increases in future income but not on cross-sectional 

differences in income), adjustments for inflation and time lags in the occurrence of adverse 

health effects. 

VSL Value Used in Offshore Safety Regulation

For the purpose the analysis to estimate the avoided costs associated with reduced mortality, $8 

million is used to value each statistical life. This is the EPA recommended estimate of $7.4 

million updated to current dollars ($2010). Although oil rig workers are involved in an 

inherently risky occupation, based on the lack of consensus in previous research focused on 

adjusting VSL values for occupational risk, the EPA VSL recommendation was chosen for this 

analysis.

Based on the estimated value of 8 deaths per blowout event, using a VSL value of $8 million, for 

a 4.8 million barrel spill, the loss of life value from a blowout would be $13/barrel. 

Nonfatal Injuries

On average, workers value non-fatal loss injuries on the job at values ranging from $20,000 to 

$70,000 per expected job injury. Thus, for example, a worker at the high end of this range would 

require $2,000 to face a one-in-25 chance of being injured that year (Viscusi, 2005).

We estimate an average value of job injuries at $45,000 per injury. With 10 injuries expected 

per catastrophic blowout event, a 4.8 million barrel spill would result in an estimated cost of 

$0.09 per barrel. 

Other Health Effects

The Centers for Disease Control and Prevention (CDC) report that the Gulf Coast oil spill has the 

potential to affect human health. CDC and the Gulf States have a plan to track symptoms28

occurring in the affected communities and will be able to investigate whether there is an 

association between symptoms and the oil spill. As of July 20, 2010, the American Association 

of Poison Control Centers reports receiving 843 “exposure calls” involving someone exposed to 

an oil-spill related toxin (e.g., oil, dispersant, food contamination).

 

28 Symptoms may be related to the eyes, skin, and respiratory, cardiovascular, gastrointestinal, and neurological 

systems, including worsening of asthma, cough, chest pain, eye irritation, nausea, and headache.
70

Human health effects from oil spills include short-term physical effects from exposure of cleanup workers and residents of the area, mental health effects on workers and residents, as well as 

long-term effects. However, the research on health effects of oil spills is limited to date. There 

has been some evidence of acute physical effects and psychological effects in a number of cases. 

For example, CDC’s National Institute for Occupational Safety and Health reports 186 injuries 

and 80 illnesses29 among spill responders in the Gulf. However, evidence of long-term health 

effects is lacking. Much of the research on the physical effects of oil spills has been conducted 

outside of the United States. Some researchers have found evidence that oil spills affect the 

health of individuals involved in clean-up activities (Pérez-Cadahía et al. 2006), residents in the 

immediate vicinity of a spill (Janjua et al. 2006, Lyons et al. 1999), and residents involved in 

clean-up efforts (Morita et al. 1999). Physical effects on residents near oil spills have included 

sore eyes and throat (Lyons et al. 1999, Janjua et al. 2006) as well as headaches and general 

malaise (Janjua et al. 2006). Pérez-Cadahía et al. (2006) show evidence of cytogenetic damage 

and alterations in hormonal status. 

Evidence of mental health effects have been shown for the Exxon Valdez and Prestige oil spills 

(Palinkas et al. 1993a, Palinkas et al. 1993b, Sabucedo et al. 2010). Palinkas et al. (1993a) show 

links between the oil spill and increased rates of depression, anxiety and post-traumatic stress 

disorder, and declines in subsistence activities and traditional social relationships. Sabucedo et 

al. (2010) show similar results with greater psychopathological symptoms in individuals living 

closer to the location of the oil spill and in fishermen.

Avoided Costs Associated with Other Activities Linked Economically 

to Avoiding an Oil Spill

A large oil spill will have economic costs that accrue beyond the area directly impacted. These 

costs will be incurred by businesses and households that are linked economically to coastal areas 

or to activities occurring in areas damaged by the spill. The oil spill may result in reduced 

producer surplus, lost producer surplus on products or services that are no longer produced, or 

some combination of the two. The magnitude and timing of any reduced producer surplus is 

difficult to predict, however the larger the spill and the more extensive its geographic impacts the 

larger the potential for producer surplus losses. The lost producer surplus associated with 

economic losses is not quantified for this analysis due to the uncertainties associated with the 

scope, magnitude, and timing.

 

29 As of June 6, 2010; mostly contusions/abrasions and heat stress.
71

Summary – Avoided External-Social Costs

Table 25 summarizes the estimated avoided external-social costs of the hypothetical catastrophic 

blowout spill conditional on the spill being precluded from occurring. Spill costs that are 

avoided could be much higher if all costs discussed previously could be monetized. Efforts to 

quantify even rough estimates for those rows left blank in the table by reference to other oil spills 

were not fruitful because such private settlements are not reported publicly. Nevertheless, given 

the relative size of those sub-elements that could be monetized, the findings indicate that 

recreation, fishing and mortality losses are quite small compared to the costs for spill cleanup, 

damage assessment, and the imputed value of natural resource damages. Thus, provision for the 

lingering effects which an oil spill might have on fishing losses is not likely to affect the overall 

results.

Table 25 Summary of Estimated Avoided External-Social Costs

Social Cost Category Cost Avoided Cost 

for 1 

Hypothetical 

Spill

($ per bbl) (4.8 mm bbl)

Natural Resource Damages $604 $2.88 billion

Recreational Losses (Recreational 

Fishing and Beach Recreation)

$42 $0.20 billion

Commercial Fishing Losses $2 $0.01 billion

Value of Life and Nonfatal Injury $13 $0.06 billion

Other Health Effects Not 

Quantified

Oil Spill Response & Damage 

Assessment Costs

$2,300 $10.97 billion

Staging, training, and other costs 

associated with prepositioning oil spill 

response assets

Not 

Quantified

Price effects in seafood markets Not 

Quantified

Property values Not 

Quantified

TOTAL $14.12 billion
72

TOTAL ESTIMATED AVOIDED SOCIAL COSTS (BENEFITS)

Table 26 combines the conditional avoided private-social and external-social costs from Table 6

and Table 25. This is the potential benefit per catastrophic spill in the baseline from fully 

eliminating the possibility of a spill.

 

Table 26 - Summary of Private and External Social Costs

Social Cost 

Category

Conditional 

Avoided Cost 

Amount

Expected Avoided Cost Given 

1 Spill in 25.8 years (3.85% 

probability of a spill each year)

Private Costs $2.17 billion $84.1 million

External Costs $14.12 billion $547.3 million

Total: $16.29 billion $631.4 million

The policies being promulgated can reduce, but not necessarily eliminate, the occurrence of a 

catastrophic spill and hence the resulting spill costs. Since the compliance costs are fully 

represented by annual expense outlays, it is convenient to express the expected avoided costs on 

an annual basis as well. Moreover, the coincident timing of compliance costs and risked avoided 

costs dispenses with the need to complicate the calculations and presentation by converting 

streams of monetary costs and benefits into discounted present value amounts.

There has been the only one deepwater blowout spill large enough to be considered in the 

catastrophic class. Based on this single observation, the number of deepwater wells drilled 

(4,123), and the anticipated annual number of future deepwater wells to be drilled (160), the 

baseline risk absent this rule is estimated to be 1 event in 26 years for this benefit-cost analysis. 

Compliance with the requirements in this rule will partly reduce the expected annualized spill 

costs by reducing the spill frequency, thereby increasing the expected interval between such 

spills and hence spreading the conditional spill costs over more years. The resulting reduction in 

the expected annualized spill costs represents the social costs associated with the hypothetical 

spill scenario avoided because of the provisions in this rule.

SCENARIO ANALYSIS

In order to compare the relative magnitudes of the expected benefits and costs associated with 

avoiding a blowout resulting in catastrophic oil spill, the agency examined several scenarios
73

based on extrapolation from historical information on deep water blowouts. Given the paucity of 

information on specific effectiveness of various measures and the likelihood of another 

catastrophic blowout, this approach aims to evaluate the Final Rule in the context of alternative 

assumptions. 

The methodology we used to compare the economic effects of the Final Rule under the various 

scenarios was to determine the hypothetical improvement in spill frequency that would have to 

occur under each scenario for the expected benefits to match the expected costs (the breakeven 

point). Calculating the breakeven point for each scenario is a useful analytical tool for 

comparing the sensitivity of the various factors in our analysis. It will also assist agency 

policymakers in getting a sense of whether promulgation of the final rule would likely have a net 

economic benefit under differing assumptions. These calculations, however, are not an agency 

determination of the actual expected improvement in spill frequency that the final rule will bring 

about. Such a determination is based upon assessing the expected effects of the provisions of the 

final rule, and not upon hypothetical economic analyses. 

By varying selected important assumptions from those of the Baseline Scenario in reasonable 

ways, we have provided a range of reasonable alternative scenarios that could be expected to 

occur. For each of those scenarios, we have calculated the improvement in spill frequency under 

which expected benefits could justify the costs of the regulation (the economic breakeven point). 

The Scenarios have been developed by varying the assumptions from the Baseline Scenario as 

follows:

1) The compliance costs are lowered by about 50% to $65.4 million reflecting 

improvements in the efficiency of safety practices. 

2) The compliance costs are raised by about 100% to $261 million reflecting more 

frequent compliance problems and work stoppages during drilling operations, as 

discussed in the next section. 

3) The population of deepwater wells subject to a future catastrophic blowout spill is 

limited to those in water deeper than 3,000 feet, where the spill size and consequences 

(but not the spill probability) from a blowout are estimated to be greater. For the 

purpose of conducting this sensitivity analysis only, we employed the historical 

population of 1,475 wells drilled in the GOM at a water depth of 3000 feet or greater 

to set the baseline risk, and forecast that an average of 110 wells will be drilled each 

year at this depth. Elaboration of this scenario is provided in the Sensitivity of 

Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic 

Blowout Spill.
74

4) The baseline of the expected number of deepwater wells drilled each year is reduced 

by 25 percent. This would reduce the number of deepwater wells in the analysis from 

160/year to 120/year. This scenario is closer to the number of deepwater wells drilled 

in the two years before the DWH spill.

Baseline Scenario

For the Baseline Scenario, the hypothetical spill from Table 26 gives an avoided social cost of 

$16.3 billion for a major event. The compliance costs of this regulation from Table 4 give an 

annual compliance cost of $131 million per year. The baseline assumption is that there was one 

major event for every 4,123 deepwater wells and we assume an average of 160 wells will be 

drilled annually. Under these circumstances, a major event is projected to occur at an average 

rate of approximately once every 26 years.30

Using the avoided social cost of $16.3 billion and dividing it by the rate of a major event, one per 

every 26 years, we calculate an annual avoided cost of $631 million. To calculate the level of 

improvement in spill frequency for the expected benefits to equal the costs of regulation, we 

divide the compliance costs by the annualized avoided costs. An annual compliance cost of $131

million divided by annualized avoided costs of $631 million results in a 21 percent improvement 

in spill frequency that would be the level at which expected benefits would match the expected 

compliance costs.

Sensitivity of Compliance Costs

A lower compliance cost estimate of $65.4 million annually assumes the industry can achieve 

longer term productivity improvements for the requirements in this regulation. Over time, 

companies can increase the efficiency of conducting tests and use technology to improve safety; 

however, a 50 percent improvement appears unlikely to be achieved in the near term. Using this 

lower compliance cost of $65.4 million, divided by the annual avoided cost of $631 million, an 

improvement in spill frequency of 10 percent would be sufficient for estimated benefits to match 

estimated compliance costs.

An upper compliance cost estimate of $261 million annually assumes that the time required for 

conducting the tests for this regulation are doubled due to unforeseen and time consuming 

problems encountered in fulfilling the additional requirements imposed by this regulation. Using 

this upper compliance cost of $261 million divided by the annual avoided cost of $631 million, 

 

30 4123 wells divided by 160 wells per year gives us 25.8 years, or 26 years.
75

an improvement in spill frequency of 41 percent would be the level at which estimated benefits

would match the estimated compliance costs.

Sensitivity of Population of Deepwater Wells and Drilling Activity 

Subject to a Catastrophic Blowout Spill

To analyze the sensitivity of the population of deepwater wells and drilling activity, along with 

the underlying effect on the baseline risk assumption, we identified the water depth at which the 

consequences of a blowout event may be more severe. In the baseline analysis we used a 500 

foot water depth demarcation since it is the upper limit of jackup rigs and where subsea BOP 

stacks start to be used for MODUs. While there is no specific water depth demarcation for an 

increase in the consequences of deepwater blowout, wells which are drilled at a water depth 

greater than 3,000 feet may have an increased potential for a catastrophic event due to changes in 

the surrounding geology and reservoirs as well as greater difficulty mitigating the consequences 

of an uncontrolled flowing well. 

The changes in the geological formations allow for greater accumulation potential with porous 

and permeable sands at these depths and result in higher flow rates. The most recent public Gulf 

of Mexico Reserves Report31 indicates that 6 of the 20 largest GOM fields are in water depths 

greater than 2,860 feet and discovered since 1989. Fourteen of the fields are in water depths 247 

feet or less and discovered in 1971 or earlier. The GOM shelf is in decline and few large fields 

are likely to be discovered in the GOM shallow water. Over the last 40 years the largest fields 

with booked reserves have all been in deepwater. Thus the reservoirs being discovered at depths 

greater than 3000 feet are generally more prolific than their shallow water counterparts. 

It is important to note that the probability of a blowout does not appear to be greater beyond 

3,000 feet water depth and based on OCS drilling history is actually lower than shallower water 

depths. However, the consequences of an uncontrolled blowout event in deeper water depths are 

more likely to be catastrophic because of the additional complications in restoring well control at 

the water depths as demonstrated by the DWH event. In this sensitivity analysis we are 

considering a scenario which based on the occurrence of a single catastrophic blowout event 

(DWH) in water depths greater than 3,000 feet.

Historically, there have been 1,475 GOM wells drilled in water depths of greater than 3,000 feet, 

with approximately 1,100 wells in the past 10 years. This gives a 1/1475 probability of a 

 

31 Reserve Data for 1,229 Proved Fields - Gulf of Mexico Outer Continental Shelf, December 31, 2006, 

http://www.gomr.boemre.gov/homepg/offshore/fldresv/2006-Table4.pdf.
76

catastrophic blowout spill event, and about 110 wells drilled per year. At this rate, one event 

occurs every 13.4 years in this alternate scenario.32

By dividing the expected avoided social cost of $16.3 billion by the alternate scenario 

catastrophic event rate of 13.4 years per event, the annual avoided cost is $1.216 billion. 

Dividing the compliance costs of $131 million per year by the alternate annual avoided costs of 

$1.216 billion per year would result in an improvement in spill frequency of 11 percent for the 

estimated benefits to match the estimated costs in this alternate hypothetical scenario.

Sensitivity of Number of Deepwater Wells Drilled per Year (25% lower)

The baseline assumption in this is for an average of 160 new deepwater wells drilled each year. 

This alternate scenario reduces the baseline number of deepwater wells by 25 percent from 160 

to 120 wells per year. The number of shallow wells remain constant at 286 per year. This 

scenario is plausible given likely reactions to drilling activity in the aftermath of the DWH event. 

Several deepwater MODU’s have left the Gulf of Mexico and other new build deepwater rigs 

previously scheduled to drill in the deepwater Gulf have announced moves overseas. 

Additionally there are other factors that may lengthen the time to drill deepwater wells including 

deeper drilling depths and the stricter application of existing regulations. These factors are 

discussed in the section titled Baseline Estimates of Future Deepwater Drilling Activity. While 

the long-term GOM drilling activity is subject to many factors, it is not unreasonable to assume 

that drilling activity could remain relatively flat and continue in the range of the number of 

deepwater wells drilled in 2009 and originally projected for 2010 (Figure 1). The following table 

provides the compliance costs estimates for the scenario of 120 (85 MODU plus 35 platform) 

deepwater wells per year.

 

32 1475 wells drilled divided by 110 wells per year equals 13.4 years.
77

Table 27 – Estimated Recurring Cost Summary (25% fewer deepwater wells per year)

Regulation Recurring Costs: MODU 

Wells 

(85/yr)

Fixed 

Platforms 

(35/yr)

Shallow 

Wells 

(186/yr)

Cost 

Shares

Total 

($MM)

Total 

($MM)

Total 

($MM)

250.449(j)(k) Subsea ROV function testing (drilling) 12.8 0.0 0.0 12%

250.516(d)(8), 

250.616(h)(1)

Subsea ROV function testing 

(completions/workover)

4.1 0.0 0.0 4%

250.423(c) Test casing strings for proper installation 

(negative pressure test)

9.6 0.0 0.0 9%

250.420(b)(3) Installation of dual mechanical barriers 39.3 7.6 20.5 65%

250.420(a)(6) PE certification for well design 1.0 0.4 2.1 3%

250.451(i)(j) Emergency cost of activated shear rams or 

LMRP disconnect

2.0 0.0 0.0 2%

250.416(e) Independent third party shear certification 0.3 0.2 0.6 1%

All Paperwork Costs taken from PRA table in 

final rule.

1.9 0.3 1.6 4%

Estimated Cost per year: 71.0 8.4 24.8 $ 104.2 

Estimated Cost per well: 0.84 0.24 0.13

Dividing the compliance costs of $104.2 million per year by the alternate annual avoided costs of 

$466 million per year ($16.3B/[4123/120]) would result in an improvement in spill frequency of 

22 percent for the benefits to match the costs in this alternate hypothetical scenario.

Scenario Analysis Summary

The following table summarizes the baseline and alternative scenario analysis: 
78

Table 28 – Alternative Scenario Summary

Scenario

Annual 

Compliance 

Costs ($MM)

Annual 

Avoided Costs 

($MM)

Catastrophic Spill 

Frequency 

Improvement Required 

for Benefits to Match 

Costs of Rule (percent)

Baseline $131 $631 21 percent 

Compliance Costs lowered 50 

Percent

$65 $631 10 percent 

Compliance Costs Increased 

100 Percent

$261 $631 41 percent 

>3,000 feet (110 deepwater 

wells/year)

$131 $1,216 11 percent

Number of Deepwater Wells 

Drilled per Year (25% lower)

$104 $466 22 percent

As can be seen from the Table 28, changing assumptions yields different risk reductions of a 

catastrophic spill event (spill frequency improvement) needed for the estimated economic 

benefits to match the estimated compliance costs of rulemaking (the breakeven point). The 

reduction in spill frequency for this match to occur would range from 10 to 41 percent, with the 

Baseline Scenario improvement level at 21 percent. Based upon this range, and upon the 

agency’s analysis of the provisions of the rule (discussed below), it is reasonable to conclude that 

this rulemaking will reduce the risk for a catastrophic blowout spill event at least enough such 

that estimated benefits will justify the estimated costs of this regulation.

Alternatives

This final rule implements selected safety measures recommended in the report entitled, 

“Increased Safety Measures for Energy Development on the Outer Continental Shelf” (Safety 

Measures Report), dated May 27, 2010 and the subsequent JIT report of BOEMRE and the 

USCG. Given the critical nature of the BP Deepwater Horizon (DWH) explosion and resulting 

oil spill and the apparent inadequacy of existing well control procedures and BOP requirements, 

the Safety Measures Report recommended that BSEE’s predecessor agency address some items 

through an emergency rulemaking. The requirements in this final rule include practices related 

to well control, including well casing and cementing, ROV intervention, unplanned disconnects, 
79

recordkeeping, well completion, and well plugging. These requirements are determined by the 

Secretary to be urgently needed to protect worker safety and the OCS environment.

Other measures recommended in the investigative reports but not included in this rulemaking 

include additional blind shear and casing ram requirements, enhanced ROV intervention 

capability, increased accumulator capacity for operating BOPs and safety case requirements for 

floating drilling operations. These and other items require further study and public input to 

determine their efficiency and effectiveness. Measures considered beneficial will be considered 

for future notice and comment rulemaking.

Small Business Alternatives

A separate Initial Regulatory Flexibility Analysis (IRFA) was performed for the interim final 

rule (75 FR 80717). A Final Regulatory Flexibility Analysis (FRFA) for this rule is found in 

Appendix A. 

CONCLUSION

On June 2, 2010, the Secretary of the Interior directed BSEE’ predecessor agency BOEMRE to 

adopt the recommendations contained in the Safety Measures Report and to implement them as 

soon as possible. On September 14, 2011, the BOEMRE published the final joint investigation 

report (DWH JIT report), on the causes of the Deepwater Horizon incident, which included 

multiple regulatory recommendations. To implement the most practical recommendations

identified by experts in the Safety Measures Report and DWH JIT report, this rulemaking 

amends corresponding drilling, well completion, well workover, and decommissioning 

regulations related to well control, including those covering: subsea and surface blowout 

preventers, well casing and cementing, secondary intervention, unplanned disconnects, 

recordkeeping, well completion, and well plugging.

BSEE has analyzed the costs and benefits of this rule using data available at the time of this 

rulemaking under various scenarios to assess when expected benefits might justify the expected 

costs. Under different assumptions about the magnitude of costs, benefits and drilling activity, 

we assessed how the frequency and the magnitude of future blowouts resulting in catastrophic 

spills should change for the expected benefits to justify the compliance costs. We have 

calculated the breakeven threshold this rulemaking would need to achieve for its potential 

benefits to balance the compliance costs. Relative to the baseline deepwater drilling experience, 

the breakeven threshold for this rulemaking is a 21 percent reduction in the probability of a 

catastrophic spill event. Although drilling system reliability data are unavailable to compute the 

blowout risk reduction associated with the specific provisions in this rulemaking, blowout risk 
80

reduction should result from the three most critical safety provisions required by the Interim 

Final Rule and the Final Rule. We expect these new requirements will reduce the chances of 

another catastrophic spill and that the breakeven risk reduction is a modest goal for the 

improvement in drilling safety likely to stem from these provisions. We confidently expect the 

improvement in drilling safety through the requirements in this rulemaking, will reduce the 

probability of a catastrophic spill by at least 21 percent.
81

Appendix A Final Regulatory Flexibility Act Analysis, RIN 

1014-AA02

Agency: Department of the Interior, Bureau of Safety and Environmental Enforcement (BSEE).

Regulatory Citations: The Safety Measures Rule is amending the drilling regulations at 30 CFR 250, 

subparts D, E, F, and Q. The rule is titled RIN 1014–AA02, Final Rule, Increased Safety Measures for 

Energy Development on the Outer Continental Shelf and was originally published as an Interim Final 

Rule on October 14, 2010 (75 FR 63346).

Summary: BSEE is publishing this Final Regulatory Flexibility Analysis (FRFA) in conjunction with 

the final rule. The Bureau’s publication of the interim final rule did not include a full Initial Regulatory 

Flexibility Analysis (IRFA) pursuant to the Regulatory Flexibility Act (5 U.S.C. 603). A supplemental 

IRFA was published on December 23, 2010 (75 FR 80717) with a 30 day comment period which closed 

on January 24, 2011. The changes from the IRFA are minor and relate to lower compliance cost 

estimates for the regulation. The revised cost estimates are the result of changes to the regulatory 

language and improved estimates of the counts and the operational timeframes required to comply with 

the regulatory provisions. 

Supplementary Information 

BSEE has updated the estimated compliance costs and small business impacts from the projections 

reported in the IRFA. These changes are minor and mostly result from updated compliance costs for 

several of the provisions and the including of paperwork and recordkeeping costs for this regulation. 

Over the last few years there have been some notable trends in the Gulf of Mexico. First, several of the 

new companies entering the Gulf of Mexico (GOM) are large foreign companies and not small 

businesses. Second, the number of deepwater wells drilled by small companies has increased as capital 

and technology has become more accessible to small entities. Third, a few of the smaller companies with 

meaningful OCS acreage have either sold their OCS assets to larger companies, become wholly owned 

subsidiaries, or merged with larger companies. Cumulatively, these trends result in a greater share of 

acreage, drilling, and production attributed to large companies.

Our analysis shows there are currently about 130 Operators of Federal oil and gas OCS leases. Small 

lessees that operate under this rule fall under the Small Business Administration's North American 

Industry Classification System (NAICS) codes 211111, Crude Petroleum and Natural Gas Extraction, and 

213111, Drilling Oil and Gas Wells. For these NAICS code classifications, a small company is one with 

fewer than 500 employees. Based on these criteria, we estimate 65 percent of these companies are small 

entities. This proposed rule, therefore would affect a substantial number of small entities. 

Much of the information in this FRFA is covered and discussed in the final rule preamble and elsewhere 

in this RIA for the Safety Measures Rule. These documents can be found at http://www.regulations.gov
82

under the Docket ID: BSEE-2012-0002. This FRFA is not intended to duplicate all the explanations and 

analysis in those documents, but rather meet the requirement and intent of the Regulatory Flexibility Act. 

This FRFA analyzes and considers the impact of the Safety Measures Rule on small entities. 

Summary of Small Business Impacts 

We estimate the Safety Measures Rule will impose a recurring operational cost of $131 million each year 

on operators drilling OCS wells. The rule affects every new well drilled after October 14, 2010; some 

requirements also apply to wells undergoing completion, workover, or abandonment operations on the 

OCS. Every operator both large and small must meet the same criteria for these operations regardless of 

company size. However, the overwhelming share of the cost imposed by these regulations will fall on the 

operating companies drilling deepwater wells, which are predominately the larger companies. We 

estimate that about 81 percent of the total costs will be imposed on deepwater lessees and operators where 

small businesses only hold 8 percent of the leases and drill 12 percent of the wells. About 19 percent of 

the total costs will apply to shallow water leases where small companies hold 45 percent of OCS leases 

and also drill 45 percent of the wells. 

Nonetheless, small companies as both operators and lease-holders will bear meaningful costs under these 

regulations. Of the annual $131million in annual cost imposed by the rule, we estimate that $12.3 million 

will apply to small businesses in deepwater and $11.0 million in shallow water. In total we estimate that 

$23.3 million or 18 percent of the regulations’ cost will be borne by small businesses.

The GOM represents 98 to 99 percent of annual OCS oil and gas drilling activity. Fiscal year 2009 

aggregate annual GOM OCS oil and gas revenues were $31.3 billion.33 Using the lease ownership 

profiles of GOM producing wells, we estimate that 87 percent ($27.2 billion) of the OCS revenues are 

ultimately received by large companies and 13 percent ($4.1 billion) by small companies. As a share of 

fiscal year 2009 revenues, the interim final rule will cost approximately 0.39 ($0.107/$27.2) percent of 

OCS revenue for large companies and 0.58 ($0.024/$4.1) percent for small companies. Although the 

difference in these ratios is not significant, small companies may experience a somewhat greater 

economic impact than large companies from the regulation primarily because they have a lower 

production share in deepwater relative to the number of deepwater wells they drill. The likely reason for 

this difference is the migration of smaller companies into deepwater as they have accessed the technology 

and capital required for exploration and development. It can take a decade for an economic discovery in 

deepwater to reach production. Additional data on lease ownership, wells drilled, and production can be 

found in Table 29, Table 30, Table 31, and Table 32.

Description of the Reasons that Action by the Agency is Being Considered

The final rule establishes regulations based on certain recommendations in the May 27, 2010, report from 

the Secretary of the Interior to the President entitled, “Increased Safety Measures for Energy 

Development on the Outer Continental Shelf” (Safety Measures Report) and selected subsequent 

recommendations from reports by the President’s National Oil Spill Commission and Joint BSEE/USCG 

 

33 The fiscal year 2010 GOM OCS revenues decreased to $24.7 billion. The corresponding share of costs as a share 

of revenues is estimated to remain essentially the same; the revenue figures have not been updated for the FRFA.
83

Joint Investigation Team. The President directed that the Department of the Interior (DOI) develop the 

Increased Safety Measures Report as a result of the Deepwater Horizon event on April 20, 2010. This 

event, which involved a blowout of the BP Macondo well and an explosion on the Transocean Deepwater 

Horizon mobile offshore drilling unit (MODU), resulted in the deaths of 11 workers, an oil spill of 

National significance, and the sinking of the Deepwater Horizon MODU. On June 2, 2010, the Secretary 

of the Interior directed BSEE to adopt the recommendations contained in the Safety Measures Report and 

to implement them as soon as possible. 

The selected measures from the Safety Measures Report and other reports being implemented initially are 

those in the Final Rule, AA-02 Increased Safety Measures for Energy Development on the Outer 

Continental Shelf. This FRFA is for the estimated impacts on small entities from this rulemaking. Some 

recommendations in the Safety Measures Report require additional review by the DOI, and yet other 

measures will be addressed through notice and comment rulemaking, as appropriate. 

The Safety Measures Rule preamble and Table 1 provide a table summarizing the rulemaking 

provisions.

Description of, and Where Feasible, an Estimate of the Number of Small 

Entities to Which the Rule will Apply

In order to understand the entities that will be impacted by the Safety Measures Rule, the role both 

operators and lessees play within the OCS oil and gas regulatory structure should be understood. 

The regulations at 30 CFR 250.105 defines “lessee” as:

Lessee means a person who has entered into a lease with the United States to explore for, develop, 

and produce the leased minerals. The term lessee also includes the BOEM-approved assignee of the 

lease, and the owner or the BOEM-approved assignee of operating rights for the lease.

While there may be multiple lessees holding an ownership interest, there can only be a single designated 

OCS operator for drilling or production operations on a lease. The regulations at 30 CFR 250.105 define 

“operator” as:

Operator means the person the lessee(s) designates as having control or management of operations 

on the leased area or a portion thereof. An operator may be a lessee, the BSEE-approved or BOEMapproved designated agent of the lessee(s), or the holder of operating rights under an BOEMapproved operating rights assignment (30 CFR 250.105).

Although the designated operator is the person BSEE typically holds responsible for complying with all 

regulations and ensuring the safety of drilling operations on a lease or unit, under BSEE regulations, joint 

and several responsibility for compliance exists among co-lessees, the operator, and persons (such as 

contractors) actually performing an activity to which a regulatory requirement applies.34 

 

34 Such responsibilities are expressly described in 30 CFR 250.146.
84

Consistent with the court’s interpretation that the RFA applies to entities directly affected by the 

rulemaking,

35 the designated operator and the co-lessees are the entities directly regulated by BSEE, 

impacted by this rulemaking and considered in the estimation of compliance costs.

While the requirements in this rulemaking apply to drilling operations under control of the operator, 

lessees are the project owners and will bear the compliance costs for the increased safety measures in this 

rulemaking. This analysis considers impacts on small and large entities based upon the lease ownership 

profiles for OCS activities because the lease owners will bear the cost of these regulations. The three 

OCS activities analyzed are (1) lease ownership, (2) wells drilled, and (3) production.

Additionally, this rulemaking requires drilling contractors to preserve certain maintenance and testing 

records. BSEE has only identified two active shallow water or platform drilling rigs operated by a small 

company on the GOM OCS among the approximately 50+ usually working there. This increased cost 

incurred by owners of drilling rigs is expected to be negligible compared to the added expense incurred 

by the Operators and Lessee owners due to the lengthened time to drill wells and additional permitting 

paperwork requirements.

Our updated analysis shows there are currently about 130 Operators of Federal oil and gas OCS leases, all 

of which will be impacted by this regulation if conducting drilling operations. Approximately 65 percent) 

of the companies operating on the OCS are considered small companies and 35 percent are considered 

large companies.

Breakout of Small and Large Companies Operating on the OCS

There are many arrangements for sharing project risks and expenses for OCS exploration and 

development projects. These include original and revised ownership agreements where the risk, equity, 

and other interests may be complex. When there is an assignment of lease rights among different parties, 

BOEM records the OCS lease assignments in a manner similar to county court property records. A 

snapshot of the OCS lease ownership profile and wells drilled on those leases for small and large 

companies’ form the basis for the Safety Measure Rule’s estimated impact on small entities. 

We analyzed OCS activity for both deepwater and shallow water by company size. Operating in the 

shallower water depths is generally less expensive and the concentration of smaller companies is greater 

in shallow water. The most costly requirements in the Safety Measures Rule apply to deepwater MODU 

drilling operations using a subsea blowout preventer (BOP). The following results for lease ownership, 

wells drilled, and production reflects leases with sole or fractional ownership as recorded by BOEM.

Deepwater

The categorization of company lessees shows that large companies (greater than 500 employees) hold 92 

percent of deepwater leases (greater than 500 feet) and small companies hold 8 percent. Cobalt 

International Energy is the only small company (less than 500 employees) among the top 30 companies 

holding deepwater acreage since Mariner merged with Apache.

 

35 Mid-Tex Electric Cooperative, Inc., v. FERC (Mid-Tex), 773 F.2d 327 (D.C. Cir. 1985).
85

When we consider deepwater drilling activity, the results are similar; of the wells spudded in deepwater 

during 2007-2009, 88 percent of deepwater wells were attributed to large company lessees and only 12 

percent to small company lessees. These results include the factional ownership by some small entities 

that are only equity investors in projects including some venture capital funds.

An even greater share of OCS deepwater hydrocarbon production and corresponding revenues accrued to 

large companies in calendar year 2009. While deepwater drilling activity attributed to small companies is 

increasing, economic projects cannot be brought to production for several more years. We use 2009 as a 

long-term proxy for the production split between small and large companies. Large companies produced 

97.5 percent of oil and 92.1 percent of gas production in deepwater. Only 2.5 percent of deepwater oil 

production and 7.9 percent of deepwater gas production is from leases owned by small companies.

Shallow water

We find that small companies hold a much greater share of acreage in shallow water (less than 500 feet) 

than in deepwater. The top two acreage-holding lease owners, Apache and Chevron, are not small 

companies, but the next four lessees in rank order are small entities: McMoRan, W & T Offshore, Stone 

Energy, and LLOG Exploration. In shallow water, small companies hold 45 percent of the leases while 

large companies hold 55 percent.

The drilling activity over the past 3 years matches the small and large companies lease ownership profile. 

Of the wells spudded during 2007-2009, 45 percent of the wells were spudded by small companies and 55 

percent by large companies.

Hydrocarbon production in the shallow water depths shows that larger companies hold the most 

productive leases. Slightly less than two-thirds of both oil and gas production accrues to large companies 

and slightly more than one-third is produced by small entities.

Summary of Large and Small Company OCS Activity

The following tables36 summarize the small and large company percentage breakouts of leases, wells 

drilled (2007-2009), production of oil and gas and value of OCS production. The results reflect lease 

fractional ownership shares among different companies.

Table 29 Lease Ownership among Small and Large Companies (11/1/2010)

Leases

11/01/2010

Shallow Water 

Leases

Deepwater 

Leases

All Leases

Large Co. 55% 92% 80%

Small Co. 45% 8% 20%

100% 100% 100%

 

36 The categorization of companies as small or large is based upon publically available data as measured by number of 

employees as of October 2010. BOEMRE collects data on lease ownership, wells drilled and operator production in our 

Technical Management System Database (TIMS).
86

Table 30 Wells Spudded among Small and Large Companies (2007-2009)

Wells

(2007-2009)

Shallow Water 

Wells Spudded

Deepwater

Wells 

Spudded

All Wells 

Spudded

Large Co. 55% 88% 65%

Small Co. 45% 12% 35%

100% 100% 100%

Table 31 Production based on Recorded Lease Share for Small and Large Companies (2009)

2009 

Production

Shallow Water 

Oil Production

Deepwater 

Oil 

Production

Shallow 

Water Gas 

Production

Deepwater 

Gas 

Production

All BOE 

Production

Large Co. 64.6% 97.5% 63.2% 92.1% 85%

Small Co. 35.4% 2.5% 36.8% 7.9% 15%

100% 100% 100% 100% 100%

Table 32 Estimated Production Value* ($millions) for Small and Large Companies (2009)

Est. 2009 

Production 

Value 

($million)

Shallow 

Water Oil 

Production

Deepwater 

Oil 

Production

Shallow 

Water Gas 

Production

Deepwater 

Gas 

Production

All BOE 

Production

Large Co. 2,581 17,284 3,271 4,079 27,215

Small Co. 1,415 442 1,905 351 4,113

TOTAL: 3,996 17,726 5,176 4,430 31,328

*Office of Natural Resource Revenue, http://www.onrr.gov/ONRRWebStats/default.aspx

Recurring Regulatory Costs Imposed by the Regulation

Table 4 summarizes the estimated recurring operational costs categories for three subgroups of wells 

affected by the new regulations. Those categories are (1) deepwater wells drilled by a MODU, (2) 

deepwater wells drilled from a platform and (3) all shallow water wells.

The regulations impact well costs differently depending on the type of drilling rig and category of well 

being drilled. As can be observed in Table 4, deepwater wells drilled by platform rigs and shallow wells 

drilled by jackups or platforms will incur lower incremental costs than deepwater wells drilled by 

MODUs, primarily because they use surface BOPs; while wells drilled by deepwater MODUs (drillships 

and semisubmersibles) will incur the greater incremental cost due to the new subsea BOP requirements. 

Additional explanation about these costs is provided in the Benefit-Cost Analysis for the Safety Measures 

Rule.
87

For this analysis, BSEE estimates that 160 deepwater wells will be drilled each year, split between 

MODU wells (112/yr) and platform wells (48/yr). An estimated 186 wells will be drilled each year in the 

shallow water depths. Using the recent drilling profiles for small and large company lessees in Table 30, 

the following table estimates the number of wells to be drilled each year by large and small entities. 

Table 33 – Estimate of Future Wells Drilled (annually)

MODU 

Deepwater 

Wells (112/yr)

Fixed Platforms 

Deepwater 

Wells (48/yr)

Shallow Wells 

(186/yr)

Large Co. 99 (88%) 42 (88%) 102 (55%)

Small Co. 13 (12%) 6 (12%) 84 (45%)

TOTAL 112 48 186

The estimated annual increased costs for each well type drilled are taken from Table 4 to estimate the 

annual compliance costs for large and small companies by type of well. Of the $131 million in annual 

cost imposed by the rule, we estimate that the $12.3 million will apply to small businesses in deepwater 

and $11.0 million in shallow water. In total, we estimate that $23.3 million or 18 percent of the 

regulation’s costs will be borne by small businesses. The following table shows the calculations for these 

estimates.

Table 34 – Large/Small Company Estimated Additional Drilling Costs

$millions Additional MODU 

Deepwater Well 

Cost (112/yr)

Fixed Platforms 

Deepwater Wells 

(48/yr)

Shallow Wells 

(186/yr)

Total 

Estimated 

Cost

Large Co. $83.3 (88% * 94.6) $9.9 (88% * $11.2) $13.7 (55% * $24.8) $106.8

Small Co. $11.4 (12% * $94.6) $1.3 (12% * $11.2) $11.2 (45% * $24.8) $23.9

TOTAL $94.6 $11.2 $24.8 $130.7

*Numbers may not add due to rounding.

Determining a precise number of small entities that will be “regulated” is complicated by the fact that the 

actual number fluctuates as OCS properties are bought, sold, the designated operator changes and not all 

operators conduct drilling operations. The same difficulty follows for the lease ownership profile of small 

and large entities. However, our best estimate of the impact on small entities when we consider how 

project and drilling costs are shared among lease owners is that small entities will bear 12 percent of 

increased regulatory costs in deepwater, and 45 percent in shallow water. The annual small entity 

regulatory compliance cost imposed by this rulemaking is estimated to be $23.9 million or 18 percent of 

the total.

Description of the projected reporting, recordkeeping, and other compliance 

requirements of the proposed rule, including an estimate of the classes of 

small entities that will be subject to the requirement and the type of 

professional skills necessary for preparation of the report or record.

The benefit-cost analysis for the Safety Measures Rule identifies $131 million in annual operational costs; 

these costs are summarized in Table 4 and discussed in the section titled Compliance Costs for this 
88

Regulation. Greater details of the regulatory provisions are provided in the rule preamble. This section 

primarily discusses the paperwork burden on drilling contractors.

The Paperwork Reduction Act (PRA) section of the Safety Measures Rule (which combines both the IFR 

and Final Rule) identifies 50,078 hours of paperwork, reporting, and recordkeeping required annually by 

the regulation. Using the Bureau of Labor Statistics estimated loaded hourly rate of $83/hr, 

the estimated paperwork cost to industry for this rulemaking is $4.6 million. The burden tables of 

the estimated annual burden hours of these rulemakings can be found in both the IFR and final rule 

procedural matters section of the Federal Register preamble.

Reporting and recordkeeping falls primarily on the OCS lessees and operators, although drilling rig 

operators do have some additional recordkeeping requirements. The frequency of response varies 

depending upon the requirement but is primarily based on drilling activity. Responses and recordkeeping 

by the drilling companies fall primarily on the Deepwater MODUs where all the deepwater MODU 

operators in the GOM are large companies. Some additional recordkeeping requirements will fall on all 

OCS drilling rig operators. As of early November, 2010 (11/4/2010 Rigzone), there are two shallow 

water rigs operating in the GOM OCS owned by a small company. They are both owned by Blake 

International and are under contract to Apache. The estimated additional recordkeeping cost for jack-up 

rig surface BOP stacks is about $5,000 annually for each rig. The direct estimated paperwork burden on 

the single small drilling operator currently active in the GOM is about $10,000 per year. The paperwork 

costs impacting this small entity are found in Table 35 and sourced from the IFR PRA table found at 

75 FR 63368.

Table 35 – Selected Paperwork Burden Requirements from AD68 IFR PRA*

Citation

30 CFR 250

Reporting & Recordkeeping

Requirement

Hour 

Burden

Average No. 

of Annual 

Responses

Annual 

Burden 

Hours

Subpart E

516(g)(l) Document the procedures used for BOP 

inspections; record results; maintain 

records for 2 years; make available to 

BSEE upon request.

7 days x 12 

hrs/ day = 

84

105 rigs / once 

every 3 years = 

35 per year

2,940

516(h) Document the procedures used for BOP 

maintenance; record results; maintain 

records for 2 years; make available to 

BSEE upon request.

1 105 rigs 105

Subpart F
89

Citation

30 CFR 250

Reporting & Recordkeeping

Requirement

Hour 

Burden

Average No. 

of Annual 

Responses

Annual 

Burden 

Hours

617(a)(l) Document the procedures used for BOP 

inspections; record results; maintain 

records for 2 years; make available to 

BSEE upon request.

7 days x 12 

hrs/ day = 

84

105 rigs / once 

every 3 years = 

35 per year

2,940

617(b) Document the procedures used for BOP 

maintenance; record results; maintain 

records for 2 years; make available to 

BSEE upon request.

1 105 rigs 105

*Full table can be found in the Preamble Procedural Matters of the IFR (75 FR 63368).

Much of the paperwork is recording the results of tests and maintenance procedures and is expected to be 

completed by workers concurrently with the tests or in between other drilling tasks. The paperwork costs 

are a moderate component of the added costs imposed by this rule and minor in comparison to the cost of 

drilling an OCS well.

Identification, to the extent practicable, of all relevant Federal rules that may 

duplicate, overlap, or conflict with the rule

The only regulations from other Federal agencies that may closely relate to the scope of BSEE regulations 

in this rulemaking are from the U.S. Coast Guard. However, for the Safety Measures Rule there is no 

overlap, conflict, or duplication with Coast Guard regulations. Under BSEE/USCG Memorandum of 

Understanding (MOU), BSEE has authority over spill abatement - which includes well control. All of the 

regulatory provisions in the rulemaking are focused on well control. Additionally and consistent with the 

MOU, BSEE has regulatory authority for drilling operations of MODUs on station while conducting 

drilling operations.

There are several MOUs between the agencies that outline the division of duties and shared 

responsibilities. BSEE has authority over drilling and oil and gas operations on the OCS while the Coast 

Guard has authority over the integrity and safety of floating vessels conducting OCS operations. The 

MOUs can be found at: http://www.uscg.mil/hq/cg5/cg522/cg5222/mou.asp

Description of any significant alternatives to the rule that accomplish the 

stated objectives of applicable statutes and that minimize any significant 

economic impact of the rule on small entities, including alternatives 

considered, such as: 

1. Establishment of differing compliance or reporting requirements or timetables that take 

into account the resources available to small entities.

2. Clarification, consolidation, or simplification of compliance and reporting requirements 

under the rule for such small entities.
90

3. Use of performance rather than design standards.

4. Any exemption from coverage of the rule, or any part thereof, for such small entities.

Under the published Safety Measures Rule, the requirements are prescriptive and lease operators 

submitting permits to BOEMRE or conducting drilling operations must comply with the requirements. 

Even though this rule may not have a significant economic impact on small businesses, BOEMRE has 

analyzed several alternatives for the provisions included the Safety Measures Rule. 

Alternative 1, Different Compliance Requirements for Small Entities

During the drafting of the IFR, BOEMRE considered lengthening the compliance deadline for both large 

and small companies. The primary reason for not including additional compliance time or different 

requirements is the overriding need to reduce the chance of a catastrophic blowout event. The risk is not 

lower for small entities and BSEE cannot compromise the safety of offshore personnel and the 

environment for any entity including small businesses. Offshore drilling is highly technical and can be 

hazardous; any delay in the implementation of Safety Measures Rule may increase the risk of OCS 

drilling operations. 

The regulatory provisions do not require significant equipment or capital upgrades and as the 2011 

resumed deepwater drilling shows, can be met in short order. The compliance costs are mostly the 

increased time to conduct drilling operations. Thus, any additional time to comply with the rule would 

not result in cost savings in the form of reduced short-term cash flow expenditures that might be expected 

if the rule required the installation of capital equipment.

BSEE is continuing to review other safety measures that may be appropriate for rulemaking in the near 

future. These may be included in a proposed rulemaking or an advanced notice of proposed rulemaking. 

Alternative 2, Testing Requirements

Alternative Testing Methods: BSEE considered if the required testing for subsea ROV intervention and 

negative pressure tests could be performed in an alternative manner. Because of the failings that occurred 

in, and lessons learned from, the BP Deepwater Horizon event, BSEE has concluded that alternative 

testing is not a viable option. No alternative testing methods have been identified that will provide the 

same assurance of reliability.

The subsea ROV intervention test upon installation of the BOP stack is required to demonstrate that the 

rams can be closed as required under realistic subsea conditions. The BOP ROV function test occurs 

upon installation on the sea floor and is in addition to the “stump” tests conducted prior to subsea 

installation. The only alternative to the subsea tests would be to only conduct the “stump test.” However, 

the stump test would not provide the same assurance of BOP ram operability as the subsea test which is 

performed under the actual conditions that would occur if the BOP rams needed to be employed.

The new requirement to perform a negative pressure test after the final casing string is installed is 

necessary to verify that no fluids are entering the well and the cement is sealing the wellbore. 
91

Alternative Testing Periods: An IRFA public comment offered an alternative to the current BOP testing 

requirement. The suggestion was to change the existing regulation at 30 CFR 250.449(h) which requires 

a BOP function test every 7 days including the blind-shear rams to a 14 day requirement

A Joint Industry Project study completed in 2009 analyzed BOP Equipment Reliability. The results of 

this study suggest that up to $193 million per year could be saved through less frequent testing while 

achieving the same reliability for BOP performance.37 Though counter intuitive, it may be possible that 

less frequent testing can provide the same BOP reliability because of the wear that more frequent tests 

may exert on the BOP equipment. While the testing alternative may have value, and is a topic that merits 

greater study, it is outside of the scope of this rulemaking.

Alternative 3, Paperwork Consolidation

BSEE did not identify any provisions of the rule that could provide efficiencies through consolidation or 

other streamlining. Some of the regulatory provisions apply to different Subparts and are necessarily 

duplicated. Most reporting requirements are dependent on drilling activity and closely related to the 

number of wells drilled or Application for Permit to Drill/Application for Permit to Modify 

(APDs/APMs) submitted. No efficiencies would be expected through further simplification or 

consolidation.

Alternative 4, Use Performance Rather than Design Standards

The provisions in the final rule generally prescribe a combination of performance and design standards 

for well design (cementing and casing), testing drilling equipment, and certifying the well’s integrity. 

Although, for instance, the rule requires the use of two independent barriers, including one mechanical 

barrier, the rule does not mandate the specifications for the particular type of barrier. BSEE or 

commenters did not identify equivalent performance standards that provide the same level of reliability 

and well integrity and that can be implemented as quickly as the provisions in this rule.

The BOEMRE is carefully evaluating how to integrate performance based systems into our regulatory 

regime. This includes the SEMS (Safety Environmental Management Systems) and the Safety Case. The 

first SEMS rule was published on October 15, 2010 (75 FR 63610) and a second SEMS proposed rule 

was published on September 14, 2011 (76 FR 56683). The Safety Case approach to risk management 

championed by the International Association of Drilling Contractors (IADC) is also receiving careful 

consideration and study by BSEE.

Implementation of a performance based solution requires long lead times and careful strategic and tactical 

implementation. Because of the immediate need to address well design, testing and reliability issues, 

BSEE is relying on a combination of performance and design standards in the Safety Measures Rule.

 

37 BOP Equipment Reliability Joint Industry Project At A Glance, West Engineering Services, 

http://www.westengineer.com/pdfs/JipTrifoldr3.pdf.
92

Departures to the provisions in the Safety Measures Rule can be approved under the current regulations if 

the alternative procedures afford an equal or greater degree of protection, safety, or performance. 

Departures are discussed in the next section.

Alternative 5, Exemptions from Rule Requirements

One alternative is to exempt small businesses from the requirements of this interim final rule. The 

“exemption” or “no action” alternative was not adopted by BSEE because of the overriding need to 

reduce the chance of a catastrophic blowout event. The risk is not lower for small entities and BSEE 

cannot compromise the safety of offshore personnel and the environment for any entity including small 

businesses. 

BOEMRE can approve departures to existing regulations when the departure would assure the continued 

safety of drilling operations. In 30 CFR 250.105 Departures means:

Approvals granted by the appropriate MMS representative for operating 

requirements/procedures other than those specified in the regulations found in this part. These 

requirements/procedures may be necessary to control a well; properly develop a lease; conserve 

natural resources; or protect life, property, or the marine, coastal, or human environment.

There are several general and drilling specific regulatory provisions that identify the availability of 

departures. Those regulatory citations are:

30 CFR 250, Subpart A, General Information, Special Approvals

§ 250.142 How do I receive approval for departures? We may approve departures to the 

operating requirements. You may apply for a departure by writing to the District Manager or 

Regional Supervisor.

30 CFR Subpart D, Oil and Gas Drilling Operations, General Requirements

§ 250.409 May I obtain departures from these drilling requirements? The District Manager 

may approve departures from the drilling requirements specified in this subpart. You may apply 

for a departure from drilling requirements by writing to the District Manager. You should identify 

and discuss the departure you are requesting in your APD see §250.414(h)).

§ 250.414 What must my drilling prognosis include?

(h) A list and description of all requests for using alternative procedures or departures from the 

requirements of this subpart in one place in the APD. You must explain how the alternative 

procedures afford an equal or greater degree of protection, safety, or performance, or why you 

need the departures;

Although not a specific provision of the Safety Measures Rule, departures to the requirements in this 

rulemaking will be considered and may be approved if the alternative proposed method does not 
93

compromise safety and environmental protection. These provisions are available to both large and small 

companies.
94

Appendix B Natural Resource Damage Data

Table 36 - Dataset of Spill Costs: Restoration and Assessment Costs

Event Year of

Settlement

Max Volume 

(bbl)

NRD plus 

Assessment 

Costs

(2009$/bbl)*

American Trader Inc. 2006 143 1,313

Anacortes 1998 952 491

Apex Houston Spill 2006 25,000 244

B.T. Nautilus 1994 6,024 816

Barge Morris J. Berman 2000 11,905 480

Barge RTC 380 1994 643 411

Bermuda Islander 2008 24 11,340

Blake IV and Greenhill 

Petroleum Corp. Well 25

1995 2,905 786

Bouchard Barge 120 2006 2,333

BP American Trader 

Vessel 

1997 9,919 300

Chevron BLDSU #5, West 

Bay Field

1996 262 249

Chevron Perth Amboy 

Facility

2006 342

Chevron, HI 1999 982 2,189

Chiltipin Creek 1994 2,950 69

Cibro Savannah 1999 2,381 138

Cold Spring Harbor Barge 2004 2,357

ConocoPhillips Bayway 2005 250

El Segundo 1993 500 300

Equinox Cockrell-Moran 

#176 well

2005 1,500 800

Evergreen International 

M/V Ever Reach Vessel 

2003 298 3,021

Exxon Bayway 1991 13,500 905

Exxon Valdez 1991 261,905 5,005

Fish Creek 1993 714 3,511

International Petroleum 

Corporation (IPC)

2009 286 882

Chelsea Creek (Global 

Oil/Irving Oil Pipeline)

2006 524 20

Jahre Spray 1996 1,400 121
95

Event Year of

Settlement

Max Volume 

(bbl)

NRD plus 

Assessment 

Costs

(2009$/bbl)*

M/T Athos I 2009 6,271 16

M/T Kentucky 1995 310 81

M/TCommand Oil Spill 1999 71 59,181

M/V Cosco Busan 2010 1,262 1,585

M/V Fortuna Reefer 1997

M/V Kure 2008 108 33,890

M/V Kuroshima 2002 929 1,661

M/V New Carissa 2004 1,667 16,118

M/V Presidente Rivera 1993 5,952 426

M/V Selendang Ayu 2006 8,000 7

M/V World Prodigy 1993 7,000 119

M/VWestchester 2003 13,095 41

Martinez 1990 9,524 1,138

McGrath Lake 1997 2,071 635

Milos Reefer 1993 5,952 67

Neches River 1997 2,095 105

Nestucca 1991 5,500 609

North Cape Barge 1999 19,714 625

Northridge 1997 4,595 1,599

OCEAN 255/B155/BALSA 37 Spill1996 8,619 928

Ocean Energy/Devon 

Energy North Pass Storage 

Facility

2006 300 393

Oil and Crooked Creeks 1996 107 2,539

Olympic Pipeline Company 

Event

2004 5,619 631

PEPCO Chalk Point 

Generating Station

2002 3,333 813

Pirates Cove 1996 600 2,333

Quinnipiac River 1996 119 334

Reedy River 1998 22,619 294

Santa Barbara, CA 1969 71,429

SS Cape Mohican Oil Spill 1998 2,286 1,761

Sugarland Run 1998 9,714 257

T/V Julie N 2002 4,277 348
96

Event Year of

Settlement

Max Volume 

(bbl)

NRD plus 

Assessment 

Costs

(2009$/bbl)*

Tenyo Maru 1994 10,776 867

Tesoro, HI 2001 117 4,359

Texaco Pipeline Company 

Lake Barre oil spill

2000 6,548 87

Williams 

Field/Transcontinental 

Natural Gas Spill

2010 3,000 84

Yoncalla Creek 1995 143 1,505

* Where a spill has a range of sizes recorded, per-barrel costs were calculated 

using the upper range.

Table 37 - Gulf Shrimp Landings, Revenue, and Price

Federal 

Permit

No 

Federal 

Permit

Total

Average revenue per vessel ($) 199,111 22,429 74,847 

Average landings per vessel (lbs) 67,386 13,160 29,247

Average price (dollars per lb) $2.95 $1.70 $2.56 

Average price (dollars per lb) $2.87 $1.73 $2.07 

Number of Vessels 1,388 3,290 4,678

Total revenue ($ millions) $276 $82 $358 

Total landings (millions lbs) 94 47 141

Note: Table for Gulf shrimp only; excludes S. Atlantic shrimp

Source: The Annual Economic Survey of Federal Gulf Shrimp Permit 

Holders: 

Report on the Design, Implementation, and Descriptive Results for 2007; 

NOAA Technical Memorandum NMFS-SEFSC-590 (2009).
97

Appendix C Well Data

Table 38 – GOM Deepwater Wells by Water and Drilling Depth

Distribution of 4,133 GOM Wells Drilled in Water > 500 Feet 

by Drilling Date, Water Depth, and Well Depth

Counts of All GOM Wells Drilled in Water >500 feet According to Well Drilled Depth

Water 

Depth (feet)

Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500-1,500 

140 

 

900 

 

607 

 

61 

 

15 

 

1 

 

1 

 

- 

 

1,725 

1,500-3,000 

39 

 

205 

 

349 

 

253 

 

71 

 

5 

 

1 

 

- 

 

923 

3,000-5,000 

21 

 

153 

 

324 

 

218 

 

123 

 

77 

 

17 

 

- 

 

933 

5,000-7,500 

- 

 

39 

 

121 

 

123 

 

82 

 

45 

 

10 

 

1 

 

421 

7,500-

10,000

 

- 

 

- 

 

51 

 

47 

 

11 

 

10 

 

- 

 

- 

 

119 

>10,000 

- 

 

- 

 

1 

 

- 

 

1 

 

- 

 

- 

 

- 

 

2 

All WD 

200 

 

1,297 

 

1,453 

 

702 

 

303 

 

138 

 

29 

 

1 

 

4,123 

>3,000 ft 

21 

 

192 

 

497 

 

388 

 

217 

 

132 

 

27 

 

1 

 

1,475 

Counts of GOM Wells Drilled before 1980 in Water >500 feet According to Well Drilled Depth

Water 

Depth (feet)

Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500-1,500 

11 

 

83 

 

32 

 

- 

 

- 

 

- 

 

- 

 

- 

 

126 

1,500-3,000 

- 

 

3 

 

5 

 

1 

 

- 

 

- 

 

- 

 

- 

 

9 

3,000-5,000 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

5,000-7,500 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

7,500-

10,000+

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

All WD 

11 

 

86 

 

37 

 

1 

 

- 

 

- 

 

- 

 

- 

 

135 

>3,000 ft 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 
98

Counts of GOM Wells Drilled During the 1980's in Water >500 feet According to Well Drilled Depth

Water 

Depth (feet)

Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500-1,500 

47 

 

324 

 

252 

 

19 

 

2 

 

- 

 

- 

 

- 

 

644 

1,500-3,000 

12 

 

59 

 

94 

 

16 

 

- 

 

- 

 

- 

 

- 

 

181 

3,000-5,000 

1 

 

3 

 

25 

 

1 

 

1 

 

- 

 

- 

 

- 

 

31 

5,000-7,500 

- 

 

- 

 

1 

 

8 

 

- 

 

- 

 

- 

 

- 

 

9 

7,500-

10,000+

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

All WD 

60 

 

386 

 

372 

 

44 

 

3 

 

- 

 

- 

 

- 

 

865 

>3,000 ft 

1 

 

3 

 

26 

 

9 

 

1 

 

- 

 

- 

 

- 

 

40 

Counts of GOM Wells Drilled During the 1990's in Water >500 feet According to Well Drilled Depth

Water 

Depth (feet)

Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500-1,500 

55 

 

334 

 

230 

 

28 

 

8 

 

1 

 

- 

 

- 

 

656 

1,500-3,000 

15 

 

74 

 

129 

 

142 

 

18 

 

2 

 

- 

 

- 

 

380 

3,000-5,000 

10 

 

60 

 

106 

 

72 

 

21 

 

2 

 

- 

 

- 

 

271 

5,000-7,500 

- 

 

5 

 

34 

 

20 

 

8 

 

3 

 

- 

 

- 

 

70 

7,500-

10,000

 

- 

 

- 

 

1 

 

1 

 

- 

 

- 

 

- 

 

- 

 

2 

>10,000 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

All WD 

80 

 

473 

 

500 

 

263 

 

55 

 

8 

 

- 

 

- 

 

1,379 

>3,000 ft 

10 

 

65 

 

141 

 

93 

 

29 

 

5 

 

- 

 

- 

 

343 
99

Counts of GOM Wells Drilled After 1999 in Water >500 feet According to Well Drilled Depth

Water 

Depth (feet)

Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500-1,500 

27 

 

159 

 

93 

 

14 

 

5 

 

- 

 

1 

 

- 

 

299 

1,500-3,000 

12 

 

69 

 

121 

 

94 

 

53 

 

3 

 

1 

 

- 

 

353 

3,000-5,000 

10 

 

90 

 

193 

 

145 

 

101 

 

75 

 

17 

 

- 

 

631 

5,000-7,500 

- 

 

34 

 

86 

 

97 

 

74 

 

42 

 

10 

 

1 

 

344 

7,500-

10,000

 

- 

 

- 

 

50 

 

44 

 

11 

 

10 

 

- 

 

- 

 

115 

>10,000 

- 

 

- 

 

1 

 

- 

 

1 

 

- 

 

- 

 

- 

 

2 

All WD 

49 

 

352 

 

544 

 

394 

 

245 

 

130 

 

29 

 

1 

 

1,744 

>3,000 ft 

10 

 

124 

 

330 

 

286 

 

187 

 

127 

 

27 

 

1 

 

1,092 
100

Appendix D Definitions

Baseline: describes the regulatory environment before promulgation of the Interim Final Rule. 

The baseline is compared to regulatory environment following promulgation of the rule for the 

cost-benefit analysis.

Benefits: are the favorable effects of a policy or action. 

Blowout: is an uncontrolled flow of reservoir fluids into the wellbore. A catastrophic blowout 

occurs when fluids flow to the surface. The most damage from a catastrophic blowout event is 

caused if the hydrocarbons ignite at the surface. If reservoir fluids flow into another formation 

and do not flow beyond the wellhead, the result is called an underground blowout because the 

well bridges over and seals itself. Similar to kicks, the BOP rams are designed to shut-in the 

well until control is reestablished.

BOP (Blowout Preventer) Stack: Is a series of valves (or rams) at the wellhead that may be 

closed if the drilling crew loses control of formation fluids. These valves are often referred to as 

BOP rams. A stack might consist of four to six ram-type preventers and one or two annular-type 

preventers. A BOP stack is used to ensure pressure control of a well.

Costs: Is the dollar values of resources needed to produce a good or service, and hence are not 

available for use elsewhere. 

Compliance Cost is the expenditure of time or money needed to conform to government’s 

regulatory requirements. It may be defined as the sum of all opportunity costs incurred as a 

result of the regulation. These opportunity costs consist of the value lost to society of all the 

goods and services that will not be produced and consumed if firms comply with the regulation 

and reallocate resources away from production activities and towards compliance with the 

regulation. 

External (social) costs are the costs the oil spill imposes on society regardless of who pays for 

them and in this analysis exclude the private (social) costs.

Deepwater: While BOEMRE has traditionally defined deepwater as greater than 1,000 feet, for 

the purposes of this analysis deepwater is defined as water depths where floating drilling rigs are 

used rather than gravity based rigs and where submersibles or ROVs must replace divers. This is 

generally at 300 to 500 of water depth and also the depth where subsea BOPs are required on 

floating mobile drilling rigs. We use 500 feet of water depth for our baseline analysis. 

Discount Rate: Per OMB Circular A-94, where appropriate all cost estimates are calculated 

back to a net present value in 2010 dollars using a discount rate of 7 percent.

Kick: is a flow of fluids from a formation into the wellbore during drilling operations. A kick is 

caused by the pressure in the wellbore being less than that of the formation fluids and most often 

happens during drilling operations from a depth other than the targeted reservoir. Kicks are most 

frequently controlled by increasing the drilling mud weight, circulating out the kick or using one 

of the BOP rams to control the flow.
101

Loaded Rig Rate: The loaded rig rate used in this analysis is the daily rate charged by the 

owner of the rig for use of the rig and the operating crew plus the operator’s engineers, supplies, 

supply craft and supporting contractors.

Net benefits: are calculated by subtracting total costs from total benefits.

Oil Spill: An oil spill as referenced in this cost/benefit analysis is oil spilled as a result of a loss 

of well control event. An oil spill for this analysis excludes spills from production or logistical 

activities if the spillage is unrelated to a loss of well control event.

Private (social) costs: are the costs of the blowout and spill that the responsible party pays for 

containment and recovery of productive capability. 

Unloaded Rig Rate: The unloaded rig rate used in this analysis is the daily rate charged by the 

owner of the rig for use of the rig and the operating crew. It does not include supplies, supply 

craft, the operator’s drilling engineers or supporting contractors.
102

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103

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Texas Parks and Wildlife Department website. 2010. “BP Oil Spill in the Gulf of Mexico.” 

Accessed on-line at http://www.tpwd.state.tx.us/site/emergency/oil_spill/.

Travis. Michael D. and Wade L. Griffin. 2004. Update on the Economic Status of the Gulf of 

Mexico Commercial Shrimp Fishery. 

U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National 

Marine Fisheries Service. 2010. NOAA Technical Memorandum NMFS-F/SPO-109. 

Fisheries Economics of the United States 2008; Economics and Sociocultural Status and 

Trends Series.

Viscusi, W. Kip. 2005. The Value of Life. Discussion Paper No. 517. Harvard Law School. 

http://www.law.harvard.edu/programs/olin_center/papers/pdf/Viscusi_517.pdf

Viscusi, W. Kip. 2010. The Heterogeneity of the Value of Statistical Life: Introduction and 

Overview. Journal of Risk and Uncertainty, 40: 1-13.

Additional References or Literature:

Joint Industry Task Force to Address Offshore Operating Procedures and Equipment, May 17, 

2010, White Paper: Recommendations for Improving Offshore Safety 

http://www.noia.org/website/download.asp?id=38556

BOEMRE/USCG Report Regarding the Causes of the April 20, 2010 Macondo Well Blowout, 

September 14, 2011, http://www.boemre.gov/pdfs/maps/DWHFINAL.pdf

DNV – Beaufort Sea Drilling Risk Study Energy Report, Imperial Oil Resources Ventures 

Limited, DNV ref no: EP00485, Rev. 6, March 11, 2010, submitted to the CanadianNational Energy Board (www.neb-one.gc.ca) https://www.neb-one.gc.ca/lleng/livelink.exe/fetch/2000/90463/589151/594086/594088/600443/609664/C-05-6C_-

_Appendix_A_Beaufort_Sea_Drilling_Risk_Study__-

_A1S2V8_.pdf?nodeid=609512&vernum=0

Executive Order 12866, Regulatory Planning and Review

http://www.whitehouse.gov/sites/default/files/omb/inforeg/eo12866.pdf
105

OMB Circular A-4, Regulatory Analysis

http://www.whitehouse.gov/sites/default/files/omb/assets/omb/circulars/a004/a-4.pdf

OMB Circular A-94, Guidelines and Discount Rates for Benefit-Cost Analysis of Federal 

Programs http://www.whitehouse.gov/sites/default/files/omb/assets/a94/a094.pdf

NYT Article on the replacement cost of the Deepwater Horizon which is estimated at $560 

million. http://www.nytimes.com/gwire/2010/05/04/04greenwire-warnings-on-backupsystems-for-oil-rigs-sounde-30452.html

Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Part 

III, Lessons Learned: Industry, Government, Energy Policy 

http://www.oilspillcommission.gov/sites/default/files/documents/FinalReportPartIII.pdf

Transocean announcement describing the total capital costs to be incurred for the construction of 

the drillship are estimated to be $750 million. 

http://www.redorbit.com/news/business/1446859/transocean_inc_announces_agreement_

to_acquire_newbuild_ultradeepwater_drillship_under/index.html
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Appendix F Voluntary Industry Measures Review

MEMORANDUM | 18 August 2010

TO Radford Schantz and Martin Heinze, BOEMRE

CC Debra Bridge, BOEMRE

FROM John Weiss, Industrial Economics, Incorporated

SUBJECT

Review of Additional Literature with Potential Relevance to OECM Development, 

Contract No. M09PC00036

Industrial Economics, Incorporated (IEc) is engaged in the development of a new version of the Offshore 

Environmental Cost Model (OECM), a decisionmaking tool used by the Bureau of Ocean Energy 

Management, Regulation, and Enforcement (BOEMRE) as it develops five-year leasing programs for oil 

and gas exploration and production on the outer continental shelf (OCS). An important component of this 

effort is the review of literature relevant to the identification and evaluation of the environmental costs 

that the model will consider. Many of those costs are the direct or indirect result of oil spills associated 

with OCS exploration and production activities. In the aftermath of the Deepwater Horizon event, 

additional information has become available that BOEMRE has asked IEc to review for relevance and 

potential application during OECM development. This memorandum describes the results of our review 

and analysis of one category of additional information, that associated with (1) the Department of the 

Interior’s 30-Day Report to the President, which describes recommended actions to reduce the probability 

of a similar event in the future, and (2) industry’s consideration of recommended voluntary safety and 

protection measures that would be designed to achieve the same objective.

In addition to reviewing relevant information for its potential applicability to the specification of OECM 

inputs, IEc has compared the currently available descriptions of proposed voluntary measures to a set of 

proposed changes to the rules governing OCS oil and gas activities. BOEMRE is currently developing an 

analysis of the costs and benefits of the proposed rules, including the estimated incremental cost to 

industry to comply with new requirements. BOEMRE can use the results of the IEc analysis to determine 

whether industry’s recommendations provide a basis for any reconsideration of industry’s compliance 

costs (i.e., whether adoption and implementation of voluntary measures might shift the baseline against 

which BOEMRE should consider the incremental compliance costs).

DOCUMENTS REVIEWED

IEc reviewed the following documents as part of this effort:

 Increased Safety Measures for Energy Development on the Outer Continental Shelf, U.S. Department 

of the Interior, May 27, 2010 (the “30-Day Report”).
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 Proposed amendments to 30 Code of Federal Regulations (CFR) Part 250 – Oil and Gas and Sulphur 

Operations in the Outer Continental Shelf (as of August 6, 2010); these proposed amendments are a 

direct result of the recommendations contained in the 30-Day Report.

 White Paper: Recommendations for Improving Offshore Safety, prepared by the Joint Industry Task 

Force to Address Offshore Operating Procedures and Equipment, May 17, 2010.

 Draft report of the Joint Industry Task Force to Address Subsea Well Control and Oil Spill Response, 

July 6, 2010.

 Isolating Potential Flow Zones During Well Construction, American Petroleum Institute (API) 

Recommended Practice 65 – Part 2, First Edition, May 2010 (referenced in the Joint Industry Task 

Force White Paper).

 Health, Safety and Environmental Case Guidelines for Mobile Offshore Drilling Units, International 

Association of Drilling Contractors (IADC), Issue 3.2.1, May 1, 2009 (referenced in the Joint 

Industry Task Force White Paper).

 Testimony of Andy Radford, API Senior Policy Advisor, before the National Commission on the BP 

Deepwater Horizon Oil Spill and Offshore Drilling, July 12, 2010.

IEc did not complete a detailed review of API Recommended Practice 65 – Part 2 or the IADC 

guidelines, as they present a level of technical detail that is beyond the scope of the intended general 

comparison of proposed rules and voluntary measures. In addition, the July 6, 2010 draft report of the 

Joint Industry Task Force to Address Subsea Well Control and Oil Spill Response does not contain 

recommendations for voluntary measures but rather the context for the Task Force’s near-term and longterm efforts, and thus does not contribute to the IEc analysis.

To facilitate the analysis, IEc retrieved electronic versions of each section of 30 CFR Part 250 in which 

BOEMRE is proposing a change and copied the text into a Microsoft Word document. Based on a careful 

review of the rulemaking document, IEc inserted, modified, or deleted text, using the redline/strikeout 

feature, to highlight the location and substance of each proposed change. The resultant document served 

as the basis for a comparison between proposed regulatory changes and the industry recommendations for 

voluntary safety and protection measures.

RESULTS

The results of the IEc analysis are described in Tables 1 and 2. Table 1 highlights the industry 

recommendations that BOEMRE explicitly addresses in its proposed rule changes. Table 2 lists selected 

additional industry recommendations that the proposed rules do not address and that could result in 

additional industry operating costs.
August 18, 2010

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TABLE 1 COMPARISON OF RECOMMENDED INDUSTRY VOLUNTARY MEASURES TO PROPOSED CHANGES IN 30 CFR PART 250

RECOMMENDED INDUSTRY VOLUNTARY MEASURE RELEVANT SECTION OF REGULATIONS PROPOSED REGULATORY CHANGE

Upon release, adopt AP RP 65 Part 2: Isolating Potential Flow 

Zones During Well Construction. 30 CFR 250.415(f)

New requirement for a discussion of how the best practices 

described in API RP 65 Part 2 were evaluated in the casing 

and cementing program.

Engage casing hanger latching mechanisms when casing is 

installed in the subsea wellhead. 30 CFR 250.423(b)

New requirement to perform a pressure test after the 

intermediate and production casing strings are installed to 

verify that the casing hanger latching mechanisms or lock 

down mechanisms are engaged and the casing has been 

sealed.

Provide two independent barriers, including one mechanical 

barrier, for each flow path prior to displacement to 

underbalanced fluid columns.

30 CFR 250.420(a)(6)

New requirement for a professional engineer to verify two 

independent tested barriers, including one mechanical 

barrier, across each flow path during well completion 

activities.

Perform negative tests to a differential pressure greater than 

or equal to anticipated pressures after displacement.

30 CFR 250.423(c) New requirement to perform a negative pressure test after 

the intermediate and production casing strings are installed. 

Test procedures and criteria must be submitted with the APD 

for approval.

Ensure shearable drillstring components are positioned in the 

shear rams during displacement.

30 CFR 250.442(a) New requirement for two BOPs, rather than one, equipped 

with a blind-shear rams, with a further requirement that the 

blind-shear rams are appropriately spaced to ensure that at 

least one cuts the drillpipe and seals the wellbore.

Ensure BOP can automatically close blind/shear ram(s) and 

close choke/kill line valves

30 CFR 250.442(f) Provide autoshear and deadman systems for dynamically 

positioned rigs.

Ensure ROV can close blind shear rams, pipe rams, casing 

shear rams, and choke and kill valves. Ensure ROV can 

unlatch the lower marine riser package.

30 CFR 250.442(d) When drilling with a subsea BOP system, the BOP must be 

equipped with ROV intervention capability; at a minimum, 

the ROV must be capable of closing all pipe rams, all shear 

rams, and unlatching the LMRP.
TABLE 2 SELECTED ADDITIONAL RECOMMENDED INDUSTRY VOLUNTARY MEASURES

 Deepwater mobile offshore drilling unit produces safety case, following guidelines 

established by the IADC.

 Develop Well Construction Interfacing Document to manage well construction activities and 

mitigate unexpected events that impact health, safety and the environment.

 Positively test each casing barrier to a pressure exceeding the highest estimated integrity of 

casing shoes below that barrier.

 Close blowout preventers during displacement to underbalanced fluid columns.

 Perform separate displacement operations for riser and casing. Monitor displacement 

volumes in and out.

 At prescribed intervals, conduct subsea testing of hydraulic function of rams and valves 

downstream of the trigger to simulate 1) unintended disconnect of lower marine riser 

package (LMRP); and 2) loss of surface control of the subsea BOP stack.

 Verify proper operation of the system by testing to MMS-approved Application for Permit to 

Drill (APD) casing pressure below blind / shear rams after system activation.

 Arm the system when BOP stack is latched on the wellhead. Disarm and rearm only if 

approved through a formalized Management of Change process.

 Standardize ROV hot stab and receptacle per API Spec 17H. Standardize hot stab designs 

between drilling and production operations.

 Stage ROV tooling / external hydraulic power supplies strategically in Gulf of Mexico for

rapid mobilization.

CONCLUSIONS

IEc has reviewed literature that has recently become available in the aftermath of the Deepwater Horizon 

event in order to determine whether and how it might suggest changes in the development of the new 

OECM. As part of this effort, IEc compared proposed regulatory changes with industry recommendations 

for safety and protection measures that industry could voluntarily adopt during the course of OCS oil and 

gas exploration and development activities.

None of the literature IEc reviewed suggests a need for any immediate changes in the methodologies or 

inputs currently associated with OECM development. However, since spill rates are an important model 

element, changes may be warranted in the future if and when new regulatory requirements or the 

voluntary adoption of new procedures or technologies result in measurable changes in the expected 

frequency of spill events.

The comparison of recommended voluntary industry measures with proposed changes to 30 CFR Part 250 

indicates several areas of overlap, as noted above in Table 1. However, it is not possible at this time to 

conclude that the articulation of industry recommendations will necessarily translate into measurable 
110

changes in baseline industry costs against which BOEMRE would compare the cost to comply with new 

regulatory requirements. If, in the context of a benefit-cost analysis, the measures in Table 1 were 

assumed to have been adopted, it would be appropriate to consider any associated costs as part of the 

baseline (i.e., the incremental cost to industry of the new regulations would be reduced). As BOEMRE 

considers additional regulatory changes, further comparison to industry recommendations, including those 

listed in Table 2, would be warranted.