1

Oil and Gas and Sulphur Operations in the Outer Continental Shelf –

Blowout Preventer Systems and Well Control

Initial Regulatory Impact Analysis

RIN: 1014-AA11

NOTICE OF PROPOSED RULEMAKING

DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

April 03, 2015
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Table of Contents

1. Introduction ....................................................................................................................................4

2. Need for regulation .........................................................................................................................5

3. Alternatives.....................................................................................................................................7

4. Economic analysis............................................................................................................................8

a. Costs............................................................................................................................................9

b. Benefits ..................................................................................................................................... 11

c. Transfers.................................................................................................................................... 12

d. Data inputs ................................................................................................................................ 12

i. Affected population................................................................................................................ 12

ii. Wage rates and loaded wage factors ..................................................................................... 12

iii. Daily rig operating costs......................................................................................................... 14

5. Section-by-section analysis of costs ............................................................................................... 14

a. Additional information in the description of well drilling design criteria ..................................... 16

b. Additional information in the drilling prognosis.......................................................................... 17

c. Prohibition of a liner as conductor casing................................................................................... 18

e. Additional information in the APM for installed packers ............................................................ 19

f. Additional information in the APM for pulled and reinstalled packers........................................ 20

g. Rig movement reporting ............................................................................................................ 22

h. Fitness requirements for MODUs and lift boats.......................................................................... 23

i. Foundation requirements for MODUs and lift boats................................................................... 24

j. Real-time monitoring of well operations.................................................................................... 25

l. Additional information in the APD, APM, or other submittal for BOP systems and system 

components ...................................................................................................................................... 28

m. Submission of a Mechanical Integrity Assessment Report....................................................... 30

o. New subsea BOP system requirements...................................................................................... 32

p. New surface accumulator system requirements......................................................................... 33

q. Chart recorders.......................................................................................................................... 33

s. Alternating BOP control station function testing ........................................................................ 35

t. ROV intervention function testing.............................................................................................. 36

u. Autoshear, deadman, and EDS system function testing on subsea BOPs .................................... 36
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v. Approval for well control equipment not covered in Subpart G.................................................. 37

w. Breakdown and inspection of BOP system and components....................................................... 39

x. Additional recordkeeping for real-time monitoring .................................................................... 40

y. Industry familiarization with the new rule.................................................................................. 40

6. Summary of the cost analysis......................................................................................................... 41

7. Benefits Analysis............................................................................................................................ 43

a. Data........................................................................................................................................... 47

b. Methods.................................................................................................................................... 47

8. Analysis results.............................................................................................................................. 52

9. Sensitivity Analysis......................................................................................................................... 57

a. Reduction in the Risk of Oil Spills ............................................................................................... 57

b. Reduction in the Risk of Fatalities............................................................................................... 59

c. Value of lost hydrocarbons ........................................................................................................ 65

10. Probabilistic Risk Assessment ............................................................................................................

 a. Overview ..........................................................................................................................................

 b. Event Trees ......................................................................................................................................

 c. Available Data .................................................................................................................................

 d. Questions .........................................................................................................................................

11. UMRA............................................................................................................................................ 66
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1. Introduction

Changes to Federal regulations must undergo several types of economic analyses. First, Executive 

Orders (E.O.) 13563 and 12866 direct agencies to assess the costs and benefits of available regulatory 

alternatives and, if regulation is necessary, select a regulatory approach that maximizes net benefits 

(including potential economic, environmental, public health, and safety effects; distributive impacts; and 

equity). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, reducing costs, 

harmonizing rules, and promoting flexibility. Under E.O. 12866, an Agency must determine whether a 

regulatory action is significant and, therefore, subject to the requirements of the E.O. and review by the 

Office of Management and Budget (OMB). Section 3(f) of E.O. 12866 defines a “significant regulatory 

action” as any regulatory action that is likely to result in a rule that: 

(a) Has an annual effect on the economy of $100 million or more, or adversely affects in a material 

way the economy, a sector of the economy, productivity, competition, jobs, the environment, public 

health or safety, or state, local, or tribal governments or communities (also referred to as “economically 

significant”); 

(b) Creates serious inconsistency or otherwise interferes with an action taken or planned by another 

agency; 

(c) Materially alters the budgetary impacts of entitlement grants, user fees, loan programs, or the 

rights and obligations of recipients thereof; or 

(d) Raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the 

principles set forth in E.O. 12866. 

The proposed rule is a “significant regulatory action” that is economically significant under section 

3(f)(1) of E.O. 12866. Accordingly, OMB has reviewed this regulation. 
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Second, the Regulatory Flexibility Act (RFA) of 1980 requires agencies to consider the economic 

impact of regulatory changes on small entities. Finally, the Unfunded Mandates Reform Act of 1995 

(UMRA) (Public Law 104-4) requires agencies to prepare a written assessment of the costs, benefits, and 

other effects of proposed or final rules that include a Federal mandate likely to result in the aggregate 

expenditure of $100 million or more annually (adjusted for inflation) by state, local, or tribal 

governments or by the private sector.

In conducting these analyses on the proposed rule, the Bureau of Safety and Environmental 

Enforcement (BSEE) provides the following summary:

(1) BSEE has determined that the proposed rule is a significant rulemaking within the definition of 

E.O. 12866 because the estimated annual costs or benefits exceed $100 million in at least one

year of the 10-year analysis period; 

(2) BSEE has determined that the proposed rule would have a “significant economic impact on a 

substantial number of small entities” under section 605(b) of the RFA; and

(3) BSEE has determined that the proposed rule would not impose an unfunded mandate on State, 

local, or tribal governments as defined by the UMRA. We have determined that the proposed 

rule, if finalized, would impose a Federal mandate that may result in the expenditure by the 

private sector of $100 million or more (adjusted annually for inflation) in a given year. 

2. Need for regulation

BSEE identified a need to amend the existing Blowout Preventer (BOP) and well-control regulations 

to enhance the safety and environmental protection of oil and gas operations on the OCS. In particular, 

BSEE considers the proposed rule necessary to reduce the likelihood of any oil or gas blowout, which can 

lead to the loss of life, serious injuries, and harm to the environment. As was evidenced by 

the Deepwater Horizon incident (which began with a blowout at the Macondo well) on April 20, 2010, 
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blowouts can result in catastrophic consequences.

1 Government and industry conducted multiple 

investigations to determine the cause of the Deepwater Horizon incident; many of these investigations 

identified BOP performance as a concern. BSEE convened Federal decision-makers and stakeholders 

from the OCS industry, academia, and other entities at a public forum on offshore energy safety on May 

22, 2012, to discuss ways to address this concern. The investigations and the forum resulted in a set of 

recommendations to improve BOP performance. 

As the agency charged with oversight of offshore operations conducted on the OCS, BSEE seeks to 

improve safety and mitigate risks associated with such operations. After careful consideration of the 

various investigations conducted after the Deepwater Horizon incident and industry’s responses to the 

incident, BSEE has determined that the requirements contained in this proposed rule are critical to 

address risks associated with offshore operations. BSEE determined that the BOP regulations need to be 

updated to incorporate some of the more pertinent recommendations, while others are being studied 

for consideration in future rulemakings. The Proposed Rule would create a new Subpart G in 30 CFR 

Part 250 to consolidate the requirements for drilling, completion, workover, and decommissioning 

operations. Consolidating these requirements would improve efficiency and consistency of the 

regulations and allow for flexibility in future rulemakings. The Proposed Rule would also revise existing 

provisions throughout Subparts D, E, F, and Q to address concerns raised in the investigations, BSEE’s

internal reviews, and the public forum. Finally, the Proposed Rule would incorporate American 

Petroleum Institute (API) Standard 53 to ensure better BOP operability and more robust regulatory 

oversight.

 

1

For example, any approximation of cost would incorporate catastrophic spills such as the Deepwater Horizon

incident. The cost to BP of cleanup operations for the Deepwater Horizon incident has been estimated at more 

than $14 billion. In addition to cleanup costs, BP has paid over $14 billion to Federal, State, and local governments 

as well as private parties for economic claims and other expenses. Source: Ramseur, J.L., Hagerty, C.L. 2014. 

“Deepwater Horizon Oil Spill: Recent Activities and Ongoing Developments,” Congressional Research Office. 

Available at: http://www.fas.org/sgp/crs/misc/R42942.pdf.
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3. Alternatives

BSEE has considered three regulatory alternatives: 

(1) Promulgate the requirements contained within the proposed rule, including increasing the BOP 

testing frequency for workover and decommissioning operations from the current requirement of 

once every 7 days to the proposed requirement of once every 14 days . The following chart 

identifies the BOP testing changes related to Alternative 1;

BOP Pressure Testing

Operation Current Testing Frequency Proposed Testing Frequency

Drilling / Completions Once every 14 days Once every 14 days

Workover / Decommissioning Once every 7 days Once every 14days

(2) Promulgate the requirements contained within the proposed rule with a change to the required 

frequency of BOP pressure testing from the existing regulatory requirements (i.e., once every 7 or 

14 days depending upon the type of operation) to once every 21 days for all operations. The 

following chart identifies the BOP testing changes related to alternative 2; 

BOP Pressure Testing

Operation Current Testing 

Frequency

Proposed Testing 

Frequency (Alternative 

1)

Alternative 2 

Testing Frequency

Drilling / Completions Once every 14 days Once every 14 days Once every 21 

days

Workover / 

Decommissioning

Once every 7 days Once every 14 days Once every 21

days*

* includes change from current 7 days to proposed 14 days

(3) Take no regulatory action and continue to rely on existing BOP regulations in combination with 

permit conditions, Deep Water Operations Plans (DWOPs), operator prudence, and industry standards. 
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By taking no regulatory action, BSEE would leave unaddressed most of the concerns and 

recommendations that were raised2regarding the safety of offshore oil and gas operations and the 

potential for another event with consequences similar to those of the Deepwater Horizon incident. 

Alternative 2 was not selected because BSEE is lacking critical data on testing frequency and 

equipment reliability. This issue may be considered in the final rulemaking if BSEE receives sufficient 

data to support alternative 2. 

BSEE has elected to move forward with Alternative 1--the proposed rule--which incorporates

recommendations provided by government, industry, academia, and other stakeholders as well as API 

Standard 53. In addition to addressing concerns and aligning with industry standards, BSEE is 

functioning in a prudent capacity with this proposed rule by advancing several of the more critical 

capabilities beyond current industry standards based on internal knowledge and experience. The 

proposed rule would also improve efficiency and consistency of the regulations and allow for flexibility 

in future rulemakings.

BSEE is requesting comments on how long it would take to come into compliance with the proposed 

rule as well as any other alternatives BSEE may reasonably consider, including alternatives to the specific 

provisions contained in the Notice of Proposed Rulemaking (NPRM).

4. Economic analysis

BSEE’s economic analysis evaluated the expected impacts of the proposed rule compared with the 

baseline. The baseline refers to current industry practice in accordance with existing regulations, 

 

2

See the DOI JIT report “Report Regarding the Causes of the April 20, 2010 Macondo Well Blowout,” September 

14, 2011; the National Commission final report, “Deep Water, The Gulf Oil Disaster and the Future of Offshore 

Drilling,” January 11, 2011; the Chief Counsel for the National Commission report, “Macondo The Gulf Oil 

Disaster,” February 17, 2011,; the National Academy of Engineering final report, ” Macondo Well-Deepwater 

Horizon Blowout,” December 14, 2011; BSEE public offshore energy safety forum, May 22, 2012.
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industry permits, DWOPs, and industry standards with which operators already comply.

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Impacts that 

exist as part of the baseline were not considered costs or benefits of the proposed rule. Specifically, the 

analysis excluded activities or capital investments that are required by existing regulations or as 

conditions for permit or DWOP approval. The analysis also excluded impacts resulting from the

incorporation of industry standards with which operators already comply. Thus, the cost analysis 

evaluates only activities and capital investments required by the proposed rule that represent a change 

from the baseline. 

This section provides an overview of the analysis of costs, benefits, and transfers, as well as the

assumptions used in the analysis. The methodology for the costs and benefits analysis is described in 

more detail in subsequent sections. BSEE requests comment on the analysis, including potential sources 

of data or information on the benefits and costs of the proposed rule.

a. Costs

Section 5 below outlines how we quantified and monetized the potential costs of the proposed rule. 

It identifies all of the provisions that would result in increased labor requirements or capital investments 

for industry or costs to BSEE. In addition to the new regulatory requirements, we also considered the 

time required of industry staff to read and familiarize themselves with the new regulation. For the 

purpose of transparency, we include footnotes presenting the information on data inputs and the 

details of the cost calculations for each rule provision. 

 

3 BSEE considers compliance with permits, DWOPs, and industry standards to be “self-implementing,” as addressed 

in Section E.2 of OMB Circular A-4, “Regulatory Analysis” (2003), and thus includes these costs in the baseline for 

the economic analysis. Each industry standard comes from a committee of industry members who develop and vet 

each of the provisions written in the standards. We are not aware of industry standards that some operators do 

not follow.
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The analysis covers 10 years (2015 through 2024) to ensure it encompasses the significant costs and 

benefits likely to result from the proposed rule. A 10-year analysis period was used for this analysis 

because of the uncertainty associated with predicting industry’s activities and the advancement of 

technical capabilities beyond 10 years. The regulated community itself finds it challenging to engage in

business modeling beyond a 10-year time frame due to market volatility around oil pricing. Over time, 

the costs associated with a particular new technology may drop because of various supply and demand 

factors, causing the technology to be adopted more broadly. In other cases, an existing technology may 

be replaced by a lower-cost alternative as business needs drive technological innovation. Extrapolating 

costs and benefits beyond this 10-year time frame would produce more ambiguous results and 

therefore be disadvantageous in determining actual costs and benefits likely to result from this 

proposed rule. BSEE concluded that this 10-year analysis period provides the best overall ability to 

forecast costs and benefits likely to result from this proposed rule. To summarize the costs of specific 

provisions, we present the estimated average annual cost as well as 10-year discounted totals to 

estimate the present value of the costs. In accordance with OMB guidance on conducting regulatory

analysis (OMB Circular A-4, “Regulatory Analysis,” 2003), we used discount rates of 3 and 7 percent to 

calculate the discounted net present value of the proposed rule.

BSEE is considering requiring operators to install technology capable of severing any components of 

the drill string (excluding drill bits) within 10 years of the effective date of the rule. However, this 

provision’s important costs are inherently difficult to quantify or monetize given available data. For 

example, the identification of impacts potentially caused by failures to comply with this potential 

provision would require highly speculative assumptions principally because the impacts of such 

compliance failures could range from record-keeping violations to full well-bore discharges from 
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submerged OCS lands situated in deep water.4 Additionally, to the extent such risks exist, their

magnitude is unknown. For these reasons, BSEE is unable to monetize or quantify these costs. BSEE is 

aware of at least one candidate technology that is currently being evaluated and believes that there are 

other possible innovative technologies that may be available to accomplish these objectives within the 

time horizon pertinent to this provision. As also discussed in the preamble to the proposed rule, BSEE 

requests comments on associated costs related to this potential provision. 

b. Benefits

Section 6 below presents the data, methodology, and results of the benefits analysis. We quantified 

and monetized the potential benefits of the proposed rule, including time savings, reduction in oil spills, 

and reduction in fatalities. We estimated the benefits derived from time savings associated with 

proposed section 250.737(d)(10) of the proposed rule, which would streamline the BOP testing. We 

also estimated time-savings benefits associated with a change in the required frequency of BOP 

pressure testing under Alternative 2, which would reduce the number of required BOP pressure tests 

per year. In addition, we estimated the benefits derived from the reduction in oil spills and fatalities 

using the incident-reducing potential of the proposed rule as a whole. 

We calculated the benefits under various risk-reduction scenarios, which allowed us to determine 

the cost-effectiveness of the proposed rule (i.e., whether the benefits justified the costs) depending on 

the percentage of potential oil spills and number of fatalities potentially prevented. In addition, we 

conducted sensitivity analysis on the price of a barrel of oil to reflect recent price fluctuations. Similar to

 

4

For example, any approximation of cost would incorporate catastrophic spills such as the Deepwater Horizon

incident. The cost to BP of cleanup operations for the Deepwater Horizon incident has been estimated at more 

than $14 billion. In addition to cleanup costs, BP has paid over $14 billion to Federal, State, and local governments 

as well as private parties for economic claims and other expenses. Source: Ramseur, J.L., Hagerty, C.L. 2014. 

“Deepwater Horizon Oil Spill: Recent Activities and Ongoing Developments,” Congressional Research Office. 

Available at: http://www.fas.org/sgp/crs/misc/R42942.pdf.
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the costs analysis, we estimated the potential benefits over a 10-year study period (2015 through 2024). 

The benefits are presented as 10-year discounted totals, that is, the present value of the benefits. 

c. Transfers

We did not identify any transfer payments associated with the proposed rule. Transfer payments, as 

defined by OMB Circular A-4, “Regulatory Analysis,” (2003) are payments from one group to another 

that do not affect total resources available to society. 

d. Data inputs

We estimated costs and benefits presented in this document using various data inputs. Some of 

these data inputs were common to many of the calculations, including the assumptions about affected 

population, wage rates and loaded wage factors, and daily rig operating costs, as explained below.

i. Affected population

We estimated that a total of 90 rigs would be affected by the proposed rule, including 40 subsea 

BOP rigs and 50 surface BOP rigs, based on the current number of operational rigs on the OCS. We also 

estimated that 320 wells are drilled per year with an average of three wells per rig. Due to the 

fluctuating nature of activity on the OCS, for the purposes of analysis we assumed that the number of 

operating wells and rigs would remain constant over the 10-year analysis period. BSEE seeks comment 

on whether these estimates are accurate.

ii. Wage rates and loaded wage factors

Many of the calculations in this analysis used wage rates for OCS oil and gas or BSEE employees. We

estimated average industry wage rates for the following labor categories: mid-level industry engineer,

administrative staff, rig crew staff (e.g., roughneck, floorman, tool-pusher, subsea engineer), and 
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technician. We estimated the average hourly wage rate of $62.24 for a mid-level industry engineer 

based on the median wage rate for a petroleum engineer in the United States as reported by the Bureau 

of Labor Statistics (BLS). We based the average hourly wage rate of $21 for an administrative staff on 

the wage rate for a clerical employee provided in BSEE’s Supporting Statement A (BSEE Production 

Safety Systems). We estimated the average hourly wage rates of $40 for a rig crew staff person and a 

technician based on BSEE’s knowledge of the industry.

We also estimated the average wage rates for BSEE personnel for a mid-level BSEE engineer and for 

clerical staff. We estimated the average hourly wage rate for a mid-level BSEE engineer to be $41.52 

using data from the OPM: GS-12, step 5 average wage rate for the Houston metropolitan statistical area 

and the parishes of Jefferson, Lake Charles, and Houma in Louisiana. We estimated the average hourly 

wage rate for a clerical staff to be $22.41 using OPM data by averaging the GS-7, step 5 wage rates for 

the Houston metropolitan statistical area and for the rest of the United States. 

To account for employee benefits, we multiplied average hourly wage rates by an appropriate 

loaded wage factor to generate average hourly compensation rates. For the OCS industry, we used a 

private sector loaded wage factor of 1.42 derived from the 2012 BLS index for salary and benefits. For 

BSEE positions, we used a Federal loaded wage factor of 1.69 derived from a U.S. Department of Labor 

analysis of overhead costs (in the absence of a similar estimate for BSEE).5 We multiplied the average 

hourly wage rates by the appropriate loaded wage factor to estimate the following average hourly 

compensation rates:

 $88.38 for a mid-level industry engineer; 

 $29.82 for an industry administrative staff; 

 

5 The 1.69 index is derived by using BLS index for salary and benefits plus the Department of Labor’s analysis of 

overhead costs averaged over all employees of the agency.
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 $56.80 for an industry rig crew staff; 

 $56.80 for an industry technician; 

 $70.17 for a mid-level BSEE engineer; and 

 $37.87 for a BSEE clerical staff.

iii. Daily rig operating costs

Some requirements in the proposed rule affect rig operations. To monetize the impacts of these 

requirements, we estimated the daily rig operating costs for affected rigs. Based on input from BSEE 

and industry subject matter experts, we assumed that subsea BOP rigs have a daily rig operating cost of 

$1 million and surface BOP rigs have a daily rig operating cost of $200,000. We recognize that these 

figures can fluctuate and thus have chosen estimates that reflect the average daily rig operating costs

for those with surface and subsea BOPs (i.e., $200,000 and $1 million, respectively6). BSEE requests 

comment on these values for consideration at the Final Rule stage. For the purposes of the analysis, we

assumed that the daily rig operating costs remain constant over the 10-year analysis period.

5. Section-by-section analysis of costs

The economic analysis presented in this document evaluated the expected impacts of the proposed 

rule compared to the baseline (i.e., current practice in accordance with existing BOP regulations, 

industry permits, DWOPs, and API industry standards with which industry already complies). Alternative 

2 results in a time-savings benefit to industry but no additional costs to industry, and thus the costs 

presented below are the same for Alternatives 1 and 2. The following proposed requirements would

result in a change from the baseline:

 

6 BSEE based the daily rig operating costs in part upon industry listings of rig day rates (see, e.g., 

http://www.rigzone.com/data/dayrates/), consultation with the Bureau of Ocean Energy Management 

economists, and review of previously approved rates in published rulemakings. We assume that the daily cost 

estimate includes both the daily operating costs of the rig and of the personnel that support those daily activities. 

BSEE is inviting comments on those cost estimates and assumptions.
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(a) Additional information in the description of well drilling design criteria;

(b) Additional information in the drilling prognosis; 

(c) Prohibition of a liner as conductor casing; 

(d) Additional capping stack testing requirements; 

(e) Additional information in the Application for Permit to Modify (APM) for installed packers; 

(f) Additional information in the APM for pulled and reinstalled packers; 

(g) Rig movement reporting; 

(h) Fitness requirements for Mobile Offshore Drilling Units (MODUs) and lift boats; 

(i) Foundation requirements for MODUs and lift boats; 

(j) Monitoring of well operations with a subsea BOP; 

(k) Additional documentation and verification requirements for BOP systems and system 

components; 

(l) Additional information in the Application for Permit to Drill (APD), APM, or other submittal for 

BOP systems and system components; 

(m) Submission by the operator of a Mechanical Integrity Assessment Report completed by a BSEEapproved verification body;

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(n) New surface BOP system requirements; 

 

7 The approved verification organization would have to submit documentation for approval by BSEE describing the 

organization’s applicable qualification and experience. See discussion on Third-party Verification in the NPRM for 

further information.
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(o) New subsea BOP system requirements; 

(p) New surface accumulator system requirements; 

(q) Chart recorders;

(r) Notification and procedures requirements for testing of surface BOP systems;

(s) Alternating BOP control station function testing; 

(t) Remote operated vehicle (ROV) intervention function testing; 

(u) Autoshear, deadman, and emergency disconnect system (EDS) function testing on subsea BOPs;

(v) Approval for well control equipment not covered in Subpart G;

(w) Breakdown and inspection of BOP system and components;

(x) Additional recordkeeping for real-time monitoring; and 

(y) Industry familiarization with the new rule.

These proposed requirements and their associated costs to industry and government are presented 

in the sections that follow.

a. Additional information in the description of well drilling design criteria

Section 250.413(g) in the proposed rule would require information on the equivalent circulating 

density (ECD) to be included in the description of the well drilling design criteria. The ECD is an 

important parameter in avoiding fracturing the formation or compromising the casing shoe integrity,

which could lead to erratic pressures and uncontrolled flows (e.g., formation kicks) emanating from a 
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well reservoir during drilling. This information is necessary to better review the well drilling design and 

drilling program.

The requirement to include information on the ECD in the well drilling design criteria would result in 

increased labor costs for industry. We calculated the annual industry labor cost associated with this 

new requirement by multiplying the time required per well to include the additional information in the 

well drilling criteria by the average hourly compensation rate for the staff most likely to complete this 

task. We then multiplied this product by the expected number of wells drilled per year, resulting in an 

estimated annual labor cost to industry for this documentation requirement of $28,282.

8 No additional 

costs to BSEE are expected as a result of this proposed requirement.

b. Additional information in the drilling prognosis

Section 250.414 would require industry to provide additional information in the drilling prognosis.

New paragraph (j) would require the drilling prognosis to identify the type of wellhead system to be 

installed with a descriptive schematic, which should include pressure ratings, dimensions, valves, load 

shoulders, and locking mechanism, if applicable. This information would provide BSEE with data to 

reference during the approval process and would enable industry and BSEE to confirm that the wellhead 

system is adequate for the intended use. 

The requirement to include additional information in the drilling prognosis would result in increased

annual labor costs to industry. BSEE considers the additional information required for the drilling 

prognosis (submitted as part of the APD) to be readily available. We calculated the annual labor cost for 

 

8 We assumed that industry staff (mid-level engineer) would spend one hour per well to include the additional

information in the well drilling design criteria. Industry already complies with this new requirement as part of its

design practice for most wells drilled. We assumed that this requirement would result in a new cost for all wells 

drilled per year (320). We multiplied the number of industry staff hours per well by the average hourly 

compensation rate for a mid-level industry engineer ($88.38) and the average number of wells drilled per year to 

obtain an average annual labor cost to industry of $28,282 (1 x $88.38 x 320).
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this activity by multiplying the time required to gather and document the information by the average 

hourly compensation rate of the staff most likely to complete this task. We then multiplied the product 

of this calculation by the estimated number of wells drilled per year, resulting in an estimated annual 

labor cost to industry for this documentation requirement of $7,070.

9

 No additional costs to BSEE are 

expected as a result of this proposed requirement.

c. Prohibition of a liner as conductor casing

Section 250.421(f) would be revised to no longer allow a liner to be installed as conductor casing. 

This would ensure that the drive pipe is not exposed to wellbore pressures during drilling in subsequent 

hole sections. 

This provision would result in an annual equipment and labor cost to industry for wells that are 

currently allowed to use a liner as conductor casing. We multiplied the average cost of the casing joints 

and wellhead per well by the number of affected wells in order to calculate annual equipment 

installation costs. To calculate the associated annual labor costs, we multiplied the time required to 

install the equipment per well by the daily labor cost of rig crew time and by the number of wells on 

which the equipment must be installed. We then summed the equipment and labor costs to estimate 

the average annual equipment and labor cost to industry for this requirement of $795,000.

10

 No 

additional costs to BSEE are expected as a result of this proposed requirement.

 

9 We assumed that industry staff (a mid-level engineer) would spend 0.25 hours to include the additional 

information in the drilling prognosis for a well. We multiplied the number of industry staff hours per well by the 

average hourly compensation rate for a mid-level industry engineer ($88.38) and the average number of wells 

drilled per year (320) to obtain the average annual labor cost to industry of $7,070 (0.25 x $88.38 x 320).

10 We estimated that approximately one percent of drilled wells currently have a liner as conductor casing 

(approximately one percent of 320 wells, or three wells), based on input provided in submittals to BSEE. In order 

to calculate the average annual equipment costs, we assumed that the average cost of the casing joints and 

wellhead per well would be $65,000. We multiplied the equipment cost per well by the number of affected wells 

to yield an average equipment cost of $195,000 ($65,000 x 3). We assumed that industry staff (rig crew) would 

spend one day to install the new equipment on a well. We then multiplied the number of industry staff days per 
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d. Additional capping stack testing requirements

Section 250.462 would address source control and containment requirements. New paragraph 

(e)(1) would detail requirements for testing of capping stacks. New requirements include the function 

testing of all critical components on a quarterly basis and the pressure testing of pressure holding critical 

components on a bi-annual basis. Under current regulations, there is no testing requirement for 

capping stacks. These new requirements would help ensure that operators are able to contain a subsea 

blowout. 

These new testing requirements would result in new equipment and service costs to industry. We 

estimated the cost of testing for each capping stack and multiplied this cost by the total number of 

anticipated tests to be performed. These calculations resulted in annual compliance costs to industry 

associated with these requirements of $80,000.11 No additional costs to BSEE are expected as a result of 

these proposed requirements.

e. Additional information in the APM for installed packers

In Section 250.518, proposed paragraphs (e) and (f) would clarify requirements for installed packers

and bridge plugs and require additional information in the APM, including descriptions and calculations 

for determining production packer setting depth. These proposed new requirements would codify 

existing BSEE policy to ensure consistent permitting. It is expected that operators already comply with 

the proposed design specifications included in this section because this is the only established industry 

 

well by the average labor cost for a rig crew per day ($200,000) and by the number of affected wells to obtain an 

estimated average annual labor cost to industry of $600,000 ($200,000 x 3) for this requirement. Summing the 

equipment and labor costs yields a total average annual cost to industry of $795,000 for this requirement.

11 We assumed that the quarterly equipment and service costs of testing for capping stacks would be $5,000 per 

test. BSEE requests comments on the reasonableness of this estimate. Additionally, we assumed that 4 capping 

stacks would be tested quarterly (or a total of 16 annual tests performed). We multiplied the costs per test by the 

number of annual tests in order to determine a total annual equipment and service cost to industry of $80,000 (16 

x $5,000). We assumed that the required testing would occur at the storage site of the capping stack and we thus 

do not anticipate costs for time diverted from normal rig operations as a result of this requirement. 
20

standard. Thus, the depth setting calculation is the only requirement that would impose a new cost

beyond the baseline. The required calculations would be submitted for every well that is completed 

where tubing is installed.

The proposed requirement to include additional information in the APM would result in a labor cost

to industry and BSEE. To calculate the industry labor cost associated with this new requirement, we 

multiplied the time required to add the new descriptions and calculations to an APM by the average 

hourly compensation rate of the industry staff most likely to complete this task and by the number of 

wells with installed packers for which an APM would be submitted per year. To calculate the new 

annual labor cost to BSEE, we multiplied the time that BSEE would spend reviewing the new information 

in an APM by the average hourly compensation rate of the BSEE staff most likely to complete this task 

and by the number of wells with installed packers for which an APM would be submitted each year. We

estimated an average annual labor cost for this proposed documentation requirement of $5,745 to 

industry and $4,561 to BSEE.12

f. Additional information in the APM for pulled and reinstalled packers

In Section 250.619, proposed new paragraphs (e) and (f) would clarify requirements for pulled and 

reinstalled packers and bridge plugs and require additional descriptions and calculations in the APM 

regarding production packer setting depth. These proposed new requirements would codify existing 

 

12 We assumed that industry staff (a mid-level engineer) would spend 0.25 hours to include the additional 

information in the APM for a well. We assumed that APMs would be submitted for an average of 260 wells with 

installed packers per year. We multiplied the number of industry staff hours per well by the average hourly 

compensation rate for a mid-level industry engineer ($88.38) and by the estimated number of wells with installed 

packers for which an APM would be submitted per year to obtain an estimated average annual labor cost to 

industry of $5,745 (0.25 x $88.38 x 260). We assumed that BSEE staff (a mid-level engineer) would spend 0.25 

hours to review the additional information in the APM for a well. We multiplied the number of BSEE staff hours 

per well by the average hourly compensation rate for a mid-level BSEE engineer ($70.17) and by the estimated 

number of wells with installed packers for which an APM would be submitted per year to obtain an average annual 

labor cost to BSEE of $4,561 (0.25 x $70.17 x 260). 
21

BSEE policy to ensure consistent permitting. It is expected that operators already comply with the 

design specifications included in this section because this is the only established industry standard. The

depth setting description and calculation is the only proposed requirement that would impose a new 

cost beyond the baseline. The required calculations would be submitted for every well that is worked 

over where tubing is pulled and then reinstalled.

The proposed requirement to include additional information in the APM would result in a labor cost 

to industry and BSEE. To calculate the industry labor cost associated with this new requirement, we 

multiplied the time required to add the new descriptions and calculations to an APM by the average 

hourly compensation rate of the industry staff most likely to complete this task and by the number of 

wells with pulled and reinstalled packers for which an APM would be submitted per year. To calculate 

the new annual labor cost to BSEE, we multiplied the time that BSEE would spend to review the new 

information in an APM by the average hourly compensation rate of the BSEE staff most likely to 

complete this task and by the number of wells with pulled and reinstalled packers for which an APM 

would be submitted per year. These calculations resulted in average annual labor costs for this 

proposed documentation requirement of $22,316 to industry and $17,719 to BSEE.

13

 

13 We assumed that industry staff (a mid-level engineer) would spend 0.25 hours to include the additional 

information in the APM for a well. We also assumed that APMs would be submitted for an average of 1,010 wells 

with pulled and reinstalled packers per year. We multiplied the number of industry staff hours per well by the 

average hourly compensation rate for a mid-level industry engineer ($88.38) and the estimated number of wells 

with pulled and reinstalled packers for which an APM would be submitted per year to obtain an average annual 

labor cost to industry of $22,316 (0.25 x $88.38 x 1,010). We assumed that BSEE staff (a mid-level engineer) would 

spend 0.25 hours to review the additional information in the APM for a well. We multiplied the number of BSEE 

staff hours per well by the average hourly compensation rate for a mid-level BSEE engineer ($70.17) and by the 

estimated number of wells with pulled and reinstalled packers for which an APM would be submitted per year to 

obtain an average annual labor cost to BSEE of $17,719 (0.25 x $70.17 x 1,010).
22

g. Rig movement reporting

Section 250.712 would list requirements for reporting movement of rig units to the BSEE District 

Manager. Revised paragraph (a) would extend the rig movement reporting requirements to all rig units 

conducting operations covered under this subpart, including MODUs, platform rigs, snubbing units, lift 

boats, and coiled tubing units. Proposed paragraphs (c) and (e) are new and would require notification

if a MODU or platform rig is to be warm or cold stacked and when a drilling rig enters OCS waters. 

Paragraph (f) would be revised to clarify that, if the anticipated date for initially moving on or off 

location changes by more than 24 hours, an updated Movement Notification Report would be required. 

Currently, movement reports are only required for drilling operations, but the proposed rule would 

require operators to submit movement reports for other operations as well, including when rigs are 

stacked or enter OCS waters. These changes would allow BSEE to better anticipate upcoming 

operations, locate MODUs and platform rigs in case of emergency, and verify rig fitness. 

The proposed requirement to notify BSEE of rig unit movement would result in a labor cost to 

industry and BSEE. To calculate the industry labor cost, we multiplied the time required to submit a 

report by the average hourly compensation rate of the industry staff most likely to complete this task

and by the number of additional reports expected per year. To calculate the new annual labor cost to

BSEE, we multiplied the time that BSEE would spend to process each report by the average hourly 

compensation rate of the BSEE staff most likely to complete this task and by the number of additional 

reports expected per year. These calculations result in average annual labor costs for this proposed 

reporting requirement of $2,485 to industry and $3,156 to BSEE.

14

 

14 We assumed that industry staff (administrative) would spend five minutes (0.08 hours) to submit a movement 

report and that industry would submit an average of 1,000 movement reports per year as a result of the new 

requirement. We multiplied the number of industry staff hours per report by the average hourly compensation 

rate for an administrative staff ($29.82) and the average number of reports per year to obtain an average annual 
23

h. Fitness requirements for MODUs and lift boats

Proposed section 250.713(a) would add a requirement that operators provide fitness information 

for a MODU or lift boat for workovers, completions, and decommissioning. Operators must provide 

information and data to demonstrate the drilling unit’s capability to perform at the proposed drilling 

location. This information must include the most extreme environmental and operational conditions 

that the unit is designed to withstand, including the minimum air gap necessary for both hurricane and 

non-hurricane seasons. If sufficient environmental information and data are not available at the time 

the APD or APM is submitted, the District Manager may approve the APD or APM but require operators

to collect and report this information during operations. Under this circumstance, the District Manager 

continues to have the right to revoke the approval of the APD or APM if information collected during 

operations show that the drilling unit is not capable of performing at the proposed location.

This proposed requirement would result in labor costs to industry and BSEE. To calculate the 

industry labor cost, we multiplied the time required to record and submit the report by the average 

hourly compensation rate of the industry staff most likely to complete this task and by the number of 

APMs per year. To calculate the BSEE labor cost, we multiplied the time that BSEE would spend to 

review the information by the average hourly compensation rate of the BSEE staff most likely to 

complete this task and by the number of APMs per year. These calculations resulted in average annual 

labor costs for this proposed reporting requirement of $44,190 to industry and $35,086 to BSEE.

15

 

labor cost to industry of $2,485 (0.0833 x $29.82 x 1,000). We assumed that BSEE staff (clerical) would spend five 

minutes (0.08 hours) to process a movement report. We multiplied the number of BSEE staff hours per report by 

the average hourly compensation rate for a clerical staff ($37.87) and by the average number of reports per year to 

obtain an average annual labor cost to BSEE of $3,156 (0.0833 x $37.87 x 1,000).

15 We assumed that industry staff (a mid-level engineer) would spend 0.5 hours per APM to provide the additional 

information and that an average of 1,000 APMs would be affected per year. We multiplied the number of industry 

staff hours per APM by the average hourly compensation rate for a mid-level industry engineer ($88.38) and by the 

estimated number of APMs affected per year to obtain an average annual labor cost to industry of $44,190 (0.5 x 
24

i. Foundation requirements for MODUs and lift boats

Proposed section 250.713(b) would introduce a requirement for foundation requirements for 

workovers, completions, and decommissioning. Operators must provide information to show that sitespecific soil and oceanographic conditions are capable of supporting the proposed rig unit. If operators

provide sufficient site-specific information in the Exploration Plan (EP), Development and Production 

Plan (DPP), or Development Operations Coordination Document (DOCD) submitted to the Bureau of 

Ocean Energy Management (BOEM), operators may reference that information. Current regulations 

state that the District Manager may require operators to conduct additional surveys and soil borings 

before approving the APD, if additional information is needed to make a determination that the 

conditions are capable of supporting the rig unit or equipment installed on a subsea wellhead. For 

moored rigs, operators must submit a plan of the rigs’ anchor patterns approved in the EP, DPP, or 

DOCD in the APD or APM.

This proposed requirement would result in labor costs to industry and BSEE. To calculate the 

industry labor cost, we multiplied the time required to record and report information by the average 

hourly compensation rate of the industry staff most likely to complete this task and by the number of 

APMs per year. To calculate the BSEE labor cost, we multiplied the time that BSEE would spend to 

review the information by the average hourly compensation rate of the BSEE staff most likely to 

complete this task and by the number of APMs per year. These calculations resulted in average annual 

labor costs for this proposed reporting requirement of $44,190 to industry and $35,086 to BSEE.

16

 

$88.38 x 1,000). We assumed that BSEE staff (a mid-level engineer) would spend 0.5 hours to review the 

information. We multiplied the number of BSEE staff hours per APM by the average hourly average hourly 

compensation rate for a mid-level BSEE engineer ($70.17) and by the average number of APMs affected per year to 

obtain an average annual labor cost to BSEE of $35,086 (0.5 x $70.17 x 1,000).

16 We assumed that industry staff (a mid-level engineer) would spend 0.5 hours per APM to provide the additional 

information and that an average of 1,000 APMs would be affected per year. We multiplied the number of industry 
25

j. Real-time monitoring of well operations 

Proposed section 250.724 is a new section that would list requirements for:

(1) Monitoring well operations on rigs that have a subsea BOP, floating facilities using surface BOPs,

and rigs operating in high pressure and high temperature (HPHT) reservoirs, and 

(2) Storing data at a designated onshore location, as listed in the APD or APM.

In order to comply with this section, industry would incur annual equipment and labor costs 

associated with gathering, recording, transmitting, and storing data. To calculate the costs associated 

with these new requirements, we estimated the average equipment and labor cost per day to perform 

continuous monitoring (based on BSEE’s interactions with the industry and review of the equipment 

involved), and the average amount of time that a rig would engage in well operations per year (and 

would thus be subject to this monitoring requirement). We assumed that this type of service mostly 

lends itself to a day rate, and multiplied the cost per day to perform the monitoring by the number of 

days per year that the rig would be engaged in well operations. We then multiplied the product by the 

number of rigs that would incur this new cost. This calculation resulted in average annual equipment 

and labor costs for this monitoring requirement of $40.5 million to industry.17 No additional costs to 

BSEE are expected as a result of this requirement. BSEE requests information related to the cost 

associated with these proposed real-time monitoring requirements.

 

staff hours per APM by the average hourly compensation rate for a mid-level industry engineer ($88.38) and by the 

estimated number of APMs affected per year to obtain an average annual labor cost to industry of $44,190 (0.5 x 

$88.38 x 1,000). We assumed that BSEE staff (a mid-level engineer) would spend 0.5 hours to review the 

information. We multiplied the number of BSEE staff hours per APM by the average hourly average hourly 

compensation rate for a mid-level BSEE engineer ($70.17) and by the average number of APMs affected per year to 

obtain an average annual labor cost to BSEE of $35,086 (0.5 x $70.17 x 1,000). 

17 We assumed that the average costs per day and the average operational days per year would be the same for 

rigs with subsea BOPs and rigs operating in HPHT reservoirs. We assumed that a rig operates for 270 days per year 

(three operations per year and three months per operation) and that the average cost per day to perform 

continuous monitoring would be $5,000, including equipment and labor. BSEE regulatory staff, in conjunction with 
26

k. Additional documentation and verification requirements for BOP systems and system 

components

Section 250.730 would list general requirements for BOP systems and system components and add

new documentation and verification requirements. Proposed section 250.730(d) would require that 

quality management systems for the manufacture of BOP stacks be certified by an entity that meets the 

requirements of International Organization for Standardization (ISO) 17011. Additionally, operators may 

submit a request for approval of equipment manufactured under quality assurance programs other than 

API Specification Q1, and BSEE may approve such a request provided the operator would submit 

relevant information about the alternative program. In regard to new paragraph (d), we were unable to 

determine the additional cost associated with the required certification by an entity that meets the 

requirements of ISO 17011 for quality management. BSEE requests feedback from the public or industry 

on estimates for this cost. Additionally, new paragraph (d) would result in labor costs to industry 

associated with submitting requests for alternative programs. 

We multiplied the hourly compensation rate for the industry staff most likely to complete this work 

by the amount of time expected to submit the request and then multiplied this annual cost by the total 

number of wells that would incur costs. These calculations resulted in an annual cost to industry of 

$1,768 associated with these submissions. This new requirement would also result in labor costs to 

BSEE associated with processing these requests. We multiplied the hourly compensation rate for the 

BSEE staff most likely to complete this work by the amount of time expected to process the request and 

 

BSEE engineers who interact with industry on a regular basis and review the equipment, estimated this cost. BSEE 

requests comments on the reasonableness of this estimate. We also estimated that half of the rigs with subsea 

BOPs already conduct this monitoring. Thus, only half of rigs with subsea BOPs (20 rigs) would incur a new cost to 

comply with these requirements. Similarly, we assumed that 10 of the rigs operating in HPHT reservoirs would 

incur a new cost to comply with these requirements. We multiplied the time that the rig is operational per year by 

the average cost per day to perform monitoring and by the number of affected rigs to obtain an average annual 

equipment and labor cost to industry of $40,500,000 (270 x $5,000 x 30).
27

then multiplied this annual cost by the total number of wells that would incur costs. These calculations 

resulted in an annual cost to BSEE of $702 associated with these submissions.18 BSEE was unable to

estimate the cost for the requirement that a certification entity meet the requirements of ISO 17011 for 

quality management systems for BOP stacks. BSEE requests feedback related to the costs associated 

with these proposed requirements for BOP systems and system components.

Proposed section 250.731(c) would require verification by a BSEE-approved verification organization 

of specified aspects of equipment design, equipment tests, shear tests, and pressure integrity tests; all 

certification documentation must be made available to BSEE. The requirements laid out in section 

250.731(c) regarding certification for BOP systems and systems components would result in new 

equipment and service costs to industry. We estimated a one-time cost to industry for equipment and 

service and multiplied the cost by the number of wells that would incur this new cost. This calculation 

resulted in one-time equipment and service costs for this proposed certification requirement of $12.8

million to industry.19

Proposed section 250.732(c) would require a comprehensive review by a BSEE-approved verification 

organization of BOP and related equipment being proposed for use in high temperature and high 

pressure service. The requirements in new section 250.732(c) surrounding a review of BOP systems and 

systems components in HPHT conditions would result in new annual costs to industry. To calculate the 

 

18 We assumed that a mid-level industry engineer would spend 2 hours to submit a request. We multiplied the 

compensation rate for a mid-level industry engineer ($88.38) by the number of hours to complete the submission 

and then multiplied this annual cost by the total number of wells (10) to determine the annual cost to industry of 

$1,768 (2 × $88.38 × 10). We assumed that a mid-level BSEE engineer would spend 1 hour to process a request. 

We multiplied the compensation rate for a mid-level BSEE engineer ($70.17) by the number of hours to complete 

the task and then multiplied this cost by the total number of wells (10) to determine the annual cost to industry of 

$702 (1 × $70.17 × 10).

19 We assumed that the equipment and service costs per well would be $40,000. We estimated that 320 wells

would incur a new cost to comply with these requirements. We multiplied the one-time cost of equipment and 

service by the number of affected wells to obtain one-time equipment and service costs to industry of $12,800,000

($40,000 x 320).
28

costs associated with the required verifications of BOP system and components by BSEE-approved 

verification organizations, we estimated the annual cost for performing the verification and multiplied 

the annual cost by the number of wells that would incur this new cost. This calculation resulted in 

annual equipment and labor costs for this proposed verification requirement of $500,000 to industry.20

l. Additional information in the APD, APM, or other submittal for BOP systems and system 

components

Section 250.731 lists the descriptions of BOP systems and system components that must be included 

in the applicable APD, APM, or other submittal for a well. Revised paragraph (a) would require the 

submittal to include descriptions of the rated capacities for the fluid-gas separator system, control fluid 

volumes, control system pressure to achieve a seal of each ram BOP, number of accumulator bottles and 

bottle banks, and control fluid volume calculations for the accumulator system. 

New paragraph (e) would require a listing of the functions with sequences and timing of autoshear, 

deadman, and EDS for subsea BOPs. Paragraph (b) would add schematic drawing requirements, 

including labeling for the control system alarms and set points, control stations, and riser cross section. 

For subsea BOPs, surface BOPs on floating facilities, and BOPs operating under HPHT conditions, new

paragraph (f) would require submission of a certification that a Mechanical Integrity Assessment report 

has been submitted within the past 12 months. New paragraphs (c) and (d) would include a change in 

required certifications; the paragraphs would require submission of certification from a BSEE-approved 

verification organization (rather than a “qualified third party”) that:

(1) Test data demonstrate that the shear ram(s) will shear the drill pipe at the water depth, and 

 

20 We assumed that the annual costs would be $50,000, including equipment and service. We estimated that 10 

wells would incur a new cost to comply with these requirements. We multiplied the annual cost of equipment and 

service by the number of affected wells to obtain an average annual equipment and service cost to industry of 

$500,000 ($50,000 x 10).
29

(2) The BOP has been designed, tested, and maintained to perform at the most extreme anticipated 

conditions, and 

(3) That the accumulator systems have sufficient fluid to function the BOP system without 

assistance from the charging system. 

These proposed requirements are necessary to enhance BSEE’s review of the BOP system and its 

emergency systems, which were the topic of many of the recommendations of the Deepwater Horizon 

incident investigation teams. Additionally, these requirements are necessary to help BSEE verify that 

the accumulator system would have sufficient fluid to function the BOP system without assistance from 

the charging system.

The proposed requirements to provide additional documentation about the BOP system and system 

components in the APD, APM, or other submittal would result in labor costs to industry and BSEE. To 

calculate the industry labor cost associated with these new requirements, we multiplied the estimated 

time it would take to document the required information in an APD, APM, or other submittal by the 

average hourly compensation rate of the industry staff most likely to complete this task. We then 

multiplied the product by the estimated number of wells drilled per year. 

Likewise, to calculate the new annual labor cost to BSEE, we multiplied the time that BSEE would 

spend to process each submittal by the average hourly compensation rate of the BSEE staff most likely 

to complete this task and by the estimated number of wells drilled per year. These calculations resulted 

in average annual labor costs for this documentation requirement of $28,282 to industry and $22,455 to 

BSEE.

21 BSEE was unable to locate any applicable data or comparative cost estimates and therefore was 

 

21 We assumed that industry staff (a mid-level engineer) would spend one hour to include additional information in 

the APD, APM, or other submittal for a well. We multiplied the number of industry staff hours per well by the 

average hourly compensation rate for a mid-level industry engineer ($88.38) and by the average number of wells 
30

unable to determine a definitive cost estimate for the annual costs to industry associated with the 

change in requiring use of BSEE-approved verification organizations referenced in new paragraph

250.732(a). BSEE requests information concerning costs associated with the proposed use of BSEEapproved verification organizations. 

m. Submission of a Mechanical Integrity Assessment Report 

Proposed section 250.732(d) would include new requirements on the submission of a Mechanical 

Integrity Assessment Report on certain BOP stack and systems. New paragraph (d) would outline the 

requirements for this report, which must be completed by a BSEE-approved verification organization

and submitted by the operator for operations that would require the use of a subsea BOP, a surface BOP 

on a floating facility, or a BOP that is being used in HPHT operations. New section 250.731(f) would 

require certification stating that this report be submitted to BSEE prior to beginning any operations (to 

include maintenance and repairs) involving these BOPs. The third-party reporting would enhance the 

BSEE review and permitting process and ensure that BSEE is aware of repairs or other changes to the 

operating BOPs.

These reporting requirements would result in new capital costs to industry and new labor costs to 

industry and BSEE associated with the submission and review of reports. To calculate the capital costs 

to industry of submitting Mechanical Integrity Assessment reports, we multiplied the annual capital cost 

of submitting the report by the estimated number of wells that would be affected. This calculation 

resulted in annual capital costs for reporting of $4.8 million to industry. To calculate the industry labor 

 

drilled per year (320) to obtain an average annual labor cost to industry of $28,282 (1 x $88.38 x 320). We

assumed that BSEE staff (a mid-level engineer) would spend one hour to review the additional information in the 

APD, APM, or other submittal for a well. We multiplied the number of BSEE staff hours per submittal by the 

average hourly compensation rate for a mid-level BSEE engineer ($70.17) and by the average number of wells 

drilled per year to obtain an average annual labor cost to BSEE of $22,455 (1 x $70.17 x 320).
31

cost, we multiplied the time required to submit a report by the average hourly compensation rate of the 

industry staff most likely to complete this task and then multiplied this annual cost by the number of 

additional reports expected per year. 

To calculate the new annual labor cost to BSEE, we multiplied the time that BSEE would spend to 

process each report by the average hourly compensation rate of the BSEE staff most likely to complete 

this task and then multiplied this annual cost by the number of additional reports expected per year. 

These calculations result in average annual labor costs for this reporting requirement of $14,141 to 

industry and $11,228 to BSEE. We then summed the labor and reporting costs to industry to obtain an 

annual cost to industry of $4.8 million and annual costs to BSEE of $11,228.

22

 

n. New surface BOP requirements

Section 250.733 would include new requirements for surface BOP stacks. Proposed new paragraph 

(e) would require that hydraulically operated locks are installed with surface BOPs. 

BSEE recognizes that the equipment and labor costs associated with the proposed surface BOP stack

requirements would be case-specific. BSEE was unable to locate any applicable data or comparative 

cost estimates and therefore was unable to determine a definitive cost estimate for the labor and 

equipment costs to industry associated with the installation of hydraulically operated locks. BSEE 

 

22 For capital costs, we assumed an annual cost of $15,000 for each well which results in an annual capital cost of 

$4.8 million ($15,000 x 320). For labor costs, we assumed that industry staff (a mid-level engineer) would spend a 

half hour to prepare a report for each well. We multiplied the number of industry staff hours per well by the 

average hourly compensation rate for a mid-level industry engineer ($88.38) and by the average number of wells 

drilled per year (320) to obtain an average annual labor cost to industry of $14,141 (0.5 x $88.38 x 320). We

assumed that BSEE staff (a mid-level engineer) would spend a half hour to receive and review the report for each

well. We multiplied the number of BSEE staff hours per submittal by the average hourly compensation rate for a 

mid-level BSEE engineer ($70.17) and by the average number of wells drilled per year to obtain an average annual 

labor cost to BSEE of $11,228 (0.5 x $70.17 x 320).
32

requests information concerning costs associated with these proposed new requirements for BOP 

stacks. 23

o. New subsea BOP system requirements

Section 250.734 would include new requirements for subsea BOP systems, based on 

recommendations from the Deepwater Horizon incident investigations. Revised paragraph (a) would 

require that BOPs be equipped with two shear rams and outlines the requirements for the shear rams. 

BSEE is also considering requiring installation of technology that is capable of severing any components 

of the drill string (excluding drill bits) within 10 years of the publication date of the rule. 

BSEE recognizes that the equipment costs associated with these new subsea BOP system

requirements would be case-specific. For example, the costs would depend on the age of the rig and 

BOP system, the BOP system type, and the size of the rig, among other factors. In order to estimate the 

cost to industry associated with these new shear ram requirements, we multiplied the estimated cost of 

compliance per rig by the estimated number of affected rigs. API Standard 53 includes the requirements 

under paragraph (a) for all rigs with the exception of moored rigs. We multiplied the cost of compliance 

for a moored rig by the number of moored rigs in order to calculate the one-time equipment costs of 

$50 million for this requirement.

24 BSEE requests comments concerning the costs of compliance with 

these new requirements.

 

23 BSEE subject matter experts estimate this cost to be nominal and would not significantly alter the estimate. It is 

BSEE’s understanding that this type of equipment usually comes standard on new orders and the costs associated 

within this equipment are a part of the entire component and not a separate cost. 

24 We estimated that 5 moored rigs would be affected and that the one-time capital compliance costs associated 

with these shear ram requirements would be $10,000,000 per rig. To calculate the total one-time capital costs to 

industry, we multiplied the equipment cost per rig by the number of affected rigs to yield a total cost to industry of 

$50,000,000 ($10,000,000 x 5).
33

p. New surface accumulator system requirements

Section 250.735(a) would list new requirements for the surface accumulator system of a BOP. The 

surface accumulator system must operate all BOP functions against MASP with at least 200 pounds per 

square inch remaining on the bottles above the precharge pressure without use of the charging system. 

Revised paragraph (a) would detail additional surface accumulator requirements regarding fluid capacity 

and accumulator regulators. This revision would ensure that the BOP system is capable of operating all 

critical functions.

The requirement that the surface accumulator system operate all functions for all BOP systems

would result in a one-time equipment and labor cost to industry. The equipment cost would result from 

the installation of additional equipment necessary to meet the requirement. To calculate the

equipment cost, we multiplied the average cost for equipment per rig by the total number of rigs. For 

the labor cost, we multiplied the time required per rig to install the equipment by the average hourly 

compensation rate of the industry staff most likely to do the work and by the total number of rigs. This 

calculation resulted in a one-time cost to industry of $2.8 million.

25 No additional costs to BSEE are 

expected as a result of this proposed requirement.

q. Chart recorders

 

25 We assumed that the average cost of the additional equipment needed to meet the requirements would be 

$25,000 per rig. It is unknown how many rigs already comply; thus, we made a assumption that all rigs would be 

affected (90 rigs). We multiplied the equipment cost per rig by the number of affected rigs to obtain an estimated

one-time equipment cost of $2.25 million ($25,000 x 90). For the one-time labor cost to industry, it was estimated

that one to three days of industry time would be required per rig to install the new equipment. We assumed that 

industry staff (a mid-level engineer) would spend 72 hours to install the new equipment on a rig. We multiplied 

the number of industry staff hours per rig by the average hourly compensation rate for a mid-level industry 

engineer ($88.38) and by the number of affected rigs to obtain an estimated one-time labor cost to industry of 

$572,702 (72 x $88.38 x 90). Summing the equipment and labor costs resulted in a total one-time cost to industry 

of $2,822,708 for this requirement.
34

Section 250.737(c), which addresses BOP testing requirements, would introduce a requirement that 

each test must hold the required pressure for five minutes while using a four-hour chart. This chart 

would contain sufficient detail to show if a leak occurred during the test.

This proposed testing requirement would result in a one-time equipment and labor cost to industry. 

Industry would have to purchase the equipment (a chart recorder) to be able to comply with the testing 

requirement. To calculate the equipment cost, we multiplied the estimated cost of equipment per rig by 

the total number of rigs. To calculate the one-time labor cost to industry, we multiplied the time 

required per rig to install the chart recorder by the average hourly compensation rate of the industry 

staff most likely to complete this task and by the total number of rigs. This calculation resulted in a onetime cost to industry of $180,426.

26 No additional costs to BSEE are expected as a result of this proposed 

requirement.

r. Notification and procedures requirements for testing of surface BOP systems

Proposed section 250.737(d)(2) would expand notification and procedures requirements regarding 

the use of water to test a surface BOP system. These expanded notification and procedures 

requirements would result in increased labor costs to industry. To calculate the new annual labor cost 

to industry, we multiplied the hourly compensation rate for the industry staff most likely to complete 

this work by the amount of time expected to complete the submittals and then multiplied this annual 

cost by the total number of submittals. These calculations resulted in an annual cost to industry of 

$5,303 associated with these submissions. This new requirement would also result in labor costs to 

 

26 We assumed that each rig would require a chart recorder for an average cost of $2,000 per rig. We multiplied 

the average equipment cost per rig by the total number of rigs (90) to obtain an estimated one-time equipment 

cost to industry of $180,000 ($2,000 x 90). We assumed that industry staff (rig crew) would spend five minutes 

(0.08 hours) per rig to install the equipment. We multiplied the number of industry staff hours per rig by the 

average hourly compensation rate for a rig crew staff ($56.80) and by the total number of rigs to obtain an 

estimated one-time labor cost to industry of $426 (0.0833 x $56.80 x 90). Summing the equipment and labor costs 

resulted in a total one-time cost to industry of $180,426.
35

BSEE associated with processing these requests. We multiplied the hourly compensation rate for the 

BSEE staff most likely to complete this work by the amount of time expected to process the submittals

and then multiplied this annual cost by the total number of submittals.27 These calculations resulted in 

an annual cost to BSEE of $4,210 associated with these submissions. BSEE requests information related 

to the costs associated with this proposed expansion of notification and procedures requirements. 

s. Alternating BOP control station function testing

Section 250.737(d)(5) would expand the requirements for function testing of BOP control stations. 

It would require that the operator designate the BOP control stations as primary and secondary and 

function test of each station weekly. 

This proposed testing requirement would result in increased operating costs to industry. To 

calculate the annual operations costs associated with this requirement, we multiplied the time required 

to conduct the testing per rig by the daily rig operating cost and by the estimated number of rigs 

affected per year. Because subsea and surface BOPs have different daily rig operating costs, we

performed separate calculations for the costs for subsea and surface BOP rigs. We estimated an

increased annual operating cost to industry associated with this provision of $25 million.

28 BSEE 

 

27 We assumed that a mid-level industry engineer would spend 1 hour on a submittal as a result of these expanded 

requirements. We multiplied the compensation rate for a mid-level industry engineer ($88.38) by the number of 

hours to complete the submission and then multiplied this annual cost by the total number of submittals (60) to 

determine the annual cost to industry of $5,303 (1 × $88.38 × 60). We assumed that a mid-level BSEE engineer 

would spend 1 hour to process a submittal. We multiplied the compensation rate for a mid-level BSEE engineer 

($70.17) by the number of hours to complete the task and then multiplied this cost by the total number of 

submittals (60) to determine the annual cost to industry of $4,210 (1 × $70.17 × 60).

28 We assumed that testing would require 0.5 days per rig per year (one hour every week for three months). 

Because subsea and surface BOPs rigs have different daily rig operating costs, we performed separate calculations 

for the costs for subsea and surface BOP rigs. For subsea BOP rigs, we multiplied the time required to conduct the 

testing per rig by the daily rig operating cost for subsea BOP rigs ($1 million) and by the number of subsea BOP rigs 

(40) for an annual cost of $20 million for subsea BOP rigs (0.5 x $1 million x 40). For surface BOP rigs, we multiplied 

the time required to conduct the testing per rig by the daily rig operating cost for surface BOP rigs ($200,000) and 

by the number of surface BOP rigs (50) for an annual cost of $5 million for surface BOP rigs (0.5 x $200,000 x 50). 
36

requests information related to the costs associated with the proposed expansion of the testing criteria 

for BOP control station function testing.

t. ROV intervention function testing

Proposed section 250.737(d)(12) would include requirements for testing ROV intervention functions

to include testing and verifying the closure of all ROV intervention functions. The operator would have 

to test and verify closure of the selected ram.

This testing requirement would result in increased annual operating costs to industry. To calculate 

the annual operating costs, we multiplied the time required to conduct the testing per subsea BOP rig by 

the daily operating cost for a subsea BOP rig and by the estimated number of subsea BOP rigs affected 

per year. We estimated the annual increased operating cost to industry for this requirement to be

$416,667.

29 No additional costs to BSEE are expected as a result of this proposed requirement.

u. Autoshear, deadman, and EDS system function testing on subsea BOPs 

Proposed section 250.737(d)(13) would expand the requirements for function testing of autoshear, 

deadman, and EDSs on subsea BOPs. It would require the test procedures submitted for the BSEE 

District Manager’s approval to include schematics of the actual controls and circuitry of the system, the 

approved schematics of the BOP control system, and a description of how the ROV would be used

during the operation. It also outlines the requirements for the deadman system test, including a 

requirement that the testing must indicate the discharge pressure of the subsea accumulator system 

 

Summing the annual costs for subsea BOP rigs and surface BOP rigs resulted in a total annual increased operating 

cost to industry associated with this provision of $25 million.

29 We assumed that it would take five minutes per well to conduct the testing and that each subsea BOP rig has 

three wells, yielding a total time requirement of 15 minutes (0.0104 days) per rig. We multiplied the time diverted 

for testing per rig by the daily operating cost per subsea BOP rig ($1,000,000) and by the estimated number of 

subsea BOP affected per year (40) to obtain an annual increased operating cost to industry of $416,667 (0.0104

x40 x $1,000,000).
37

throughout the test. It would require that the blind-shear rams be tested to verify closure. The 

operator must document the plan to verify closure of the casing shear ram, if installed, as well as all test 

results. 

These proposed documentation and testing requirements would result in a one-time equipment 

cost and increased annual operating costs to industry. The OCS industry would incur a one-time 

equipment cost to purchase a sensing device to detect the discharge pressure during deadman system 

testing. We multiplied the average cost per rig of the sensing device by the estimated number of subsea 

BOP rigs required to comply. We assumed installation costs to be negligible because the sensing device 

would be installed as part of routine servicing. In order to calculate the annual operations cost, we 

multiplied the estimated time per subsea BOP rig required to comply with the document and testing 

requirements by the daily operating cost for a subsea BOP rig and by the estimated number of subsea 

BOP rigs affected per year. These calculations resulted in a one-time equipment cost to industry of 

$100,000 and an average annual increased operating cost to industry of $5 million.

30 No additional costs 

to BSEE are expected as a result of this proposed requirement.

v. Approval for well control equipment not covered in Subpart G

Proposed section 250.738 would describe the required actions for specified situations involving BOP 

equipment or systems. Paragraphs (b), (i), and (o) would include requirements for reports from 

verification organizations. Reports previously required to be prepared by a “qualified third party” under 

 

30 We assumed that the average cost of the sensing device would be $2,500 per rig. We multiplied the equipment 

cost by the total number of subsea BOP rigs (40) to obtain the one-time equipment cost to industry of $100,000 

($2,500 x 40). We assumed that it would take one hour per well to perform the testing and documentation tasks 

required by this provision per well and that each subsea BOP rig has three wells, for a total time requirement per 

subsea BOP of three hours (0.125 days). We also assumed that all subsea BOP rigs (40) would be affected. We 

multiplied the time diverted for testing by the daily operating cost per subsea BOP rig ($1,000,000) and by the 

estimated number of subsea BOP rigs affected per year to obtain an average annual increased operating cost to 

industry of $5 million (0.125 x $1,000,000 x 40).
38

these sections would be required to be prepared by a “BSEE-approved verification organization.”

Paragraph (m) would include a similar change and introduce a requirement that an operator request 

approval from the BSEE District Manager to use well control equipment not covered in Subpart G. The 

operator must submit a report from a BSEE-approved verification organization, as well as any other 

information required by the District Manager. 

This proposed approval request requirement would result in labor costs to industry and BSEE. In 

order to calculate the annual labor costs for industry, we multiplied the estimated time required to 

submit an approval request and BSEE-approved verification organization report by the average hourly 

compensation rate of the industry staff most likely to complete this task and by the estimated number 

of rigs that would require approval for well control equipment per year. For BSEE, we multiplied the 

estimated time to review the submissions by the average hourly compensation rate of the BSEE staff 

most likely to complete this task, and the estimated number of rigs for which an approval request and 

report would be submitted per year. These calculations resulted in average annual labor costs of $88 to 

industry and $70 to BSEE.

31 BSEE was unable to locate any applicable data or comparative cost 

estimates and therefore was unable to determine a definitive cost estimate for the annual costs to 

industry associated with the third-party verification. BSEE requests information concerning costs 

associated with the proposed third-party verification requirements.

 

31 We assumed that industry staff (a mid-level engineer) would spend 0.5 hours to submit an equipment approval 

request and report. We also assumed that industry would submit a request and report for an average of two 

deepwater rigs per year. We multiplied the number of industry staff hours per submission by the average hourly 

compensation rate for a mid-level industry engineer ($88.38) and the average number of submissions per year to 

obtain an average annual labor cost to industry of $88 (0.5 x $88.38 x 2). We assumed that BSEE staff (a mid-level 

engineer) would spend 0.5 hours to review a submission. We multiplied the number of BSEE staff hours per 

submission by the average hourly compensation rate for a mid-level BSEE engineer ($70.17) and by the estimated 

number of submissions per year to obtain an average annual labor cost to BSEE of $70 (0.5 x $70.17 x 2).
39

w. Breakdown and inspection of BOP system and components

Proposed section 250.739(b) would introduce a requirement for a complete breakdown and 

inspection of the BOP and every associated component every 5 years. During this complete breakdown 

and inspection, a BSEE-approved verification organization must document the inspection and any 

problems encountered. This BSEE-approved verification organization report must be available to BSEE 

upon request. This additional requirement is necessary to ensure that the components on the BOP stack 

would be regularly inspected. In the past, BSEE has, in some cases, seen components of BOP stacks go 

more than 10 years without this type of inspection.

This proposed inspection and documentation requirement would result in cost to industry

associated with generating reports by BSEE-approved verification organizations. To calculate this report

cost, we multiplied the estimated report cost per rig provided by subject matter experts by the number 

of reports completed per rig annually and by the estimated number of rigs in operation per year. 

Because subsea and surface BOPs differ in structure, they incur different costs to break down and 

inspect. In order to reflect these differences, we performed separate calculations for the costs for 

subsea and surface BOP rigs. We assumed that costs would be incurred in year 1 and year 6 of the 10-

year analysis period. These calculations resulted in a total cost to industry to obtain third-party reports

of $21.5 million32 during the year of inspection, which would occur once every 5 years or twice during 

the 10-year analysis period, for a total of $43 million.

 

32 For subsea BOP rigs, based on input from subject matter experts, we assumed that equipment and labor cost 

would be $350,000 per rig. We multiplied the total number of subsea BOP rigs (40) by the equipment and labor 

cost to obtain an inspection-year cost of $14 million (40 x $350,000) which occurs every five years for subsea BOP 

rigs. For surface BOP rigs, based on input from subject matter experts, we assumed that equipment and labor cost 

would be $150,000 per rig. We multiplied the total number of surface BOP rigs (50) by the equipment and labor 

cost to obtain an inspection-year cost of $7.5 million (50 x $150,000) which occurs every five years, for surface BOP 

rigs.
40

x. Additional recordkeeping for real-time monitoring

Proposed sections 250.740(a) and § 250.741(b) would introduce requirements for recordkeeping of

real-time monitoring data and other for well operation data. These additional records would require 

labor costs to industry. To calculate the annual labor costs for industry, we multiplied the estimated 

time required to keep real-time monitoring records per well by the average hourly compensation rate of 

the industry staff most likely to complete this task and by the estimated number of wells affected per 

year. These calculations resulted in average annual labor costs of $1,789 to industry.

33

 No additional 

costs to BSEE are expected as a result of these requirements.

y. Industry familiarization with the new rule

When the new regulation takes effect, operators would need to read and interpret the rule. 

Through this review, operators would familiarize themselves with the structure of the new rule and 

identify any new provisions relevant to their operations. Operators would evaluate whether any new 

action must be taken to achieve compliance with the rule. 

Reviewing the new regulations would require staff time, imposing a one-time labor cost on industry. 

We estimated the one-time labor cost by multiplying the time required for an administrator at each field 

office to review the rule by the total number of field offices. This calculation resulted in a total one-time 

cost to industry of $28,059.

34

 

33 We assumed that industry staff (administrative staff) would spend 0.5 hours to keep real time monitoring 

records per well. We multiplied the number of industry staff hours per well by the average hourly compensation 

rate for administrative staff ($29.82) and then multiplied this cost by the number of affected wells (120, based on 

an assumption of three wells per subsea BOP rig) to obtain an average annual labor cost of $1,789 (0.5 x $29.82 x 

120).

34 We assumed that industry staff (a professional engineer, supervisory) would spend two hours to review the new

regulation. The average hourly wage rate for a professional engineer (supervisory) is $76.00, based on BSEE’s 

Supporting Statement A (BSEE Production Safety Systems). We multiplied this wage rate by the private sector 

loaded wage factor of 1.42 to account for employee benefits, resulting in a loaded average hourly compensation 
41

6. Summary of the cost analysis

Exhibit 1 summarizes the estimated cost for the proposed rule by provision. Exhibit 2 displays the 

monetized costs as annual summations of the calculations described above and as a 10-year total. The 

increase in the annual cost estimate for the year 2019 reflects the inspection-year costs that would 

occur every 5 years, as described in section 5.w above. Sums in Exhibit 1 and those that follow may not 

add because of rounding.

 

rate of $107.92. We assumed that an industry staff would review the new regulation at each of the 130 field 

offices. Multiplying the number of hours per review by the average hourly compensation rate and by the number 

of field offices resulted in an estimated one-time labor cost of $28,059 (2 x $107.92 x 130) to industry.
42

EXHIBIT 1: COST OF THE PROPOSED RULE BY PROVISION1

Total 10 Year 

Cost

Average 

Annual Cost

Percent 

of Total 

Cost

Industry 

Share

Government 

Share (undiscounted) (undiscounted)

(a) Additional information in the 

description of well drilling design criteria $282,819 $28,282 0.03% 100% 0%

(b) Additional information in the drilling 

prognosis $70,705 $7,070 0.01% 100% 0%

(c) Prohibition of a liner as conductor 

casing $7,950,000 $795,000 0.90% 100% 0%

(d) Additional capping stack testing 

requirements $800,000 $80,000 0.09% 100% 0%

(e) Additional information in the APM 

for installed packers $103,060 $10,306 0.01% 56% 44%

(f) Additional information in the APM for 

pulled and reinstalled packers $400,347 $40,035 0.05% 56% 44%

(g) Rig movement reporting $56,411 $5,641 0.01% 44% 56%

(h) and (i) Information on MODUs, 

including lift boats $1,585,532 $158,553 0.18% 56% 44%

(j) Real-time monitoring of well 

operations $405,000,000 $40,500,000 45.85% 100% 0%

(k) Additional documentation and 

certification requirements for BOP 

systems and system components

$17,824,6932 $1,782,4692 2.02% 100% 0%

(l) Additional information in the APD, 

APM, or other submittal for BOP 

systems and system components

$507,370 $50,737 0.06% 56% 44%

(m) Submission of a Mechanical Integrity 

Assessment Report by a BSEE approved 

certification body

$48,253,685 $4,825,369 5.46% 100% 0%

(n) New surface BOP requirements Data not available; requesting comments

(o) New subsea BOP system 

requirements $50,000,0002 $5,000,0002 5.66% 100% 0%

(p) New surface accumulator system 

requirements $2,822,708 $282,271 0.32% 100% 0%

(q) Chart recorders $180,426 $18,043 0.02% 100% 0%

(r) Use water to test surface BOP system $95,132 $9,513 0.01% 56% 44%

(s) Alternating BOP control station 

function testing $250,000,000 $25,000,000 28.30% 100% 0%

(t) ROV intervention function testing $4,166,667 $416,667 0.47% 100% 0%

(u) Autoshear, deadman, and EDS 

system function testing on subsea BOPs $50,100,000 $5,010,000 5.67% 100% 0%

(v) Approval for well control equipment 

not covered in Subpart G $1,586 $159 0.00% 100% 0%

(w) Breakdown and inspection of BOP 

system and components $43,000,000 $4,300,000 4.87% 100% 0%
43

EXHIBIT 1: COST OF THE PROPOSED RULE BY PROVISION1

Total 10 Year 

Cost

Average 

Annual Cost

Percent 

of Total 

Cost

Industry 

Share

Government 

Share (undiscounted) (undiscounted)

(x) Additional record-keeping for realtime monitoring $17,892 $1,789 0.00% 100% 0%

(y) Industry familiarization with the new 

rule $28,059 $2,806 0.00% 100% 0%

TOTAL $883,247,090 $88,324,709 100.00% 99.86% 0.14%

1 Totals may not add because of rounding.

2 This is a lower-bound estimate of the costs of this provision; BSEE seeks comment on costs that we were unable 

to estimate (see section 5 above for details).

EXHIBIT 2: SUMMARY OF MONETIZED COSTS1

Year

Industry Costs Government Costs Total Costs

(2012 dollars/year)

1 2015 $164,728,509 $134,273 $164,862,782 

2 2016 $77,297,317 $134,273 $77,431,590 

3 2017 $77,297,317 $134,273 $77,431,590 

4 2018 $77,297,317 $134,273 $77,431,590 

5 2019 $77,297,317 $134,273 $77,431,590 

6 2020 $98,797,317 $134,273 $98,931,590 

7 2021 $77,297,317 $134,273 $77,431,590 

8 2022 $77,297,317 $134,273 $77,431,590 

9 2023 $77,297,317 $134,273 $77,431,590 

10 2024 $77,297,317 $134,273 $77,431,590 

Undiscounted 10-year total $881,904,358 $1,342,732 $883,247,090 

10-Year Total with 3% discounting $762,252,353 $1,145,377 $763,397,731 

10-Year Total with 7% discounting $638,941,758 $943,078 $639,884,837 

10-year Average $88,190,436 $134,273 $88,324,709 

Annualized with 3% discounting $89,359,230 $134,273 $89,493,503 

Annualized with 7% discounting $90,970,932 $134,273 $91,105,205 

1 Totals may not add because of rounding.

7. Benefits Analysis

We have quantified three types of benefits that would result from the proposed rule; time savings,

potential reductions in oil spills, and potential reductions in fatalities (see Sensitivity Analysis, section 

9.b, below). A time-savings benefit would result from § 250.737(d)(10), which would streamline the 
44

testing criteria for BOP control station function and reduces the time required for this testing. The 

section would require operators to test the functionality of the blind-shear ram.

 a. Time Savings

BSEE proposes to change the testing frequency for workover and decommissioning operations to 

once every 14 days, which is consistent with the testing frequency for drilling and completion 

operations. Some drilling, completion, workover, and decommissioning operations use the same rigs 

and BOP systems; therefore, to ensure consistency among different operations involving the same 

equipment, BSEE proposes to harmonize the requirements for that type of equipment. Harmonization 

of the testing frequency would streamline the BOP function-testing criteria and increase safety by 

reducing the repetition of operations (such as pulling pipe out of the hole and running pipe back into the 

hole) that pose operational safety issues, thereby limiting the exposure of offshore personnel to 

potential risks. This may also have a positive effect on overall equipment durability and reliability. 35 The 

new proposed provisions within this rulemaking increase the level of safety and reduce risk which translates into 

the operations conducted during this time-savings benefit. When combing this provision with the rest of the 

proposed provisions, the rulemaking increases the level of safety and reducing the risk for these operations. 

We calculated the savings from this provision by multiplying the amount of operating time saved per 

rig by the daily operating cost for a rig and by the number of affected rigs. Because subsea and surface 

BOPs have different daily rig operating costs, we calculated the time savings for subsea and surface BOP 

rigs separately. This calculation resulted in a total time-savings to industry of approximately 

$150,000,000 per year.36

 

35Neither Alternative 1 nor Alternative 2 consider potential benefits related to extended equipment life and 

reduced well control risks arising from fewer pressure tests and fewer trips out of the hole.

36 We assumed that this requirement would save three days of operating time per rig. BSEE estimates that the 

pressure testing takes about 20 hours and that the trip time is about 52 hours for workover and decommissioning 

operations. For the 40 subsea BOP rigs, we assumed that the daily operating cost is $1,000,000, and we assumed 
45

With regard to potential time savings for Alternative 2, the change in the required BOP pressure 

testing frequency under Alternative 2 would further change the frequency of BOP pressure testing from 

once every 14 days to once every 21 days and could result in a time-savings benefit to industry by 

decreasing the number of required tests per year for operators. To estimate the time-savings benefit 

associated with this potential change, we made the following assumptions: 

 We assumed that operators conduct 26 tests per year (i.e., one test every 14 days). BSEE 

recognizes that operators will not likely operate continuously, but we assumed continuous 

operations as a conservative approach because this approach results in the highest number 

of tests assumed to be conducted per year and thus the largest estimated costs per year. 

 We assumed that, under this alternative, operators would conduct 17 tests per year (i.e., 

one test every 21 days). This resulted in a net decrease of 9 tests per year (26 tests – 17 

tests) under this alternative. 

 We assumed that each BOP test takes 20 hours, based on input from subject matter experts

contacted by BSEE. 

Based on these inputs, we estimated that each rig will save 7.5 days of operating time annually (i.e., 

9 tests not conducted each year, with each test comprising 20 hours) as a result of Alternative 2. Using 

the daily rig operating costs assumed above, this would result in an annual per-rig benefit of $7.5 million 

for subsea BOP rigs (7.5 days x $1,000,000 per day) and $1.5 million for surface BOP rigs (7.5 days x 

$200,000 per day). Accounting for the number of rigs assumed to be operating on the OCS, we 

estimated an annual time-savings benefit of $300 million to subsea rigs ($7,500,000 x 40 rigs) and $75 

 

that the daily operating cost for the 50 surface BOP rigs is $200,000 per rig. We multiplied the time saved per rig 

by the daily operating cost per rig and by the number of affected rigs. Most rigs have the capability to perform 

multiple operations therefore we include all rig into this factor. This calculation resulted in an estimated annual 

time savings to industry of $150 million (3 x 50 x $200,000 + 3 x 40 x $1,000,000).
46

million for surface rigs ($1,500,000 x 50 rigs).37 As a result, the total benefits under Alternative 2 would 

be approximately $525,000,000 annually (see Exhibit 5 for further details of these benefits). 

We did not, however, include reduced trip time in the calculations of savings for Alternative 2.38 

Drilling trip time depends on factors such as well depth, hole size, mud weight, the amount of open 

hole, hole conditions, surge and swab pressure, borehole deviation, bottom hole assembly 

configuration, hoisting capacity, type of rigs, and crew efficiency. BSEE is not aware of any analysis of 

offshore operations that provides reasonable estimates of average trip time that could be used for the 

purpose of this calculation. In addition, it is common practice in the Gulf of Mexico (GOM) to perform 

BOP tests earlier than the required interval whenever operational opportunities become available (i.e., 

whenever there is no drill pipe across the BOPs due to the need to change drill bits). This practice would 

reduce the overall benefit from this alternative. BSEE requests comments and data on both of these 

issues to assist in the assessment of the overall benefits of this alternative.

 b. Potential reductions in oil spills

The proposed rule would result in benefits to society by reducing the probability of incidents 

involving oil spills. To estimate the benefits associated with the potential risk reduction of oil spills, we 

estimated the costs associated with an oil spill related to natural resource damages, the value of lost 

hydrocarbons, spill containment and cleanup, lost recreation opportunities, and impacts to commercial 

fishing. The magnitude of these benefits, however, is dependent on the effectiveness of the proposed 

 

37 These estimates are based on the following calculations: for subsea rigs, (9 tests saved per year) x (20 hours per 

test) x (1 day/24 hours) x ($1 million/day) x 40 rigs = $300,000,000.; for surface BOP rigs, (9 tests saved per year) x 

(20 hours per test) x (1 day/24 hours) x ($200,000/day) x 50 rigs = $75,000,000. 

38 Trip time refers to the time needed to stop drilling or workover operations, remove or raise the drill/work string 

from the well, and then lower the string back to the bottom of the well to restart operations. A trip is often made

to change a dull drill bit and/or to perform the pressure test or BOP test. During some deep drilling situations, the 

trip time may equal or exceed the on-bottom drilling time.
47

rule in reducing the number of incidents, which is uncertain. We thus conducted analysis to estimate

the monetized net benefits (the difference between total benefits and total costs) from the reduction in 

oil spills for a variety of risk reduction levels, from 1 to 20 percent, that could potentially be achieved by 

the proposed rule. 

Although common in situations where regulatory benefits are highly uncertain, we did not conduct a 

break-even analysis to estimate the minimum risk reduction the proposed rule would need to achieve in 

order for the rule to be cost-beneficial. This is because the rule is already cost-beneficial from the 

savings in operating costs under proposed section 250.737 (d)(10). In other words, the break-even risk 

reduction level of the proposed rule is 0 percent, indicating that the proposed rule would be costbeneficial even if it does not achieve any reductions in the risk of oil spills. (The same is true of 

Alternative 2, which would have even greater time-savings benefits, as discussed above.) 

In addition to the time savings and risk reduction benefits presented above, the proposed rule also 

has other benefits. Due to difficulties in measuring and monetizing these benefits, we do not offer a 

quantitative assessment of them. BSEE has used a conservative approach in the valuation of a 

catastrophic oil spill, including only selected costs of such a spill. For example, although we capture the 

environmental damage associated with a catastrophic oil spill, the analysis is limited because it only 

considers the environmental amenities that researchers could identify and monetize. Therefore, the 

resulting benefits of avoiding such a spill should be considered as a lower-bound estimate of the true 

benefit to society that results from decreasing the risk of oil spills. BSEE followed the approach used in 

the Case Study and sought to avoid double-counting the costs of a catastrophic event.

i. Benefits Data

To estimate the potential benefits of the proposed rule associated with reducing the risk of 

incidents, we examined historical data from the BSEE oil spill database, which contains information for 
48

spills greater than 10 barrels of oil for the Gulf of Mexico and Pacific regions. Based upon an analysis of 

the BSEE oil spill database during the period between 1964 and 2010,

39 BSEE identified 27 blowouts 

associated with oil spills greater than 10 barrels40 and used this data within the economic analysis (see 

the initial RIA for details). Blowouts that resulted in uncontrolled flow of gas, damage to a rig, and/or 

harm to personnel (but not oil spills over 10 barrels) are not reflected in this analysis41. Accordingly, the 

benefits and the overall risk reduction associated with this proposed rule are likely understated. BSEE is 

specifically soliciting comments on any data and costs associated with any blowout that did not result in 

an oils spill greater than 10 barrels, and how to include that information within the economic analysis. 

ii. Methods

We assumed that the proposed rule would reduce the likelihood of all oil spills, regardless of the size

of the spill. We therefore applied a uniform probability distribution to take this assumption into 

account. We assumed a 1 percent risk reduction because it represents BSEE’s best judgment of the 

causes of risk without the proposed rule and how those causes of risk would be affected by it.

42 Thus, 

 

39 BSEE based the analysis on the historical oil spill database for the period between 1964 and 2010, but recognizes 

that significant regulatory and technological improvements have taken place since 1964. Limiting the analysis 

period to 1988 (the year when the most recent comprehensive overhaul of the Department of the Interior’s 

offshore regulatory program took place) through 2010, and assuming a 1 percent risk reduction, would increase 

10-year net benefits (including avoided fatalities) by $51,230,511 and $42,182,077 (with 3 percent and 7 percent 

discounting, respectively). The increase in the total net benefits from starting the analysis at such a later point 

results from the proportionately greater influence of the damages of the Deepwater Horizon incident on the 

estimated benefits of the proposed rule during that shorter timeframe. 

40 Source: http://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-Incidents/Spills/.

41 Previous Minerals Management Service studies indicate a total of 126 blowouts during drilling operations on the 

OCS between 1971 and 2006. These blowouts resulted in 26 fatalities, 63 injuries, damage to facilities and 

equipment, and the release of hydrocarbons.

42 Several recent studies have estimated the probabilities of blowout failures under a wide range of circumstances. 

See, e.g., “Blowout Preventer (BOP) Failure Event and Maintenance, Inspection and Test (MIT) Data Analysis for 

the Bureau of Safety and Environmental Enforcement (BSEE),” American Bureau of Shipping and ABSG Consulting 

Inc., (under BSEE contract M11PC00027), June 2013; “Improved Regulatory Oversight Using Real-Time Data 

Monitoring Technologies in the Wake of Macondo,” K. Carter, U. of Texas at Austin, 2014, published with E. van 

Oort and A. Barendrecht, Soc’y of Petroleum Engineers, 2014; “Deepwater Horizon Blowout Preventer Failure 

Analysis Report to the U.S. Chemical Safety and Hazard Investigation Board,” Engineering Services, LP, 2014. Given 

this accumulated knowledge of failure likelihoods under various circumstances, and analysis of how those 
49

the 1 percent risk reduction represents the lower bound of the potential benefits of the proposed rule. 

Nevertheless, we present a sensitivity analysis on the assumed risk reduction level in section 9.a below.

To calculate the expected annual reduction in barrels of oil spilled associated with the proposed 

rule, we multiplied the annual number of spilled barrels (the total number of barrels spilled in the 

incident divided by 46.945 years) by 1 percent to calculate the expected annual reduction in barrels of 

oil spilled associated with the proposed rule. Exhibit 3 displays the calculation of the expected annual 

reductions in barrels of oil spilled assuming a 1-percent risk reduction resulting from the proposed rule.

EXHIBIT 3: CALCULATIONS OF NUMBER OF BARRELS SPILLED

(AT A 1-PERCENT RISK REDUCTION FROM THE PROPOSED RULE)

Incident 

Rank

Barrels of Oil 

Spilled

Annualized 

Barrels

Adjusted Risk 

Reduction

Reduced 

Barrels

(a) (b) (c = b ÷ 46.945 

years) (d = 1%) (e = c * d)

27 10 0.2 1.00% 0.0

27 10 0.2 1.00% 0.0

27 10 0.2 1.00% 0.0

24 11 0.2 1.00% 0.0

23 25 0.5 1.00% 0.0

22 50 1.1 1.00% 0.0

21 60 1.3 1.00% 0.0

20 62 1.3 1.00% 0.0

19 64 1.4 1.00% 0.0

18 75 1.6 1.00% 0.0

17 100 2.1 1.00% 0.0

17 100 2.1 1.00% 0.0

15 125 2.7 1.00% 0.0

14 200 4.3 1.00% 0.0

 

likelihoods would be reduced by the proposed rule, BSEE has determined that 1 percent is a reasonable lowerbound of risk reduction that could occur as a result of the proposed rule, although in BSEE’s expert opinion, the 

actual risk reduction from the proposed rule will likely be substantially higher than 1 percent.
50

14 200 4.3 1.00% 0.0

12 350 7.5 1.00% 0.1

11 450 9.6 1.00% 0.1

10 774 16.5 1.00% 0.2

9 1,061 22.6 1.00% 0.2

8 1,688 36.0 1.00% 0.4

7 2,500 53.3 1.00% 0.5

6 5,100 108.6 1.00% 1.1

5 5,180 110.3 1.00% 1.1

4 53,000 1,129.0 1.00% 11.3

3 65,000 1,384.6 1.00% 13.8

2 80,000 1,704.1 1.00% 17.0

1 4,928,100 104,975.5 1.00% 1049.8

Total Annual Reduced Barrels 1,0961

1 Totals may not add because of rounding.

A risk reduction of 1 percent leads to an annual reduction of 1,096 spilled barrels. (See the appendix 

for the number of spilled barrels associated with each incident.) To estimate the benefits from a 

reduction in oil spilled, we multiplied the estimated annual reduction in spilled barrels of oil by the social 

and private cost of a spilled barrel of oil, which is estimated at $3,599. We derived this estimate from 

the “Economic Analysis Methodology for the Five Year OCS Oil and Gas Leasing Program for 2012-2017” 

(the “BOEM Case Study”),43 and this value includes costs associated with natural resource damages, the 

value of lost hydrocarbons, and spill cleanup and containment.44 Natural resource damages relate to 

the natural resources on the OCS that would be damaged by an oil spill. The value of the lost 

hydrocarbons reflects the lost usable oil. Finally, spill containment and cleanup costs include all the 

resources (capital and labor) needed to contain the spill and clean up the site. These costs are all 

included in the social cost of a barrel of oil, as per the directive of OMB Circular A-4 to include costs 

 

43 U.S. Department of the Interior. Bureau of Ocean Energy Management (2012), available at 

http://www.boem.gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012-

2017_Five_Year_Program/PFP%20EconMethodology.pdf.

44 The BOEM Case Study presents per-barrel costs associated with a catastrophic event. We use this estimate 

because the BOEM Case Study represents a recent estimate for the costs associated with an oil spill that includes

data from the Deepwater Horizon incident.
51

regardless of where, when, or to whom the costs accrue.45 We assumed a natural resource damage cost 

of $642 per barrel and a cleanup and containment cost of $2,857 per barrel as estimated for the Gulf of 

Mexico in the BOEM Case Study. Consistent with the BOEM Case Study, we used a value of lost 

hydrocarbon per barrel of $100, which is the value applied across all regions analyzed in the BOEM Case 

Study. We recognize the uncertainty associated with projecting the price of oil during the 10-year 

period of analysis and present a sensitivity analysis in section 9.c.

We also accounted for one-time costs associated with catastrophic oil spills.46 Consistent with the 

BOEM Case Study, we assumed losses associated with recreation of $199 million per catastrophic 

incident and losses for commercial fishing of $13 million per incident. The BOEM Case Study estimated 

these costs on a per-incident basis because these costs are not dependent on the volume of oil spilled.

47

 

Historical data includes one catastrophic incident over the course of the past 46.945 years. We 

estimated an annual loss associated with recreation and commercial fishing due to catastrophic events 

of $4,515,899 (($212,000,000 per incident) x (1 incident/46.945 years)). We assumed a 1 percent risk 

reduction associated with these per-incident costs, resulting in an estimated annual risk reduction of 

$45,159. 

 

45 Using both natural resource damages and containment and cleanup costs is consistent with the natural resource 

damages assessment methods described in the BOEM Case Study. This also accounts for any temporal or spatial 

distribution in the accrual of cleanup costs. For example, the cleanup on the coast may occur at a later time and 

different place than the initial spill.

46 The BOEM Case Study defines a catastrophic oil spill in the GOM as one ranging in size from 900,000 barrels to 

7,200,000 barrels.

47 The BOEM Case Study presents seven separate cost categories to estimate the impact of a catastrophic spill, 

including natural resource damages, and impacts on recreation and commercial fishing. The natural resource 

damage cost associated with each barrel of oil spilled (expressed as a per-barrel cost) accounts for the damage 

(e.g. to wildlife, habitats, and ecosystems) caused by the oil itself as well as by cleanup crews. . Additional costs 

associated with catastrophic oil spills that are not represented in this per-barrel natural resource damage cost 

Include costs to commercial fishing (i.e., economic losses due to fishery closures during a catastrophic oil spill and 

lost recreational values (based on the average number of trips and the value for each recreation trip).
52

The annual benefit from the reduction in spilled barrels of oil and the adjusted one-time costs of a 

catastrophic event is estimated at $4.0 million.

8. Analysis results

Exhibit 4 displays the monetized costs to industry and BSEE, as well as the total costs for each year 

and for the 10-year analysis period. The 10-year undiscounted total cost of the proposed rule is $883.2

million with $881.9 million of the total cost falling on industry and $1.3 million on BSEE. The discounted 

total costs for the 10-year period are $763.4 and $639.9 million at 3 and 7 percent discounting, 

respectively.

Exhibit 5 displays the monetized benefits for both time savings (under Section 250.737(d)(10) and 

under Section 250.447(b) for Alternative 2) and the risk reduction of oil spills for each year and for the 

10-year analysis period. The 10-year total benefits for Alternative 1, the proposed rule, are $1,313.6

million and $1,081.6 million at 3 and 7 percent discounting, respectively, with the majority of the 

quantified benefits under Alternative 1 stemming from time-savings benefits under Section 

250.737(d)(10). The discounted 10-year benefits for Alternative 2 are $4,512.4 million and $3,715.4 

million at 3 and 7 percent discounting, respectively, with the majority of quantified benefits under 

Alternative 2 stemming from time-savings benefits under Section 250.477(b).

EXHIBIT 4: SUMMARY OF MONETIZED COSTS1

Year

Industry Costs Government Costs Total Costs

(2012 dollars/year)

1 2015 $164,728,509 $134,273 $164,862,782 

2 2016 $77,297,317 $134,273 $77,431,590 

3 2017 $77,297,317 $134,273 $77,431,590 

4 2018 $77,297,317 $134,273 $77,431,590 

5 2019 $77,297,317 $134,273 $77,431,590 
53

6 2020 $98,797,317 $134,273 $98,931,590 

7 2021 $77,297,317 $134,273 $77,431,590 

8 2022 $77,297,317 $134,273 $77,431,590 

9 2023 $77,297,317 $134,273 $77,431,590 

10 2024 $77,297,317 $134,273 $77,431,590 

Undiscounted 10-year total $881,904,358 $1,342,732 $883,247,090 

10-Year Total with 3% discounting $762,252,353 $1,145,377 $763,397,731 

10-Year Total with 7% discounting $638,941,758 $943,078 $639,884,837 

10-year Average $88,190,436 $134,273 $88,324,709 

Annualized with 3% discounting $89,359,230 $134,273 $89,493,503 

Annualized with 7% discounting $90,970,932 $134,273 $91,105,205 

1 Totals may not add because of rounding.

Because we are not able to monetize all of the consequences of an oil spill (and conversely, the 

benefits of avoiding such a spill), the risk reduction estimates we present reflect only a portion of the 

total value to society from reducing the risk of a spill. These estimates are assumed to be lower-bound 

estimates for the true benefit to society arising from a reduction in the risk of oil spills. 
54

EXHIBIT 5: SUMMARY OF MONETIZED BENEFITS (AT A 1-PERCENT RISK REDUCTION FROM THE PROPOSED RULE)1

Year

Alternative 1 -

250.737(d)(10)

(subsea rigs)2

Alternative 1 -

250.737(d)(10)

(surface rigs)

2

Alternative 2 -

250.447(b)

(subsea rigs)3

Alternative 2 -

250.447(b)

(surface rigs)3

Risk Reduction

Benefits

Total Benefits

(Alternative 1)

Total Benefits

(Alternative 2)

(2012 dollars/year)

1 2015 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

2 2016 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

3 2017 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

4 2018 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

5 2019 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

6 2020 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

7 2021 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

8 2022 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

9 2023 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

10 2024 $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

Undiscounted 10-year total $1,200,000,000 $300,000,000 $3,000,000,000 $750,000,000 $39,889,771 $1,539,889,771 $5,289,889,771 

10-Year Total with 3% 

discounting $1,023,624,340 $255,906,085 $2,559,060,851 $639,765,213 $34,026,784 $1,313,557,210 $4,512,383,273 

10-Year Total with 7% 

discounting $842,829,785 $210,707,446 $2,107,074,462 $526,768,616 $28,016,906 $1,081,554,137 $3,715,397,215 

10-year Average $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

Annualized with 3% 

discounting $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

Annualized with 7% 

discounting $120,000,000 $30,000,000 $300,000,000 $75,000,000 $3,988,977 $153,988,977 $528,988,977 

1 Totals may not add because of rounding.

2 Amounts include timesaving benefits of pressure testing and trip time associated with increasing BOP testing interval for completions and workovers from 7 to 14 days. 

3 Amounts include timesaving benefits of pressure testing associated with increasing testing intervals for all BOPS (drilling, completions, workovers) from 14 to 21 days. This estimate does not include trip time.
55

Exhibit 6 summarizes the net benefits at a 1 percent risk reduction. The total 10-year net benefits 

for Alternative 1 are $550.2 million and $441.7 million at 3 and 7 percent discounting, respectively. The 

10-year net benefits for Alternative 2 are $3,749.0 million and $3,075.5 million at 3 and 7 percent 

discounting, respectively. 
56

EXHIBIT 6: SUMMARY OF NET BENEFITS (AT A 1-PERCENT RISK REDUCTION FROM THE PROPOSED Rule) 1

Year

Total Benefits

(Alternative 1)

Total Benefits

(Alternative 2) Total Costs2 Net Benefits(Alternative 1)

Net Benefits

(Alternative 2)

(2012 dollars/year)

1 2015 $153,988,977 $528,988,977 $164,862,782 ($10,873,805) $364,126,195 

2 2016 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

3 2017 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

4 2018 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

5 2019 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

6 2020 $153,988,977 $528,988,977 $98,931,590 $55,057,387 $430,057,387 

7 2021 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

8 2022 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

9 2023 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

10 2024 $153,988,977 $528,988,977 $77,431,590 $76,557,387 $451,557,387 

Undiscounted 10-year total $1,539,889,771 $5,289,889,771 $883,247,090 $656,642,682 $4,406,642,682 

10-Year Total with 3% discounting $1,313,557,210 $4,512,383,273 $763,397,731 $550,159,479 $3,748,985,543 

10-Year Total with 7% discounting $1,081,554,137 $3,715,397,215 $639,884,837 $441,669,301 $3,075,512,378 

10-year Average $153,988,977 $528,988,977 $88,324,709 $65,664,268 $440,664,268 

Annualized with 3% discounting $153,988,977 $528,988,977 $89,493,503 $64,495,474 $439,495,474 

Annualized with 7% discounting $153,988,977 $528,988,977 $91,105,205 $62,883,772 $437,883,772 

1 Totals may not add because of rounding.

2 This is a lower-bound estimate of the costs of this provision; BSEE seeks comment on costs that we were unable to estimate.
57

BSEE has concluded that after consideration of the impacts of the NPRM, the societal benefits of the 

proposed rule justify the societal costs.

9. Sensitivity Analysis

This section presents sensitivity analyses of the potential benefits of the proposed rule that could 

result from varying the following factors:

a. The level of risk reduction of oil spills achieved by the proposed rule

b. The level of risk reduction of fatalities achieved by the proposed rule

c. The price of a barrel of oil (i.e., the value of lost hydrocarbons)

These sensitivity analyses are presented for Alternative 1, the proposed rule. 

a. Reduction in the Risk of Oil Spills

We thus far have assumed a 1 percent reduction in the annual risk of oil spills resulting from this 

proposed rule because it represents the lower bound estimate of the benefits of the rule based on 

BSEE’s expert judgment. The benefits, and thus net benefits, of this proposed rule would differ under 

other assumed levels of reduction in the risk of oil spills. Exhibit 7 presents the total 10-year risk 

reduction benefits, total benefits (includes cost savings from changes in testing frequency),, and net 

benefits under a range of possible annual risk reduction levels for oil spills from 0 to 20 percent.
58

EXHIBIT 7: SUMMARY OF NET BENEFITS UNDER DIFFERENT RISK REDUCTION LEVELS1

Annual 

Risk 

Reduction 

Annual 

Benefits

Total 10-Year 

Risk Reduction 

Benefits (7% 

Discounting)

Total 10-Year 

Risk Reduction 

Benefit (3% 

Discounting)

Total 10-Year 

Benefits (7% 

Discounting)

Total 10-Year 

Benefit (3% 

Discounting)

Total 10-Year 

Net Benefits 

(Undiscounted)

Total 10-Year 

Net Benefit (7% 

Discounting)

Total 10-Year 

Net Benefit (3% 

Discounting)

0% $0 $0 $0 $1,053,537,231 $1,279,530,426 $616,752,910 $413,652,394 $516,132,695 

1% $3,988,977 $28,016,906 $34,026,784 $1,081,554,137 $1,313,557,210 $656,642,682 $441,669,301 $550,159,479 

2% $7,977,954 $56,033,812 $68,053,568 $1,109,571,044 $1,347,583,994 $696,532,453 $469,686,207 $584,186,263 

3% $11,966,931 $84,050,719 $102,080,353 $1,137,587,950 $1,381,610,778 $736,422,225 $497,703,113 $618,213,047 

4% $15,955,909 $112,067,625 $136,107,137 $1,165,604,856 $1,415,637,562 $776,311,996 $525,720,019 $652,239,832 

5% $19,944,886 $140,084,531 $170,133,921 $1,193,621,762 $1,449,664,346 $816,201,768 $553,736,926 $686,266,616 

6% $23,933,863 $168,101,437 $204,160,705 $1,221,638,669 $1,483,691,131 $856,091,539 $581,753,832 $720,293,400 

7% $27,922,840 $196,118,344 $238,187,489 $1,249,655,575 $1,517,717,915 $895,981,311 $609,770,738 $754,320,184 

8% $31,911,817 $224,135,250 $272,214,273 $1,277,672,481 $1,551,744,699 $935,871,082 $637,787,644 $788,346,968 

9% $35,900,794 $252,152,156 $306,241,058 $1,305,689,387 $1,585,771,483 $975,760,854 $665,804,551 $822,373,752 

10% $39,889,771 $280,169,062 $340,267,842 $1,333,706,294 $1,619,798,267 $1,015,650,625 $693,821,457 $856,400,537 

11% $43,878,749 $308,185,969 $374,294,626 $1,361,723,200 $1,653,825,051 $1,055,540,397 $721,838,363 $890,427,321 

12% $47,867,726 $336,202,875 $408,321,410 $1,389,740,106 $1,687,851,836 $1,095,430,168 $749,855,269 $924,454,105 

13% $51,856,703 $364,219,781 $442,348,194 $1,417,757,012 $1,721,878,620 $1,135,319,939 $777,872,176 $958,480,889 

14% $55,845,680 $392,236,687 $476,374,978 $1,445,773,919 $1,755,905,404 $1,175,209,711 $805,889,082 $992,507,673 

15% $59,834,657 $420,253,594 $510,401,763 $1,473,790,825 $1,789,932,188 $1,215,099,482 $833,905,988 $1,026,534,457 

16% $63,823,634 $448,270,500 $544,428,547 $1,501,807,731 $1,823,958,972 $1,254,989,254 $861,922,894 $1,060,561,242 

17% $67,812,611 $476,287,406 $578,455,331 $1,529,824,637 $1,857,985,756 $1,294,879,025 $889,939,801 $1,094,588,026 

18% $71,801,589 $504,304,312 $612,482,115 $1,557,841,544 $1,892,012,541 $1,334,768,797 $917,956,707 $1,128,614,810 

19% $75,790,566 $532,321,219 $646,508,899 $1,585,858,450 $1,926,039,325 $1,374,658,568 $945,973,613 $1,162,641,594 

20% $79,779,543 $560,338,125 $680,535,683 $1,613,875,356 $1,960,066,109 $1,414,548,340 $973,990,519 $1,196,668,378 

1 For Alternative 1, the proposed rule.
59

Based on this analysis, the net benefits of the proposed rule are more sensitive to the percent 

reduction in the annual risk of oil spills than the other parameters evaluated within this RIA. As can be 

seen in Exhibit 7, the larger the risk reduction, the larger the net benefits. For example, 10-year total 

net benefits are $441.7 million and $550.2 million at a 1 percent risk reduction and $974.0 million and 

$1,196.7 million at a 20 percent risk reduction, at 7 and 3 percent discounting, respectively.

b. Reduction in the Risk of Fatalities

In addition to the time savings and the prevention of oil spills, the proposed rule is anticipated 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 national workforce, but with a fatality rate that is higher than for

most industries. The fatality rate for oil and gas extraction workers is 23.9 fatalities per 100,000 fulltime equivalent workers (Exhibit 8).

EXHIBIT 8: SELECTED OCCUPATIONAL FATALITY 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, and law 

enforcement)

9.1

Manufacturing 2.5

Management, professional, and related occupations 1.6

Finance, insurance, and real estate and leasing 1.1

Source: Bureau of Labor Statistics, 2010.
60

The economic benefits of occupational risk reduction are often measured using the value of a 

statistical life (VSL). The VSL concept is based on individual willingness to pay for reductions in small 

risks of premature death. In concept, the VSL measures the sum of society’s willingness to pay for one 

unit of reduction in the risk of a fatality. 

A large number of VSL estimates can be found in the academic literature. Published literature has 

included either explicit or implicit valuation of fatality risks and generally derives VSL estimates from 

studies on wage compensation for occupational hazards, on consumer product purchase and use 

decisions, or from using stated preference approaches. These values have varied over time, geographic 

locations, and worker heterogeneity. In the early 1980s, VSL estimates ranged from less than $1 million 

to approximately $3 million and were used to assess policies that reduced worker fatality. More recent 

studies have replaced these estimates with values as high as $9 million. However, the literature based 

on estimates using U.S. labor market data typically shows a VSL in the range of $4 to $9 million. 

The U.S. Environmental Protection Agency (EPA) recommends using a VSL value of $7.4 million 

($2006), updated to the base year of the analysis, in all benefits analyses that seek to quantify mortality 

risk reduction regardless of the age, income, or other characteristics of the affected population. This 

approach was endorsed by EPA in its 2000 Guidelines for Preparing Economic Analyses. A recent report 

from the EPA’s Science Advisory Board 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,

48 inflation, and time lags in the occurrence of adverse health effects.

For the purpose this analysis, BSEE used a VSL of $8.4 million to estimate the avoided costs 

associated with a reduction in the fatality rate. This is the EPA-recommended estimate of $7.4 million 

 

48 EPA allows the adjustment of VSL based on increases in future income but not on cross-sectional differences in 

income.
61

updated to 2012 dollars. The EPA-recommended VSL was chosen for this analysis because of the lack of 

consensus in previous research on adjusting VSL values for occupational risk.

There are a number of ways to use the concept of VSL when estimating risk reduction benefits. 

Dividing the number of fatalities by the number of years provides the average number of fatalities per 

year. Dividing the number of fatalities by the number of barrels spilled over the analysis time period 

gives the average number of fatalities per barrel of oil spilled.

Between 1964 and 2010, there have been 27 blowouts with oils spills greater than 10 barrels. Only 

two of these events resulted in injuries or fatalities. Those two events are a 1984 blowout and the 2010 

Deepwater Horizon incident that resulted in 4 and 11 fatalities, respectively. Based on the 46.945-year 

period from 1964 to 2010, the average number of fatalities was 0.320 annually (15 / 46.945). Using a 

VSL of $8,423,301, the average cost of fatalities is $2,691,423 per year (0.320 x $8,423,301). Therefore, 

each 1 percent reduction in the risk of a fatality results in a risk reduction benefit of $26,914 (1% x 

$2,691,423).49 Exhibit 9 presents the resulting fatality risk reduction benefit across a range of risk 

reduction values from 0 to 20 percent as both annual and total 10-year (undiscounted and discounted) 

values.

Next, Exhibit 10 presents the effect on the net benefits of the proposed rule if the additional benefit 

of fatality risk reduction is considered. The exhibit presents the undiscounted and discounted 10-year 

total net benefits when fatality risk reduction is considered in addition to the benefits of the rule 

included in the economic analysis presented above. For example, at a 1 percent fatality risk reduction

level, the 10-year total benefits are $229,584 and $189,034 at 3 and 7 percent discounting, respectively. 

 

49 Note that this calculation likely understates the benefits associated with fatality risk reduction because blowouts 

that did not result in an oil spill greater than 10 barrels were not part of the database used for this analysis. 

Previous MMS studies indicate a total of 126 blowouts during drilling operations on the OCS between 1971 and 

2006. These blowouts resulted in 26 fatalities, 63 injuries, damage to facilities and equipment, and the release of 

hydrocarbons. Accounting for any additional fatalities would increase the fatality risk reduction benefits. 
62

Assuming a higher fatality risk reduction of 20 percent, 10-year total benefits are $4.59 and $3.78 

million (at 3 and 7 percent discounting, respectively).
63

EXHIBIT 9: SUMMARY OF MONETIZED BENEFITS FROM AVERTED FATALITIES

Fatality Risk 

Reduction

Fatalities 

Averted Annual Value

10-year Total

Undiscounted 3% Discounting 7% Discounting

0% 0.000 $0 $0 $0 $0

1% 0.003 $26,914 $269,142 $229,584 $189,034

2% 0.006 $53,828 $538,285 $459,168 $378,069

3% 0.010 $80,743 $807,427 $688,752 $567,103

4% 0.013 $107,657 $1,076,569 $918,335 $756,137

5% 0.016 $134,571 $1,345,712 $1,147,919 $945,171

6% 0.019 $161,485 $1,614,854 $1,377,503 $1,134,206

7% 0.022 $188,400 $1,883,996 $1,607,087 $1,323,240

8% 0.026 $215,314 $2,153,139 $1,836,671 $1,512,274

9% 0.029 $242,228 $2,422,281 $2,066,255 $1,701,309

10% 0.032 $269,142 $2,691,423 $2,295,839 $1,890,343

11% 0.035 $296,057 $2,960,565 $2,525,422 $2,079,377

12% 0.038 $322,971 $3,229,708 $2,755,006 $2,268,412

13% 0.042 $349,885 $3,498,850 $2,984,590 $2,457,446

14% 0.045 $376,799 $3,767,992 $3,214,174 $2,646,480

15% 0.048 $403,713 $4,037,135 $3,443,758 $2,835,514

16% 0.051 $430,628 $4,306,277 $3,673,342 $3,024,549

17% 0.054 $457,542 $4,575,419 $3,902,926 $3,213,583

18% 0.058 $484,456 $4,844,562 $4,132,509 $3,402,617

19% 0.061 $511,370 $5,113,704 $4,362,093 $3,591,652

20% 0.064 $538,285 $5,382,846 $4,591,677 $3,780,686
64

EXHIBIT 10: SUMMARY OF MONETIZED BENEFITS FROM AVERTED FATALITIES w/ NET BENEFITS1

Fatality 

Risk 

Reduction

Fatality Risk 

Reduction 

Benefit 

Net Benefits of 

Proposed Rule 

Without 

Fatality Risk 

Reduction (at a 

1-Percent Risk 

Reduction from 

the Proposed 

Rule)

Net Benefits of Proposed Rule With Fatality Risk Reduction

(at a 1-Percent Risk Reduction from the Proposed Rule)

(Total 10-year) (Total 10-year) (Total 10-year)

Undiscounted Undiscounted Undiscounted 3% Discounting 7% Discounting

0% $0 $656,642,682 $656,642,682 $550,159,479 $441,669,301 

1% $269,142 $656,642,682 $656,911,824 $550,389,063 $441,858,335 

2% $538,285 $656,642,682 $657,180,967 $550,618,647 $442,047,369 

3% $807,427 $656,642,682 $657,450,109 $550,848,231 $442,236,403 

4% $1,076,569 $656,642,682 $657,719,251 $551,077,814 $442,425,438 

5% $1,345,712 $656,642,682 $657,988,393 $551,307,398 $442,614,472 

6% $1,614,854 $656,642,682 $658,257,536 $551,536,982 $442,803,506 

7% $1,883,996 $656,642,682 $658,526,678 $551,766,566 $442,992,541 

8% $2,153,139 $656,642,682 $658,795,820 $551,996,150 $443,181,575 

9% $2,422,281 $656,642,682 $659,064,963 $552,225,734 $443,370,609 

10% $2,691,423 $656,642,682 $659,334,105 $552,455,318 $443,559,644 

11% $2,960,565 $656,642,682 $659,603,247 $552,684,901 $443,748,678 

12% $3,229,708 $656,642,682 $659,872,390 $552,914,485 $443,937,712 

13% $3,498,850 $656,642,682 $660,141,532 $553,144,069 $444,126,746 

14% $3,767,992 $656,642,682 $660,410,674 $553,373,653 $444,315,781 

15% $4,037,135 $656,642,682 $660,679,817 $553,603,237 $444,504,815 

16% $4,306,277 $656,642,682 $660,948,959 $553,832,821 $444,693,849 

17% $4,575,419 $656,642,682 $661,218,101 $554,062,405 $444,882,884 

18% $4,844,562 $656,642,682 $661,487,244 $554,291,988 $445,071,918 

19% $5,113,704 $656,642,682 $661,756,386 $554,521,572 $445,260,952 

20% $5,382,846 $656,642,682 $662,025,528 $554,751,156 $445,449,986 

1 For Alternative 1, the proposed rule.
65

c. Value of lost hydrocarbons

As an additional sensitivity analysis, BSEE estimated the net benefits of the proposed rule for 

different assumptions on the value of lost hydrocarbons. In the analysis presented above, BSEE used

$100 as the per-barrel value of lost hydrocarbons in the event of a spill. To reflect recent fluctuations in 

the price of a barrel of oil, BSEE also estimated the net benefits of the proposed rule under two 

alternative price scenarios during the 10-year analysis period: $50/barrel and $130/barrel. These prices 

reflect what BSEE currently anticipates using for planning purposes.

Comparing the results of these two scenarios with the net benefit estimates presented above in 

Exhibit 6 demonstrates the sensitivity of the analysis results to changes in the assumed per-barrel value 

of lost hydrocarbons. Exhibit 11 presents the net benefits of the proposed rule under three scenarios

for the value of lost hydrocarbons: $50/barrel, $100/barrel, and $130/barrel. As shown in Exhibit 11, 

with 3 percent discounting, the 10-year total net benefits range from $549.7 to $550.4 million at perbarrel values of lost hydrocarbons of $50 and $130, respectively. This range can be compared to the net 

benefits estimated above in Exhibit 6 of $550.2 million when the per-barrel value of lost hydrocarbons is 

assumed to be $100.

Because the value of lost hydrocarbons is a small component of the costs of an oil spill, fluctuations 

in this value per barrel of oil result in very small changes to the net benefits of the proposed rule. A 50 

percent decrease in the per-barrel value of lost hydrocarbons (from $100 to $50) results in a decrease in 

the net benefits of the proposed rule of only 0.08 percent. Alternately, a 30 percent increase in the perbarrel value of lost hydrocarbons (from $100 to $130) results in an increase in the net benefits of the 

proposed rule of only 0.05 percent. 
66

EXHIBIT 11: SUMMARY OF NET BENEFITS UNDER THREE OIL PRICE

SCENARIOS (AT A 1-PERCENT RISK REDUCTION FROM THE PROPOSED RULE)1

 Year

$50/Barrel $100/Barrel $130/Barrel

(2012 dollars/year)

1 2015 ($10,928,596) ($10,873,805) ($10,840,931)

2 2016 $76,502,597 $76,557,387 $76,590,262 

3 2017 $76,502,597 $76,557,387 $76,590,262 

4 2018 $76,502,597 $76,557,387 $76,590,262 

5 2019 $76,502,597 $76,557,387 $76,590,262 

6 2020 $55,002,597 $55,057,387 $55,090,262 

7 2021 $76,502,597 $76,557,387 $76,590,262 

8 2022 $76,502,597 $76,557,387 $76,590,262 

9 2023 $76,502,597 $76,557,387 $76,590,262 

10 2024 $76,502,597 $76,557,387 $76,590,262 

Undiscounted 10-year total $656,094,777 $656,642,682 $656,971,425 

10-Year Total with 3% discounting $549,692,105 $550,159,479 $550,439,903 

10-Year Total with 7% discounting $441,284,475 $441,669,301 $441,900,196 

10-year Average $65,609,478 $65,664,268 $65,697,142 

Annualized with 3% discounting $64,440,684 $64,495,474 $64,528,349 

Annualized with 7% discounting $62,828,982 $62,883,772 $62,916,646 

1 For Alternative 1, the proposed rule.

10. Probabilistic Risk Assessment

a. Overview

BSEE is considering various alternative approaches to estimating the potential benefits of the 

proposed rule. The benefits (and costs) of a proposed regulation are based on the difference between 

the baseline (i.e., status quo) and the proposed regulation. In relation to safety, environmental, and 

security benefits, one approach to estimating the benefits is based on the amount of risk reduction (as 

previously discussed). In general, risk can be reduced in two distinct ways; by decreasing the probability 

of the event, and/or by decreasing the consequences of the event. The evaluation of the reduction in 

risk typically can be performed in either a deterministic or probabilistic approach.
67

 Historically, BSEE has evaluated the reduction of risk based on a deterministic approach. However, 

as statistical models and information become more available, BSEE is evaluating other possibilities, 

including whether to move toward a probabilistic approach, in this regulation. A probabilistic approach 

may enhance and extends more traditional, approaches by: (1) allowing consideration of a broader set 

of potential challenges; (2) providing a logical means for prioritizing these challenges based on risk 

significance; and (3) allowing consideration of a broader set of resources to address these challenges. 

Probabilistic risk assessments have been used by some federal agencies including the U.S. Nuclear 

Regulatory Commission, Department of Homeland Security, and the National Aeronautics and Space 

Administration. 

 For this proposed regulation, BSEE is requesting comment on whether or not BSEE should use a 

probabilistic risk assessment (PRA), including statistical information (e.g., failure rates of valves), 

probabilities, uncertainties, and assumptions that potentially could help inform BSEE’s final decision on

the proposed regulation. It is important to note that the basic PRA approach described below has not 

been peer-reviewed (as PRAs should be) and is being provided at this time for transparency and 

informational purposes and not as the basis for a decision. 

 The basic modeling tools of PRA are event trees and fault trees. Event trees describe initiating 

events that threaten the system (e.g., a loss of well control) and map the progression of events as 

successive layers of safeguards are engaged. Fault trees can model the response of subsystems down to 

the component level. The modeling of PRA fault trees affords many insights into risk and reliability of 

the system, including how failures propagate through the system. 

b. Event Trees

Offshore well drilling typically proceeds in a sequence of repetitive steps: drilling ahead with suitably 

dense mud to prevent fluid influx from the formations being penetrated; setting casing to enclose and 
68

reinforce the well segment just drilled before proceeding to drill a further segment with denser mud; 

cementing the casing that has just been set to secure it to the well wall and prevent any openings that 

could allow hydrocarbons to migrate upward in the well; setting various plugs to ensure wellbore 

stability, provide zonal isolation, and/or create a barrier to potential well kicks or losses of well control; 

and continually testing and monitoring parameters, such as pressure readings and flow volumes, to 

confirm that well integrity is maintained. 

By consolidating this often complex sequence of steps into a few events, one could draw a very 

simple event tree.

50 For example, a failure of one or more barriers (e.g., mud, casing, cement, plugs) if 

not recognized through integrity testing and rectified, and if the blowout preventer fails, could result in 

a complete loss of well control. It is important to note that such an event tree would not model actions 

after the significant uncontrolled escape of hydrocarbons (SUEH) to mitigate the consequences of the 

accident, even though the mitigation would affect the overall risk. Therefore, the consequences of the 

accident may differ depending on the accident progression both before and after SUEH.

c. Available Data

BSEE currently collects a variety of data that could be useful in modeling some risks. BSEE requires 

operators to report incidents under 30 CFR 250.188, and may subsequently investigate the incident 

according to the procedures specified at 30 CFR 250.191. BSEE also conducts scheduled and 

unscheduled on-site inspections of oil and gas operations at least once a year, documenting any

 

50 For more information on how to develop and use event trees and fault tees in PRAs, see generally U.S. Nuclear 

Regulatory Commission, “Probabilistic Risk Assessment (PRA),” July 17, 2013, available at 

http://tinyurl.com/mefe7om; National Offshore Petroleum Safety and Environmental Management Authority, 

"Guidance Note: Hazardous Identification, N-04300-GN0107, Revision 5" (2012), available at 

http://www.nopsema.gov.au/assets/Guidance-notes/N-04300-GN0107-Hazard-Identification.pdf;. "Optimising 

Hazard Management by Workforce Engagement and Supervision," V. Trbojevic, Health and Safety Executive, 

United Kingdom Government (2008), available at http://www.hse.gov.uk/research/rrpdf/rr637.pdf .
69

Potential Incidents of Non-Compliance (PINC). PINCs help to determine whether a facility is operating 

up to standards, though the majority of PINCs are not precursors to a loss in well control and therefore 

would not be relevant for a risk model.

However, BSEE does not currently collect data that provides a comprehensive basis for a 

probabilistic risk model. In addition, BSEE is not aware of any current industry-wide efforts to collect 

data for such a purpose, although BSEE has requested that the Ocean Energy Safety Institute (OESI) 

develop a database related to equipment reliability that might provide useful information for the future 

development of a PRA. BSEE welcomes comments and suggestions on all potential sources of data that 

could be useful in developing probabilistic risk models for offshore oil and gas operations.

d. Questions

BSEE is interested in the public’s views on the potential advantages and disadvantages to

developing a PRA model for this rulemaking. We specifically seek comments on the following issues:

1) What would be the potential advantages and disadvantages if BSEE were to move to riskinformed decisions in this proposed rule through the use of methods such as PRAs and event 

trees?

2) Given that there are a significant number of offshore drilling operations with different types of 

rig construction and drilling plans, if BSEE were to use event trees in risk reduction assessments, 

how much detail would such event trees need so that they would be representative of the 

affected operators and best inform stakeholders and decision makers? Provide examples of

benefits and costs of any suggested level of detail and explain why that detail would be

appropriate.

3) Describe any completed, ongoing or planned activities, not associated with BSEE, that could 

provide information useful to the potential development of a PRA approach applicable to this 
70

proposed rules, including any analyses identifying areas of significant risk or uncertainties. If so, 

provide timelines for the activity, if not already completed; indicate whether the activity will be 

peer-reviewed; and explain how it could be used in the potential development of a PRA 

approach.

4) In addition to the request already made by BSEE to OESI mentioned above, please describe

any other planned or ongoing data collection efforts that could provide relevant information 

useful in the potential development of PRAs for offshore oil and gas activities? If there are no 

such efforts at this time, how could such a data collection program be developed?

5) What challenges and concerns would there be to industry providing data to inform and help 

BSEE decide whether to engage in PRA modeling? What are ways that the challenges and 

concerns could be mitigated?

Please provide data and studies, if possible, to support any comments.

11. UMRA

This proposed rule would not impose an unfunded Federal mandate on State, local, or tribal 

governments but would, if finalized, create a private-sector mandate that could require expenditures 

exceeding $100 million in a single year by offshore oil and gas companies operating on the OCS. The 

Initial RIA, the initial Regulatory Flexibility Act analysis for this proposed rule, and the proposed rule 

itself address applicable requirements of the UMRA, 2 U.S.C. 1501 et seq. 

Among other things, the proposed rule, the Initial RIA, or the initial RFA must: 

(1) Identify the provisions of the Federal law (OCSLA and OPA) under which this rule is being 

proposed; 
71

(2) Includes a quantitative assessment of the anticipated costs to the private sector (i.e., 

expenditures on labor and equipment) of the proposed rule (sections 5 and 6 above); and 

(3) Include qualitative and quantitative assessments of the anticipated benefits of the proposed 

rule (see section 7 above). 

In addition, because all anticipated expenditures by the private sector analyzed in the Initial RIA and 

the initial RFA analysis would be borne by the offshore oil and gas industry, the Initial RIA and initial RFA 

analysis satisfy the UMRA requirement to estimate any disproportionate budgetary effects of the 

proposed rule on a particular segment of the private sector. 

In addition, the Initial RIA describes BSEE’s consideration of three major regulatory alternatives 

(section 3). BSEE has decided to move forward with this proposed rule, in lieu of the other alternatives, 

because those alternatives would not as efficiently or effectively address the concerns and 

recommendations that were raised regarding the safety of offshore oil and gas operations and the 

potential for another event with consequences similar to those of the Deepwater Horizon incident or 

achieve the objectives of this proposed rule.

BSEE has determined that the proposed rule would not impose any unfunded mandates or any 

other requirements on State, local, or tribal governments; thus, the proposed rule would not have 

disproportionate budgetary effects on these governments. Assuming, however, that the proposed rule 

results in budgetary effects, BSEE has determined that accurately estimating such effects is not 

reasonably feasible. Because the proposed rule would not impose any requirements on any entities, 

other than operators engaged in OCS offshore oil and gas activities, any budgetary effects would be at

least secondary results of actions or decisions taken by regulated (or unregulated) entities, based on a 

variety of circumstances (such as the price of oil and each entities’ overall financial health) at the time. 

Because each of those factors is variable and unpredictable, it is not feasible to estimate how those 
72

factors would affect an entity’s future decisions, or what impacts, if any, such decisions could have on 

future regional budgets.

Similarly, BSEE has determined that accurately estimating the potential effects, if any, of the 

proposed rule on the national economy (e.g., productivity, economic growth, employment, international 

competitiveness) is not reasonably feasible. Any potential impact on the national economy would 

depend on individual business decisions made by regulated entities (e.g., whether or not to hire new 

employees). 
73

APPENDIX: List of Incidents Used in Benefits Analysis 

Exhibit A-1 lists the oil spills used in the benefits analysis, including the date, total volume spilled (in 

barrels), and the number of fatalities for each incident. Spills presented in Exhibit A-1 include only 

incidents caused by blowouts from 1964 to 2010 that resulted in spills of 10 barrels of more. These data 

were obtained from the BOEMRE OCS Spill Database. 

EXHIBIT A-1 : INCIDENTS USED IN BENEFITS 

ANALYSIS

Date Total Spilled 

(Barrels) Fatalities

1964-01-20 100 0

1964-10-03 5,100 0

1964-10-03 5,180 0

1965-07-19 1,688 0

1969-01-28 80,000 0

1969-03-16 2,500 0

1970-02-10 65,000 0

1970-12-01 53,000 0

1971-05-16 10 0

1971-10-16 450 0

1974-09-07 75 0

1974-12-22 200 0

1981-11-28 64 0

1985-02-23 50 4

1987-03-20 60 0

1992-12-26 100 0

1999-09-09 125 0

2000-02-28 774 0

2002-10-03 350 0

2003-03-08 10 0

2004-10-21 11 0

2006-02-20 10 0

2006-11-18 25 0

2007-10-21 1,061 0

2009-04-19 200 0

2009-12-30 62 0

2010-04-20 4,928,100 11

Source: BOEMRE OCS Spill Database, June 2011.