1 

Benefit-Cost Analysis for the Interim Final Rule on Increased 

Safety Measures for Energy Development on the Outer 

Continental Shelf 

RIN 1010 AD68 

Bureau of Ocean Energy Management, 

Regulation and Enforcement 

September 30, 2010 
 

 2 

Table of Contents 

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

INTRODUCTION AND NEED FOR FEDERAL ACTION................................................ 8

HISTORICAL INFORMATION ABOUT BLOWOUTS................................................... 10

Shallow Water Drilling Activity ................................................................................... 10

Deepwater Drilling Activity ......................................................................................... 11

Baseline Size and Duration of a Catastrophic Deepwater Blowout Spill.................... 11

EXISTING AND NEW REGULATORY PROVISIONS .................................................. 12

Benefit-Cost Approach............................................................................................... 18

BASELINE ASSUMPTIONS IN THE BENEFIT-COST ANALYSIS.............................. 20

Baseline Estimates of Future Deepwater Drilling Activity .......................................... 21

Shallow Water Drilling Activity ................................................................................... 22

Baseline Chance of Another Deepwater Blowout Spill .............................................. 22

COMPLIANCE COSTS FOR THIS REGULATION....................................................... 22

Seafloor Function Testing of ROV Intervention and Deadman Systems - Drilling ..... 23

Seafloor Function Testing of ROV Intervention and Deadman Systems – 

Workover/Completions.......................................................................................... 25

Negative Pressure Tests ........................................................................................... 25

Installation of Dual Mechanical Barriers..................................................................... 26

Professional Engineer Certification for Well Design................................................... 26

Retrieval and Testing of a BOP Stack After a Well Control Situation......................... 27

Third Party Certification of Shear Ram Capability...................................................... 27

Summary of Annual Recurring Costs......................................................................... 28

Voluntary Measures by Industry ................................................................................ 29

AVOIDED PRIVATE-SOCIAL COSTS ......................................................................... 29

Damage to Drilling Rig............................................................................................... 29

Well Containment and Plugging ................................................................................ 30

Hydrocarbon Losses.................................................................................................. 30

Fines and Criminal Penalties ..................................................................................... 31

Summary of Avoided Private-Social Costs ................................................................ 31

AVOIDED EXTERNAL-SOCIAL COSTS...................................................................... 32

Conceptual Approach ................................................................................................ 33

Valuing Natural Resource Damages.......................................................................... 34

Caveats and Assumptions ..................................................................................... 39

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

Spilled ................................................................................................................... 39

Valuing Commercial Fishery Losses.......................................................................... 40

Data Availability...................................................................................................... 40

Background......................................................................................................................40

Revenues.........................................................................................................................43

Operating Costs ...............................................................................................................47

Closures...........................................................................................................................50

Valuing Lost Recreation............................................................................................. 52
 

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Recreational Fishing .............................................................................................. 53

Beach Recreation................................................................................................... 54

Oil Spill Response and Damage Assessment Costs ................................................. 56

Avoided Costs Associated with Reduced Loss of Life and Nonfatal Injuries ............. 58

Value of Statistical Life........................................................................................... 58

VSL Value Used in Offshore Safety Regulation...............................................................61

Nonfatal Injuries ...............................................................................................................61

Other Health Effects .................................................................................................. 61

Avoided Costs Associated with Other Activities Linked Economically to Avoiding an 

Oil Spill.................................................................................................................. 62

Summary – Avoided External-Social Costs ............................................................... 63

TOTAL ESTIMATED AVOIDED SOCIAL COSTS (BENEFITS) .................................. 64

 SCENARIO ANALYSIS ............................................................................................... 64

Sensitivity of Compliance Costs ................................................................................ 66

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

Catastrophic Blowout Spill ..................................................................................... 66

Alternatives................................................................................................................ 67

Small Business Alternatives................................................................................... 68

CONCLUSION AND UNCERTAINTIES ....................................................................... 68

Appendix A Natural Resource Damage Data ........................................................... 71

Appendix B Well Data ................................................................................................ 74

Appendix C Definitions.............................................................................................. 77

Appendix D References............................................................................................. 79

Appendix E Voluntary Industry Measures Review .................................................. 83

Figures 

Figure 1 - Historical Deepwater Wells (Greater than 500 feet) .............................................................................21

Figure 2. Distribution of Dataset Spills by Response Costs per Barrel ($2009) ...................................................35

Figure 3. Distribution of Spills, by NRD + Assessment Cost per Barrel ($2009) .................................................36

Figure 4. Distribution of Spills, by Total Spill Costs ($2009).................................................................................36

Figure 5. Oil Spill Liability Trust Fund Claims Requested and Paid (Sep 1972-Feb 2010)................................37

Figure 6 Gulf State Landings and Revenue, 1999-2008 (2009$)............................................................................41

Figure 7 Average Annual Price per Pound (2009$)................................................................................................41

Figure 8 Gulf State Landings, 1999-2008 (mmlbs) .................................................................................................42

Figure 9 Resident Louisiana Shrimping Licenses (Trawl, Butterfly Net, and Skimmer Net) Source: Louisiana 

Department of Wildlife and Fisheries .............................................................................................................43

Figure 10 Monthly Commercial Fishery Landings (Texas, West Florida, Alabama)..........................................45

Figure 11 Monthly Commercial Fishery Landings (Louisiana, Mississippi)........................................................45

Figure 12 Summer Commercial Fishery Landing Revenues (West Florida, Mississippi, Alabama) .................46

Figure 13 Summer Commercial Fishery Landing Values (Louisiana, Texas) .....................................................46
 

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Tables 

Table 1 - 30 CFR 250 Subpart D Provisions............................................................................................................13

Table 2 – Deepwater Rig Counts, Day Rates, and Annual Drill Rates .................................................................25

Table 3 – Estimated Recurring Cost Summary ......................................................................................................28

Table 4 - Summary of Estimated Avoided Private-Social Costs...........................................................................32

Table 5 Seven Gulf Coast Spills: Natural Resource Damages ...............................................................................38

Table 6 Gulf of Mexico Commercial Fisheries Data, 2008.....................................................................................44

Table 7 Estimated 2010 Baseline Values for Gulf State Commercial Fisheries ($ millions, trend 2002-2008)..47

Table 8 Gulf Commercial Shrimping Costs as a Percentage of Revenues (simulated)........................................47

Table 9 Gulf Shrimping Fleet: Large and Small Vessels .......................................................................................48

Table 10 Large and Small Vessel Contributions to Gulf Commercial Fishing Revenues (2009$ millions) .......49

Table 11 Estimated Baseline Profits for 2010: Large and Small Gulf Commercial Fishing Vessels (2009$ 

millions) .............................................................................................................................................................49

Table 12 Estimated Baseline Profits for 2010: Gulf Coast Commercial Fisheries (2009$ millions)...................50

Table 13 2010 Gulf Fishery Closures in Federal Exclusive Economic Zone (EEZ)............................................51

Table 14 Estimated Gulf State Profits Lost to Closures........................................................................................52

Table 17 Average Number of Trips (May-July) (2005-2009).................................................................................53

Table 18. Estimated Number of Recreation Days (May-July)...............................................................................54

Table 19. Recreation Studies ...................................................................................................................................56

Table 20 Cost of Spills by Fuel Type........................................................................................................................57

Table 21 Cost of Spills by Length of Shoreline Oiled .............................................................................................57

Table 22 Cost of Spills by Location..........................................................................................................................58

Table 23 Oil Spill Response Costs by Spill Volume ................................................................................................58

Table 24 Selected Fatal Occupational Injury Rates by Industry, 2008.................................................................59

Table 25 Summary of Estimated Avoided External-Social Costs .........................................................................63

Table 26 - Summary of Private and External Social Costs ....................................................................................64

Table 27 - Dataset of Spill Costs: Restoration and Assessment Costs...................................................................71

Table 28 - Gulf Shrimp Landings, Revenue, and Price..........................................................................................73

Table 29 – GOM Deepwater Wells by Water and Drilling Depth.........................................................................74
 

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EXECUTIVE SUMMARY

This document describes the benefit-cost analysis conducted for this interim rule, RIN 1010 

AD68, Increased Safety Measures, Drilling Operations on the Outer Continental Shelf (OCS). It 

represents a joint effort by the BOEMRE Economics Division and the Office of Policy Analysis 

(OPA) in the Department of the Interior. The preamble to the regulation gives instructions for 

providing public comment on this analysis. 

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, BOEMRE 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 BOEMRE 

as part of the public forums and information gathering that the bureau has conducted since July 

12, 2010. 

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

enumerated requirements of approximately $180 million per year, have a strong foundation and 

are based on 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 

complex factors that affect the risk of a blowout event. As noted by the Secretary of the Interior 

in his July 12 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 
 

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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 BPDH event commencing on April 20, 2010. 

Three new requirements account for virtually all of the compliance costs imposed by this 

regulation (1) use of dual mechanical barriers in addition to cement barriers in the final casing 

string to prevent hydrocarbon flow in the event of cement failure, (2) application of negative

pressure tests to all intermediate and the production casing strings to ensure their proper 

installation, and (3) maintenance of standby ROV capability to close BOP rams and testing that 

capability after the BOP has been installed on the sea floor. BOEMRE estimates that these three 

requirements will impose compliance costs of approximately $174 million per year, representing 

95 percent of the total annual compliance costs of $183 million associated with this rulemaking. 

These cost estimates were developed by BOEMRE based on public data sources and confidential 

information provided by several offshore operators and drilling companies. 

On the benefit side, the avoided costs for a hypothetical 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 OPA using damage costs per 

                                                           

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 BPDH 

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

estimations of the amount of oil released as a result of the BPDH 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 BPDH event. As such, the damage and cost 

estimates presented herein should not be considered reliable monetary assessments associated with the BPDH 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 BPDH spill or any other spill.
 

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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. 

The above estimate of compliance costs is somewhat uncertain. This is the case primarily 

because the $183 million annual estimate is perhaps higher than the actual costs that will be 

incurred by society from this rule because industry is voluntarily undertaking some steps 

following the BPDH event that overlap those in this regulation. The Joint Industry Task Force 

draft recommendations include use of mechanical barriers and negative pressure tests. 

Voluntary action, perhaps spurred on as well by revised liability expectations and increased 

insurance prospects, means the incremental costs associated with these overlapping measures are 

not truly imposed solely by the new regulations. Less incremental required costs reduce the 

improvement in reliability necessary for expected benefits to cover the cost of complying with 

the new regulations. 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) 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 factors derived from past oil spills. Possible 

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. 

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), the baseline risk of a catastrophic blowout is estimated to be about 

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

hypothetical spill implies that the expected annualized spill cost is about $631 million ($16.3 

billion once in 26 years, equally likely in any 1 year). To balance the $183 million annual cost 

imposed by these regulations with the expected benefits, the reliability of the well control system 

needs to improve by about 29 percent ($183 million / $631 million). We have found no studies 

that evaluate the degree of actual improvement that could be expected from dual mechanical 

barriers, negative pressure tests, and a seafloor ROV function test. 
 

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INTRODUCTION AND NEED FOR FEDERAL ACTION 

The interim 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, 20102. 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 interim final rule address items 1) secondary control system requirements 

and 3) deepwater well control procedure requirements. The rule does not include 2) new blindshear 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 Interior Strike Teams to determine their efficiency and effectiveness. Measures 

considered beneficial will be considered for future notice and comment rulemaking. 

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 interim 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. 

                                                           

2

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

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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. 

The BOEMRE carries out this duty through regulations, the terms and conditions of 

leases, conditions of exploration and development plan approval, and inspections of OCS 

oil and gas operations. Although current regulations extensively address shallow and 

deepwater drilling operations, the BPDH 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 current ex post compensation regime perhaps provides too little information to 

regulators regarding the effectiveness of safe operating incentives embodied in the existing 

regulatory regime. A more prescriptive regime 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 because of the potential to 

avoid some or all of the liability. 

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. BOEMRE 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 
 

 10 

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, BOEMRE commissioned an 

outside assessment of the voluntary measures proposed by Joint Industry Task Forces (JITFs) as 

compared to these regulations. (See Appendix E). While the work of the JITFs is not complete 

and the lessons learned or other measures have not been implemented, an assessment of 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 interim 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 BPDH 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 BPDH blowout. The BPDH 

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

Shallow Water Drilling Activity 

While blowouts 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. BOEMRE has recorded 6 GOM shallow water blowouts 

resulting in a spill of hydrocarbons from 1990-2010. 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 
 

 11 

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. 

The compliance costs for this regulation fall over 90 percent 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 

BOEMRE has obtained these historical data on deepwater drilling 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. 

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 BPDH spill and 

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

government volumetric estimate of the BPDH 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 BPDH 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. BOEMRE 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 
 

 12 

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

reasonable proxy for regulatory cost-benefit analysis purposes. This scenario results in an oil 

spill of 4.77 million barrels. 

EXISTING AND NEW REGULATORY PROVISIONS 

This interim rulemaking will revise selected sections of 30 CFR 250 subparts D, E, F, O, 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.3 Table 1 compares the 

existing 30 CFR 250 Subpart D provisions with the new provisions. We expect that all of 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 intermediate and production casing strings; 250.423(c). 

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

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 certification that the shear rams will shear drill pipe under maximum 

anticipated pressure; 250.416(e) 

                                                           

3 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.
 

 13 

Table 1 ‐ 30 CFR 250 Subpart D Provisions

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions Cost 

- Requires the operator to evaluate 

the best practices according to API 

RP 65-Part 2 and submit a written 

description for the evaluation. 

- Written description must include 

the mechanical barriers and 

cementing practices the operator 

will use for each casing string. 

30 CFR 

§250.415(f) 

Evaluate best 

practices in 

API RP 65-

Part 2 

- No evaluation 

required 

- API RP 65 Part 2 addresses 

cementing practices and factors 

affecting cementing success. 

- No meaningful 

cost 

- Schematics of all control 

systems, including primary 

controls, secondary controls, and 

pods for the BOP system must be 

submitted. 

30 CFR 

§250.416(d) 

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 - Location of the controls must be 

included 

- No meaningful 

cost 

 

- 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 in 

the hole under maximum 

anticipated surface pressure. 

- Independent third 

party certification 

will require a small 

cost per well 

- Independent third party must be a 

technical classification society or 

an API licensed manufacturing, 

inspection, certification firm, or 

licensed professional engineering 

firm. 

30 CFR 

§250.416(e) 

Independent 

third party 

verification 

to ensure 

blind-shear 

rams are 

capable of 

cutting the 

drill pipe 

used 

- No independent third 

party certification 

required 

- Independent third party must not 

be the OEM. 

- 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 
 

 14 

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions Cost 

- PE will verify there are two 

independent barriers 

- Small cost per well 

if performed by an 

independent third 

party 

- No cost if PE 

certification is done 

in house 

30 CFR 

§250.420(a)

(6) 

Professional 

Engineer 

verification 

of well 

casing and 

cementing 

program 

- No PE verification 

required 

- Verify the casing cementing 

design is appropriate for the 

purpose it was intended under 

expected wellbore conditions - Assumed that some 

majors would verify 

in-house; smaller 

operators will use 

third party 

- Installation of dual 

mechanical barriers 

is estimated to take 

30 minutes. 

- Estimated 

additional float 

valve cost of 

$20,000 

30 CFR 

§250.420(b)

(3) 

Dual 

mechanical 

barriers 

- No requirement - Operator must install dual 

mechanical barriers in addition to 

cement in the final casing string 

and document to BOEMRE. 

- Dual float valves, or one float 

valve and a mechanical plug. 

- Will add 

significant costs to 

regulation 

- PE will verify there are two 

independent barriers 

- 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(a)

(6) 

Professional 

Engineer 

verification 

of well 

casing and 

cementing 

program 

- No PE verification 

required 

- Verify the casing cementing 

design is appropriate for the 

purpose it was intended under 

expected wellbore conditions 

- Will add 

significant costs to 

regulation 
 

 15 

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions Cost 

- Perform a pressure 

test on all casing 

strings (except 

drive/structural) 

according to 250.423 

(a) 

- Pressure tests are 

already required, no 

extra equipment 

time 

- Each pressure test 

only takes a few 

minutes 

30 CFR 

§250.423(b)

(2) 

Pressure test 

on the casing 

seal 

assembly 

- No requirement to 

ensure proper 

installation of the 

casing in the subsea 

wellhead 

 

- 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. 

 

- No meaningful 

cost 

- Negative pressure 

test will take 90 

minutes for each 

required string of 

casing 

30 CFR 

§250.423(c) 

Negative 

pressure test 

- No negative pressure 

test required 

- Perform a negative pressure test 

to ensure proper installation of 

intermediate and production casing 

strings 

 

- Will result in 

significant costs for 

the regulation 

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 to 

have 

autoshear/deadman 

systems 

- No meaningful 

cost 
 

 16 

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions 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 

- 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 

 

30 CFR 

§250.442(i) 

Develop 

management 

system for 

BOP 

 - 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) 

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 

- No meaningful 

cost 
 

 17 

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions Cost 

- 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 

30 CFR 

§250.449(j) 

Subsea 

function test 

for ROV 

intervention 

on a subsea 

BOP stack 

Additional 

stump testing 

requirements 

- 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 

- 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 

- ROV seafloor test 

is estimated to take 

about 24 hours 

- Will add 

significant costs 

30 CFR 

§250.449(k) 

Autoshear/D

eadman 

function test 

- No required function 

test 

- The autoshear and deadman 

systems must be function tested 

during the stump test and during 

the initial test on the seafloor. 

- No meaningful 

cost 

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 

- No approval 

requirement 

- Approval required from District 

Manager before displacing killweight drilling fluid from the 

wellbore 

- No meaningful 

cost 

District 

Manager 

approval for 

displacing 

kill-weight 

drilling fluid 

 - Submit reasons for displacing 

and provide detailed procedures of 

displacement process. 

 

30 CFR 

§250.456(j) 

 - Follow procedures in 250.456 
 

 18 

EMERGENCY SUBPART D INTERIM FINAL RULE PROVISIONS 

Regulation Summary Existing Regulatory 

Provisions 

New Regulatory Provisions Cost 

- All ROV intervention functions 

must be tested during the stump 

test and one set of rams during the 

initial test on the seafloor 

- 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 

30 CFR 

§250.516(d)

(8) 

Subsea 

function test 

for ROV 

intervention 

on a subsea 

BOP stack 

- Stump test BOP stack 

before installation 

- 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 costs for 

well completions 

operations 

- All ROV intervention functions 

must be tested during the stump 

test and one set of rams during the 

initial test on the seafloor 

- 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 

30 CFR 

§250.616(h)

(1) 

Subsea 

function test 

for ROV 

intervention 

on a subsea 

BOP stack 

- Stump test BOP stack 

before installation 

- 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 costs for 

well workover 

operations 

Benefit-Cost Approach

The purpose of this benefit-cost 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 rule is 

considered major and economically significant because it is expected to impose annual costs on 

the economy of more than $100 million. 
 

 19 

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 

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 interim rule, we have not been able to quantify the 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 
 

 20 

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

pressure tests, and a seafloor ROV function check. 

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

appropriate well design reliability studies. If such studies are identified, their results will 

be included in future analysis. 

 

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 BPDH blowout. The BPDH 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 interim 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 most recent government estimate of 

the BPDH 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 activity4. 

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 BPDH spill. This 

assumption may understate 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 this analysis must be conducted for the emergency interim rulemaking, we did not 

adjust the baseline for any voluntary measures. A further discussion of voluntary measures can 

be found in the section on Compliance Costs for this Regulation. 

                                                           

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

the BPDH event.  They are not pertinent to the BPDH 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 BPDH 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 BPDH event.  As such, the damage and cost estimates presented herein should not be

considered reliable monetary assessments associated with the BPDH event.
 

 21 

Baseline Estimates of Future Deepwater Drilling Activity 

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

wells. BOEMRE 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 drilling, leasing, aggregate production forecasts and other available data. 

BOEMRE estimates that there will be an average of 160 deepwater wells drilled annually over 

the next 20 years. The drilling of 160 deepwater wells per year is used to estimate the expected 

interval before another catastrophic blowout similar to the BPDH. This projection was divided 

into 112 wells drilled from floating rigs and 48 from rigs on deepwater production platforms. 

The recent historical annual well count5

 is shown in the following figure. 

DW Wells >500 ft (historical)

0

50

100

150

200

250

300

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

Year

Wells

DW Wells >500 ft

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

The GOM deepwater is generally expected to follow a progression similar to the GOM shelf. 

That means most of the remaining deepwater wells will be drilled farther from shore. Because of 

the extremely high cost of exploring and developing deep and ultra-deep prospects, the number 

of wells drilled in the deeper water depths is unlikely to again reach the peak set in 2001-2002. 

                                                           

5 All counts of wells exclude bypasses which are often included in other BOEMRE counts of spudded wells.  These

counts also exclude well completion and workover operations which involve re‐entering a wellbore and re‐

deploying of BOPs and ROVs.  
 

 22 

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. BOEMRE 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, a catastrophic 

blowout spill under current regulations and practices is estimated 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. 

 

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 emergency 

rule raises drilling costs for every new deepwater well on the OCS. These new requirements add 

mechanical barriers to well design requirements and time for testing several features during 

drilling operations. BOEMRE estimates that each year the seven activities discussed in this 

section will add $183 million to the cost of operations on the OCS. For purposes of calculating 
 

 23 

annual costs associated with this rule, 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 17 workover and 

completion operations on successful (wet) exploratory wells. 

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 

floor. The BOP system is tested on the stump to ensure the BOP is functioning properly. New 

section §250.449 (j) requires 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 section §250.449 (k) requires 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. 

BOEMRE assumes it is 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. BOEMRE also assumes dynamically positioned rigs have autoshear/deadman 

systems. BOEMRE 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 confirm 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. The deadmanswitch test on the seafloor verifies that the well bore closes automatically if both hydraulic 

pressure and electrical communication are lost with the rig. 

BOEMRE 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 blindshear rams, one set of pipe rams, and disconnect the LMRP?” Results averaged about 24 hours 

of lost rig time to perform these subsea tests. 
 

 24 

However, the interim 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. Although the 24 hour survey average is an overestimate based on the interim regulations, 

the additional stump testing requirements and the deadman system seafloor tests are estimated to 

take about the same amount of time as the extra ram test and LMRP disconnect.6 Using the 

additional stump tests and deadman seafloor test as a proxy for the extra ram test and LMRP 

disconnect, BOEMRE maintains the 24 hours of lost rig time for costing purposes. The 

regulation will not affect platform rigs or shallow wells since they do not use subsea BOPs or 

ROVs. 

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

rate ($916,622) yields a total estimated compliance cost for this provision of $102.66 million. 

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 24 hour 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 negative pressure tests for intermediate casings 

cannot be scheduled with accuracy and 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 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. 

                                                           

6 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 require the use of an ROV during the stump test.
 

 25 

Table 2 – Deepwater 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 10 $400,000 48

Seafloor Function Testing of ROV Intervention and Deadman Systems 

– Workover/Completions

Current regulations do not require subsea ROV function testing of the BOP during workover or 

completions operations. New sections 250.516(d)(8) and 250.616(h)(1) 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 on the seafloor. These sections extend the 

requirements added to deepwater drilling operations (discussed in the previous section) to well 

completion operations and workover 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 24 hours. This is in addition to the 24 hours testing time 

discussed in the previous section for selected wells. BOEMRE data shows that two-thirds of 

deepwater wells drilled are exploratory wells, and approximately 23% of exploratory wells are 

completed. Using our estimate of 112 MODU wells each year results in an additional 17 subsea 

BOP tests from workover and completions operations. Using a weighted average of MODU day 

rates from Table 2, 17 redeployments of a BOP will cost $15.47 million. 

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. New section §250.423 (c) requires that a negative

pressure test be conducted for all intermediate and production casing strings. This 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 conduct 
 

 26 

negative pressure tests on selected casing strings as a best practice, we do not have the data 

available in an easily accessible database to determine the frequency at which this occurs. Based 

on typical industry procedures, we estimate each new negative pressure test will take 

approximately 90 minutes for each casing string. We also estimate that on average deepwater 

wells use one production and four intermediate casing strings and shallow wells use one 

production and two intermediate casing strings. 

Ninety minutes is equivalent to 0.0625 days. Using the weighted average of the MODU day 

rates in Table 2, and a platform day rate of $400,000, 0.0625 days times 5 casing strings times 

112 MODU wells and 48 platform wells yields an annual average additional costs in deepwater 

for this test of $38.08 million. A loaded day rate of $200,000 for a shallow water rig (jackup) 

times 0.0625 days times 3 casing strings for each of 186 wells adds another $6.975 million to the 

extra cost for the universal requirement for the negative pressure test. 

Installation of Dual Mechanical Barriers

Current regulations do not require the installation of dual mechanical barriers although this 

requirement can be considered the use of best available and safety technology (BAST) per § 

250.107(d). For this benefit-cost analysis this 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 mechanical barriers in addition to 

cement barriers for the final casing string. These barriers prevent hydrocarbon flow in the event 

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

dual mechanical barriers and submit this documentation to BOEMRE within 30 days after 

installation. These new requirements will ensure that the best casing and cementing design will 

be used for a specific well. Dual mechanical barriers may include two float valves, or one float 

valve and one mechanical plug. Based on in-house expertise, BOEMRE estimates that all wells 

will require a second mechanical barrier. We estimate an average cost of $20,000 for each 

mechanical barrier and 30 minutes of installation time. 

For the 112 MODU wells each year, these parameters yield $2.24 million for the barriers (112 

times $0.02 million) plus [2.08% of a day (half hour divided by 24 hours) times the weighted 

average day rate from Table 2 times 112 wells] $2.14 million in installation costs. Similar 

calculations for 48 platform and 186 shallow water wells yields a total annual compliance cost of 

$10.3 million for this requirement. 

Professional Engineer Certification for Well Design

Current regulation 30 CFR 250.420(a) specifies well casing and cementing requirements but 

does not require verification by a Professional Engineer although verification could be 

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

 27 

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

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

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

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

the well thus decreasing the likelihood of a blowout. We assume that many of the larger 

companies will verify 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 deepwater 

leases are owned by large entities, BOEMRE assumes that 50% of future deepwater wells and all 

shallow water wells will incur an additional cost for a third party professional engineer 

certification of the well design. Based on an informal survey of drilling contractors and lease 

operators, BOEMRE 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 $0.540 million, and for shallow water wells $4.185 million. 

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

Current regulations do 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 meet the regulatory standard for BOPs. Surface inspection following shear ram activation 

may not have been enforced by the government or 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 study7, 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. We estimate 112 wells drilled 

per year from drillships or semisubmersibles; therefore we 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 Certification of Shear Ram Capability

Section 30 CFR 250.416(e) requires information verifying that BOP blind-shear rams are 

capable of cutting through any drill pipe in the hole under maximum anticipated conditions. This 

regulation has been modified to require the BOP verification be conducted by an independent 

                                                           

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

 28 

third party. The independent third party provides an objective assessment that the blind-shear 

rams can shear any drill pipe 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 these standards are not a new regulatory requirement, independent 

verification and submission of that verification was apparently not enforced by the government; 

therefore this analysis considers the independent verification to be a new cost. Based on inhouse 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. 

Summary of Annual Recurring Costs

Table 3 summarizes the cost estimates for these recurring cost categories for three subgroups of 

wells affected by the new regulations. 

Table 3 – Estimated Recurring Cost Summary

MODU Wells 

(112/yr) 

Fixed 

Platforms 

(48/yr) 

Shallow 

Wells 

(186/yr) 

Cost 

Shares 

Regulation Recurring Costs:

Total ($MM) Total 

($MM) 

Total 

($MM) 

250.449(j)(k) Subsea ROV function testing 

(drilling) 102.7 0.0 0.0 56% 

250.516(d)(8), 

250.616(h)(1) 

Subsea ROV function testing 

(workover/completions) 15.5 0.0 0.0 8% 

250.423(c) Test casing strings for proper 

installation 32.1 6.0 7.0 25% 

250.420(b)(3) Installation of dual mechanical 

barriers 4.4 1.4 4.5 6% 

250.420(a)(6) PE certification for well design 1.3 0.5 4.2 3% 

250.451(i)(j) Emergency cost of activated shear 

rams or LMRP disconnect 2.6 0.0 0.0 1% 

250.416(e) Independent third party shear 

certification 0.4 0.2 0.6 1% 

Estimated Cost per year: 158.8 8.1 16.3 $ 183.1 

 Estimated Cost per well: 1.42 0.17 0.09 
 

 29 

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 3, 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 requirements. 

Voluntary Measures by Industry

Some part of the roughly $183 in annual compliance cost total may not be rightfully assigned to 

the regulation as industry is undertaking a number of steps following the BPDH event that may 

overlap those in this regulation. An independent analysis by Industrial Economics Inc. (See 

Appendix E) indicates overlap exists for the mechanical barriers 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 potential actions, but acknowledge that our cost estimate may overstate compliance 

costs for this reason. 

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 social avoided 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 BPDH 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: 
 

 30 

• 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, BOEMRE 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 million8

) and the cost of a new drillship ($750 million9). We take 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 BPDH 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.). BOEMRE 

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. 

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. BOEMRE assumes that a 

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

                                                           

8

 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-sounde-30452.html

9

 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/in

dex.html
 

 31 

for 90 days. This equates to 4.77 million barrels of oil spilled10. 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. 

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 11. For computing the value of lost natural gas, BOEMRE estimates a market 

value of $4.00/MMBtu for a total lost value of almost $28 million. 

Fines and Criminal Penalties 

The Clean Water Act provides for fines against the responsible party for 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 benefitcost estimate for this rulemaking. 

Summary of Avoided Private-Social Costs 

Table 4 summarizes the avoided private costs estimated for this analysis, stated in 2010 dollars. 

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. 

                                                           

10 See footnote number. 11 5.8 MMBtu per BOE.
 

 32 

Table 4 ‐ 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.12 

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 

                                                           

12 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.
 

 33 

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. 

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 
 

 34 

values associated with different categories of avoided costs, and reporting averages or most 

likely values to determine point estimates for calculations. 

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, BOEMRE 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 BOEMRE 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 BPDH 

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 
 

 35 

determine the amount of natural resource damages associated with any particular oil spill, 

including the BPDH spill. 

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)
 

 36 

Figure 3. Distribution of Spills, by NRD + Assessment Cost per Barrel ($2009)

Figure 4. Distribution of Spills, by Total Spill Costs ($2009)
 

 37 

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).13 The 

vast majority of the spills were 10,000 barrels or less. As stated, this data set does not include 

the BPDH 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 

                                                           

13 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.
 

 38 

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 5 Seven Gulf Coast Spills: Natural Resource Damages

Event Volume 

spilled 

(bbls) 

NRD+Assessement 

Costs $/bbl $2010 

Injured Resources 

OCEAN 255/B155/BALSA 37 Spill 8,619 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 
 

 39 

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 to relevant in calculating damages for any 

particular oil spill, including the BPDH 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 A. 

• 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 
 

 40 

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 profits14 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. Prices do not appear to contribute to the decline in 

revenues. For the top ten commercial species, which together account for over 96 percent of 

                                                           

14 We use producers’ profits as a proxy for producer surplus.
 

 41 

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. 

$0

$2

$4

$6

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

2

0

0

9

$

p

e

r

L

b

Crab, Stone

Tunas

Snapper,Red

Oyster

Groupers

Shrimp

Crawfish

Crab,Blue

Mullets

Menhaden

Figure 7 Average Annual Price per Pound (2009$)

Source: NMFS Fisheries Economics of the United States 2008. 
 

 42 

1

10

100

1,000

10,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

L

a

n

d

i

n

g

s

(

M

i

l

l

i

o

n

L

b

s

)

Menhaden

Shrimp

Crab, Blue

Oyster

Mullets

Groupers

Crab, Stone

Snapper,Red

Tunas

Crawfish

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. 
 

 43 

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 6. 
 

 44 

Table 6 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, 15 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. 

                                                           

15 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.
 

 45 

0

5

10

15

20

25

M

i

l

l

i

o

n

l

b

Texas

Florida, West

Alabama

Figure 10 Monthly Commercial Fishery Landings (Texas, West Florida, Alabama)

0

50

100

150

200

250

300

350

M

i

l

l

i

o

n

l

b

Louisiana

Mississippi

Figure 11 Monthly Commercial Fishery Landings (Louisiana, Mississippi)
 

 46 

$0

$5

$10

$15

$20

M

i

l

l

i

o

n

(

2

0

0

9

$

)

Florida, West

Mississippi

Alabama

Figure 12 Summer Commercial Fishery Landing Revenues (West Florida, Mississippi, Alabama)

$0

$20

$40

$60

$80

M

i

l

l

i

o

n

(

2

0

0

9

$

)

Louisiana

Texas

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 7. 
 

 47 

Table 7 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 8. 

Table 8 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, 
 

 48 

and one-third of the vessels are 60 to 65 feet long. Tallying the proportions below 60 feet 

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 9, where the same approach is used to apportion the total fleet shrimp landings and 

landings revenue. 

Table 9 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 9, 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 7 to determine the contribution of each 

vessel class to baseline revenues for the entire commercial fishing industry (see Table 10). We 

then apply the assumptions from Travis and Griffin (2004) about variable costs as a percentage 
 

 49 

of revenues to determine baseline profits accruing to each vessel class (see Table 11). Finally, in 

Table 12 the results for large and small vessels are summed together to find the 2010 baseline for 

total industry profits by month. 

 

Table 10 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 11 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 11 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 7 gives the 2010 baseline profits in Table 12. 

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. 
 

 50 

Table 12 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 13. 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 15.16 The eastern edge of the Gulf has also remained open, and Florida has 

closed only about 20 miles of the coastline near Pensacola.17 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.18 On July 20, Mississippi State 

coastal waters re-opened to live-bait shrimping and catch-and-release fishing.19 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.20 

                                                           

16 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/. 17 Florida closure data were taken from a Florida Fish and Wildlife Conservation Commission press release dated

June 13, 2010. 18 Alabama closure data were taken from an Alabama Department of Conservation and Natural Resources press

release dated June 28, 2010. 19 Mississippi closure data were taken from a Mississippi Department of Environmental Quality/Department of

Marine Resources news release dated July 19, 2010. 20 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/.
 

 51 

Table 13  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. 
 

 52 

Table 14  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 

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 
 

 53 

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 15). 

Table 15 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 13) 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 

likely that the decrease in number of trips would be smaller than if fewer substitutes are 

available. 
 

 54 

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 16. 

 

Table 16. 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 

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 
 

 55 

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. 
 

 56 

Table 17.  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 

Entities), OMB considered benefits of vessel response plans and double-hull vessels by valuing 
 

 57 

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 18 presents estimates in 

current dollars of oil spill cleanup costs by oil type; Table 19 presents estimates by kilometer of 

shoreline oiled; Table 20 presents estimates by proximity to shore. Table 21 presents 

information by spill volume.21

Table 18 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 19 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

                                                           

21 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.
 

 58 

Table 20 Cost of Spills by Location

Location US Spills 

(2010 

$/bbl)

In-port 6,033

Nearshore 4,437

Offshore 1,217

Source: Etkin, 2001. 

Table 21 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 
 

 59 

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 22). 

Table 22 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; 

• Delayed/immediate; 
 

 60 

• 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 

Preparing Economic Analyses were drafted. A recent report of the EPA’s Science Advisory 
 

 61 

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 symptoms22

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). 

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 

                                                           

22 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.
 

 62 

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 illnesses23 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. 

                                                           

23 As of June 6, 2010; mostly contusions/abrasions and heat stress.
 

 63 

Summary – Avoided External-Social Costs 

Table 23 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 23 Summary of Estimated Avoided External‐Social Costs

Cost   Avoided Cost

for 1

Hypothetical

Spill

Social Cost Category

($ 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
 

 64 

TOTAL ESTIMATED AVOIDED SOCIAL COSTS (BENEFITS) 

Table 24 combines the conditional avoided private-social and external-social costs from Table 4 

and Table 23. This is the potential benefit per catastrophic spill in the baseline from fully 

eliminating the possibility of a spill. 

Table 24 ‐ 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. 

The compliance 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 avoided associated with the 

hypothetical spill scenario owing to 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 

based on extending historical information on deep water blowouts. Given the paucity of 
 

 65 

information on specific effectiveness of various measures and the likelihood of another 

catastrophic blowout, this approach aims to identify scenarios in which the expected benefits 

justify the expected costs. 

The hypothetical spill from Table 24 gives us an avoided social cost of $16.3 billion for a major 

event. The compliance costs of this regulation from Table 3 give an annual compliance cost of 

$183 million per year. The baseline assumptions establish that there was 1 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.24

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 required 

proportional 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 $183 million divided by annualized avoided costs of $631 million suggests a 

finding of a 29 percent improvement in spill frequency when expected benefits justify the 

expected compliance costs. 

By varying selected important inputs in reasonable ways, we can provide a range for the 

scenarios under which expected benefits justify the costs of the regulation. 

1) The compliance costs are lowered by about 50% to $97 million reflecting 

productivity improvements, and raised by about 100% to $352 million reflecting 

more frequent compliance problems and work stoppages during drilling operations, as 

discussed in the next section. 

2) 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.

                                                           

24 4123 wells divided by 160 wells per year gives us 25.8 years, or 26 years.
 

 66 

Sensitivity of Compliance Costs

A lower compliance cost estimate of $97 million annually assumes the industry can achieve 

longer term productivity improvements for the requirements in this regulation. The lower 

compliance cost estimate for the sensitivity analysis is determined by taking 1⁄2 of the ROV 

testing time (12 hours) for the subsea BOP on the stack and seafloor for drilling and 

workover/completions operations and 1⁄2 of the casing strings required (an average of 2.5 strings 

tested for deepwater wells and 1.5 strings tested for shallow wells) for the negative pressure test. 

Additionally, we include only the capital cost of the second mechanical barrier and exclude the 

30 minutes of lost rig time due to installation from the baseline estimate and assume the 

frequency of emergency activation of the BOP is halved. Over time, companies will improve the 

efficiency of conducting these tests, improve technology to use fewer casing strings and find 

other methods to improve lost productivity; however, a 50 percent improvement appears unlikely 

to be achieved in the near term. Using this lower compliance cost of $97 million, divided by the 

annual avoided cost of $631 million, the required proportional improvement in spill frequency is 

found to be 15 percent. 

An upper compliance cost estimate of $352 million annually assumes that the time required for 

conducting the tests for this regulation were underestimated due to unforeseen and time 

consuming problems encountered through the additional requirements imposed by this 

regulation. The higher compliance cost estimate for the sensitivity analysis is determined by 

doubling the ROV subsea BOP testing time for drilling and workover/completion operations and 

doubling the time needed to complete negative pressure tests for all intermediate and production 

casing strings. The subsea BOP stack testing components would take a full 48 hours and each 

negative pressure test would take 3 hours in this scenario. Additionally, the lost rig time for 

installing the second mechanical barrier would be doubled to 60 minutes and the frequency of 

the emergency activation of the subsea BOP stack would occur twice as often. The upper bound 

annual compliance cost consistent with these assumptions is found to be $352 million annually. 

Using this upper compliance cost of $352 million, divided by the annual avoided cost of $631 

million, the required proportional improvement in spill frequency is found to be 56 percent. 

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 
 

 67 

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. Thus the reservoirs 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 is not 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 of the water depths as 

demonstrated by the BPDH event. 

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 

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.25

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. Taking 

the compliance costs of $183 million per year, divided by the alternate annual avoided costs of 

$1.216 billion per year, results in a required proportional improvement in spill frequency of 15 

percent for the benefits to justify the costs in this alternate scenario. 

Alternatives 

This interim 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. Given the critical nature of the BP Deepwater Horizon 

(BPDH) explosion and resulting oil spill and the apparent inadequacy of existing well control 

procedures and BOP requirements, the Safety Measures Report recommended that BOEMRE 

address some items through an emergency rulemaking. The requirements in this interim final 

rule include practices related to well control, including well casing and cementing, ROV 

intervention, unplanned disconnects, recordkeeping, well completion, and well plugging. These 

requirements were determined by the Secretary to be urgently needed to protect worker safety 

and the OCS environment. 

Other measures recommended in the Safety Measures Report but not included in this emergency 

interim rulemaking include additional blind shear and casing ram requirements, enhanced ROV 

                                                           

25 1475 wells drilled divided by 110 wells per year equals 13.4 years.
 

 68 

intervention capability, increased accumulator capacity for operating BOPs and safety case 

requirements for floating drilling operations. These and other items in the Safety Measures 

Report require further study by industry and Interior Strike Teams to determine their efficiency 

and effectiveness. Measures considered beneficial will be considered for future notice and 

comment rulemaking. 

Small Business Alternatives 

Two alternatives to ease impacts on small business were considered. One alternative is to 

exempt small businesses from the requirements of this interim final rule. A second alternative is 

to delay the implementation timelines to comply with the regulation. Both of these alternatives 

are being rejected by BOEMRE because of the overriding need to reduce the chance of a 

catastrophic blowout event. We do not believe it is responsible for a regulator to 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 may increase the interim 

risk of OCS drilling operations. Additionally, more than 90 percent of the costs will be imposed 

on deepwater lessees and operators where small businesses only hold 12 percent of deepwater 

leases. Every operator and drilling contractor both large and small must meet the same criteria 

for drilling operations regardless of company size. However, the overwhelming share of the cost 

imposed by this regulation will fall on companies drilling deepwater wells, which are 

predominately the larger companies. Nonetheless, small companies as both lease-holders and 

contractors serving lease-holders will bear meaningful costs under this regulation. 

To better understand the economic impact of this rule on small entities, the BOEMRE will 

conduct a supplemental Initial Regulatory Flexibility Analysis (IFRA) to examine in greater 

detail the impact of this regulation on the small entities. We are requesting comments on the 

economic analysis for this interim final rule and this rulemaking’s impact on small entities. The 

supplemental IFRA will be made available to the public when completed. 

CONCLUSION AND UNCERTAINTIES 

The BOEMRE has analyzed the costs and benefits of this interim 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 and benefits, 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. 

Future long term studies should be conducted to assess the likely effectiveness of these increased 

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

 69 

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

BOEMRE TIMS data base may enable studies that assess how requirements for extra subsea 

ROV and deadman testing, widespread use of negative pressure tests, dual mechanical barriers in 

the final casing string, along with the remaining items required in this rulemaking, could improve 

well control performance. Parenthetically, such data are available to conduct statistical tests on 

prospective BOP enhancements which are not included in this rule. Absent the ability to conduct 

these studies of the key features that are included in this rule, we turn to possible refinements in 

the baseline assessments. 

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

other factors not specifically addressed in this benefit-cost analysis. Industry and government 

reaction to this spill has added experience that will improve planning, response and technology 

used to mitigate spill effects before a relief well is completed. However, the nature and impact 

of these changes are not easily quantifiable at this stage of the investigative process and are not 

included in the benefit-cost baseline. 

One area of further study involves the voluntary measures being recommended by the Joint 

Industry Task Forces. If the American Petroleum Institute’s (API) Recommended Practices (RP) 

are published and incorporated into BOEMRE regulations, we would consider those RP’s to be 

part of the inherent cost of sound well design and best practice drilling operations. In this 

circumstance the RP’s would not be considered a new compliance cost for the purposes of this 

benefit-cost analysis. Rather, the benefits and costs would be included in our baseline for this 

analysis. Therefore, to the extent that voluntary measures recommended by the Industry Joint 

Task Forces become API RP’s and are incorporated into BOEMRE regulations, the actual 

compliance costs imposed by this rule would be reduced. As a result, the required proportional 

improvement in spill reliability necessary for the benefits from the expected costs avoided by 

these provisions to exceed their compliance costs would be lowered, unless the voluntary 

measure also reduced the baseline risk of a spill under current regulations by a proportionally 

equal or greater amount than the reduction in costs. 

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

deepwater oil spill. Future studies and analyses are necessary to more fully reflect all the effects 

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

Mexico. 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 
 

 70 

hypothetical $16.3 billion benefit estimate, then the future analysis should be adjusted to reflect 

the new estimate. 
 

 71 

Appendix A Natural Resource Damage Data 

Table 25 ‐ 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 
 

 72 

Event Year of 

Settlement

Max Volume 

(bbl) 

NRD plus 

Assessment 

Costs 

(2009$/bbl)* 

Jahre Spray 1996 1,400 121 

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 Spill 1996 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 
 

 73 

Event Year of 

Settlement

Max Volume 

(bbl) 

NRD plus 

Assessment 

Costs 

(2009$/bbl)* 

T/V Julie N 2002 4,277 348 

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 26 ‐ 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). 
 

 74 

Appendix B Well Data 

Table 27 – 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 Well Total Depth (thousands of feet) 

Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 

Totals 

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 Well Total Depth (thousands of feet) 

Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 

Totals 

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 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 

- 

 
 

 75 

Counts of GOM Wells Drilled During the 1980's in Water >500 feet According to Well Drilled Depth 

Water Well Total Depth (thousands of feet) 

Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 

Totals 

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 Well Total Depth (thousands of feet) 

Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 

Totals 

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 

 
 

 76 

Counts of GOM Wells Drilled After 1999 in Water >500 feet According to Well Drilled Depth 

Water Well Total Depth (thousands of feet) 

Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 

Totals 

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 
 

 77 

Appendix C Definitions

Baseline: describes the status quo scenario (“the world absent the new regulation”). The 

baseline is compared to “the world with the regulation" 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 BOP’s are required on 

floating mobile drilling rigs. 

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. 
 

 78 

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.
 

 79 

Appendix D References 

Alabama Department of Conservation and Natural Resources. 2010. “Conservation Department 

Designates Coastal Boating Closures, Idle Speed-No Wake Areas.” Press release dated 

June 28, 2010. Accessed on-line at 

http://www.outdooralabama.com/news/release.cfm?ID=822 . 

American Association of Poison Control Centers. Accessed on-line at: 

http://www.aapcc.org/dnn/NewsandEvents/PoisonCentersandtheGulfOilSpill/tabid/472/D

efault.aspx

Bureau of Labor Statistics, U.S. Department of Labor. 2010. Career Guide to Industries, 2010-

11 Edition, Mining. Accessed on-line at: http://www.bls.gov/oco/cg/cgs004.htm (visited 

July 30, 2010). 

Centers for Disease Control and Prevention. 2010. Emergency Preparedness and Response, 

Health Surveillance. Accessed on-line at: 

http://www.bt.cdc.gov/gulfoilspill2010/2010gulfoilspill/health_surveillance.asp . 

Chapman, D. and W.M. Hanemann. 2001. Environmental Damages in Court: The American 

Trader Case. In: The Law and Economics of the Environment. Anthony Heyes (Ed.). 

pp. 319-367. 

Department of Health and Human Services, Centers for Disease Control and Prevention, 

National Institute for Occupational Safety and Health. 2010. NIOSH Report of BP Illness 

and Injury Data (April 23 – June 6, 2010). 

Dunford, Richard W. and Miranda L. Freeman. 2001. A Statistical Model for Estimating 

Natural Resource Damages from Oil Spills. 2001 International Oil Spill Conference. 

Florida Fish and Wildlife Conservation Commission. 2010. “Oil forces partial fishing closure in 

Escambia County.” Press release dated June 13, 2010. Accessed on-line at 

http://www.myfwc.com/NEWSROOM/10/statewide/News_10_X_OilSpill19.htm . 

Janjua, Navved Zafar, Pashtoon Murtaza Kasi, Haq Nawaz, Sadia Zohra Farooqui, Urooj Bakht 

Khuwaja, Najam-ul-Hassan, Syed Nadim Jafri, Shahid Ali Lutfi, Muhammad Masood 

Kadir and Nalini Sathiakumar. 2006. Acute Health Effects of the Tasman Spirit Oil 

Spill on Residents of Karachi, Pakistan. BMC Public Health, 6:84. 

Kochi, Ikuho, Bryan Hubbell, and Randall Kramer. 2006. An Empirical Bayes Approach to 

Combining and Comparing Estimates of the Value of a Statistical Life for Environmental 

Policy Analysis. Environmental & Resource Economics, 34:385–406. 

Liese, Christopher, Michael D. Travis, Diana Pina, and James R. Waters. 2009. 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, 107 p. 

Louisiana Department of Wildlife and Fisheries (LDWF); Interactive Closure Maps at 

http://www.wlf.louisiana.gov/oilspill/map/ 
 

 80 

Louisiana Department of Wildlife and Fisheries; Number of Shrimpers 1998-2005

http://www.wlf.louisiana.gov/pdfs/education/number_of_shrimpers_89_to_07.xls 

Louisiana Department of Wildlife and Fisheries, Office of Management and Finance (2000) The 

Louisiana Shrimp Industry; A Preliminary Analysis of the Industry’s Sectors

http://www.wlf.louisiana.gov/pdfs/education/La.%20Shrimp%20Industry.pdf

Lyons, Ronan A., J. Mark F. Temple, Daphne Evans, David L. Fone, and Stephen R. Palmer. 

1999. Acute Health Effects of the Sea Empress Oil Spill. Journal of Epidemiology and 

Community Health, 53(5): 306-310. 

Mississippi Department of Environmental Quality and Mississippi Department of Marine 

Resources. 2010. News release 10-94-SB, dated July 19, 2010. “Mississippi Territorial 

Waters Open to Live Bait Shrimping and Recreational Catch-and-Release Hook and Line 

Fishing.” 

Morita, Akemi, Yukinori Kusaka, Yoji Deguchi, Akio Moriuchi, Yuko Nakanaga, Masayuki Iki, 

Shigekazu Miyazaki, and Kazuo Kawahara. 1999. Acute Health Problems among the 

People Engaged in the Cleanup of the Nakhodka Oil Spill. Environmental Research 

Section A, 81: 185-194. 

Murley, J., L. Alpert, W.B. Stronge, and R. Dow. 2005. Tourism in Paradise: The Economic 

Impact of Florida’s Beaches. Proceedings of the 14th Biennial Coastal Zone Conference, 

New Orleans, LA, July 17-21, 2005. 

http://www.csc.noaa.gov/cz/CZ05_Proceedings/pdf%20files/Alpert.pdf

National Survey of Recreation in the Environment. 2000. 

http://egisws02.nos.noaa.gov/socioeco/genericProfile.html?datasource=nsre2000

NOAA (National Oceanic and Atmospheric Association). Marine Recreational Statistics Survey. 

http://www.st.nmfs.noaa.gov/st1/recreational/index.html

Palinkas, Lawrence A., Michael A. Downs, John S. Petterson, and John Russell. 1993a. Social, 

Cultural, and Psychological Impacts of the Exxon Valdez Oil Spill. Human Organization, 

52(1): 1-13. 

Palinkas, Lawrence A., John S. Petterson, John Russell, and Michael A. Downs. 1993b. 

Community Patterns of Psychiatric Disorders After the Exxon Valdez Oil Spill. Am J 

Psychiatry, 150(10): 1517-1523. 

Pearson, Walter. H, et al. (1996 ) “Assessment of Damages to Commercial Fisheries and Marine 

Environment of Fujairah, United Arab Emirates, Resulting from the Seki Oil Spill of 

March 1994: A Case Study.” Yale F&ES Bulletin #103, p. 407-428. 

Pérez-Cadahía, Beatriz, Anunciación Lafuente, Teresa Cabaleiro, Eduardo Pásaro, Josefina 

Méndez, and Blanca Laffon. 2006. Initial Study on the Effects of Prestige Oil on 

Human Health. Environment International. 
 

 81 

Posadas, Benjamin (2008) Economic Assessment of the Impacts of Hurricane Katrina on the 

Mississippi Commercial Fishing Fleet. Mississippi Agricultural & Forestry Experiment 

Station, Mississippi State University. 

Robinson, Lisa A. 2007. How U.S. Government Agencies Value Mortality Risk Reductions. 

Review of Environmental Economics and Policy, 1(2): 283-299. 

Sabucedo, José M., Constantino Arce, Carmen Senra, Gloria Seoane, and Isabel Vázquez. 2010. 

Symptomatic Profile and Health-Related Quality of Life of Persons Affected by the 

Prestige Catastrophe. Disasters, 34(3): 809-820. 

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. 

Added References: 

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 

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

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
 

 82 

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 

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 
 

 83 

Appendix E 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”). 
 

 84 

• 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.
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 described in API RP 65 Part 2 werand 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 printermediate and production casiverify that the casing hanger latcdown mechanisms are engaged ansealed. 

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 professionindependent tested barriers, inclbarrier, across each flow path duactivities. 

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 ne

the intermediate and production Test procedures and criteria must for approval. 

Ensure shearable drillstring components are positioned in the shear rams during displacement. 

30 CFR 250.442(a) New requirement for two BOPs, r

with a blind-shear rams, with a fublind-shear rams are appropriatelleast one cuts the drillpipe and se

Ensure BOP can automatically close blind/shear ram(s) and close choke/kill line valves 

30 CFR 250.442(f) Provide autoshear and deadman s

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 s

equipped with ROV intervention cthe ROV must be capable of closinrams, 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 
 

 87 

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.