1



## Final Regulatory Impact Analysis for the Final Rule on Increased Safety Measures for Energy Development on the

Outer Continental Shelf

RIN 1014

- AA02



# Bureau of Safety and Environmental

Enforcement

March 7 , 201 22 

### Table of Contents

EXECUTIVE SUMMARY

................................ ................................ ................................ 5 INTRODUCTION AND NEE D FOR FEDERAL ACTION

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

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

................................ ......................... 10 HISTORICAL INFORMATI ON ABOUT BLOWOUTS

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

................................ ................................ .................... 12 Deepwater Drilling Activity

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

............................. 13 EXISTING AND NEW REGULATORY PROVISIONS

................................ .................. 14 Benefit

- Cost Approach

................................ ................................ ............................... 20 BASELINE ASSUMPTIONS IN THE BENEFIT

- COST ANALYSIS

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

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

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

................................ .............. 24 COMPLIANCE COSTS FOR THIS REGULATION

................................ ....................... 25 Seafloor Function Testing of ROV Intervention and Deadman Systems

- Drilling

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

– Workover/Completions/Abandonment

................................ ................................ ... 28 Testing the Subsea BOP between Development Wells and Workover/Completions/Abandonment on a Single Project

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

................................ ................................ ........................... 29 Installation of Dual Barriers

................................ ................................ ........................ 30 Professional Engineer Certification for Well Design

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

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

................................ ....................... 32 Paperwork Costs

................................ ................................ ................................ ....... 33 Summary of Annual Recurring Costs

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

................................ ....... 35 Voluntary Measures by Industry

................................ ................................ ................ 36 AVOIDED PRIVATE

- SOCIAL COSTS

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

................................ ................................ ............................... 37 Well Containment and Plugging

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

................................ ................................ ................................ .. 38 Fines and Criminal Penalties

................................ ................................ ..................... 39 Summary of Avoided Private

- Social Costs

................................ ................................ 39 AVOIDED EXTERNAL

- SOCIAL COSTS

................................ ................................ ...... 40 Conceptual Approach

................................ ................................ ................................ 41 Valuing Natural Resource Damages

................................ ................................ .......... 42 Caveats and Assumptions

................................ ................................ ..................... 47 Relationship between Natural Resource Damages and Spill Size and Type of Oil Spilled

................................ ................................ ................................ ................... 47 Valuing Commercial Fishery Losses

................................ ................................ .......... 483

Data Availability

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

................................ ................................ ................................ .................... 48
Revenues

................................ ................................ ................................ ....................... 51 Operating Costs

................................ ................................ ................................ ............. 55 Closures

................................ ................................ ................................ ......................... 58 Valuing Lost Recreation

................................ ................................ ............................. 60 Recreational Fishing

................................ ................................ .............................. 61 Beach Re creation

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

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

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

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

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

................................ ................................ ................................ ............. 6 9 Other Health Effects

................................ ................................ ................................ .. 69 Avoided Costs Associated with Other Activities Linked Economically to Avoiding an Oil Spill

................................ ................................ ................................ .................. 70 Summary

– Avoided External

- Social Costs

................................ ............................... 71 TOTAL ESTIMATED AVOI DE D SOCIAL COSTS (BENE FITS)

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

................................ ................................ ................................ 72 Baseline Scenario

................................ ................................ ................................ ...... 74 Sensitivit y of Compliance Costs

................................ ................................ ................ 74 Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blowout Spill

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

............... 76 Scenario Analysis Summary

................................ ................................ ...................... 77 Alternatives

................................ ................................ ................................ ................ 78 Small Business Alternatives

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

................................ ................................ ................................ .............. 79 Appendix A Final R egulatory Flexibility Act Analysis, RIN 1014

- AA02

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

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

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

................................ ................................ ................................ ................. 84 Shallow water

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

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

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

................................ ................................ .......... 90 Alternative 3, Paperwork Consolidation

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

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

................................ .................. 92 Appendix B Natural Resource Damage Data

................................ ............................ 94 Appendix C Well Data

................................ ................................ ................................ . 97 Appendix D Definitions

................................ ................................ ............................. 100 Append ix E References

................................ ................................ ........................... 102 Appendix F Voluntary Industry Measures Review

................................ ................ 10645



## EXECUTIVE SUMMARY

This document describes the regulatory impact analysis (RIA) conducted for the final rule, RIN
1014

- AA02 , Increased Safety Measures, Drilling Operations on the Outer C ontinental Shelf ( OCS )

. On October 14, 2010 BSEE’ predecessor agency published an Interim Final Rule (75 FR 63346) as RIN 1010 AD68 addressing certain recommendations from the Safety Measures Report, and soliciting public comment on the Interim Final Rule. The Interim Final Rule was effective immediately, with a 60

- day comment period. The Final Rule will modify, in part, provisions of the Interim Final Rule based on comments received, however many of the provisions adopted October 14, 2010, are retained without change. The resulting changes from the draft benefit cost analysis published with the interim final rule (IFR) are minor an d are mostly found in the compliance cost estimates for the final rulemaking. Because of regulatory changes in the final rule, revised cost assumptions and estimated drilling activity, the estimated annual compliance costs is reduced to $131 million from $183 million in the IFR.

V arious events around the world as well as the US over the years demonstrate that catastrophic oil spills can and do occur. The costs associated with such spills can be enormous . As a matter of policy, B SEE has decided that a ny reasonable measures to reduce the risks of another catastrophic spill occurring on the OCS should be put in place and enforced. The requirements included in this rulemaking are such measures. They were identified in the May 27, 2010 report,
Increased Safety Measures for Energy Development on the Outer Continental Shelf, for which the recommendations were peer

- reviewed by seven experts identified by the National Academy of Engineering, or identified by industry or academic experts in materials presented to BSEE as part of the public forums and information gathering

. Also on September 14, 2011 BSEE’s predecessor agency published the final joint investigation report on the causes of the Deepwater Horizon incident, which included multiple regulatory recomm endations. Upon review of the report recommendations, BSEE decided to include in the interim final rule only those recommendations that are appropriate for change without public comment (i.e. updating definitions and clarifications). The remainder of the report recommendations will be addressed through future rulemakings subject to public comment procedures.

While the estimated costs of this rulemaking, as reflected in the compliance costs of the enumerated requirements of approximately $131 million per year are based on updated BSEE
estimates from surveys of public and industry sources, quantification of the benefits is uncertain. The benefits are represented by the avoided costs of a catastrophic spill, which are estimated under the stipulated scenario as being $16.3 billion per spill avoided. These regulations will reduce the likelihood of another blowout and associated spill, but the risk reduction associated with the specific provisions of this rulemaking cannot be quantified because there are many6

complex factors that affect the risk of a bl owout event. As noted by the Secretary of the Interior in his July 12 , 2010 decision memo suspending certain drilling activities, drilling accidents can have a profound, devastating impact on the economic and environmental health of a region. The

measure s codified in this rule will reduce the likelihood of such an event in the future, at a cost that is not prohibitive, and therefore this rulemaking is justified.

The purpose of a benefit

- cost analysis is to provide policy makers and others with detailed

i nformation on the economic consequences of the regulatory requirements. The benefit

- cost analysis for this rule was conducted using a scenario analysis. This analysis considers a regulation designed to reduce the likelihood of a catastrophic oil spill. The costs are the compliance costs of imposed regulation. If another catastrophic oil spill is prevented, the
b enefits are the avoid ed costs associated with a catastrophic oil spill (e.g., reduction in expected natural resource damages owing to the reduct ion in likelihood of failure)

.

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

benefit s transfer approach is used to estimate the avoided costs. The benefit s transfer method estimates economic values by transferring existing benefit calculations from studies already completed for another location or issue to the case at hand

. Accordingly, none of the avoided costs used in this analysis of hypothetical catastr ophic spills rely upon, or should be taken to represent, our estimate for the DWH event commencing on April 20, 2010.

Three new requirements account for most of the compliance costs imposed by this regulation.
These are (1) use of dual barriers in the fi nal casing string to prevent hydrocarbon flow in the
event of cement failure , (2) application of negative pressure tests to the production casing string
for wells drilled with a subsea BOP , and (3) testing time for the ROV to close BOP rams after
the BOP has been installed on the sea floor. BSEE estimates that these three requirements will impose compliance costs of approximately $11 8 million per year, representing 91 percent of the total annual compliance costs of $ 1 31 million associated with this rulemaking. These cost estimates were developed based on public data sources, prior experience and confidential information provided by several offshore operators and drilling companies. The $ 1 31 million estimated annual comp liance costs are 29 percent less than the $183 million cost estimate for the interim final rule, largely reflecting a reduced estimate of the time it takes to conduct an ROV
function test when the BOP is on the seafloor and lower negative pressure test cos ts resulting from relaxed testing requirements in the final rule relative to the IFR. These reduced costs are partly offset by the costs associated with a revision that precludes use of a float valve to meet the
criteria for a second mechanical barrier an d by inclusion of paperwork costs omitted from the
estimates in the interim final rule.7

On the benefit side, the avoided costs for a representative deepwater blowout resulting in a catastrophic oil spill are estimated to be about $16.3 billion (in 2010 do llars)

. 1 Most of this amount derives from detailed cleanup estimates developed by the Department of the Interior Office of Policy Analysis using damage costs per barrel measures found in historical spill data (from all sources including pipeline, tanker, and shallow water as well as deepwater wells) and from aggregate damage measures contained in the legal settlement documents for past spills applied to a catastrophic deepwater spill of hypothetical size. The rest of this avoided cost amount represents th e private costs for blowout containment operations. In sum, three components account for nearly the entire avoided spill cost total: (1) natural resource damage to habitat and creatures, 2) infrastructure salvage and cleanup operations of areas soiled by oil, and (3) containment and well

- plugging actions plus lost hydrocarbons.

We believe that the compliance cost estimates are closer to the actual cost than those used in the IFR because of the information gathered since deepwater drilling resumed in the GOM in the Spring of 2011. On the benefit side, t he total avoided cost estimate of $16.3 billion (representing a measure of expected benefits for avoiding a future catastrophic oil spill) has not been revised. The true magnitude of an avoided spill is highly uncertain because of the limited historical data upon which to judge the cost of failure, the disparity between the damages associated with spills of different sizes, locations, and season of occurrence, and owing to the fact that the measure employed reflects only those outlays that we ha ve been able to calculate based primarily upon data derived from past oil spills . Possible avoided losses from human health effects or reduced property values have not been quantified in this analysis. Moreover, the likelihood of a future blow out leading to a catastrophic oil spill is difficult to quantify because of limited historical data on catastrophic offshore blowouts.

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

- cost exercise, are not relevant in calculating damages for any particular oil spill, including the DWH spill. Although the hypoth etical spill discussed in this document is similar in volumetric magnitude to estimations of the amount of oil released as a result of the DWH event, damages are highly specific to a particular event, and depend on a multitude of complex and interacting fa ctors. This report addresses a hypothetical Gulf of Mexico spill that is not intended to correspond to any real event, and whose characteristics have been designed to permit modeling and analysis, rather than being designed to reflect to the facts of a spe cific event or set of events. This document is also not able to incorporate scientific data relating to the specific circumstances of a particular spill or to any other specific spill, among other limitations of the model and analysis applied in this repo rt. Moreover, the nature of the economic analysis contained in this document, and the space limitations of this document, have required that a number of potential factors be excluded from the scope of the analysis, or have entailed other changes. Additio nally, the estimate of potential costs avoided used in this analysis do not reflect an assessment or quantification of the costs of injury or fatality resulting from the DWH event. As such, the damage and cost estimates presented herein should not be cons idered reliable monetary assessments associated with the DWH event. This document is only intended to provide a cost

- benefit analysis for a defined regulatory purpose, and is not intended to be used, and should not be used, for any other purpose or in any other situation. In particular, estimates contained in this report are not intended to be used, nor are of any relevance, in litigation relating to damages resulting from the DWH spill or any other spill.8

Based on the occurrence of only a single catastrophic blowout, the number of GOM deepwater wells drilled historically (4,123), and the forecasted future drilling activity in the GOM (160 deepwater wells per year), we estimate the baseline risk of a catastrophic blowout to be about once every 26 years. Combining the base line likelihood of occurrence with the cost of a representative spill implies that the expected annualized damage cost absent this regulation is $631 million ($16.3 billion once in 26 years, equally likely in any 1 year). To balance the $ 131
million annua l cost imposed by these regulations with the expected benefits, the reliability of the well control system needs to improve by 21 percent ($ 131 million / $631 million). We have found no studies that evaluate the degree of actual improvement that could be expected from dual barriers, negative pressure tests, and a seafloor ROV function test and no additional information was provided during the public comment period

. However, based upon the blowout risk reduction that would be achieved primarily from the th ree most critical safety provisions required by the Interim Final Rule and the Final Rule, it is reasonable to conclude that this rulemaking will reduce the risk for a catastrophic blowout spill event at least enough such that benefits will justify the cos ts estimated to be imposed by the regulation, or, at a minimum, 21
percent.9



## INTRODUCTION AND NEED FOR FEDERAL ACT ION

Investigative Reports

The final rule amends drilling regulations related to well control in response to recommendations in the Increased Safety Measures Report ( Safety Measures Report ) that DOI sent to the President on May 27, 2010

. 2 This regulation will affect all lessees and operato rs undertaking drilling operations on the OCS. The Safety Measures Report identified four items for emergency rulemaking: (1) Develop secondary control system requirements; (2) Establish new blind

- shear ram redundancy requirements; (3) Establish new deepwater well con trol procedure requirements; and (4) Adopt safety case requirements for floating drilling operations on the OCS.

The provisions of this final rule address items 1) secondary control system requirements and 3) deepwater well control procedure requirements. Th e rule does not include 2) new blind

- shear ram redundancy requirements and 4) safety case requirements for floating drilling operations. These and other items in the Safety Measures Report require further study by industry and the Department of Interior to determine their efficiency and effectiveness. Measures considered
beneficial will be proposed for future notice and comment rulemaking.

Th e Joint Investigation Team (JIT) report conducted by BSEE and the United States Coast Guard into the rig operations , and subsequent explosion, fire and sinking of the Mobile Offshore Drilling Unit (MODU) Deepwater Horizon made several recommendations consistent with the regulatory provisions in this rule. 3 This final rule only includes the recommendations from the JIT report that are within the scope of this rulemaking. The only changes made to this rulemaking from the JIT recommendations involve updating certain definitions and adding clarifications including that a dual float valve by its self is not considered a me chanical barrier. Other JIT report recommendations will be addressed in other future rulemakings and will be available for public comment.

The report by the Pre sidential Oil Spill Commission recommended the Department of the Interior should require offshore operators seeking its approval of proposed well design to

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

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

3 BOEMRE/USCG Report Regarding the Causes of the April 20, 2010 Macondo Well Blowout, available at: http://www.boemre.gov/pdfs/maps/DWHFINAL.pdf10

demonstrate that w ells are designed to mitigate risks to well integrity during post

- blowout
containment efforts. 4

This final rule requires additi onal testing for the BOP stacks on the seafloor and professional engineering certification of well design. It does not require subsea BOP stacks to be fitted with additional controls and sensors beyond the existing dual blue and yellow control pods. Simi lar to the regulatory recommendations in other reports, appropriate Oil Spill Commission recommendations will be addressed through future rulemakings.



### Need for Well Control and Voluntary Measures
In general, procedures for maintaining or regaining well co ntrol can be divided into primary and secondary measures. Primary measures include items such as the use of drilling mud, casing and cementing to keep the well under control. These requirements will strengthen primary well
control barriers t hereby reduc ing the likelihood that secondary barriers

, like the BOPs

, will be
needed. Secondary measures include the BOP stack and its redundant control devi c es to seal the well and prevent environmental or safety impacts in the case of a blowout event. The final ru le also requires increased testing of secondary measures including a check of remotely operated vehicle (ROV) intervention capability and deadman switch on the seafloor to better assure backstop activation of the subsea BOP

, should the need arise. These r equirements provide greater protections against a catastr ophic blowout event

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

.

The Secretary of the Interior (Secretary) ha s the duty to ensure that operations on the Outer Continental Shelf ( OCS ) are managed in a safe manner, under the authority of the OCS Lands Act (OCSLA). Section 21(b) of the OCS Lands Act provides guidance on the discharge of this duty as follows.
the S ecretary . . . shall require, on all new drilling and production operations and, wherever practicable, on existing operations the use of the best available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies

.

4 Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Part III, Lessons Learned: Industry, Government, Energy Policy http://www.oilspillcommission.gov/sites/default/files/documents/FinalReportPartIII.pdf , p. 275.11

The BSEE and BOEM carr y out this duty through regulations, inspection of OCS oil and gas operations

, the terms and conditions of leases and conditions of exploration and development plan approval. Although current regulations extensively address shallow and deepwater drilling operations, the DWH event and related investigations revealed that those regulations insufficiently protect the environment and those conducting operations on the OCS under certain situations.

There are other rationales for this regulation. The first relates to the uncertainty associated with actual damages and related magnitude of liability for those damages, and how that uncertainty may adversely influence operator behavior. Another rationale relates to information asymmetries. The regulator y regime in effect before promulgation of the interim final rule, wherein certain information did not come to the attention of regulators until after the event, perhaps provided too little information to regulators regarding the effectiveness of safe opera ting incentives embodied in the then existing regulatory regime. A more prescriptive regime, such as that contained in the interim final rule and the final rule, could assist in this regard by providing society with greater transparency and assurance that safety measures on all operations perform as expected. Lastly, because of statutory liability limits and the potential to avoid liability by declaring bankruptcy, offshore operators may take certain risks and cost

- cutting actions absent explicit federal r equirements relating to safety and the environment.

The regulatory changes published in the se new drilling regulations are designed to reduce both the frequency of a catastrophic spill and the severity of its impact (through a shorter period of discharge)

. The frequency of deepwater well control events (blowouts) that could lead to a spill does not appear to have changed materially over time. Historic data shows that blowout frequencies on the OCS have stabilized at about 1 for every 2 75 deepwater wells over the last
several decades (see the Baseline, Section

- Chance of a nother Spill for a more in

- depth
discussion ) . Thus, while a greater number of deepwater wells are being drilled in ever deeper water depths, this history indicates that normal evolution of deepwater practices may not have materially reduced the chance of a blowout event. Moreover, a blowout may pose more problems in deepwater where drilling a relief well is likely to take longer. Hence prescriptive regulations are being instituted to i ncrease the control measures that will manage and contain a blowout event with a greater degree of reliability.

We recognize that liability implications and increased insurance costs may compel changes by drilling companies independent of these regulation s. Accordingly, BSEE’s predecessor agency (BOEMRE) commissioned an outside assessment of the voluntary measures proposed by Joint Industry Task Forces (JITFs) in May, 2010 as compared to these regulations

. (See Appendix F).
While the lessons learned or other measures have not been fully implemented, an assessment of12

existing JITF proposals serve as guidance on how much of the addition al costs industry may incur are not really imposed by the new regulations. Joint Industry Task Force draft
recommendations include use of mechanical barriers and negative pressure tests which happen to account for a substantial share of the compliance costs we attribute to the final rule. We did not adjust for these potential voluntary actions, so for this reason our complian ce cost estimate may be higher than the actual costs imposed by this rule.

While voluntary measures by industry may result in some of the same changes, the federal government has an obligation to protect offshore workers, the environment and our economic interests with regulations that make critical changes in systems legally enf orceable . The catastrophic failure of the primary and secondary barriers on the Mac o ndo well (the location of the DWH blowout) supports federal regulations intended to reduce the identified risks.



## HISTORICAL INFORMATI ON ABOUT BLOWOUTS

The “no action” baseline is the recent Gulf of Mexico deepwater oil and gas activity levels and
the historical rate of events up to and including the April 20, 2010 DWH blowout. The DWH spill is the first U.S. Gulf of Mexico catastrophic deepwater blowout spill.



### Shallow Water Drilling Activity
While well control incidents a ctually occur more frequently in shallow water, the consequences and spill damage resulting from a blowout tends to be less than in deep water due to the generally lower reservoir pre ssure, the greater prevalence of gas rather than oil

, and the presence
of more accessible surface BOPs with diverters. From 1990

- 2010 BSEE has recorded 6 GOM shallow water well control incidents resulting in a spill of hydrocarbons. The total volume spil led is estimated to be 132 barrels of oil or condensate over these last two decades. If we go back another 20 years to 1970, we add another 6 spills for total hydrocarbon spill volume of 138.5 barrels from 12 blowout events over the last 40 years in the G OM. Since 1970 there have been 32,339 shallow water wells drilled in the GOM and since 1990 there have been 13,675 shallow water wells drilled. Over this period there have been several major revisions to the drilling regulations and some of these regulato ry changes have specifically addressed drilling
risks in shallow water.

While minimal drilling activity has occurred in the Alaska program areas, spill frequencies are expected to be lower than the Gulf of Mexico. This result excludes consequences. The study supporting this conclusion (Bercha 2008) uses different spill sizes and probabilities than used in this analysis for a catastrophic spill event, but the conclusion remains. Because the13

overwhelming share of historical OCS wells and future shallow w ater drilling is expected to be in the GOM, this analysis relies on historical GOM data. Approximately 81 percent of t he compliance costs for this regulation fall on deepwater wells.
Thus

, in our analysis the baseline chance of another spill and the calculation of avoided costs focus exclusively on a scenario in which hypothetical catastrophic deepwater blowout event s may occur randomly at some periodic rate based on the historical evidence

.



### Deepwater Drilling Activity
BSEE obtained th ese historical data on deepwater drilling from its Technical Information Management System database. There have been 4,123 wells spudded between 1973 and mid

2010 not counting bypasses in water depths of at least 500 feet.

There have been 20 OCS deepwater blowouts i n the history of the program with 3 resulting in a spill during drilling operations. Only one deepwater blowout has resulted in a spill of a catastrophic size. The other two deepwater blowout spills were estimated to be 11 and 200
barrels of crude/conden sate spilled.

The 20 deepwater blowouts average one blowout for about every 200 deepwater wells drilled on the OCS. The average number of wells between blowouts increased until about 1990 but has
since leveled of

f at about one for every 275 deepwater w ells.



### Baseline Size and Duration of a Catastrophic Deepwater Blowout Spill
Since the baseline for this regulatory analysis is the world at the time of the DWH spill and without these regulations, we are using a n estimate of spill volume similar to the government
volumetric estimate of the DWH event. Estimates of potential natural resource damages and other avoided costs are based upon this blowout spill volume but in all other respects are derived from information not specific to this sp ill.

The baseline size and duration of the catastrophic spill used in this analysis is taken from the National Incident Command’s (“NIC”) updated estimate of August 2, 2010 of the DWH spill. The scientific team charged by the NIC with determining flow rate concluded that 53,000 barrels of oil per day were leaking from the well immediately before closure by the capping stack on July 15, 2010. Measurements and modeling showed that, as a result of depletion of the reservoir, the daily flow rate decre ased over the 87 days prior to the capping of the well; the scientific team estimated at the beginning of the spill, the flow rate was 62,000 barrels per day. BSEE is using
the estimate of 53,000 barrels a day for 90 days as the figure upon which to base the estimated avoided costs for this regulatory analysis. While a catastrophic deepwater spill may have a higher flow rate in a worst

- case scenario, the 53,000 barrels a day for 90 days is a reasonable14

proxy for regulatory cost

- benefit analysis purposes. This scenario results in an oil spill of 4. 77
million barrels.

This 4.77 million barrel estimate is also consistent with the Central Planning Area Gulf of
Mexico Sale 216/222 SEIS

. 5 It is approximately the mid

- point of a potential catastrophic deepwater GOM spill event . The range for a catastrophic spill event is assumed to be between
2.7 and 7.2 million barrels. The 216/222 SEIS catastrophic spill e vent assumptions are excerpted
below.

3.1.3.2. Deep Water For the purposes of this analysis, an uncontr olled flow rate of 30,000

- 60,000 barrels per day is assumed for a catastrophic blowout in deep water. This flow rate is based on the assumption in Section 3.1.3, well test results, and the maximum expected flow rate of the 2010 Deepwater Horizon blowout, which occurred in deep water. Therefore, total volume of oil spilled is estimated to be 2.7

- 7.2 million barrels over 3

- 4 months. In addition, deepwater drilling rigs hold a large amount of diesel fuel (10,000

- 20,000 barrels). Therefore, it is assumed tha t any remaining diesel fuel from a sunken drilling rig would also leak and add to the spill.



## EXISTING AND NEW REGULATORY PROVISIONS

This final rulemaking revis es selected sections of 30 CFR 250 subparts D, E, F and Q as related to the drilling of new wells

. As in most benefit

- cost analysis studies a full compliance scenario is assumed and analyzed for the baseline and new regulatory requirements. We expect o nly a portion of the proposed changes in Subpart D will add material capital or operating costs (some of which will be significant ) to the drilling of new OCS wells

. 6 Table 1 compares the existing 30
CFR 250 Su bpart D provisions with the new provisions. As demonstrated since the publication of the IFR these requirements can be implemented immediately using existing equipment and established practices. Those changes that will impose significant costs include:

1. S eafloor function testing of ROV intervention and deadman systems; 250.449(j) and (k), 250.516(d) and 250.616(h)

. 2. Negative pressure testing of the final casing string for wells drilled with a subsea BOP; 250.423(c).
3. Installation of dual barriers for the fin al casing string; 250.420(b).

5 OCS EIS/EA BOEMRE 2011

- 027 http://www.gomr.boemre.gov/PDFs/2011/2011

- 027.pdf

6 Identical costly new requirements for subsea function testing of ROV intervention during drill operations (Subpart D) also apply to well completion (Subpart E) and wor kover (Subpart F) operations.15

4. Professional engineer certification that the well design is appropriate for expected well bore conditions; 250.420(a).
5. Retrieval and testing of BOP after a shear ram has been activated in a well control situation; 250.451(i).

6. Third party verification that the shear rams will shear drill pipe under maximum anticipated pressure; 250.416(e)

7. Additional record keeping and other paperwork required by the regulations.16 Table 1

- 30 CFR 250 Subpart D Provisions
EMERGENCY SUBPART D /E/F/Q FINAL RULE PROVISIONS Regulation Summary Existing Regulatory
Provisions (before

IFR New Regulatory Provisions (final rule) Cost

30 CFR §250.415(f) Evaluate best

practices in
API RP 65

- Part 2 - No evaluation

required - Requires the operator to evaluate the best practices according to API
RP 65

- Part 2 and submit a written description for the evaluation. - No meaningful

cost

- Written description must include
the mechanical barriers and cementing practices the operator will use for each casing string.

- API RP 65 Part 2 addresses cementing practices and factors affecting cementing success.

30 CFR §250.416(d)

, §250.1705 Submittal of

schematics of
all control systems for
BOP stack - Schematic of BOP

system showing inside diameter of BOP stack, number and type of preventers, location of
choke and kill lines - Schematics of all control systems, including primary controls, secondary controls, and pods for the BOP system must be
submitted. - No meaningful

cost

- Location of the controls must be
included

30 CFR §250.416(e)

, §250. 1712 ( g ) Independent

third party
verification

to ensure
blind

- shear

rams are capable of cutting the drill pipe
used - Information that the

blind

- shear ram is capable of shearing the pipe - Verification that the blind

- shear
rams installed in the BOP stack are capable of shearing the drill pipe or tubing in the hole under maximum anticipated surface

pressure. - Independent third party certification will require a small cost per well

- No independent third party certification required - Independent third party must be a technical classification society or an API licensed manufacturing, inspection, certification firm, or licensed professional engineering
firm. - Will add moderate

costs

30 CFR §250.418(i) Submit

qualifications
of independent third parties
with APD - No independent third

party certification required - Description of qualifications in accordance with §250.416 (e) - No meaningful

cost17

30 CFR §250.420(a)( 6)

, §250. 1712 ( g ) Professional

Engineer
certification
of well casing and cementing

program - No PE certification

required

- Certify the casing cementing design is appropriate for the purpose it was intended under expected wellbore conditions - Small cost per well if perfo rmed by an independent third
party

- No cost if PE
certification is done
in house

- Assumed that some majors would verify

in

- house; smaller operators will use third party

30 CFR §250.420(b)( 3) Dual barriers

- No requirement

- Operator must install dual
barriers including one mechanical barrier in each annular flow path. - Installation of dual
barriers and the increased drilling depth required to
install the
mechanical barrier is
estimated to be on average 12 hours.

- Will add significant costs to regulation

.

30 CFR §250.423(b) ( 2) Pressure test

on the casing
seal assembly - Perform a pressure

test on all casing strings (except drive/structural) according to 250.423 (a) - Additional pressure test for the
intermediate and production casing strings on the casing seal assembly to ensure proper installation of the casing in the subsea wellhead. - Pressure tests are already required, no extra equipment
time

- No requirement to

ensure proper installation of the casing in the subsea
wellhead - Each pressure test only takes a few
minutes

- No meaningful

cost18

30 CFR §250.423(c) Negative

pressure test - No negative pressure

test required - Perform a negative pressure test to ensure proper installation of the
final casing string or liner and prior to unlatching the BOP for all
wells drilled with a subsea BOP. - Negative pressure
test will take 3 hours for each required string of casing

- Will result in significant costs for the regulation

30 CFR §250.42 8 If operator

receives
indication of inadequate cement job

, conduct
further tests. - No specific

evaluation required Operator must: run a temperature

survey, r un a cement evaluation log; or u se a combination of these techniques

. - These tests would normally be conducted by a prudent operator. This regulation will
not add additional

costs.
30 CFR §250.442(e) Maintain

ROV and a
trained crew - ROVs used for visual

inspection every 3 days; 250.446(b) - Required to maintain an ROV
and trained crew on each floating rig on a continuous basis. - All rigs are
assumed to have an
ROV on board. This regulation will not
add additional costs.

- ROV must be capable of shutting in the well during emergency
situations - Regulation does not require a timed

test, therefore
current ROVs will be capable of performing all required functions.

30 CFR §250.442(f) Provide an

autoshear
and deadman system for dynamically positioned rigs - No

autoshear/deadman system requirement - All dynamically positioned rigs
must have an autoshear and deadman system - Industry standard for dynamically positioned rigs is to
have autoshear/ deadman systems

- No meaningful

cost
30 CFR §250.442(g) Barriers on

BOP control panels to
prevent
accidental
disconnect
functions - No two

- handed

requirement - Incorporate enable buttons on control panels to ensure two

handed operations for all critical
functions. - No meaningful

cost

30 CFR §250.442(h) Label subsea

BOP control panel - No labeling

requirement - Clearly label all control panels, such as hydraulic control panels
and ROV interface on the BOP - No meaningful

cost19

30 CFR §250.442(i) Develop

management system for

BOP - No management

requirement - Develop and use a management system f or operating the BOP
system - No meaningful

cost

- Written procedures for operating
the BOP stack and LMRP

- Minimum knowledge requirements for personnel authorized to operate and maintain critical BOP components

30 CFR §250.442(j) Training for

BOP equipment - No training

requirement - Train BOP personnel in deepwater well control theory and practice in accordance with 30 CFR 250, Subpart O - No meaningful

cost

30 CFR §250.446(a)

, §250. 1708(a) Document

maintenance
and inspections

to BOP
system - No documentation

requirement - BOP maintenance and inspections must meet or exceed provisions of Section 17.10 and

18.10 Inspections; 17.11 and 18.11, Maintenance; 17.12 and 18.12 Quality Management in API

RP 53 - No meaningful

cost20

30 CFR §250.4 49(j)

, §250. 5 1 6 ( d), §250. 6 1 6 ( h )

, §250. 1707(h) Subsea

function test
for ROV
intervention
on a subsea
BOP stack

Additional stump testing requirements - No initial test on the

seafloor - All ROV intervention functions must be tested during the stump
test and one set of rams during the
initial test on the seafloor

. - Initial test on the
seafloor is not industry standard
and is estimated to
take about 2 hours.

- Stump test BOP stack

- ROV h ot stabs must be function

tes ted and capable of actuating at
least 1 set of pipe rams, 1 set of
blind

- shear rams and unlatching
the LMRP - No meaningful

cost since stump
tests can be conducted topside prior to BOP deployment.

- Operator must examine all
surface and subsea well control equipment to ensure that it is properly maintained and capable of shutting in the well during emergency operations - Will add significant costs to well drilling, workover,
abandonment and completion operations

30 CFR §250.449(k)

, §250. 5 1 6 ( d), §250. 6 1 6 ( h )

, §250. 1707(h) Autoshear/

Deadman
function test - No required function

test - The autoshear and deadman systems must be function tested during the stump test and the
deadman tested on the seafloor. The deadman test is
estimated to take
about 2 h ours on

average.

30 CFR §250.451(i) Emergency

activation of
blind or casing shear

rams - No required action

- If the blind

- shear or casing shear
rams are activated in a well control situation, the BOP must be retrieved and fully inspected and
tested - Emergency situation only, will incur significant loss of rig time when
activated

30 CFR §250.456(j)

, §250. 514(d), § 250.614 (d), §250. 1709 Displacement

of kill

- weight
fluid from
the wellbore - No required action S ubmit APM, with reasons for displacing the kill

- weight drilling fluid and provide procedures describing ho w the fluids will safely displace

. - No meaningful

cost



### Benefit

- Cost Approach
The purpose of this regulatory impact analysis is to meet the requirements of Execu tive Order
12866 ( Regulatory Planning and Review ) and OMB Circular A

- 4 by providing policy makers
and others with detailed information on the consequences of the regulatory requirements. This is

a significant rule because of the policy implications and es timated annual costs of more than $100 million.

A benefit

- cost analysis requires estimating the net benefits associated with the rule. Net
economic benefits are total benefits less total costs. The benefits from this rulemaking include21

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

consequence of stricter well control requirements. Costs include compliance costs associated
with the specific provisions of the rule, such as wider use of best well desig n practices, extra testing and certification requirements , along with any additional administrative costs anticipated
as a result of the rule

.

A benefit

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

- cost a nalysis reflect direct first

- order real resource market outcomes, such as more abundant or higher valued outputs and the accompanying enhancement of consumer utility, along with the costs imposed by the regulatory action as expressed in terms of the market value of the scarce factors of production needed to comply with the rulemaking. In contrast, while an economic impact analysis could include these output measures as well, it tends to focus upon broad macroeconomic measures, such as national income, empl oyment, wages, and revenue transfers, among others, as they may be relate to specific industries and geographical locations associated with the regulatory requirements. Anecdotal economic impact information is provided for commercial fisheries impacts con sistent with the avoided cost estimate for this analysis.

Th e approach use d in this benefit

- cost report utilizes consumer surplus measures to estimate
avoided

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

- cost impacts on in dustry , i.e., the benefits of the regulatory action, rather than measuring these benefits from disparate economic considerations such as lost wages and employment in affected industries (hotels, restaurants, charter fishing boats, etc.)

. E stimated output impacts do not
account for the value of the increased environmental benefits (or reduction in potential environmental damages) that accrue to individua ls, as part of consumer surplus.

In the case of this rule, we have not been able to quantify the precise extent to which the new safety measures required by this rulemaking can be expected to reduce the chance of another catastrophic oil spill. A study by Det Norske Veritas for the Canadian National Energy Board titled Beaufort Sea Drilling Risk Stud y dated March 11, 2010 used a fault tree analysis methodology to develop estimates of the change in the probability of a blowout associated with several secondary well control measures like enhancements to
the BOP. We have not discovered sufficient data t hat would allow adapting that methodology to the change in the probability of blowout associated with the enhanced primary well control measures in this rulemaking. Nor have w e found other studies that evaluate the degree of improvement that could be expe cted from enhanced barriers, pressure tests, and a seafloor ROV function check.22

The preamble to the interim rule requested comments on the availability of appropriate well design reliability studies. Commenters did not cite any applicable reliability stu dies.



## BASELINE ASSUMPTIONS IN THE BENEFIT

- COST ANALYSIS

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

baseline is the recent Gulf of Mexico deepwater oil and gas activity levels and the historical rate
of events up to and including the April 20, 2010 DWH blowout. The DWH spill is the first U.S. Gulf of Mexico catastrophic deepwater blowout spill. While there have been other OCS spills
and blowouts

, the requirements in this rule are primarily focused on deepwater and designed to prevent or more quickly control deepwater blowouts. Estimates of potential natural resource damages are based on a spill volume similar to the government estimate of the DWH blowout spill volume but in all other respects are deri ved from information not specific to this spill.
Estimates are also consistent with projections of future GOM deepwater drilling activity 7

.

We estimated t he baseline rates of deepwater blowouts, injuries, fatalities and spills directly from
historical d ata. Th is baseline assumes that industry has not voluntarily implemented additional safety and protection measures as a result of the lessons learned from the DWH spill. This assumption may overstate likely future blowout chances under existing regulatio ns since industry
can be expected to implement some new safety measures on its own

. Because of this uncertainty
about many of the se changes

, difficulty of quantifying them and the time limitations under which analysis was conducted for this rulemaking

, we did not adjust the baseline for any voluntary

measures.



### Baseline Estimates of Future Deepwater Drilling Activity The key drilling input for this benefit

- cost analysis is the future number of GOM deepwater
wells. BSEE projected average deepwater drilling activity for 2011

– 2030 in the Central and
Western GOM using 6 different methods and then calculated the 20

- year average to determine a reasonable drilling projection

. The component projections were based on recent trends in

7 The damage and loss estimates in this analysis are purely hypothetical and do not provide values applicable to the
DWH event. They are not pertinent to the DWH event because they rely on dollar per barrel factors derived fr om a number of earlier spills. These dollar measures vary widely across the different spills in the sample set so the average is not relevant to any actual spill. The exception is for well containment costs cited directly by BP and extrapolated to a hypo thetical GOM deepwater catastrophic blowout event postulated in this analysis. Otherwise, there is insufficient information available at this time to determine the magnitude of the costs that could have been avoided, including natural resource damages, fr om the DWH event. Moreover, the estimate of potential costs avoided used in this analysis do not reflect an assessment or quantification of the costs of injury or fatality resulting from the DWH event. As such, the damage and cost estimates presented he rein should not be considered reliable monetary assessments associated with the DWH event.23

drilling, leasing

, aggregate production forecasts and other available data. Using these techniques we estimate d there will be an average of 160 deepwater wells drilled annually over the next 20 years.

However, going forward this pace of deepwater drilling activity may be optimistic even if drilling regulations did not change. The main reason is that a larger share of future deepwater wells will be deeper (25,000 to 36,000 feet as opposed to under 22,000 feet in the recent past) requiring more ti me to drill and complete. Together with the new safety regime 8 , operators may average fewer wells drilled each year. In the section titled Sensitivity of Number of Deepwater
Wells Drilled per Year (25% lower) we estimate the benefits/costs under an alternative scenario of 120 deepwater wells per year.

The drilling of 160 deepwater wells per year is used to estimate the expected interval before another catastrophic blowout similar to the DWH

. This projection was divided into 112 wells drilled from floating rigs and 48 from rigs on deepwater production platforms. The recent
histori cal annual well coun t is shown in Figure 1

. 9

Figure 1

- Historical Deepwater Wells (Greater than 500 feet)

8 Under the new safety regime, deepwater drilling permits require more complex analyses by both operators of deepwater leases and BSEE prior to approval. These complex reviews include determination and verification of worst case discharge and planned blowout scenarios (included in revised plans) for potential blowouts, submittal and review of containment plans (including well screening t ool) for potential blowouts, review of blowout preventer (BOP) diagrams and shearing capabilities, and review of certifications of casing and cement analyses proposed for the wells.

9 All counts of wells exclude bypasses which are often included in other B SEE counts of spudded wells. These counts also exclude well completion and workover operations which involve re

- entering a wellbore and re

deploying of BOPs and ROVs. The count includes sidetracks.24



### Shallow Water Drilling Activity
While the greatest cost imposed by this regulation will affect deepwater drilling activities using
MODUs

, new regulatory testing and casing requirements apply to wells drilled both in shallow water and deep water . Future regulatory compl iance costs for shallow water wells are estimated using the 2009 GOM shallow water drilling activity rate of 186 wells a year and the additional costs imposed on shallow wells by this regulation.



### Baseline Chance of Another Deepwater Blowout Spill

The basel ine chance of another catastrophic deepwater blowout spill uses only deepwater drilling, blowout and spill data on the U.S. federal OCS. BSEE has obtained this historical data from its Technical Information Management System database. There have been 4,1 23 wells spudded between 1973 and mid

- 2010 not counting bypasses in water depths of at least 500 feet.

There have been 20 OCS deepwater blowouts in the history of the program with 3 resulting in a spill during drilling operations. Only one deepwater b lowout has resulted in a spill of a catastrophic size. The other two deepwater blowout spills were estimated to be 11 and 200 barrels of crude/condensate spilled.

The 20 deepwater blowouts average one blowout for about every 200 deepwater wells drilled on the OCS. The average number of wells between blowouts increased until about 1990 but has
since leveled of

f at about one for every 275 deepwater wells.

Using the estimated 160 new deepwater wells that will be drilled annually, we estimate a catastroph ic blowout spill under current regulations and practices to be 1 in 4,123 wells. This implies a baseline major spill once every 26 years under current deepwater drilling rates. A sensitivity analysis was conducted on this baseline probability assumption. The results of that analysis can be found in the section titled Scenario Analysis

.



### U ncertainties
Available data on drilling system reliability do not allow computation of the blowout risk reduction associated with the specific provisions in this rulemaking. Future long term studies should be conducted to assess the likely effectiveness of these and o ther increased safety measures, using statistical analysis of historic information on existing well configurations and testing practices. Cross

- sectional data that are now collected but not captured in the BSEE TIMS data base may enable studies that asses s how requirements for subsea ROV and deadman testing, use of negative pressure tests, dual barriers in the final casing string, along with the remaining items required in this rulemaking, could improve well control performance.25

We can expect the risk a nd impact of a deepwater catastrophic blowout will be lessened by other factors not specifically addressed in this analysis. Industry and government reaction to th e DWH spill has added experience that will improve the human factors of planning and respons e. The technology used to mitigate spill effects before a relief well is completed is currently deployed
and on stand

- by in case of a blowout and subsea BOP failure. While these are significant advances, the nature and impact of these changes are not eas ily quantifiable and are not included
in the benefit

- cost baseline.

Another area for further inquiry involves determining the impact and cost of a catastrophic deepwater oil spill. Ongoing studies will be helpful to more fully record the effects of a catastrophic deepwater blowout on the natural and human environments in the Gulf of Mexico. One ongoing BOEM study is titled Simulation Modeling of Ocean Circulation and Oi l Spills in the Gulf of Mexico (GM110

- 2). Universities and consultants are conducting environmental studies of the Gulf of Mexico and the impact of the DWH event over the next decade. We also note that the basis for our damage estimates relies on dollar per barrel factors derived from
historic near

- shore spills which may not be the best analogies for a future deepwater spill far from land. If future estimates of the individual cost elements of a hypothetical deepwater spill imply that the resulting socia l costs vary significantly from our hypothetical $16.3 billion benefit

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



## COMPLIANCE COSTS F OR THIS REGULATION

This section addresses the main compliance costs resulting from this regulation. The compliance costs fall primarily on lessees and operators operating on the federal OCS because t he rule raises drilling costs for each new deepwater well and shallow water well on the OCS . These new requirements add mechanical barriers to well design requirements and time for testing several features during drilling operations. BSEE estimates that each year the s even activities discussed
in this section will add $ 131 million to the cost of operations on the OCS. For purposes of calculating annual costs associated with this rulemaking, we assume that in an average year operators will drill 160 deepwater wells and 186 shallow wells on the federal OCS as well as complete 36 workover, completion and abandonment operations using a subsea BOP

.26



### Seafloor Function Testing of ROV Intervention and Deadman Systems

- Drilling
Current regulation s at 30 CFR 250.449(b) require a stump test of the subsea BOP system

. In a stump test, the subsea BOP system is placed on a simulated wellhead (the stump) on the rig designated area. The BOP system is tested on the stump to ensure the BOP is functioning properly. New sections § 250.449(j), §250.516(d), §250.616(h) and §250.1707(h) require that all
ROV intervention functions on the subsea BOP stack must be tested during the stump test and one set of rams must be tested by an ROV on the seafloor

. New sections § 250.449 (k), §250.516 (d), §250.616(h) and §250.1707(h) require that the autoshear and deadman systems be function tested during the stump test, and the deadman system tested during the initial test on the seafloor. The initial test on the seafloor is performed as soon as the B OP is attached to the subsea wellhead. This section provides the calculations for drilling subsea ROV testing compliance costs. The following section provides the calculations for workovers

, completions and
abandonment operations.

BSEE assumes it is an industry standard to have ROVs on board

. Regulation 250.446(b) requires that all subsea BOPs and marine risers must be visually inspected every 3 days ; ROVs are the industry standard for meeting this requirement, therefore we reasonably assume all rigs
ha ve ROVs . BSEE also assumes dynamically positioned rigs have autoshear/deadman systems. BSEE has data showing that all dynamically positioned rigs being used in the Gulf of Mexico employ an autoshear/deadman system. Therefore, it is assumed to be industry standard for all dynamically positioned rigs to have an autoshear/deadman system.

These new requirements will provide a higher probability that a well will be secured in an emergency situation and prevent a possible loss of well control . Autoshear and deadman control systems activate during an accidental disconnect or loss of power respectively. Th e ROV test requirement will ensure that the dedicated ROV has the capacity to close a BOP ram on the sea floor using its pump or an available accumulator bank. The deadman test on the seafloor verifies that the BOP closes automatically if both hydraulic pressure and electrical communication are lost with the rig

.

BSEE’s predecessor agency conducted a survey to investigate the potential impact of subsea ROV testing. Several d rilling contractors, lease operators and equipment manufacturers were
asked: “H ow long would it take to function test the ROV to ver if y that the ROV could be used to
close one s et of blind

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

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

However, the regulation only requires one set of rams and the deadman system to be tested on
the sea floor ; not two rams (one pipe ram/one blind

- shear ram) nor disconnecting the LMRP

. The 24 hour survey average in the IFR was an overestimate based on the final regulations. Since the publication of the interim final rule in October, 2010, BSEE has had the opportunity to observe stump tests and subsea tests required by this rulemaking. The testing of one set of rams on the seafloor is estimated to add about 2 hours on average to the testing time. The deadman system
seafloor tests are estimated to take 2 ad ditional hours. The total additional time for the subsea tests is estimated to be about 4 hours on average. 10 The estimate of 4 hours is a reduction from the 24 hours used for the interim final rule analysis. Th e regulatory provision will not affect platf orm rigs or shallow wells since they do not use subsea BOPs.

Multiplying the number of estimated deepwater MODU wells each year (112) by the weighted average day rate ($916,622) by 4/24 hours yields a total estimated compliance cost for this provision of $ 17

. 1 million . This is one

- sixth the cost estimated in the analysis for the interim
final rule. Table 2 reports the number of the various kinds of deepwater drilling rigs operating in the Gulf of Mexico and the rig (day) rates used to calculate the cost of the extra 4 hours added to
drill time. The rig rate was taken from RIGZONE and increased (loaded) to reflect the assumed cost of the assorted support contractors on the rig whose services are not covered in the day rate. The loaded day rate is appropriate because BOP and other tests cannot b e scheduled with

accuracy so they occur in the middl e of the drilling operations. The subsea BOP is not lowered to the seafloor until after the surface casings are set (maybe 10

- 30 days into the drilling) when
the increased down

- hole pressure and risks fo r gas kicks and blowouts are possible. Most deepwater wells are drilled more than 100 miles off shore and contractors and supplies that contribute to the loading of the day rate are contracted for the duration of the drilling operation.
Part of the reason that crews stay on the rig for 2 weeks at a time is that round trips to shore are expensive, so “unloading” and “reloading” for part of a day is likely to cost more than maintaining capability at the ready. Additionally, delays and problems occur frequen tly during drilling operations and it is standard practice to maintain the contractor and company capability available to resume operations as soon as the problem is resolved.

10 T he ROV stump test components are not considered becau se they are not expected to significantly increase testing time. Some operators simulate the hydraulic flow of an ROV to perform the stump test on the BOP stack, while others use an actual ROV to stump test the BOP stack; this regulation remove s the option of simulating hydraulic flow and require s the use of an ROV during the stump test.28 Table 2

– Rig Counts, Day Rates, and Annual Drill Rates Rig Type Number of Rigs Loaded Day Rate Wells Drilled/Year

Drillship 11 $1,000,000 33

Deep Semisubmersible 21 $923,953 63

Low Semisubmersible 4 $715,792 16

MODU Total or Weighted Average 36 $916,622 112

Platform (deepwater) 10 $400,000 48

Shallow water n/a $200,000 186



### Seafloor Function Testing of ROV Intervention and Deadman Systems

– Workover/Completions/Abandonment
As is the case with drilling operations, regulations in place before the IFR did not require subsea ROV function testing of the BOP during workover completions, or abandonment operations. New sections 250.516(d), 250.616(h) and §250.1707(h) require testi ng of ROV intervention functions and the autoshear/deadman systems during the stump test, and a function test of at least one set of rams and the deadman system during the initial test on the seafloor. These section s extend the requirements added to deepwa ter d rilling o perations (discussed in the previous section) to well completion operations , workover and abandonment operations using a subsea
BOP stack. Successful exploratory wells are typically temporarily abandoned until additional equipment is install ed to produce the reservoir. When the operator is preparing to produce the well it is often completed using a different rig or redeployment of the original rig. This testing time for completion operations is estimated to also be 4 hours. This is in addi tion to the 4 hours testing time discussed in the previous section for selected wells. BSEE estimates that on average each year there will be 12 completions, 12 workovers and 12 abandonments each year employing
a subsea BOP. Using a weighted average of MODU day rates ( Table 2 )

, 36 ( 1 2 workovers [plus] 12 completions [plus] 12 abandonments) redeployments of a BOP will cost $ 5.5 million

. This is

one

- third of the cost estimated in the interim final rule analysis. This compliance cost reduction is the result of the testing time being reduced to 4 hours from 24 hours while being partially offset by the revised counts of workove rs/completions and the addition of the 12 annual
abandonment subsea BOP tests not counted in the interim final rule.29



### Testing the Subsea BOP between Development Wells and Workover/Completions/Abandonment on a Single Project

BSEE past history, practice and c ustom was that departures were routinely but not always granted when an Operator wished to move a subsea BOP between wells on the same project without pulling the BOP to the surface for a visual inspection and stump test. Comments on the
IFR claimed that the compliance cost for rulemaking was greatly under estimated. Commenters claimed the cost to pull a BOP for a visual inspection is underestimated and the real cost of pulling a subsea BOP for a visual inspection would result in a $5

- $15 million opportunity cost.

BSEE’s termination of the practice allowing Operators to “hop” a subsea BOP between wells on the same development project is not the result of this regulation, but rather BSEE’s cessation of the practice of granting departures t o existing regulations ( 30 CFR 250.446 ). BSEE acknowledges the opportunity cost to pull a subsea BOP for the full suite of inspections may range between 5

- 14 days. BSEE estimates that this practice may have applied up to 50 wells or workover/completions /abandonments using a MODU each year. If an average of 7 days is added
to th e time required to drill or complete these 5 0 wells, the increased cost would be approximately $320.8 million (5 0 wells x 7 days x $916,622/day). This is a significant cost t o deepwater Operators, but it is not a cost directly applicable to this rulemaking. 11 It is the result of a tighter regulatory environment through the BSEE practice of no longer granting departures for the regulatory requirement to pull the subsea BOP stac k between each well on a project

. 

### Negative Pressure Tests

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

, except for the drive or structural casing string

. This test confirms that fluid from the casing string is not flowing into the formation. In the IFR, section § 250.423(c) require d that a negative pressure test be conducted for all intermediate and production casing strings for wells drilled

with a subsea BOP. The final rule § 250.423(c) only requires that the negative pressure test be conducted on the final casing before the subsea BOP is removed or if the BOP is to be removed during drilling operations.

The negative pressure test will reveal whether gas or fluid from outside the casing is flowing into
the well and ensures that the casing and cement provide a seal. Maintenance of pressure under
both tests ensures proper casing installation and the integrity of the casing and cement. While some companies routinely conduct negative pressure tests on casing strings as a best practice, we do not have the data to determine the frequency at which this occurs, so we assume all negative pressure testing is a new cost imposed by this regulation. Based on typical industry procedures,
we estimate e ach new negative pressure test will take approximately 3 hours

.

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

Three hours is equivalent to 0.125 days. Using the weighted average of the MODU day rates ( Table 2 ) 0 .125 days times 1 casing string times 112 MODU wells yields an annual additional costs in deepwater for this test of $ 12.8 million . The estimated duration for an average negative pressure test was doubled from 90 minutes used in the interim rule to 3 hours based upon improved estimates of the time it takes both to create and then hold the low pressure state. The negative pressure te st requirement for wells drilled with a surface BOP was removed from the final rule. Therefore compliance costs no longer include estimated costs of negative pressure tests for deepwater wells drilled from a platform or for shallow water wells. Additiona lly, the number of casing strings subject to the negative pressure test has been reduced substantially from the requirements in IFR. The IFR required that the negative pressure test be conducted on all intermediate and production casing strings. We previ ously estimated, on average, a deepwater well required 5 negative pressure tests and a shallow water well 3 tests. The final rule only requires a single negative pressure test for deepwater wells drilled with a subsea BOP. This change results in a signif

icantly lower compliance cost for this regulation as shown in Table 5

.



### Installation of Dual Barriers

R egulations before the issuance of the IFR d id not require the installation of dual barriers although this requirement could be considered the use of best available and safety technology (BAST) per § 250.107(d). For this analysis the requirement is considered new because the government had not previously specified this technology in the regulations

. New regulatory
section § 250.420(b)(3) requires the operator install dual barriers in cluding cement barriers for the final casing string. This second mechanical barrier prevent s hydrocarbon flow in the event of
cement failure at the bottom of the well

. The operator must document the installation of the dual
barriers and submit this documentation to BSEE in the End

- of

- Operations Report (Form BSEE

0125) . These new requirements wi ll ensure that the best casing and cementing design will be used for a specific well.

The IFR allowed dual barriers which could include one float valve. We estimated that all wells will require a second mechanical barrier and that the installation time would be 30 minutes and an equipment cost of $20,000. This yielded an IFR annual compliance cost estimate of $10.3

million for all OCS wells.

The regulatory provision for mechanical barriers in § 250.420(b)(3) has been changed from the IFR and now requ ires the second barrier must be mechanical. BSEE no longer considers a float valve to be a mechanical barrier meeting the requirement of this provision. The result of this change is that the compliance cost estimate for this requirement at § 250.420 (b)(3 ) increases31

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

A well may require 4 or more hours (depending on the drilling depth) of additional drilling time to extend the well the 50 feet deeper necessary to install the mechanical barrier and the corresponding additional cement necessary to ensure integrity of the mechanical barrier. An alternative to drilling the well 50 feet deeper is to wait until after the primary cement job hardens
and inst all the mechanical plug above the wiper plug. This requires tripping the drill string in
and out to install the mechanical barrier and re

- cementing. BSEE estimates that if the operator must trip in and out of the hole to install a bridge plug and reconne ct, it will require approximately 24 or more hours of additional rig time. For this regulation we are estimating that installing two mechanical plugs will add, on average, 12 hours to the drilling time of all deepwater and shallow water OCS wells.

For al l wells we estimate that requiring a mechanical barrier and cement will cost about $10,000 in equipment and cement; this is a reduction from the $20,000 estimate used in the IFR. This yields $1.12 million for deepwater MODU wells, $0.48 million for deepwa ter platform wells and $1.86 million for shallow water wells. The average additional drilling time of 12 hours (1⁄2 of a day) per OCS well using the day rates
from Table 2 is estimated to cost:

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

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

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

The combined compliance cost ($millions) of the equipment and additional drilling time is estimated to be: ($1.12 + $51.33) + ($0.48 + $9.60) + ($1.86 + $18.60) = $83. 0 million for this regulatory provision. This § 250.420(b)(3) change between the IFR and the final rule increases the compliance cost for this regulatory provision as shown in Table 5

.



### Professional Engineer Certi fication for Well Design

R egulation 30 CFR 250.420(a) in place before the IFR specifie d well casing and cementing requirements but did not require certification by a Professional Engineer although certification
could be considered the use of best available safety technology (BAST) per § 250.107(d). New regulatory section § 250.420 (a)(6) requires that well casing and cementing specifications must be

certified by a Professional Engineer. The Professional Engineer will certify that the well casing and cementing design is appropriate for the purpose for which it is intended under expected
wellbore conditions. Th is certification will add assurance that the appropriate design is used for32

the well thus decreas ing the likelihood of a well failure during a blowout. Many of the larger companies probably will certify the well design using in

- house expertise for little or no extra

cost . Other companies will hire a third

- party professional enginee ring firm. Since a majority of leases are owned by large entities, BSEE assumes that at most 50% of future wells will incur an
additional cost for a third party professional engineer certification of the well design . The assumption for shallow water well s is changed from the IFR where we assumed that all wells would incur the cost of an external PE certification. The percentage of shallow water wells using external PE services is now estimated to be the same as deepwater wells. Based on an informal

surv ey of drilling contractors and lease operators, BSEE estimates that the external certifications will cost about $22,500 each.

For MODU wells, those parameters yield $1.2 6 million (112 times 50% times $0.0225 million), for platform wells $0.5 4 million , and for shallow water wells $ 2.09 million

. 

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

R egulations in place before the IFR did not specifically address BOP inspection following use of
the blind

- shear ram or casing shear ram , although a prudent operator would tend to conduct such an inspection to confirm the reliability of the BOPs

. Surface inspection following shear ram activation may not have been conducted by the entire industry absent a more specific regulatory requirement; therefore this analysis considers the surface inspection to be a new cost. New regulation § 250.451(i) req uires that if a blind

- shear ram or casing shear ram is activated in a well

control situation where the pipe is sheared, the BOP stack must be retrieved, fully inspected and
tested. This provision will ensure the integrity of the BOP and that the BOP will s till function and hold pressure after the event

. T his activity, when triggered, will add about 1 3 days to drilling time. According to a D et N orske V eritas s tudy 12 , out of 5

, 611 deepwater wells, there
were 12 situations where either the blind

- shear or casin g shear ram was activated ; this implies one activation for every 515 wells drilled

. W ith 112 wells drilled per year from drillships or semisubmersibles; one can expect 0.22 (112/515) relevant activities per year for costing purposes. At the day rates quo ted in Table 2 , 13 days times a 22% annual chance of occurrence yields $2. 61 million expected annual compliance cost for this provision.



### Th ird Party Verification of Shear Ram Capability
Before promulgation of the IFR, 30 CFR 250.416(e) require d submission of information showing
that BOP blind

- shear rams are capable of cutting through the drill pipe in the hole under maximum anticipated conditions

. Th e IFR and the final rule modifies this earlier regulation to require a BOP verification of shear ram capability by an independent third party. The independent third party provides an objective assessment that the blind

- shear rams can cut any

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

.33

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

. This confirmation will be required for both subsea and surface BOPs, thereby adding a small cost
to each well dri lled. While the requirement to demonstrate shear ram capability is not new, independent verificatio n and submission of that verification is a new provision ; therefore this analysis considers the independent verification to be a new cost. Based on in

- house expert judgment, we assume this will add $3,250 to the cost of each well. Applied to 346 wells pe r year, this yields a compliance cost estimate of $1. 1 2 45 million for this provision.



### Paperwork Costs
Paperwork burden costs were not fully incorporated into the benefit

- cost analysis for the interim final rule. This final rule analysis adds recordkeepi ng and other paperwork costs from the PRA (Paperwork Reduction Act) burden to the compliance costs for the regulation. Rather than repeat the PRA analysis by listing individual regulatory citations, the aggregate paperwork costs from that analysis are sum marized in a single line in Table 4. This cost includes both the paperwork burden included in the IFR (75 FR 63368) and also includes the paperwork burden added in this
final rule . Because the IFR was effective immediately, the paperwork burden summarized in the IFR (75 FR 63368) is already approved by OMB and is not included in this final rule.

The estimate of annual responses for the paperwork costs in the IFR PRA table (75 FR 63368) differs slightly from the estimates used in this RIA analysi s. This difference is the result of different methods used to estimate future drilling activity. Generally the paperwork burden
estimates a 3

- year historical average of responses or actions. This RIA estimates drilling activity using both historical act ivity and forecast scenarios. For example in this rulemaking the paperwork burden analysis number of deepwater MODU wells drilled is 110 versus 112 used in this RIA analysis. The differences are minor and are not considered to have a material impact on

t he compliance cost estimates.

The estimated total annual burden hours includes both the burden hours from the IFR (75 FR 63368, OMB Control Number 1014

- 0014) of 44,731 burden hours and the additional burden hours included in the final rule ( 5,347 hours). The paperwork costs are estimated using the total annual burden hours and the average respondent cost of $ 92 */hour (rounded). This cost is broken out in the below table using the Bureau of Labor Statistics data for the Houston, TX

area. See BLS website: http://www.bls.gov/bls/wages.htm

. The total paperwork burden for this rulemaking is estimated to be $ 4.6 million ( 50,078 hours x $ 92 hr = $ 4,607,176 ).34 Table 3

– Hourly Salary Rate for Industry
Position Level Hourly Pay rate ($/hour estimate) Hourly rate

including benefits (1.4** x $/hour) Percent of time

spent on
collection Weighted

Average ($/hour)

Secretaries and
Administrative
assistants 6 $21 $29 10% $3

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

Petroleum Engineers /Geologists All
Workers $68 $95 50% $48

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

Weighted Average ($/hour): $92

* Note that this BLS source reflects their last update from December 2009. ** A multiplier of 1.4 (as implied by BLS news release USDL 11

- 1718, December 7, 2011 (see http://www.bls.gov/news.release/ecec.nr0.htm)) was added for benefits. *** This position is cl osest representative to Regulatory Specialist.


### Summary of Annual Recurring Costs

Table 4 su mmarizes the cost estimates for these recurring cost catego ries for three subgroups of wells affected by the new regulations.35 Table 4

– Estimated Recurring Cost Summary Regulation Recurring Costs: MODU Wells (112/yr) Fixed

Platforms (48/yr) Shallow

Wells (186/yr) Cost

Shares

Total ($MM) Total

($MM) Total

($MM)

250.449(j)(k) Subsea BOP and ROV function

testing (drilling) 17.1 0.0 0.0 13% 250.516(d)(8), 250.616(h)(1) §250.1707(h) Subsea ROV function testing

(completions/workover/abandonment) Total of 36 instances. 5.5 0.0 0.0 4%

250.423(c) Test casing strings for proper

installation (negative pressure test) 12.8 0.0 0.0 10%

250.420(b)(3) Installation of dual mechanical

barriers 52.5 10.1 20.5 63%

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

250.451(i) Retrieval and Testing of a BOP Stack

After a Well Control Situation 2.6 0.0 0.0 2%

250.416(e) Independent third party shear ram

ver ification 0.4 0.2 0.6 1%

All Paperwork Costs taken from PRA

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

Estimated Cost per year: 94.6 11.2 24.8 $ 130.7 Estimated Cost per well: 0.85 0.23 0.13

The regulations impact well costs differently depending on the category of drilling rig and type of well being drilled. As can be observed in Table 4 , deepwater wells drilled by platform rigs
and shallow wells drilled by jackups will incur lower incremental costs , primarily because they use surface BOPs while wells drilled by MOD U’s (drillships and semisubmersibles) will incur the greater incremental cost due to the new subsea BOP and dual barrier requirements.



### Compliance Cost Changes between IFR and Final Rule The reasons for the compliance cost changes between the IFR and the final rule vary from regulatory changes to revised BSEE counts and rig time. The following table provides a side

- by

side comparison between the IFR compliance costs and those in this final rule.36 Table 5

– Compliance Cost Comparison between IFR and Final Rule Annual Recurring Costs IFR ($millions) Final Rule

($millions) Compliance Cost Change between IFR and Final

Rule Subsea ROV function testing (drilling) 102.7 17.1 Estimated time was reduced. BSEE ov er estimated the time required for the subsea tests. Subsea ROV function testing (completions/workover/abandonme nts) 15.5 5.5 Estimated time was reduced. BSEE over estimated the time required for the subsea tests. Count of abandonment operations added to revised count of workover/completions. Test casing strings for proper installation (negative pressure test) 45.1 12.8 Regulation was changed and the count of actions is
redu ced. BSEE no longer requires a negative pressure test on all intermediate casing strings, but only on the final casing before the subsea BOP is
removed.

Installation of dual mechanical
barriers 10.3 83.0 Regulation was changed. A float valve no longer
meets the definition of a second mechanical barrier.
The estimated time to install the second mechanical
barrier increased to 12 hours.
PE certification for well design 6.0 3.9 Cost estimate reduced because the large companies drilling in shallow water are now assumed to have
Professional PE available for in

- house certification.
Retrieval and Testing of a BOP Stack After a Well Control Situation 2.6 2.6 No change.

Independent third party shear

ver ification 1.2 1.2 No change.

Paperwork Costs taken from PRA
tables in IFR & Final Rule. 0.0 4.6 Paperwork costs were not included in the IFR
benefit

- cost analysis, but are added to the compliance cost for the final rule.

Total: 183.4 130.7



### Voluntary Measures by Industry
Some part of th e roughly $ 131 million in annual compliance cost total may not be rightfully assigned to the regulation as industry is undertaking a number of steps following the DWH event that may overlap those in this regulation. An independent analysis by Industrial Economics Inc. for the IFR (See Appendix F) indicates overlap exists for the second barrier and negative
pressure test provisions . However, these actions by industry are voluntary and, as such, not subject to enforcement. For these reasons, we have not adjusted the compliance cost estimate to
account for these new potential actions, but acknowledge that our cost estimate may overstate compliance costs.37



## AVOIDED PRIVATE

- SOCIAL COSTS

The objective of this section is to describe the avoided private

- social costs resulting from a catastrophic oil spill in the Gulf of Mexico. Private

- social costs as defined in this analysis are the costs incurred by the lessees and operator contractors based on the actual property loss and containment costs emerging from a catastrophic blowout on their rig and OCS lease . The avoided private

- social costs include damage to the drilling rig, costs for containment and plugging of the bl owout well and the value of hydrocarbons lost as a result of a blowout spill.
Costs for clean

- up of spilled oil are considered external

- social costs in this analysis since they are incurred off the lease and are focused on mitigating the external costs to society from a catastrophic blowout event. E stimate s of external

- social cost s are provided in the section on
Avoided External

- Social Costs. The combination of private

- social costs and external

- social costs equal the avoided social costs in this analysis

. 

### Damage to Drilling Rig
A catastrophic deepwater blowout event can caus e serious damage to or even destroy the

MODU

. Recently delivered floating deepwater semisubmersible drilling rig s reportedly cost
about $ 5 60 million and a drillship $750 million. In addition to the DWH event where the drilling rig sank, there is only one other deepwater blowout event with rig damage and fatalities. This
blowout occurred on September, 1984 in Green Canyon, Conoco (Zapata Lexington Drilling Rig) . Salient points of that event include:

 T here were deaths, serious injuries and damage to the d rilling r ig.

 While the blowout bridged (i.e., closed off on its own by cave

- in or material falling in the well bore) and did not spill oil, the explosion did cause $15 million of damage to the drilling rig.

We use only these two deepwater blowout events to estimate the avoided costs for drilling rig damage because even in serious blowout events there are redundant systems designed to protect the rig and it s workers, including disconnect of the lower marine riser package (LMRP).

For a prospective catastrophic blowout event

, BSEE is assuming the value of a rig is $650 million, which is the approximate midpoint of the new construction cost of a deepwater semisubmersible rig ($560 million) 13 and the cost of a new drillship ($750 million) 14

. We take

13 May 4, 2010, The replacement cost of the Deepwater Horizon is estimated at $560 million. http://www.nytimes.com/gwire /2010/05/04/04greenwire

- warnings

- on

- backup

- systems

- for

- oil

- rigs

- sounde

30452.html38

this as the expected loss if the rig is destroyed. Additionally, we assume there is an equal likelihood of damaging but not sinking the rig

, with resulting damage estimated at $26 million ($15m in 1984$ from the Zapata Lexington rig accident, inflated to 2010$)

. The calculation

use d to estimate the expected damage/loss of the drilling rig per catastrophic spill event is ($26m + $650m) / 2) = $338 million

.



### Well Containment and Plugging
This analysis uses containment and well plugging costs for a deepwater well blowout extrapolated from the amount provided by the North America BP Investor Relations desk on July
23

, 2010 for the DWH event

. In a phone call, BP stated the company h ad spent a total of $4.3 billion through July 22

, 2010 which is approximately 90 days after the explosion . Of the $4.3 billion, $200 million ha d been spent on the two r elief w ells and $ 9 00 million on other s ource

c ontrol efforts (e.g., failed ROV interven tion efforts, containment structures, etc.)

. BSEE

assumes that while the oil will flow for 90 days in the baseline (pre

- regulation) case, the containment and well plugging efforts will extend to 120 days. The $1.1 billion ($200m + $900m) for the first 90 days extrapolated to 120 days yields $1.467 billion per catastrophic spill event

.

While BP has now paid out more than this figure for its DWH well containment and plugging, BSEE is not increasing our estimate for this analysis. Both the Marine Well Containment Company and Helix well containment system are operational. 15 In the unlikely chance of another significant blowout event, specialized equipment has become available and response time to stem the flow from the well is anticipated to be reduced. Cognizant that every situation and event is different, the $1.467 billion estimate remains.



### Hydrocarbon Losses
In addition to the well containment efforts, private

- social costs include the market value of the lost oil and gas as a result of an uncontroll ed blowout event. BSEE assumes that a deepwater
well that has suffered an uncontrolled blowout would flow 53,000 barrels of oil a day for 90 days. This equates to 4.77 million barrels of oil spilled 16 . While some oil may be captured through various skimm ing systems, the overwhelming majority of captured oil is likely to be flared or disposed of as waste rather than sold into the market. Moreover, for our purposes we can ignore the relatively modest size of the hypothetical extraction costs of the lost oi l.

14 Total capital costs to be incurred for the construction of the drillship are estimated to be $750 million http://www.redorbit.com/news/business/1446859/transocean_inc_announces_agreement_to_acquire_newbuil d_ultra deepwater_drillship_under/index.html

15 The cost to stand

- up and maintain the MWCC and Helix systems is a significant regulatory cost to industry. However it is not a specific compliance cost of this regulation and is not otherwise considered in th is analysis.

16 See footnote number 1 and page 12 for cautions about this estimate.39

Accordingly, assuming a market oil price of $70/barrel, the value of lost crude oil is estimated to
be $ 334 million

.

In the deepwater Gulf of Mexico oil averages 80 percent and natural gas the other 20 percent of hydrocarbon production on a BOE basi s. If the oil spilled is 4.77 million barrels

, associated natural gas would be another 1. 19 million BOE or 6.92 million MMBtu , implying a total of 5.96
million BOE is lost 17 . For computing the value of lost natural gas, BSEE estimates a market value of $4.00/MMBtu for a total lost value of almost $ 28 million

.



### Fines and Criminal Penalties
A number of statutes, including t he Clean Water Act ( 33 U.S.C. 1 321(b)(7)), and the Outer
Continental Shelf Lands Act (43 U.S.C. 1350) provide for fines against the part ies responsible for an oil spill or for violations related to an oil spill . In the context of benefit

- cost analysis, fines and other penalties not specifically for natural resource damages or other social costs
incurred b y society are considered “transfer payments.” These transfer payments simply move funds from the responsible party to the government. Transfer payments do not involve real
resource costs and are therefore excluded from the avoided benefit

- cost estimate f or this rulemaking

.



### Summary of Avoided Private

- Social Costs

Table 6 summarizes the avoided private costs estimated for this analysis , stated in 2010 dollars

. These estimates have not changed from the IFR. Note that only about one

- sixth of the private cost total is from lost hydrocarbon values which the lessees would have realized had the spill not
occurred.

17 5.8 MMBtu per BOE.40 Table 6

- Summary of Estimated Avoided Private

- Social Costs Private

- Social Cost Estimated Value Damage/loss of Drilling Rig 338,000,000 Well Containment, 120 days 1,466,666,667 Lost Crude Oil, 4.77 million barrels 333,900,000 Lost Natural Gas, 6.92 million MMBtu 27,666,000

Total: $2,166,232,667



## AVOIDED EXTERNAL

- SOCIAL COSTS

This section evaluates (in quantitative terms where possible) the avoided natural resource and cleanup costs , categorized as external

- social costs, from a major oil spill in the deepwater Gulf of Mexico (GOM). The results from the avoided external

- social costs estimated in this section are combined with the estimated private

- social costs summarized in the table above to provide the estimate ($16.3 billion) of avoided social costs (benefits) used in this analysis. External

- Social costs associated with oil spills may include loss of property value, natural resource damages, health effects, litigation costs, non

- use values, loss of consumer surplus from recreational users, loss of p roducer surplus from commercial fishing or shell

- fishing businesses, welfare effects associated with price changes in seafood markets, operational disruptions at marinas, commercial ports, or Naval facilities, temporary or permanent displacements of famili es or businesses, and reduction of supply of water for certain industrial purposes. 18

The main categories of external

- social costs considered in this section of the analysis include

 Natural resource damages;

 Lost recreational values;

 Lost commercial fish ery production; and

 Oil spill response (cleanup) and damage assessment costs.

The avoided external

- social cost estimate focuses on these categories of avoided social costs
because information appropriate to a benefit

- cost analysis is readily available to estimate their magnitude from studies and historical data

. Recall that c osts for the containment and the killing of an uncontrollably flowing well, damage to drilling equipment from a blowout, and lost hydrocarbons have already been discussed in the se ction on External

- Private Costs.

18 Water of a certain quality is required for various industrial uses, power generation, and desalination. There are nineteen thermoelectric plants on the Gulf coast (Florida, Mississippi and Texas). There is a Gulf

- water fed desalination plant located in Tampa Bay, and one planned for San Antonio.41

Three main factors affect the economic value of the avoided external

- social costs of an oil spill: the spill’s location, the time of year it occurs, and the type of oil spilled. Spill location and timing affect all categories of costs. Spills near locations with sensitive biota, significant fishery
resources or recreational area s, or in locations where the oil could easily spread to such locations will have relatively greater costs. Little is known about the short

- and long

- term impacts of deepwater oil spills on the water column or deepwater biota. Timing also has situation

- sp ecific effects. A spill occurring near bird habitats during nesting or breeding season might be associated with greater natural resource damages, while a spill occurring near a shrimp fishery during harvesting season would be associated with larger fishery

- related costs.

The specific type of oil affects the amount of cleanup needed and the amount of natural resource damages incurred. Light oils naturally dissipate and evaporate quickly

— requiring minimal cleanup

—

but are highly toxic and create severe envir onmental impacts. Heavy oils do not evaporate, and therefore may require intensive structural and shoreline cleanup. While they are less toxic than light oils, heavy oils can harm waterfowl and fur

- bearing mammals through coating and ingestion. Each spi ll’s cost reflects the particular mix of these factors, and no factor is clearly predictive of the outcome.



### Conceptual Approach
Typically, the external

- social cost of damages to natural resources, fisheries and recreational
areas is evaluated after a spil l has occurred and subsequent to the completion of response activities. This evaluation includes collecting data that allow assessing the nature and extent of the damages (both spatially and over time) to all of the impacted resources relative to the pre

spill baseline and then, where possible, monetizing the damages using economic techniques designed to value resources that are not typically bought and sold in markets. In concept, damages include use and non

- use values, for example, both the value of a t rip to the beach now and the value of being able to take such a trip in the future.

For the proposed regulation, this level of information is not readily available. Baseline information such as the number, timing, duration, and location of potential spills during the period of analysis are not known. In addition, while baseline projecti ons for the number of future deepwater wells drilled are assumed for this benefit

- cost analysis, it is not possible to forecast the timing, magnitude, duration, and trajectory of future spills. This introduces a considerable degree of uncertainty into est imates of the value of the avoided costs associated with the proposed regulation. The analysis addresses this uncertainty by providing a range of values associated with different categories of avoided costs, and reporting averages or most likely values to determine point estimates for calculations.42

Given the limited information available to evaluate the avoided natural resource costs, the technique used in this analysis falls into the category of “benefit transfer.” This technique can be implemented in a variety of ways, ranging from simply transferring values from sufficiently similar studies, to adapting willingness

- to

- pay functions for new site

- specific changes in environmental conditions, prices, and other values. In situations where time or resource s do not permit extensive data collection or primary research, benefit transfer may be an appropriate technique for evaluating the magnitude of economic benefits. There are many caveats that accompany use of this approach, the most important perhaps being the extent to which the study site/situation is similar to the study from which the values are to be transferred.

As discussed in the Baseline section of this analysis, BSEE estimated the probability of a catastrophic spill based on the history of dee pwater blowout events and the resulting spills on the Federal outer continental shelf (OCS).

The BSEE estimates that about 160 new deepwater wells will be drilled annually over the next
several decades. BOEMRE also assumes that the baseline scenario incl udes one catastrophic deepwater spill every 26 years, with the probability of a spill in any given year during the period of analysis being 3.85%. In this analysis, the hypothetical spill is assumed to be 4. 77 million barrels of oil. The analysis does no t assume a specific grade of crude oil for future spills, although oil from a deepwater GOM blowout would likely be a sour light crude typical in the
GOM. The type of oil spilled affects spill dispersion and clean

- up costs.



### Valuing Natural Resource Damage s The avoided costs for natural resource damages depend on the particular circumstances associated with an oil spill. Natural resource damages from prior oil spills (excluding the DWH spill) were used to inform the cost

- benefit analysis of this rulemaking . We collected information on coastal oil spills that were responded to under the authority of the Oil Pollution Act, including the natural resource damage settlements associated with these event s. For the purposes of this
benefit

- cost analysis, t he valu es contained in the legal settlement documents represent the best
source of available information on the monetary value of the natural resource damages associated with coastal oil spills . Settlement amounts reflect compromises based on factors other
than the actual amount of damages, such as litigation risk with respect to legal issues in the case or the ability of parties to support protracted, complex litigation. Further, although this information is useful for the purpose of a benefit

- cost analysis, it should not be relied on to determine the amount of natural resource damages associated with any particular oil spill, including the DWH spill

.43

The dataset includes 62 coastal spills, none of which occurred a significant distance offshore.
While vesse l

- related spills have previously occurred offshore, primarily in foreign waters, there is little information available on the associated natural resource damages. Similarly, little information is available on natural resource damages associated with blowo uts occurring in foreign waters. Information on the spills contained in the data set is summarized in Figure 2 through Figure 5 and in the Appendix.

 Figure 2 shows a histogram of the per

- barrel response costs in the dataset, with the majority of spills below $10,000/bbl, and a large number below $10/bbl;

 Figure 3 shows a histogram of the per

- barrel restoration and assessment costs in the dataset, with the majority of spills below $10,000/bbl, and a large number below $1,000/bbl;

 Figure 4 shows a histogram of the total spill costs in the dataset, with the majority of spills below $10 million, and a large number below $1 million;

 Figure 5 shows a histogram of claims requested and claims paid out by the U.S. Coast Guard from the National Pollution Trust Fund. The majority of th ese are below $10,000 per claim; many are below $1,000 per claim.

Figure 2 . Distribution of Dataset Spills by Response Costs per Barrel ($2009)44 Figure 3 . Distribution of Spills, by NRD + Assessment Co st per Barrel ($2009)

Figure 4 . Distribution of Spills, by Total Spill Costs ($2009)45 Figure 5 . Oil Spill Liability Trust Fund Claims Requested and Paid (Sep 1972

- Feb 2010)

The 62

- spill dataset is characterized by a wide range of volumes spilled (24 to 262,000 barrels) as well as a wide range of per

- barrel natural resource damages ($7 to $76,000 per barrel). 19 The vast majority of the spills were 10,000 barrels or less. As stated, t his data set doe s not include
the DWH spill

. For the 62 spills, the average monetary value of the natural resource damages (including assessment costs) was about $3,700 per barrel, the median spill was about $850 per barrel, and the standard deviation was about $11,300 p er barrel. The per

- barrel damage values are related to both spill size and type of hydrocarbon.

Of the 62 spills, 10 spills occurred in the Gulf region. Natural resource damages (including assessment costs) for the Gulf spills range from $49 to $1,287 per barrel (in 2010 dollars), with an average of $456, per barrel, a median of $244 per barrel, and a standard deviation of $470 per barrel. For this analysis of a hypothetical catastrophic oil spill , we selected seven Gulf spills that
appear most german e. Summary information on these seven spills is reported in Table 5. The average damages across these spills were $604/bbl, which is used as a conservative estimate for our avoided cost calculations. The Ocean 255 spill was highest

- damage Gulf spill pri or to April 2010, and the only non

- crude oil spill in the Gulf data.

Although the hydrocarbons spilled in the Ocean 255 spill were fuel oil, rather than crude, the resources impacted were typical of some of the marine resources throughout the Gulf that co uld be affected by a catastrophic spill: sea turtles, mangroves, sea grasses, oyster beds, and beaches. These impacts suggest that the Ocean 255 spill may be a good representation of a future large

19 The upper end of the range of natural resource damages is given by the M/T Command oil spill in San Fra ncisco Bay in 1998. Spills occurring in or near northern California are associated with some of the largest dollar

- per

- barrel damages.46

spill. As discussed below, while the model used for this analysis appears to predict natural resource damage costs for smaller spills reasonably well, this model may have poor predictive capability for the NRD costs of catastrophic spills.

Table 7 Seven Gulf Coast Spills: Natural Resource Damages

Event Volume spilled (bbls) NRD+Assessement

Costs $/bbl $2010 Injured Resources

OCEAN 255/B

155/BALSA 37 Spill 8,619 1,287 366 birds, 2117 sea turtles, 5.5 acres mangroves, 255 acres seagrasses, 0.85 acre s salt marshes, 0.22 acres oyster beds, 20 linear miles seawalls, surface waters, 1.34 acres bottom sediments and 39,827 cubic yards of oiled sands (13 linear miles)
Blake IV and Greenhill Petroleum Corp. Well 25 2,905 1,122 Intertidal marshes, marine and estuarine fish, bottom dwelling species, birds, sediments Equinox Cockrell

- Moran #176 well 1,500 891 1,221 acres saltmarshes, Birds/Wildlife, 12 acres mangroves, 21 acres subtidal sediments, recreational activities Chevron BLDSU #5, West Bay Field 262 346 200 Acres Fresh Water Marsh Vegetation, Birds/Wildlife Ocean Energy/Devon Energy North Pass Storage Facility 300 424 120 acres freshwater marsh

Texaco Pipeline Company Lake Barre oil spill 6,548 109 4,237 acres of marshes, 7,465 finfish and shellfish, 333 birds,
M/VWestchester 13,095 49 Oiled shoreline and surface waters; lost recreational use of the Mississippi River. Average per Event 60447



### Caveats and Assumptions The analysis includes the following caveats and assumptions:

 The estimate of natural resource damages from the table above, while a useful tool for the purpose of this cost

- benefit exercise, is not relevant in calculating damages for any particular oil spi ll, including the DWH spill.

 For the purposes of this exercise, it is assumed that t he average natural resource damage
value for Gulf cases per barrel spilled, equal to $604 from the table above, is a reasonable approximation of the value of avoided natural resource damages for a spill significantly larger than the cases contained in the dataset of natural resource damage cases. It is worth noting , however, that a future catastrophic spill c ould result in a significantly higher natural resource damag e value per barrel spilled, depending on the circumstances. In the Exxon Valdez oil spill, which resulted in a release of 261,905 barrels of oil, natural resource damages plus assessment costs averaged $5,005 per barrel (2009 dollars). See Appendix B

.

 T otal d amages for a given hypothetical event are a linear function of the amount spilled

.

 The average damage value is not adjusted to account for distance to shore, evaporation, degradation, dispersion, containment, etc. It is assumed that reported natural resource damage values already incorporate these effects.

 The injured resources for the cases in the dataset are similar to the resources potentially damaged from a large Gulf spill in the future.

 This analysis translates estimated avoided costs into dol lar

- per

- barrel values. This metric is useful because barrels are a common measure of spill volume. However, the wide variation in social spill costs across events is noted

. In short, t he damages ultimately depend on the characteristics of an individual spill as noted earlier in the reference to the Exxon Valdez spill

. 

### Relationship between Natural Resource Damages and Spill Size and Type of Oil Spilled
Similar to previous analysis by Dunford and Freeman (2001), a statistical model was developed to explain the factors that affect the monetary value of natural resource damages in the oil spill data set. The regression analysis used the log of natural resource damage and assessment costs (in $/barrel) as the dependent variable. Independent (explanatory) var iables included the type of oil spilled (with dummy variables included for crude, diesel and gasoline), a time trend, the log of the volume of oil spilled (in barrels), and a dummy variable indicating if the oil spill occurred in California. The regressio n results explain a reasonable amount of variation in the sample; however, the predictive ability of the model appears to be better for small size spills. The model is able to predict costs for smaller spills in the sample reasonably well, although predic tions of larger spills in the sample result in smaller values than expected. Based on the historic spill data48

available, the model appears to have poor predictive capability for the NRD costs of catastrophic spills.



### Valuing Commercial Fishery Losses

Comm ercial fishing as an industry must be differentiated from other types of fishing, such as recreation, “subsistence” consumption, or informal sale. One approach to calculating commercial fishing profits 20 requires tallying revenue earned by industry operators, and subtracting operating costs. Operating costs include labor costs, such as wages for harvesting and processing; and non

- labor costs such as fuel and supplies.

The commercial fishing industry inc ludes various species of aquatic life (shrimp, crabs, oysters, finfish) and types of economic activity (fishermen, processors/cleaners, dealers, marinas, support facilities). Impacts to the industry from an oil spill can be expected to affect all sectors of the industry.

Economic damages related to an oil spill can result from :

 Fishery closures, when fishermen must either shift to different areas or not fish at all;

 Fish population impacts that result in lower catch rates, different target species, or changes in fishing methods; and

 Market price changes, for example due to public reluctance to consume fish from the region.
This approach for assessing damages related to an oil spill requires identifying changes in catch rates, prices, fishing areas, and methods employed.



### Data Availability

Background
The Gulf States include, from West to East, Texas, Louisiana, Mississippi, Alabama and Florida. The region’s shrimp landings are the nation’s largest: 188.3 million pounds, for 73 percent of the

national tot al (Fisheries of the United States 2008). The region landed approximately 30 percent of the total blue crabs for the nation (48.7 million pounds) in 2008. The Gulf region leads the nation in the production of oysters, some 67 percent of the nation’s tota l.

Gulf fishery total landings (in pounds) and the revenues from those landings have tended to fall over the past decade, as shown in Figure 6

. Flu ctuations in p rices do not appear to contribute to the decline in revenues. For the top ten commercial species, which together account for over 96

20 We use producers ’ profits as a proxy for producer surplus.49

percent of annual harvests, prices show no steady downward trend in Figure 7 , while landings of all species show moderate declines in Figure 8

.

Figure 6 Gulf State Landings and Revenue, 1999

- 2008 (2009$) Note: Data include landings for Florida’s Gulf coast and Atlantic coast.

Source: NMFS Fisheries Economics of the United States 2008.

Figure 7 A verage Annual Price per Pound (2009$)

Source: NMFS Fisheries Economics of the United States 2008.

Finfish & Other (lbs), 1999, 1,638 Finfish & Other (lbs), 2000, 1,397 Finfish & Other (lbs), 2001, 1,254 Finfish & Other (lbs), 2002, 1,377 Finfish & Other (lbs), 2003, 1,229 Finfish & Other (lbs), 2004, 1,110 Finfish & Other (lbs), 2005, 888 Finfish & Other (lbs), 2006, 975 Finfish & Other (lbs), 2007, 1,071 2008, 993 Shellfish (2009$), 1999, 828 Shellfish (2009$),
2000, 1,017 Shellfish (2009$),
2001, 780 Shellfish (2009$), 2002, 641 Shellfish (2009$),
2003, 614 Shellfish (2009$),
2004, 601 Shellfish (2009$),
2005, 555 Shellfish (2009$), 2006, 593 Shellfish (2009$),
2007, 565 2008, 511 Shellfish (lbs), 1999,

367 Shellfish (lbs), 2000,

398 Shellfish (lbs), 2001,

359 Shellfish (lbs), 2002,

351 Shellfish (lbs), 2003,

367 Shellfish (lbs), 2004,

365 Shellfish (lbs), 2005,

310 Shellfish (lbs), 2006,

387 Shellfish (lbs), 2007,

333 Shellfish (lbs), 2008,

281 Finfish & Other (2009$), 1999, 228

Finfish & Other (2009$), 2000, 223

Finfish & Other (2009$), 2001, 200

Finfish & Other (2009$), 2002, 177

Finfish & Other (2009$), 2003, 163

Finfish & Other (2009$), 2004, 164

Finfish & Other (2009$), 2005, 135

Finfish & Other (2009$), 2006, 145 Finfish & Other (2009$), 2007, 151 (2009$), 2008, 145 Finfish & Other (lbs)

Shellfish (2009$)

Shellfish (lbs)

Finfish & Other (2009$)50 Figure 8 Gulf State Landings , 1999

- 2008 (mmlbs) Notes: Data include landings for Florida’s Gulf coast and Atlantic coast.

Crawfish landings for 2000 totaled 393,000 lbs.
Source: NMFS Fisheries Economics of the United States 2008.

Datasets were more readily available for commercial shrimp fishing than for other Gulf fisheries. The domestic shrimp industry has been in decline since t he 1980s and may not be a good indicator of the overall commercial fishing industry in the Gulf. Louisiana accounts for about 50% of Gulf Coast shrimp landings. By 2007 resident shrimping licenses in Louisiana had fallen
to less than one

- third of their 1 989 value, as shown in Figure 9

.51

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

Source: Louisiana Department of Wildlife and Fisheries

Revenues
In calculating producer surplus, we estimated gross revenues using the gross value of landings, multiplying pounds of fish landed by the wholesale price for that fish. The National Oceanic an d Atmospheric Administration (NOAA) provides summary data on the value of commercial fisheries in the Gulf of Mexico, as shown in Table 8

.52 Table 8 Gulf of Mexico Commercial Fisheries Data, 2008
Texas Louisiana Mississippi Alabama West Florida Total

Shrimp Volume (million lbs) 63.9 89 .0 8.6 17 .2 9.9 188 .5 Value (million $) 157.1 130. 3 17.1 38.4 23.3 366.3 Crabs (Blue crabs) Volume (million lbs) 2.3 39.8 0. 5 1.8 2. 6 47.3 Value (million $) 2.6 3 1.1 1.0 1.5 3.3 3 8.7 Oysters Volume (million lbs) 2.7 12. 6 2.6 0.7 2. 4 20.4 Value (million $) 8.8 38. 2 6. 9 0. 1 5. 3 5 9.5 Finfish ( and other ) Volume (million lbs) 3.7 759.3 190.2 5.4 34.7 993.4 Value (million $) 7.7 64 .0 19.2 4.1 50.5 145.6

Source: NOAA Fish eries Economics of the U.S.

These data were accessed on

- line at http://www.st.nmfs.noaa.gov/st5/publication/fisheries_economics_2008.html#

NOAA’s National Marine Fisheries Service (NMFS) data on weights and values of landings exhibit strong seasonality: Figure 10 and Figure 11 show a pronounced peak in each State’s landings during one or two summer month s each year; Figure 12 and Figure 13 show revenues by State during the summer months. This seasonality indicates that the timing of closures and population impacts should be considered in an analysis of oil spill damages. The seasonality is also rather stable, 21 suggesting that reasonable future monthly harvest values might be inferred
from the data. We used the early summer months which correspond to the high revenue season for convenience rather than employing more sophisticated assumptions to reflect the seasonality.
This choice deviat es from our usual practice of using conservative assumptions to generate avoided social costs, but the values involved are so small relative to other social costs that further efforts in this regard do not appear warranted.

21 Within

- month coefficients of variation for May, June, Jul y and August are below 0.45 for all five Gulf States over 1997 through 2008, and below 0.37 outside of Mississippi. The variation is lower still (outside of Mississippi) for 2002 through 2008: below 0.26 for all months.53 Figure 10 Monthly Commercial Fishery Landings (Texas, West Florida, Alabama)

Figure 11 Monthly Commercial Fishery Landings (Louisiana, Mississippi)54

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

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

Baseline monthly landings values were estimated separately for each month of 2010 by sorting
the 2002

- 2008 data by month, and finding the monthly trend for each State using ordinary least squares. These values are reported in Table 9

.55

Table 9 Estimated 2010 Baseline Values for Gulf State Commercial Fisheries ($ millions, trend 2002

- 2008) Texas Louisiana Mississippi Alabama West Florida May $12.0 $29.8 $0.9 $2.5 $8.5

June $11.7 $43.6 $6.5 $7.6 $7.2 July $23.2 $29.3 $6.6 $6.4 $5.8

Operating Costs

Liese et al

. (2009) performed a cash

- flow analysis based on a sample of Gulf commercial shrimpers. They found the average net revenue (before taxes) for a gulf shrimping operation was $2,654, with a 95% confidence interval spanning

- $4,138 to +$9,446. This wide conf idence interval, which includes zero, suggests that while the average vessel may be earning positive net revenues, there are at least some vessels that are earning negative net revenues. This was observed in spite of the fact that “the effective economic environment actually improved somewhat from 2006 as shrimp prices increased proportionally more than fuel prices. However, with the liquidity constraint implied by a negative cash flow and following many marginal years, it seems the average vessel simply d id not have the ability to exploit this improvement and had to cut its overall effort (Liese et al

. 2009).

Travis and Griffin (2004) had predicted the improvement noted by Liese in a simulation that assumed that variable costs as a percentage of revenues would fall for Gulf commercial shrimping. Their assumptions are given in Table 10

.

Table 10 Gulf Commercial Shrimping Costs as a Percentage of Revenues (simulated)

2002 2007 2010

- 2018 (lowest

- cost period) Large Vessels (at least 60 feet long) 98% 78% 75%

Small Vessels (<60 feet long) 114% 96% 93%

Liese’s 2007 survey results can be used to make some inferences about how the Gulf fleet is divided between “large” and “small” vessels. They found 12% of the fleet was less than 50 feet long, and 56% of the fleet was more than 75 feet long. For the 31 % of the sample that was 50 to 75 feet long, the average length was 65 feet. We assume that vessels are evenly distributed by size within this category, so that half the vessels (16 percent of the fleet) are longer than 65 feet.
Of the 16% of vessels tha t are 50 to 65 feet long, two

- thirds of the vessels are 50 to 60 feet long,
and one

- third of the vessels are 60 to 65 feet long. Tallying the proportions below 60 feet56

indicates that 23 percent of the fleet consists of “small” vessels (by Travis and Griff in’s definition), while 77% of the fleet consists of “large” vessels. These results are summarized in

Table 11 , where the same approach is used to app ortion the total fleet shrimp landings and landings revenue.

Table 11 Gulf Shrimping Fleet: Large and Small Vessels

Categories from Liese et al. (2009) Categories from
Travis and Griffin (2004)

< 50 feet 50 feet to

60 feet 60 feet to

65 feet 65 feet to

75 feet > 75 feet < 60 feet >= 60
feet

% of
Fleet
Vessels 12% 10% 5% 16% 56% 23% 77%

% of
Fleet Shrimp Landings 4% 10% 5% 15% 66% 14% 86%

% of
Fleet Landings

Revenue 3% 9% 5% 14% 69% 12% 87%

*A small percentage (0.2 percent) of the landings revenue is from non

- shrimp landings.

As shown in Table 11 , the smallest vessels in Liese’s survey (those less than 50 feet long) form a disproportionately small part of the industry: these vessels make up 12 % of the fleet, but bring in only 4 % of the landings, and receive only 3 % of the landings revenue. In part this is due to the lower price that they receive for shrimp ($2.40 per pound versus the fleet average of $3.00). Likewise, the largest vessels form a disproportionately large part of the industry. Vessels over 75 feet long make up 56 % of the fleet, but bring in 66% of the landings, an d receive 69% of the landings revenue. We preserve this imbalance when we switch to the 60

- foot designation for “large” vessels.

The proportions of Gulf commercial shrimp landing revenues going to large and small vessels is
combined with the baseline re venue projections in Table 9 to determine the contribution of each vessel class to baseline revenues for the entire commercial fishing industry (see Table 12 ). We then apply the assumptions from Travis and Griffin (2004) about variable costs as a percentage of revenues to determine baseline profits accruing to each vessel class (see Table 13 ). Finally, in57

Table 14 the results for large and small vessels are summed together to find the 2010 baseline for total industry profits by month.

Table 12 Large and Small Vessel Contributions to Gulf Commercial Fishing Revenues (2009$ millions)
Vessels Texas Louisiana Mississippi Alabama West Florida May Fleet $12.0 $29.8 $0.9 $2.5 $8.5 Large $9.2 $22.9 $0.7 $1.9 $6.5
Small $2.8 $6.9 $0.2 $0.6 $2.0

June Fleet $11.7 $43.6 $6.5 $7.6 $7.2 Large $9.0 $33.6 $5.0 $5.9 $5.5
Small $2.7 $10.0 $1.5 $1.7 $1.7 July Fleet $23.2 $29.3 $6.6 $6.4 $5.8 Large $17.9 $22.6 $5.1 $4.9 $4.5
Small $5.3 $6.7 $1.5 $1.5 $1.3

Table 13 Estimated Baseline Profits for 2010: Large and Small Gulf Commercial Fishing Vessels (2009$ millions)
Vessels Texas Louisiana Mississippi Alabama West Florida May Large $2.3 $5.7 $0.2 $0.5 $1.6

Small $0.2 $0.5 $0.0 $0.0 $0.1

June Large $2.3 $8.4 $1.3 $1.5 $1.4

Small $0.2 $0.7 $0.1 $0.1 $0.1 July Large $4.5 $5.6 $1.3 $1.2 $1.1

Small $0.4 $0.5 $0.1 $0.1 $0.1

The calculations presented in Table 13 assume that all Gulf commercial fishing operations have similar cost structures, namely that variable costs average 75 % of revenues for large vessels, or
93 % for small vessels. This is a conservative estimate: commercial shrimping is a high

- cost industry, and other types of fishing are likely to have lower costs. Applying this percentage to
the 2010 baseline revenues from Table 9 gives the 2010 baseline profits in Table 14

.

If labor used in commercial fishing is not easily redeployed to alternatives, i.e., it does not have an opportunity cost, then this lost labor would also be included as an avoided social cost. We did not attempt to include estimates of this effect since the entire lost fishing and recreation item is such a small fraction of the total avoided cost estimate. Even counting all lost fishing revenue adds only one percent to our total avoided cost estimate.58

Table 14 Estimated Baseline Profits for 2010: Gulf Coast Commercial Fisheries (2009$ millions)
Texas Louisiana Mississippi Alabama West Florida May $2.5 $6.2 $0.2 $0.5 $1.8

June $2.4 $9.1 $1.4 $1.6 $1.5 July $4.8 $6.1 $1.4 $1.3 $1.2 August $6.9 $7.4 $1.0 $1.8 $2.5

Closures
Gulf fishery closures in the Federal Exclusive Economic Zone (EEZ) are tracked over time in
Table 15 . As of July 21, 2010, about a third of Federal w aters in the central Gulf were closed, while Texas had not experienced any closures, and shrimping season in the western Gulf opened as usual on July 15. 22 The eastern edge of the Gulf has also remained open, and Florida has closed only about 20 miles of the coastline near Pensacola. 23 All of Alabama State coastal waters (outside of Mobile Bay) have been closed to commercial fishing since June 24, though

so me shrimping and catch

- and

- release fishing are allowed. 24 On July 20, Mississippi State
coastal waters re

- opened to live

- bait shrimping and catch

- and

- release fishing. 25 As of July 5, about half of Louisiana oyster harvest areas were closed, as was about ha lf of the Louisiana coastline (from Oyster Bayou to the Mississippi border) for commercial fishing. A smaller set of areas was closed to recreational fishing. 26

22 Texas data were taken from the Te xas Parks and Wildlife Department website “BP Oil Spill in the Gulf of Mexico” at http://www.tpwd.state.tx.us/site/emergency/oil_spill/.

23 Florida closure data were taken from a Florida Fish and Wildlife Conservation Commission press release dated June 13, 2010.

24 Alabama closure data were taken from an Alabama Department of Conservation and Natural Resources press release dated June 28, 2010.

25 Mississippi closure data were taken from a Mississippi Department of Environmental Quality/Department of Marine R esources news release dated July 19, 2010.

26 Louisiana closure data were taken from the Interactive Closure Maps on the website of the Louisiana Department of Wildlife and Fisheries (LDWF) at http://www.wlf.louisiana.gov/oilspill/map/.59 Table 15 2010 Gulf Fishery Closures in Federal Exclusive Economic Zo ne (EEZ) Closure Date (2010) Percent Coverage

of Gulf EEZ Days Closure

was in Effect Effective Days of

Full EEZ Closure

2

- May 2.8% 5 0.1

7

- May 4.5% 4 0.2
11

- May 6.6% 1 0.1
12

- May 7.3% 2 0.1
14

- May 8.0% 3 0.2
17

- May 10.0% 1 0.1
18

- May 18.9% 3 0.6
21

- May 19.8% 4 0.8
25

- May 22.4% 3 0.7
28

- May 25.1% 3 0.8
31

- May 25.6% 1 0.3 May 2010 Subtotal 3.9
1

- Jun 31.4% 1 0.3
2

- Jun 36.6% 2 0.7
4

- Jun 32.3% 1 0.3
5

- Jun 32.5% 2 0.7

7

- Jun 32.3% 9 2.9
16

- Jun 33.4% 5 1.7
21

- Jun 35.9% 2 0.7
23

- Jun 32.5% 5 1.6
28

- Jun 33.2% 6 2.0
June 2010 Subtotal 10.9
4

- Jul 33.5% 8 2.7
12

- Jul 34.8% 1 0.3
13

- Jul 34.7% 10 3.5
23

- Jul 23.8% 8 1.9 July 2010 Subtotal 8.4 May

- July 2010 Total 23.2

source: http://sero.nmfs.noaa.gov/ClosureSizeandPercentCoverage.htm

We applied the “effective days of full EEZ closure” by month to the profits for Louisiana, Alabama and Mississippi. This approach relies on the assumption that landings, costs and vessel classes are evenly distributed throughout a State’s waters and the a djacent portion of the EEZ. We are also assuming that the timing for landings is seasonally fixed, so that applying extra
effort ahead of the spill could, but did not shift profits to that particular point in time.60 Table 16 Estimated Gulf State Profits Lost to Closures Days of
Closure Days in

Month 2010 Baseline Profits

(LA, MS, AL), millions (2009$) Lost profits,

millions (2009$) May 3.9 31 $6.9 $0.9

June 10.9 30 $12.0 $4.4 July 7.7 31 $8.8 $2.2

Total $ 2 7. 8 $7.5

A total of $7.5 million in lost profits due to a spill of 4.8 million barrels is equivalent to $1.56 per barrel.



### Valuing Lost Recreation
Recreation activities are often affected when oil spills result in contamination of coastal or ocean
resources. These d amages can result in value losses to consumers who either are unable or choose not to participate in a given recreation activity due to the contamination or do participate but have a lower quality experience than if there was no contamination. In order to arrive at a value of lost recreation, estimates must be obtained for the number of recreation trips (or days) lost per barrel of oil spilled and the average value for a particular type of recreation trip.

Economists use consumer surplus, or the differenc e between what an individual is willing to pay for a good and what they actually pay for it, to arrive at these recreation values. Since market price data is lacking for the value of recreational activities, these values are inferred from
consumer behavio r (such as the costs incurred to travel to the recreation site) or from individual stated preferences about their willingness to pay for the resource. Ideally, survey

- based data
would be collected from individuals to obtain information about the value tha t they place on the resource in a particular geographic location and the value loss incurred from an oil spill. However, when it is not feasible to undertake an original study to obtain these values, the benefit
transfer approach is often used. Benefit t ransfer is a method that applies values obtained from previous studies to a new situation where primary data has not been collected.

In this section, benefit transfer is used to produce estimates of the value of lost recreation associated with a catastrop hic oil spill event in the Gulf of Mexico for recreational fishing and beach recreation. Other recreational activities such as scuba diving, snorkeling and boating are likely to be affected as well but estimates for those activities are not included in th is analysis due61

to lack of information about the impacts and potential overlap among activities. In order to arrive at an estimate of the impact of a catastrophic oil spill, several assumptions are required about the size, duration and location of the spi ll. In this analysis, the spill is assumed to result from a catastrophic blowout event in the GOM. In addition, this analysis does not account for the substitution of less desirable or more costly recreation sites for those that are affected by the spill

. 

### Recreational Fishing In order to estimate the value of lost recreational fishing trips, historic data on the total number of trips is first required. Historic data from the NOAA Marine Recreational Fishing Statistics Survey (MRFSS) for the Gulf Coast R egion including Alabama, Mississippi, Louisiana, and Western Florida (data for Texas was not available) was used to arrive at an estimate of number of trips over a three month period including May, June and July (Wave 3 and half of Wave 4 in
the MRFSS data set). These totals were not adjusted to reflect non

- offshore fishing since such adjustments would be arbitrary and the overall cost of this element is small, relative to the much larger social cost estimate. Using a five

- year average from 2005

- 2009, an estimate of 7,667,567 recreational fishing trips was obtained ( Table 17 ).

Table 17 Average Number of Trips (May

- July) (2005

- 2009) Area Number of Trips

Alabama 572,907

West Florida 4,576,280
Louisiana 1,455,094 Mississippi 384,055
Federal EEZ 679,261
Total 7,667,597

Source: NOAA Marine Recreational Fishing Statistics Survey

The number of effective days of full closure ( see Table 15 ) was then applied to the average number of trips per day for each month to estimate the number of trips lost during the period of closure. Effective days of closure for the Federal EEZ were also applied to each of the States due to lack of specific data on State water closures. This is likely to result in an underestimate for Alabama, Mississippi and Louisiana, and an overestimate for Florida. In addition, this
estimate does not account for certain areas that re

- opened to catch

- and

- release recreational fishing after initial closures. It should also be noted that these estimates do not explicitly account for the availability of substitute fishing destinations, or the differences in behavior of local versus out of state fishermen (local fishermen may be less likely to find a suitable substitute if recreational fishing is affected throughout the region). If suitable substitutes are available, it is62

likely that the decrease in number of trips w ould be smaller than if fewer substitutes are
available.

Benefit transfer was then used to value the lost recreational fishing trips. Consumer surplus estimates (in dollars per activity day) were obtained from previous non

- market valuation studies
of rec reational fishing in the Gulf Coast region. All values were converted to current (2010) dollars, and an average value of $54.48/day was obtained from the 7 studies considered. This value was multiplied by the number of trips lost for State waters in each state and the Federal
EEZ to arrive at total estimated consumer surplus over the three

- month period. The total recreation value lost over the period is estimated to be $111.8 million. In this catastrophic spill scenario, we assume the impacts discussed result from a spill of 4.8 million barrels. Dividing the recreation value lost by the number of barrels spilled gives a value loss of $23.43 per barrel.



### Beach Recreation Historic data on the annual number of visitor days for beach recreation in the Gulf C oast States was obtained from the 2000 National Survey of Recreation in the Environment (NSRE) conducted by the U.S. Forest Service and NOAA. In order to estimate the number of visitor days in May, June and July, the monthly visitation data from Gulf Isla nds National Seashore (located in MS and FL) was used to estimate the percentage of visitation during this three month period (48%) and this percentage was applied to the annual state visitation data. For the State of Florida, information from Murley et a l. (2005) was used to estimate the percentage of beach recreation visits that occur on the western coast (25.7%). The estimated recreation days in each state during the period are shown in Table 18

.

Table 18 . Estimated Number of Recreation Days (May

- July)

State Recreation Days

Alabama 5,683,200

West Florida 21,853,224

Louisiana 1,939,200
Mississippi 4,161,600

Texas 16,910,400

Total 50,547,624

Ideally, in order to estimate the number of recreation days lost, actual visitation data would be collected from beach surveys or over flight surveys during the affected period and compared to average visitation levels for that time of year. In the absenc e of actual visitor counts, certain assumptions must be made to estimate the recreation days lost. In this case, the percentage of oiled shoreline in each state as of July 22, 2010 was used to approximate the percentage of63

recreation days in each state th at were affected (12% in AL, 2% in FL, 5% in LA, 30% in MS and 0% in TX). This is likely to be an underestimate for much of the area because the total shoreline used to calculate the percentage of area affected includes areas that are not used for
beach r ecreation.

Although most beaches along the Gulf Coast may remain open after a deepwater catastrophic oil spill , decreased visitation and a reduction in quality experience for those that still participate in
beach recreation are likely to occur. In this analysis, we assume that all beaches remain open, with a decrease in recreation days of 20% compared to historic levels. We also assume that remaining visitors experience a loss in consumer surplus due to decreased quality of th e recreation activity. We assume a 20% loss in quality for each recreation day affected, following Chapman and Hanemann (2001).

Consumer surplus values for beach recreation per activity day were obtained from 8 studies conducted in the Gulf Coast regio n. All values were converted to current (2010) dollars and averaged to obtain a value of $88.47 per activity day. This value was then multiplied by the number of recreation days in each state to arrive at a total consumer surplus value for beach
recreati on during the three month period. Using these values, we estimate a loss in the value of beach recreation of $75.5 million over the period, or $15.82 per barrel for a spill of 4.8 million barrels. It should be noted that these estimates do not explicitly account for the availability of substitute beach sites, or the differences in behavior of local versus out of state visitors. If suitable substitutes are available, it is likely that the decrease in consumer surplus would be
smaller than if fewer substit utes are available.

As with the commercial fishing analysis, we used selected characteristics of the BP spill as a proxy for a future catastrophic spill simply for analytical convenience. These factors include the closure periods and time of year. The m inor size of the recreational fishing and beach use values relative to the total social cost estimate did not justify devoting further effort to refining the spill circumstances such as randomizing time of year or adjusting for fishing trip substitution.64 Table 19 . Recreation Studies Recreational Fishing

Year State Reference

1991

- 1992 Florida (Tampa Bay) Greene et al., 1997

1991 Gulf of Mexico Gillig et al., 2000

1991 Florida Leeworthy, 1990

1992 Florida Bell et al., 1982

1999 Louisiana Bergstrom et al., 2004

1990 Florida Bell, 1992

1988 Florida McConnell and Strand, 1994

Beach Recreation

Year State Reference

1996 Florida (Keys and Key West) Leeworthy and Bowker, 1997

1984 Florida Bell and Leeworthy, 1986

1984 Florida Bell and Leeworthy, 1986

2008 Texas (Padre Island Nat. Seashore) Parsons et al., 2009

1990 Florida (Clearwater Beach) Leeworthy and Wiley, 1994

1990 Florida (Honeymoon Island State Park) Leeworthy and Wiley, 1995

1984 Florida Bell and Leeworthy, 1990

1988 Florida (John Pennekamp State Park) Leeworthy (1991)



### Oil Spill Response and Damage Assessment Costs
Response or removal expenditures include rescue and rehabilitation of personnel and wildlife, salvage of infrastructure, cleanup of oil from aquatic a nd terrestrial areas, and hearings and investigations into causes of a spill. Removal costs include the equipment used in the

response

— skimmers to pull oil from the water, booms to contain the oil, airplanes for aerial observation or dispersant applicatio n

— as well as salaries, travel and lodging costs for responders. Response expenditures can be incurred by: Federal, State, Tribal governments; industry; non

- governmental organizations; private companies; and foreign entities. Response
costs exclude the we llhead containment costs to secure and kill the uncontrolled flow from a well
blowout. Although technically “response costs” under the Oil Pollution Act (OPA), t hose containment costs are considered private

- social costs for this analysis and covered in th e section

on Avoided Private

- Social Costs . Damage assessment costs can include costs associated with data collection and analysis required to evaluate the impacts of the spill relative to pre spill
conditions.

In a 2003 report to Congress, ( Informing Regulatory Decisions: 2003 Report to Congress on the Costs and Benefits of Federal Regulations and Unfunded Mandates on State, Local, and Tribal65

Entities ), OMB considered benefits of vessel response plans and double

- hull vessels by valuing
avoide d spills at $2,000 per barrel, noting that “This is double the sum of the most likely estimates of environmental damages plus cleanup costs contained in a published journal article.”

Estimates of response costs can also be found in the literature. Table 20 presents estimates in current dollars of oil spill cleanup costs by oil type; Table 21 presents estimates by kilometer of shoreline oiled; Table 22 presents estimates by pro ximity to shore. Table 23 presents information by spill volume. 27

Table 20 Cost of Spills by Fuel Type Oil Type US Spills (20 10

$/bbl)
No. 2 diesel fuel 638

Light crude 554
No. 4 fuel Data not available
No. 5 fuel 1,539
Crude 2,570 Heavy crude 3,733
No. 6 fuel 3,198

Per

- unit cleanup costs by degree of shoreline oiling

Source: Etkin, June 2000

.

Table 21 Cost of Spills by Length of Shoreline Oiled

Shoreline Length Oiled US

Spills (2010 $/bbl)
0

- 1 km 468
2

- 5 km 1,060
8

- 15 km 1,866
20

- 90 km 2,684
100 km 4,832
500 km 9,197

27 Etkin, D. June 2000. Worldwide Analysis of Marine Oil Spill Cleanup Cost Factors. Presented at Arctic and Marine Oil Spill Program Technical Seminar; Etkin, D. 2001. Comparative Methodologies for Estimating on Water Response Costs for Marine Oil Spills, International Oil Spill Conference.66 Table 22 Cost of Spills by Location Location US Spills

(2010 $/bbl)
In

- port 6,033
Nearshore 4,437
Offshore 1,217

Source: Etkin, 2001

.

Table 23 Oil Spill Response Costs by Spill Volume Spill Volume (bbls) Total Cost

($2010) $ per bbl

($2010)
240 203,803 856 2,400 2,072,094 870 12,000 10,953,217 920 120,000 46,885,858 394 240,000 90,476,930 380

Source: Etkin, 2001

.

For the purposes of the benefit

- cost analysis it is assumed that one third of the response efforts

occur near shore and two

- thirds offshore. The weighted average of the near

- and offshore response cost estimates presented above is $2,300 per bbl.



### Avoided Costs Associated with Reduced Loss of Life and Nonfatal Injuries

T here have been 20 blowouts from deepwater wells, with 2 resulting in injuries or fatalities.
Those two events are a 1984 blowout with 4 fatalities and 3 injuries and the 2010 BP

- Deepwater
Horizon explosion and resulting spill with 11 fatalities and 17 injuries. For purposes of estimating costs avoided from reduce loss of life and injuries, the following uses the average fatalities and injuries for these 2 cases as values for a hypothetical catastrophic deepwater
blowout.



### Value of Statistical Life The proposed regulation, because it is anticipated to reduce the probability of catastrophic blowout events, is likely to reduce the risk of premature death of rig workers. The oil and gas extraction industry is characterized by a rel atively small percentage of the Nation’s workforce and a higher fatality rate than most other industries. Approximately 161,600 workers were employed in oil and gas extraction occupations in 2008 (Bureau of Labor Statistics 2010). The67

fatality rate for o il and gas extraction workers is high compared to many other industries, with a rate of 23.4 fatalities per 100,000 full

- time equivalent workers ( Table 24 ).

Table 24 Selected Fatal Occupational Injury Rates by Industry, 2008

Industry Fatality Rate (per 100,000 Full

- Time Equivalent Workers) Agriculture, forestry, fishing, and hunting 30.4

Oil and gas extraction 23.9 Transportation and warehousing 14.9

Construction 9.7 Protective service occupations (includes protective service occupations such as fire fighters, law enforcement) 9.1

Manufacturing 2.5 Management, professional, and related occupations 1.6

Finance, insurance, real estate and leasing 1.1

Source: Bureau of Labor Statistics, 2010.

The benefits of occupational risk reduction are usually measured using the concept of “value of statistical life” (VSL). The VSL concept is based on individual willingnes s to pay for reductions in small risks of premature death and not on the present value of future earnings. In concept, the VSL is the measurement of the sum of society’s willingness to pay (WTP) for one unit of fatal risk reduction, which is society’s wil lingness to pay for reducing each individual’s risk by a

small amount.

VSL estimates are derived from aggregated estimates of individual values for small changes in mortality risks. For the analysis of benefits, mortality risks can generally be classif ied across the characteristics of the affected population and the characteristics of the risk itself. These factors should be addressed in any analysis that transfers values from one study to a new policy context.
The literature on VSL identifies the fo llowing factors that affect risk perceptions that could be considered in selecting and adjusting any VSL values:

 Voluntary/involuntary;

 Ordinary/catastrophic;68

 Delayed/immediate;

 Natural/man

- made;

 Old/new;

 Controllable/uncontrollable;

 Necessary/unnecessary; and

 Occasional/continuous.

Whether adjustments are made to the VSL value depends on a variety of factors, including the extent to which such adjustments could be made on a systematic and defensible basis. To date
there has been a lack of consensus on the merits of using a single VSL for all situations versus adjusting the VSL estimates to reflect the specific rule context.

Income has been found to have a clear and measurable effect on the VSL: as income increases,
WTP for risk r eductions usually increases. While this effect could be measured both cross

sectionally (across individuals or subpopulations) and longitudinally (over time), most studies

are cross

- sectional. However, using different VSL estimates for individuals with dif ferent incomes is controversial and has raised issues about the equitable treatment of richer and poorer segments of the population in policy decisions (Robinson, 2007). Some recent studies only consider samples from extremely dangerous jobs, such as poli ce officers. Workers in these jobs may have different risk preferences and face risks much higher than those evaluated in typical environmental policy contexts (Kochi, 2006). Other recent research has examined how VSL varies with age, how it varies betwee n males and females, and how worker heterogeneity may impact VSL.

A large number of estimates of VSL exist in the academic literature. This literature involves either explicit or implicit valuation of fatality risks, and generally involves the use of esti mates of VSL from studies on wage compensation for occupational hazards, on consumer product purchase and use decisions, or from an emerging literature using stated preference approaches. Values reported have varied over time, geographic location, and wor ker heterogeneity. VSL estimates from under $1 million to around $3 million that were used to assess policies in the early 1980s have now been replaced by estimates as high as $9 million (Viscusi, 2010). A substantial majority of the resulting estimates of VSL vary from roughly $1 million to $10 million per statistical life. The literature based on estimates using U.S. labor market data typically shows a VSL in the range of $4 million to $9 million.

EPA recommends that the central estimate of $7.4 mil lion ($2006), updated to the base year of the analysis, be used in all benefits analyses that seek to quantify mortality risk reduction benefits regardless of the age, income, or other population characteristics of the affected population. This approach wa s vetted and endorsed by the Agency when the 2000 Guidelines for69

Preparing Economic Analyses were drafted. A recent report of the EPA’s Science Advisory Board (SAB) concluded that the available literature does not support adjustments of VSL for
most facto rs. However, the panel did support adjustments to reflect changes in income (EPA allows the adjustment of VSL based on increases in future income but not on cross

- sectional differences in income), adjustments for inflation and time lags in the occurrence of adverse
health effects.

VSL Value Used in Offshore Safety Regulation For the purpose the analysis to estimate the avoided costs associated with reduced mortality, $8

million is used to value each statistical life. This is the EPA recommended estimate of $7.4 million updated to current dollars ($2010). Although oil rig workers are involved in an inherently risky occupation, based on the lack of consensus in previous research focused on adjusting VSL values for occupational risk, the EPA VSL recommenda tion was chosen for this analysis.

Based on the estimated value of 8 deaths per blowout event , using a VSL value of $8 million, for a 4.8 million barrel spill, the loss of life value from a blowout would be $1 3 /barrel.

Nonfatal Injuries
On average, worke rs value non

- fatal loss injuries on the job at values ranging from $20,000 to $70,000 per expected job injury. Thus, for example, a worker at the high end of this range would require $2,000 to face a one

- in

- 25 chance of being injured that year (Viscusi, 2 005).

We estimate an average value of job injuries at $45,000 per injury. With 10 injuries expected

per catastrophic blowout event, a 4.8 million barrel spill would result in an estimated cost of $0. 09 per barrel.



### Other Health Effects

The Centers for Disease Control and Prevention (CDC) report that the Gulf Coast oil spill has the potential to affect human health. CDC and the Gulf States have a plan to track symptoms 28
occurring in the affected communities and will be able to investigate whether there is an association between symptoms and the oil spill. As of July 20, 2010, the American Association of Poison Control Centers reports receiving 843 “exposure calls” involving someone exposed to

an oil

- spill related toxin (e.g., oil, dispersant, food conta mination).

28 Symptoms may be related to the eyes, skin, and respiratory, cardiovascular, gastrointestinal, and neurological systems, including worsening of asthma, cough, chest pain, eye irritation, nausea, and headache

.70

Human health effects from oil spills include short

- term physical effects from exposure of clean

up workers and residents of the area, mental health effects on workers and residents, as well as long

- term effects. However, the research on health effects of oil spills is limited to date. There has been some evidence of acute physical effects and psychological effects in a number of cases. For example, CDC’s National Institute for Occupational Safety and Health reports 186 injuries
and 80 illness es 29 among spill responders in the Gulf. However, evidence of long

- term health effects is lacking. Much of the research on the physical effects of oil spills has been conducted
outside of the United States. Some researchers have found evidence that oil s pills affect the
health of individuals involved in clean

- up activities (Pérez

- Cadahía et al. 2006), residents in the immediate vicinity of a spill (Janjua et al. 2006, Lyons et al. 1999), and residents involved in
clean

- up efforts (Morita et al. 1999). Ph ysical effects on residents near oil spills have included sore eyes and throat (Lyons et al. 1999, Janjua et al. 2006) as well as headaches and general malaise (Janjua et al. 2006). Pérez

- Cadahía et al. (2006) show evidence of cytogenetic damage
and alter ations in hormonal status.

Evidence of mental health effects have been shown for the Exxon Valdez and Prestige oil spills (Palinkas et al. 1993a, Palinkas et al. 1993b, Sabucedo et al. 2010). Palinkas et al. (1993a) show links between the oil spill a nd increased rates of depression, anxiety and post

- traumatic stress disorder, and declines in subsistence activities and traditional social relationships. Sabucedo et al. (2010) show similar results with greater psychopathological symptoms in individuals living closer to the location of the oil spill and in fishermen.



### Avoided Costs Associated with Other Activities Linked Economically to Avoiding an Oil Spill
A large oil spill will have economic costs that accrue beyond the area directly impacted. These

co sts will be incurred by businesses and households that are linked economically to coastal areas or to activities occurring in areas damaged by the spill. The oil spill may result in reduced producer surplus, lost producer surplus on products or services t hat are no longer produced, or some combination of the two. The magnitude and timing of any reduced producer surplus is difficult to predict, however the larger the spill and the more extensive its geographic impacts the larger the potential for producer surplus losses. The lost producer surplus associated with economic losses is not quantified for this analysis due to the uncertainties associated with the scope, magnitude, and timing.

29 As of June 6, 2010; mo stly contusions/abrasions and heat stress.71



### Summary

– Avoided External

- Social Costs

Table 25 summarizes the estimated avoided external

- social costs of the hypothetical catastrophic
blowout spill conditional on the spill being precluded from occurring. Spill costs that are
avoided could be much higher if all costs discussed previously could be monetized

. Efforts to quantify even rough estimates for those rows left blank in the table by reference to other oil spills were not fruitful because such private settlements are not reported publicly. Nevertheless, given
the relative size of those sub

- elements th at could be monetized, the findings indicate that recreation, fishing and mortality losses are quite small compared to the costs for spill cleanup, damage assessment, and the imputed value of natural resource damages. Thus, provision for the lingering eff

ects which an oil spill might have on fishing losses is not likely to affect the overall
results.

Table 25 Summary of Estimated Avoided External

- Social Costs Social Cost Category Cost Avoided Cost

for 1 Hypothetical Spill ($ per bbl) (4.8 mm bbl)
Natural Resource Damages $604 $2.88 billion
Recreational Losses (Recreational Fishing and Beach Recreation) $42 $0.20 billion

Commercial Fishing Losses $2 $0.01 billion

Value of Life and Nonfatal Injury $13 $0.06 billion

Other Health Effects Not
Quantified Oil Spill Response & Damage

Assessment Costs $2,300 $10.97 billion

Staging, training, and other costs associated with prepositioning oil spill

response assets Not
Quantified

Price effects in seafood markets Not
Quantified Property values Not
Quantified

TOTAL $14.12 billion72



## TOTAL ESTIMATED AVOI DED SOCIAL COSTS (BE NEFITS)

Table 26 combines the conditional avoided private

- social and external

- social costs from Table 6
and Table 25

. This is the potential benefit per catastrophic spill in the baseline fr om fully eliminating the possibility of a spill.

Table 26

- Summary of Private and External Social Costs Social Cost Category Conditional

Avoided Cost
Amount Expected Avoided Cost Given

1 Spill in 25.8 years (3.85% probability of a spill each year)

Private Costs $2.17 billion $84.1 million

External Costs $14.1 2 billion $547.3 million

Total: $16. 29 billion $631.4 million

The policies being promulgated can reduce, but not necessarily eliminate, the occurrence of a catastrophic spill and hence the resulting spill costs. Since the compliance costs are fully represented by annual expense outlays, it is convenient to express the expected avoided costs on
an annual basis as wel l. Moreover, the coincident timing of compliance costs and risked avoided costs dispenses with the need to complicate the calculations and presentation by converting streams of monetary costs and benefits into discounted present value amounts.

There has been the only one deepwater blowout spill large enough to be considered in the catastrophic class. Based on this single observation, the number of deepwater wells drilled (4,123), and the anticipated annual number of future deepwater wells to be drilled ( 160), the
baseline risk absent this rule is estimated to be 1 event in 26 years for this benefit

- cost analysis. Compliance with the requirements in this rule will partly reduce the expected annualized spill costs by reducing the spill frequency, thereby i ncreasing the expected interval between such spills and hence spreading the conditional spill costs over more years. The resulting reduction in the expected annualized spill costs represents the social costs associated with the hypothetical spill scenario avoided because of the provisions in this rule.



## SCENARIO ANALYSIS

In order to compare the relative magnitudes of the expected benefits and costs associated with avoiding a blowout resulting in catastrophic oil spill, the agency examined several scenarios73

based on extrapolation from historical information on deep water blowouts. Given the paucity of information on specific effectiveness of various measures and the likelihood of another catastrophic blowout, this approach aims to evaluate the Final Rule in the context of alternative assumptions.

The methodology we used to compare the economic effects of the Final Rule under the various scenarios was to determine the hypothetical improvement in spill frequency that would have to occur under each scenario for the expected benefits to match the expected costs (the breakeven point). Calculating the breakeven point for each scenario is a useful analytical tool for comparing the sensitivity of the various factors in our analysis. It w ill also assist agency policymakers in getting a sense of whether promulgation of the final rule would likely have a net economic benefit under differing assumptions. These calculations, however, are not an agency determination of the actual expected impr ovement in spill frequency that the final rule will bring about. Such a determination is based upon assessing the expected effects of the provisions of the final rule, and not upon hypothetical economic analyses.

By varying selected important assumptio ns from those of the Baseline Scenario in reasonable

ways, we have provide d a range of reasonable alternative scenarios that could be expected to occur. For each of those scenarios, we have calculated the improvement in spill frequency under which expect ed benefits could justify the costs of the regulation (the economic breakeven point)

. The Scenarios have been developed by varying the assumptions from the Baseline Scenario as
follows:

1) The compliance costs are lowered by about 50% to $6 5.4 million reflecting improvements in the efficiency of safety practices. 2) The compliance costs are raised by about 100% to $ 261 million reflecting more frequent compliance problems and work stoppages during drilling operations, as
discussed in the next section. 3) T he population of deepwater wells subject to a future catastrophic blowout spill is limited to those in water deeper than 3,000 feet, where the spill size and consequences (but not the spill probability) from a blowout are estimated to be greater. For the purpose of conducting this sensitivity analysis only, we employed the historical population of 1,475 wells drilled in the GOM at a water depth of 3000 feet or greater to set the baseline risk, and forecast that an average of 110 wells will be drilled each year at this depth. Elaboration of this scenario is provided in the Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blowout Spill.74

4) The baseline of the expected number of deepwater wells drilled each year is red uced by 25 percent. This would reduce the number of deepwater wells in the analysis from 160/year to 120/year. This scenario is closer to the number of deepwater wells drilled in the two years before the DWH spill.



### Baseline Scenario

For the Baseline Scenario, t he hypothetical spill from Table 26 gives an avoided social cost of $16.3 billion for a major event. The compliance costs of this regulation from Table 4 give an annual compliance cost of $ 131 million per year. The baseline assumption is that there was one major event for every 4,123 deepwater wells and we assume an average of 160 wells will be drilled annually. Under these circumstances, a major event is projected to occur at an average
rate of approximately once every 26 years. 30

Using the avoided social cost of $16.3 billion and dividing it by the rate of a major event, one per

every 26 years

, we calculate an annual avoided cost of $631 million. To calculate the level of improvement in spill frequency for the expected benefits to equal the costs of regulation, we divide the compliance costs by the annualized avoided costs. An annual compliance cost of $ 131 million divided by annualized avoided costs of $631 million results in a 2 1 perce nt improvement in spill frequency that would be the level at which expected benefits would match the expected compliance costs.



### Sensitivity of Compliance Costs

A lower compliance cost estimate of $ 65.4 million annually assumes the industry can achieve longer term productivity improvements for the requirements in this regulation. Over time, companies can increase the efficiency of conducting tests and use technology to improve safety ; however, a 50 perc ent improvement appears unlikely to be achieved in the near term. Using this lower compliance cost of $6 5.4 million, divided by the annual avoided cost of $631 million, an improvement in spill frequency of 10 percent would be sufficient for estimated bene fits to match estimated compliance costs

.

An upper compliance cost estimate of $2 61 million annually assumes that the time required for conducting the tests for this regulation are doubled due to unforeseen and time consuming problems encountered in fulf illing the additional requirements imposed by this regulation. Using this upper compliance cost of $ 261 million divided by the annual avoided cost of $631 million,

30 4123 wells divided by 160 wells per year gives us 25.8 years, or 26 years.75

an improvement in spill frequency of 41 percent would be the level at which e stimat ed benefits
would match the e stimat ed compliance costs

.



### Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blowout Spill
To analyze the sensitivity of the population of deepwater wells and drilling activity, along wi th the underlying effect on the baseline risk assumption, we identified the water depth at which the consequences of a blowout event may be more severe. In the baseline analysis we used a 500 foot water depth demarcation since it is the upper limit of jac kup rigs and where subsea BOP stacks start to be used for MODUs. While there is no specific water depth demarcation for an increase in the consequences of deepwater blowout, wells which are drilled at a water depth greater than 3,000 feet may have an incr eased potential for a catastrophic event due to changes in the surrounding geology and reservoirs as well as greater difficulty mitigating the consequences of an uncontrolled flowing well.

The changes in the geological formations allow for greater accumu lation potential with porous and permeable sands at these depths and result in higher flow rates. The most recent public Gulf
of Mexico Reserves R eport 31 indicate s that 6 of the 20 largest GOM fields are in water depths greater than 2,860 feet and discover ed since 1989. Fourteen of the fields are in water depths 247 feet or less and discovered in 1971 or earlier. The GOM shelf is in decline and few large fields are likely to be discovered in the GOM shallow water. Over the last 40 years the largest field s with booked reserves have all been in deepwater. Thus the reservoirs being discovered at depths greater than 3000 feet are generally more prolific than their shallow water counterparts.

It is important to note that the probability of a blowout does not appear to be greater beyond 3,000 feet water depth and based on OCS drilling history is actually lower than shallower water depths. However, the consequences of an uncontrolled blowout event in deeper water depths are more likely to be catastrophic becau se of the additional complications in restoring well control at the water depths as demonstrated by the DWH event. In this sensitivity analysis we are considering a scenario which based on the occurrence of a single catastrophic blowout event (DWH) in wat er depths greater than 3,000 feet.

Historically, there have been 1,475 GOM wells drilled in water depths of greater than 3,000 feet, with approximately 1,100 wells in the past 10 years. This gives a 1/1475 probability of a

31 Reserve Data for 1,229 Proved Fields

- Gulf of Mexico Outer Continental Shelf, December 31, 2006, http://www.gomr.boemre.gov/homepg/offshore/fldresv/2006

- Table4.pdf

.76

catastrophic blowout spill event , and about 110 wells drilled per year. At this rate, one event occurs every 13.4 years in this alternate scenario. 32

By dividing the expected avoided social cost of $16.3 billion by the alternate scenario catastrophic event rate of 13.4 years per event, th e annual avoided cost is $1.216 billion. Dividing the compliance costs of $1 31 million per year by the alternate annual avoided costs of $1.216 billion per year would result in a n improvement in s pill frequency of 1 1 percent for the
estimated benefits to m atch the estimated costs in this alternate hypothetical scenario.



### Sensitivity of Number of Deepwater Wells Drilled per Year (25% lower)
The baseline assumption in this is for an average of 160 new deepwater wells drilled each year. This alternate scenario reduces the baseline number of deepwater wells by 25 percent from 160 to 120 wells per year. The number of shallow wells remain constant at 286 per year. This scenario is plausible given likely reactions to drilling activity in the aftermath of the DWH event. Several deepwater MODU’s have left the Gulf of Mexico and other new build deepwater rigs previously scheduled to drill in the deepwater Gulf have announced moves overseas. Additionally there are ot her factors that may lengthen the time to drill deepwater wells including deeper drilling depths and the stricter application of existing regulations. These factors are
discussed in the section titled Baseline Estimates of Future Deepwater Drilling Activity . While the long

- term GOM drilling activity is subject to many factors, it is not unreasonable to assume that drilling activity could remain relati vely flat and continue in the range of the number of deepwater wells drilled in 2009 and originally projected for 2010 ( Figure 1 ). The following tabl e provides the compliance costs estimates for the scenario of 120 (85 MODU plus 35 platform) deepwater wells per year.

32 1475 wells drilled divided by 110 wells per year equals 13.4 years.77 Table 27

– Estimated Recurring Cost Summary (25% fewer deepwater wells per year) Regulation Recurring Costs: MODU

Wells (85/yr) Fixed

Platforms (35/yr) Shallow

Wells (186/yr) Cost

Shares

Total ($MM) Total

($MM) Total

($MM)

250.449(j)(k) Subsea ROV function testing (drilling) 12.8 0.0 0.0 12%

250.516(d)(8), 250.616(h)(1) Subsea ROV function testing

(completions/workover) 4.1 0.0 0.0 4%

250.423(c) Test casing strings for proper installation

(negative pressure test) 9.6 0.0 0.0 9%

250.420(b)(3) Installation of dual mechanical barriers 39.3 7.6 20.5 65%

250.420(a)(6) PE certification for well design 1.0 0.4 2.1 3%

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

LMRP disconnect 2.0 0.0 0.0 2%

250.416(e) Independent third party shear certification 0.3 0.2 0.6 1%

All Paperwork Costs taken from PRA table in

final rule. 1.9 0.3 1.6 4%

Estimated Cost per year: 71.0 8.4 24.8 $ 104.2

Estimated Cost per well: 0.84 0.24 0.13

Dividing the compliance costs of $10 4.2 million per year by the alternate annual avoided costs of $ 466 million per year ($16.3B/[4123/120]) would result in a n improvement in s pill frequency of

22 percent for the benefits to match the costs in this alternate hypothetical scenario.



### Scenario Analysis Summary
The following table summarizes the baseline and alternative scenario analysis:78 Table 28

– Alternative Scenario Summary

Scenario Annual

Compliance Costs ($MM) Annual

Avoided Costs ($MM) Catastrophic Spill

Frequency Improvement Required
for Benefits to Match
Costs of Rule (percent)

Baseline $131 $631 21 percent

Compliance Costs lowered 50

Percent $65 $631 10 percent

Compliance Costs Increased
100 Percent $261 $631 41 percent

>3,000 feet (110 deepwater wells/year) $131 $1,216 11 percent

Number of Deepwater Wells Drilled per Year (25% lower) $104 $466 22 percent

As can be seen from the Table 28, c hang ing assumptions yield s different risk reductions of a catastrophic spill event (spill frequency improvement) needed for the estimated economic
benefits to match the estimated compliance costs of rulemaking (the breakeven point) . The reduction in spill frequency for this match to occur would range from 10 to 41 percent, with the
Baseline Scenario improvement level at 21 percent. Based upon this range, and upon the agency’s analysis of the provisions of the rule (discussed below), it is reasonable to conclude that this rulemaking will reduce the risk for a catastrophic blowout spill event at least enough such that estimated benefits will justify the estimated costs of this regulation.



### Alternatives

This final rule implements selected safety measures recommended in the report entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (Safety Measures Report), dated May 27, 2010 and the subsequent JIT report of BOEMRE and the
USC G . Given the critical nature of the BP Deepwater Horizon ( DWH ) explosion and resulting oil spill and the apparent inadequacy of existing well control procedures and BOP requirements, the Safety Measures Report recommended that BSEE’s predecessor agency ad dress some items through an emergency rulemaking. The requirements in this final rule include practices related to well control, including well casing and cementing, ROV intervention, unplanned disconnects,79

recordkeeping, well completion, and well pluggin g. These requirements are determined by the Secretary to be urgently needed to protect worker safety and the OCS environment.

Other measures recommended in the investigative r eport s but not included in this rulemaking
include additional blind shear and c asing ram requirements, enhanced ROV intervention capability, increased accumulator capacity for operating BOPs and safety case requirements for floating drilling operations. These and other items require further study and public input to
determine their efficiency and effectiveness. Measures considered beneficial will be considered for future notice and comment rulemaking.



### Small Business Alternatives
A separate Initial Regulatory Flexibility Analysis (IRFA) was performed for the interim final
rule (75 FR 80717) . A Final Regulatory Flexibility Analysis (FRFA) for this rule is found in Appendix A.



## CONCLUSION

O n June 2, 2010, the Secretary of the Interior directed BSEE’ predecessor agency BOEMRE to adopt the recommendations contained in the Safety Measures Report and to implement them as soon as possible. O n September 14, 2011, the BOEMRE published the final joint investigation report (DWH JIT report)

, on the causes of the Deepwater Horizon incident, which included multiple regulatory recommendatio ns. To implement the most practical recommendations identified by experts in the Safety Measures Report and DWH JIT report

, this rulemaking
amends corresponding drilling, well completion, well workover, and decommissioning regulations related to well con trol, including those covering : subsea and surface blowout preventers, well casing and cementing, secondary intervention, unplanned disconnects, recordkeeping, well completion, and well plugging.

BSEE has analyzed the costs and benefits of this rule using data available at the time of this rulemaking under various scenarios to assess when expected benefits might justify the expected

costs

. Under different assumptions about the magnitude of costs, benefits and drilling activity,

w e assessed how the frequen cy and the magnitude of future blowouts resulting in catastrophic spills should change for the expected benefits to justify the compliance costs. We have calculated the breakeven threshold this rulemaking would need to achieve for its potential
benefits to balance the compliance costs . Relative to the baseline deepwater drilling experience, the breakeven threshold for this rulemaking is a 21 percent reduction in the probability of a catastrophic s pill event. Although d rilling system reliability data are unavailable to compute the blowout risk reduction associated with the specific provisions in this rulemaking

, blowout risk80

reduction should result from the three most critical safety provisions required by the Interim
Final Rule and the Final Rule. W e ex pect these new requirements will reduce the chances of another catastrophic spill and that the breakeven risk reduction is a modest goal for the improvement in drilling safety likely to stem from these provisions. We confidently expect the improvement in drilling safety through the requirements in this rulemaking, will reduce the probability of a catastrophic spill by at least 21 percent.81



## Appendix A Final Regulatory Flexibility Act Analysis, RIN 1014

- AA02

Agency: Department of the Interior, Bureau of Safety and Environmental Enforcement (BSEE).

Regulatory Citations : The Safety Measures Rule is amending the drilling regulations at 30 CFR 250, subparts D, E, F, and Q. The rule is titled RIN 101 4



### – A A02 , Final Rule, Increased Safety Measures for Energy De velopment on the Outer Continental Shelf and was originally published as an Interim Final Rule on October 14, 2010 (75 FR 63346).

Summary : BSEE is publishing this Final Regulatory Flexibility Analysis (FRFA) in conjunction with
the final rule. The Bureau ’s publication of the interim final rule did not include a full Initial Regulatory Flexibility Analysis (IRFA) pursuant to the Regulatory Flexibility Act (5 U.S.C. 603). A supplemental IRFA was published on December 23, 2010 (75 FR 80717) with a 30 day co mment period which closed on January 24, 2011. The changes from the IRFA are minor and relate to lower compliance cost estimates for the regulation. The revised cost estimates are the result of changes to the regulatory language and improved estimates of the counts and the operational timeframes required to comply with the regulatory provisions.



### Supplementary Information
BSEE has updated the estimated compliance costs and small business impacts from the projections reported in the IRFA. These changes are minor and mostly result from updated compliance costs for several of the provisions and the including of paperwork and recordkeeping costs for this regulation.

Over the last few years there have been some notable trends in the Gulf of Mexico. First, several of the new companies entering the Gulf of Mexico (GOM) are large foreign companies and not small
businesses. Seco nd, the number of deepwater wells drilled by small companies has increased as capital and technology has become more accessible to small entities. Third, a few of the smaller companies with meaningful OCS acreage have either sold their OCS assets to large r companies, become wholly owned subsidiaries, or merged with larger companies. Cumulatively, these trends result in a greater share of acreage, drilling, and production attributed to large companies.

Our analysis shows there are currently about 130 Opera tors of Federal oil and gas OCS leases. Small lessees that operate under this rule fall under the Small Business Administration's North American Industry Classification System (NAICS) codes 211111, Crude Petroleum and Natural Gas Extraction, and 213111, D rilling Oil and Gas Wells. For these NAICS code classifications, a small company is one with fewer than 500 employees. Based on these criteria, we estimate 65 percent of these companies are small entities. This proposed rule, therefore would affect a su bstantial number of small entities.

Much of the information in this FRFA is covered and discussed in the final rule preamble and elsewhere

in th is RIA for the Safety Measures Rule. These documents can be found at http://www.regulations.gov82

under the Docket ID: BSEE

- 201 2

- 00 02 . This FRFA is not intended to duplicate all the explanations and analysis in those documents, but rather meet the requirement and intent of the Regulatory Flexibility Act. This FRFA analyz es and considers the impact of the Safety Measures Rule on small entities.



### Summary of Small Business Impacts
We estimate the Safety Measures Rule will impose a recurring operational cost of $131 million each year on operators drilling OCS wells. The rul e affects every new well drilled after October 14, 2010; some requirements also apply to wells undergoing completion, workover, or abandonment operations on the OCS. Every operator both large and small must meet the same criteria for these operations rega rdless of company size. However, the overwhelming share of the cost imposed by these regulations will fall on the operating companies drilling deepwater wells, which are predominately the larger companies. We
estimate that about 81 percent of the total c osts will be imposed on deepwater lessees and operators where small businesses only hold 8 percent of the leases and drill 12 percent of the wells. About 19 percent of the total costs will apply to shallow water leases where small companies hold 45 percen t of OCS leases and also drill 45 percent of the wells.

Nonetheless, small companies as both operators and lease

- holders will bear meaningful costs under these regulations. Of the annual $ 131 million in annual cost imposed by the rule, we estimate that $ 12.3 million will apply to small businesses in deepwater and $ 11

. 0 million in shallow water. In total we estimate that $ 23.3 million or 18 percent of the regulations’ cost will be borne by small businesses.

The GOM represents 98 to 99 percent of annual OC S oil and gas drilling activity. Fiscal year 2009 aggregate annual GOM OCS oil and gas revenues were $31.3 billion. 33 Using the lease ownership profiles of GOM producing wells, we estimate that 87 percent ($27.2 billion) of the OCS revenues are ultimately received by large companies and 13 percent ($4.1 billion) by small companies. As a share of fiscal year 2009 revenues, the interim final rule will cost approximately 0. 39 ($0.1 07 /$27.2) percent of OCS revenue for large companies and 0.5 8 ($0.02 4 /$4.1) pe rcent for small companies. Although the difference in these ratios is not significant, small companies may experience a somewhat greater economic impact than large companies from the regulation primarily because they have a lower production share in deepw ater relative to the number of deepwater wells they drill. The likely reason for this difference is the migration of smaller companies into deepwater as they have accessed the technology and capital required for exploration and development. It can take a decade for an economic discovery in deepwater to reach production. Additional data on lease ownership, wells drilled, and production can be

found in Table 29

, Table 30

, Table 31 , and Table 32

. 

### Description of the Reasons that Action by the Agency is Being Considered

The final rule establ ishes regulations based on certain recommendations in the May 27, 2010, report from the Secretary of the Interior to the President entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (Safety Measures Report) and sele cted subsequent recommendations from reports by the President’s National Oil Spill Commission and Joint BSEE/USCG

33 The fiscal year 2010 GOM OCS revenues decreased to $24.7 billion. Th e corresponding share of costs as a share of revenues is estimated to remain essentially the same; the revenue figures have not been updated for the FRFA.83

Joint Investigation Team. The President directed that the Department of the Interior (DOI) develop the Increased Safety Measures Report as a result of the Deepwater Horizon event on April 20, 2010. This event, which involved a blowout of the BP Macondo well and an explosion on the Transocean Deepwater Horizon mobile offshore drilling unit (MODU), resulted in the deaths of 11 workers, an oil sp ill of National significance, and the sinking of the Deepwater Horizon MODU. On June 2, 2010, the Secretary of the Interior directed BSEE to adopt the recommendations contained in the Safety Measures Report and to implement them as soon as possible.

The selected measures from the Safety Measures Report and other reports being implemented initially are those in the Final Rule, A A

- 02 Increased Safety Measures for Energy Development on the Outer Continental Shelf. This FRFA is for the estimated impacts on small entities from this rulemaking. Some recommendations in the Safety Measures Report require additional review by the DOI, and yet other measures will be addressed through notice and comment rulemaking, as appropriate.

The Safety Measures Rule preambl e and Table 1 provide a table summarizing the rulemaking provisions.



### Description of, and Where Feasible, an Estimate of the Number of Small Entities to Which the Rule will Apply
In order to understand the entities that will be impacted by the Safety Measures Rule, the role both

operators and lessees play within the OCS oil and gas regulatory structure should be understood.

The regulations at 30 CFR 250.105 defines “lessee” as:

Lessee means a person who has entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term lessee also includes the BOEM

- approved assignee of the lease, and the owner or the BO EM

- approved assignee of operating rights for the lease.

While there may be multiple lessees holding an ownership interest, there can only be a single designated OCS operator for drilling or production operations on a lease

. The regulations at 30 CFR 250.1 05 define “operator” as:

Operator means the person the lessee(s) designates as having control or management of operations on the leased area or a portion thereof. An operator may be a lessee, the BSEE

- approved or BOEM

approved designated agent of the less ee(s), or the holder of operating rights under an BOEM

approved operating rights assignment (30 CFR 250.105).

Although t he designated operator is the person BSEE typically holds responsible for complying with all regulations and ensuring the safety of dril ling operations on a lease or unit , under BSEE regulations, joint and several responsibility for compliance exists among co

- lessees, the operator, and persons (such as contractors) actually performing an activity to which a regulatory requirement applies. 34

34 Such responsibilities are expressly described in 30 CFR 250.146.84

Consistent with the court’s interpretation that the RFA applies to entities directly affected by the rulemaking

, 35 the designated operator and the co

- lessees are the entit ies directly regulated by B SEE

, impacted by this rulemaking and considered in the estimation of compliance costs.

While the requirements in this rulemaking apply to drilling operations under control of the operator, lessees are the project owners and will bear the compliance costs for the increased safety measures in this rulemaking. T his analysis considers impacts on small and large entities based upon the lease ownership profiles for OCS activities because the lease owners will bear the cost of these regulations. The three OCS activities analyzed are (1) lease ownership, (2) wells dr illed, and (3) production.

Additionally, this rulemaking requires drilling contractors to preserve certain maintenance and testing records. BSEE has only identified two active shallow water or platform drilling rigs operated by a small company on the GOM OCS among the approximately 50+ usually working there. This increased cost incurred by owners of drilling rigs is expected to be negligible compared to the added expense incurred by the Operators and Lessee owners due to the lengthened time to drill wells and additional permitting paperwork requirements.

Our updated analysis shows there are currently about 130 Operators of Federal oil and gas OCS leases, all of which will be impacted by this regulation if conducting drilling operations. Approximately 65 p ercent) of the companies operating on the OCS are considered small companies and 35 percent are considered large companies.



### Breakout of Small and Large Companies Operating on the OCS
There are many arrangements for sharing project risks and expenses for OCS exploration and development projects. These include original and revised ownership agreements where the risk, equity, and other interests may be complex. When there is an assignme nt of lease rights among different parties, BOEM records the OCS lease assignments in a manner similar to county court property records. A snapshot of the OCS lease ownership profile and wells drilled on those leases for small and large companies’ form th e basis for the Safety Measure Rule’s estimated impact on small entities.

We analyzed OCS activity for both deepwater and shallow water by company size. Operating in the shallower water depths is generally less expensive and the concentration of smaller companies is greater in shallow water. The most costly requirements in the Safety Measures Rule apply to deepwater MODU drilling operations using a subsea blowout preventer (BOP)

. The following results for lease ownership, wells drilled, and production r eflects leases with sole or fractional ownership as recorded by BOEM.



### Deepwater
The categorization of company lessees shows that large companies (greater than 500 employees) hold 92 percent of deepwater leases (greater than 500 feet) and small companies hold 8 percent. Cobalt International Energy is the only small company (less than 500 employees) among the top 30 companies holding deepwater acreage since Mariner merged with Apache.

35 Mid

- Tex Electric Cooperative, In c., v. FERC (Mid

- Tex), 773 F.2d 327 (D.C. Cir. 1985).85

When we consider deepwater drilling activity

, the results are similar; of the wells spudded in deepwater during 2007

- 2009, 88 percent of deepwater wells were attributed to large company lessees and only 12 percent to small company lessees. These results include the factional ownership by some small entities that are only equ ity investors in projects including some venture capital funds.

An even greater share of OCS deepwater hydrocarbon production and corresponding revenues accrued to large companies in calendar year 2009. While deepwater drilling activity attributed to smal l companies is increasing, economic projects cannot be brought to production for several more years. We use 2009 as a long

- term proxy for the production split between small and large companies. Large companies produced 97.5 percent of oil and 92.1 percen t of gas production in deepwater. Only 2.5 percent of deepwater oil production and 7.9 percent of deepwater gas production is from leases owned by small companies.



### Shallow water
We find that small companies hold a much greater share of acreage in shallow water (less than 500 feet) than in deepwater. The top two acreage

- holding lease owners, Apache and Chevron, are not small companies, but the next four lessees in rank order are small entities: McMoRan, W & T Offshore, Stone Energy, and LLOG Exploration. In shallow water, small companies hold 45 percent of the leases while large companies hold 55 percent.

The drilling activity over the past 3 years matches the small and large companies lease ownership profile. Of the wells spudded during 2007

- 2009, 45 per cent of the wells were spudded by small companies and 55 percent by large companies.

Hydrocarbon production in the shallow water depths shows that larger companies hold the most productive leases. Slightly less than two

- thirds of both oil and gas producti on accrues to large companies and slightly more than one

- third is produced by small entities.



### Summary of Large and Small Company OCS Activity
The following tables 36 summarize the small and large company percentage breakouts of leases, wells drilled (2007

- 20 09), production of oil and gas and value of OCS production. The results reflect lease fractional ownership shares among different companies.

Table 29 Lease Ownership among Small and Large Companies (11/1/2010)

Leases 11/01/2010 Sha llow Water

Leases Deepwater

Leases All Leases

Large Co. 55% 92% 80%
Small Co. 45% 8% 20%

100% 100% 100%

36 The categorization of companies as small or large is based upon publically available data as measured by number of employees as of October 2010 . BOEMRE collects data on lease ownership, wells drilled and operator production in our Technical Management System Database (TIMS).86 Table 30 Wells Spudded among Small and Large Companies (2007

- 2009)

Wells (2007

- 2009) Shallow Water

Wells Spudded Deepwater

Wells Spudded All Wells

Spudded

Large Co. 55% 88% 65%
Small Co. 45% 12% 35%

100% 100% 100%

Table 31 Production based on Recorded Lease Share for Small and Large Companies (2009)

2009 Production Shallow Water

Oil Production Deepwater

Oil Production Shallow

Water Gas Production Deepwater

Gas Production All BOE

Production

Large Co. 64.6% 97.5% 63.2% 92.1% 85%
Small Co. 35.4% 2.5% 36.8% 7.9% 15%

100% 100% 100% 100% 100%

Table 32 Estimated Production Value* ($millions) for Small and Large Companies (2009)

Est. 2009 Production Value ($million) Shallow

Water Oil Production Deepwater

Oil Production Shallow

Water Gas Production Deepwater

Gas Production All BOE

Production

Large Co. 2,581 17,284 3,271 4,079 27,215

Small Co. 1,415 442 1,905 351 4,113

TOTAL: 3,996 17,726 5,176 4,430 31,328

*Office of Natural Resource Revenue, http://www.onrr.gov/ONRRWebStats/default.aspx



### Recurring Regulatory Costs Imposed by the Regulation

Table 4 summarizes the estimated recurring operational costs categories for three subgroups of wells affected by the new regulations. Those categories are (1) deepwater wells drilled by a MODU, (2) deepwater wells drilled from a platform and (3) all shallow water wells.

The regulations impact well costs differently depending on the type of drilling rig and category of well being drilled. As can be obse rved in Table 4 , deepwater wells drilled by platform rigs and shallow wells drilled by jackups or platforms will incur lower incremental costs than deepwater wells drilled by MODUs, primarily because they us e surface BOPs; while wells drilled by deepwater MODUs (drillships and semisubmersibles) will incur the greater incremental cost due to the new subsea BOP requirements. Additional explanation about these costs is provided in the Benefit

- Cost Analysis for the Safety Measures
Rule.87

For this analysis, BSEE estimates that 160 deepwater wells will be drilled each year, split between MODU wells (112/yr) and platform wells (48/yr). An estimated 186 wells will be drilled each year in the shallow water depths. Us ing the recent drilling profiles for small and large company lessees in Table 30

, the following table estimates the number of wells to be drilled each year by large and small entities.

Table 33

– Estimate of Future Wells Drilled (annually)

MODU Deepwater Wells (112/yr) Fixed Platforms

Deepwater Wells (48/yr) Shallow Wells

(186/yr)

Large Co. 99 (88%) 42 (88%) 102 (55%)
Small Co. 13 (12%) 6 (12%) 84 (45%)
TOTAL 112 48 186

The estimated annual increased costs for each well type drilled are taken from Table 4 to estimate t he annual compliance costs for large and small companies by type of well. Of the $ 131 million in annual cost imposed by the rule, we estimate that the $1 2. 3 million will apply to small businesses in deepwater and $1 1

. 0 million in shallow water. In total, we estimate that $23. 3 million or 1 8 percent of the regulation’s costs will be borne by small businesses. The following table shows the calculations for these
estimates.

Table 34

– Large/Small Company Estimated Additional Drilling Costs $millions Additional MODU

Deepwater Well Cost (112/yr) Fixed Platforms

Deepwater Wells (48/yr) Shallow Wells

(186/yr) Total

Estimated Cost Large Co. $8 3

. 3 (88% * 9 4

. 6 ) $9. 9 (88% * $11. 2 ) $13. 7 (55% * $24. 8 ) $10 6

. 8
Small Co. $11. 4 (12% * $9 4

. 6 ) $1.3 (12% * $11. 2 ) $11. 2 (45% * $24. 8 ) $23. 9
TOTAL $9 4

. 6 $11. 2 $24. 8 $1 30

. 7 *Numbers may not add due to rounding.

Determining a precise number of small entities that will be “regulated” is complicated by the fact that the actual number fluctuates as OCS properties are bought, sold, the designated operator changes and not all operators conduct drilling operations . The same difficulty follows for the lease ownership profile of small and large entities. However, our best estimate of the impact on small entities when we consider how project and drilling costs are shared among lease owners is that small entities will bear 12 percent of increased regulatory costs in deepwater, and 45 percent in shallow water . The annual small entity regulatory compliance cost imposed by this rulemaking is estimated to be $2 3

. 9 million or 1 8 percent of
the total.



### Description of the projected reporting, recordkeeping, and other compliance requirements of the proposed rule, inc luding an estimate of the classes of small entities that will be subject to the requirement and the type of professional skills necessary for preparation of the report or record.

The benefit

- cost analysis for the Safety Measures Rule identifies $1 31 million in annual operational costs;
these costs are summarized in Table 4 and discussed in the section titled Compliance Costs f or this88

Regulation

. Greater details of the regulatory provisions are provided in the rule preamble. This section primarily discusses the paperwork burden on drilling co ntractors.

The Paperwork Reduction Act (PRA) section of the Safety Measures Rule (which combines both the IFR and Final Rule) identifies 50,078 hours of paperwork, reporting, and recordkeeping required annually by the regulation. Using the Bureau of Labor Statistics estimated loaded hourly rate of $83/hr,

the estimated paperwork cost to industry for this rulemaking is $ 4.6 million. The burden tables of
the estimated annual burden hours of these rulemakings can be found in both the IFR and final rule

proce dural matters section of the Federal Register preamble.

Reporting and recordkeeping falls primarily on the OCS lessees and operators, although drilling rig operators do have some additional recordkeeping requirements. The frequency of response varies
de pending upon the requirement but is primarily based on drilling activity. Responses and recordkeeping by the drilling companies fall primarily on the Deepwater MODUs where all the deepwater MODU operators in the GOM are large companies. Some additional r ecordkeeping requirements will fall on all OCS drilling rig operators. As of early November , 2010 (11/4/2010 Rigzone), there are two shallow water rigs operating in the GOM OCS owned by a small company. They are both owned by Blake
International and are under contract to Apache. The estimated additional recordkeeping cost for jack

- up rig surface BOP stacks is about $5,000 annually for each rig. The direct estimated paperwork burden on the single small drilling operator currently active in the GOM is abo ut $10,000 per year. The paperwork costs impacting this small entity are found in Table 35 and sourced from the IFR PRA table found at
75 FR 63368.

Table 35

– Selected Paperwork Burden Requirements from AD68 IFR PRA*

Citation

30 CFR 250 Reporting & Recordke eping

Requirement Hour
Burden Average No.

of Annual Responses Annual

Burden
Hours

Subpart E

516(g)(l) Document the procedures used for BOP

inspections; record results; maintain records for 2 years; make available to
BSEE upon request. 7 days x 12
hrs/ day =
84 105 rigs / once

every 3 years = 35 per year 2,940

516(h) Document the procedures used for BOP

maintenance; record results; maintain records for 2 years; make available to
BSEE upon request. 1 105 rigs 105

Subpart F89 Citation

30 CFR 250 Reporting & Recordke eping

Requirement Hour
Burden Average No.

of Annual Responses Annual

Burden
Hours

617(a)(l) Document the procedures used for BOP

inspections; record results; maintain records for 2 years; make available to
BSEE upon request. 7 days x 12 hrs/ day =
84 105 rigs / once

every 3 years = 35 per year 2,940

617(b) Document the procedures used for BOP

maintenance; record results; maintain records for 2 years; make available to

BSEE upon request. 1 105 rigs 105

*Full table can be found in the Preamble Procedural Matters of the IFR (75 FR 63368)

.
Much of the paperwork is recording the results of tests and maintenance procedures and is expected to be completed by workers concurrently with the tests or in between other drilling tasks. The paperwork costs are a moderate component of the added costs imposed by this rule a nd minor in comparison to the cost of drilling an OCS well.



### Identification, to the extent practicable, of all relevant Federal rules that may duplicate, overlap, or conflict with the rule
The only regulations from other Federal agencies that may closely re late to the scope of BSEE regulations in this rulemaking are from the U.S. Coast Guard. However, for the Safety Measures Rule there is no overlap, conflict, or duplication with Coast Guard regulations. Under BSEE/USCG Memorandum of Understanding (MOU), B SEE has authority over spill abatement

- which includes well control. All of the regulatory provisions in the rulemaking are focused on well control. Additionally and consistent with the MOU, BSEE has regulatory authority for drilling operations of MODUs on station while conducting drilling operations.

There are several MOUs between the agencies that outline the division of duties and shared responsibilities. BSEE has authority over drilling and oil and gas operations on the OCS while the Coast
Guard has authority over the integrity and safety of floating vessels conducting OCS operations. The
MOUs can be found at: http://www.uscg.mil/hq/cg5/cg522/cg5222/mou.asp



### Description of any signific ant alternatives to the rule that accomplish the stated objectives of applicable statutes and that minimize any significant economic impact of the rule on small entities, including alternatives considered, such as:

1. Establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities. 2. Clarification, consolidation, or simplification of compliance and reporting requirements under the rule for such small entities.90

3. Use of performance rath er than design standards. 4. Any exemption from coverage of the rule, or any part thereof, for such small entities.

Under the published Safety Measures Rule, the requirements are prescriptive and lease operators submitting permits to BOEMRE or conducting dri lling operations must comply with the requirements. Even though this rule may not have a significant economic impact on small businesses, BOEMRE has analyzed several alternatives for the provisions included the Safety Measures Rule.



### Alternative 1, Diffe rent Compliance Requirements for Small Entities
During the drafting of the IFR , BOEMRE considered lengthening the compliance deadline for both large and small companies. The primary reason for not including additional compliance time or different requirem ents is the overriding need to reduce the chance of a catastrophic blowout event. The risk is not lower for small entities and BSEE cannot compromise the safety of offshore personnel and the environment for any entity including small businesses. Offshore drilling is highly technical and can be hazardous; any delay in the implementation of Safety Measures Rule may increase the risk of OCS drilling operations.

The regulatory provisions do not require significant equipment or capital upgrades and as the 20 11 resumed deepwater drilling shows, can be met in short order. The compliance costs are mostly the increased time to conduct drilling operations. Thus, any additional time to comply with the rule would not result in cost savings in the form of reduced s hort

- term cash flow expenditures that might be expected if the rule required the installation of capital equipment.

BSEE is continuing to review other safety measures that may be appropriate for rulemaking in the near future. These may be include d in a pr oposed rulemaking or an advanced notice of proposed rulemaking.



### Alternative 2, Testing Requirements
Alternative Testing Methods : BSEE considered if the required testing for subsea ROV intervention and negative pressure test s could be performed in an alte rnative manner. Because of the failings that occurred in, and lessons learned from

, the BP Deepwater Horizon event, BSEE has concluded that alternative testing is not a viable option. No alternative testing methods have been identified that will provide the same assurance of reliability.

The subsea ROV intervention test upon installation of the BOP stack is required to demonstrate that the rams can be closed as required under realistic subsea conditions. The BOP ROV function test occurs upon installation on the sea floor and is in addition to the “stump” tests conducted prior to subsea installation. The only alternative to the subsea tests would be to only conduct the “stump test.” However, the stump test would not provide the same assurance of BOP ram operability as the subsea test which is performed under the actual conditions that would occur if the BOP rams needed to be employed.

The new requirement to perform a negative pressure test after the final casing string is installed is necessary to verify that no fluids are entering the well and the cement is sealing the wellbore.91

Alternative Testing Periods : An IRFA public comment offered an alternative to the current BOP testing requirement. The suggestion was to change the existing regulation at 30 C FR 250.449(h) which requires a BOP function test every 7 days including the blind

- shear rams to a 14 day requirement

A Joint Industry Project study completed in 2009 analyzed BOP Equipment Reliability. The results of this study suggest that up to $193 mil lion per year could be saved through less frequent testing while achieving the same reliability for BOP performance. 37 Though counter intuitive, it may be possible that less frequent testing can provide the same BOP reliability because of the wear that mor e frequent tests may exert on the BOP equipment. While the testing alternative may have value, and is a topic that merits greater study, it is outside of the scope of this rulemaking.



### Alternative 3, Paperwork Consolidation
BSEE did not identify any provis ions of the rule that could provide efficiencies through consolidation or other streamlining. Some of the regulatory provisions apply to different Subparts and are necessarily duplicated. Most reporting requirements are dependent on drilling activity and closely related to the number of wells drilled or Application for Permit to Drill/Application for Permit to Modify (APDs/APMs) submitted. No efficiencies would be expected through further simplification or
consolidation.



### Alternative 4, Use Performance Ra ther than Design Standards
The provisions in the final rule generally prescribe a combination of performance and design standards for well design (cementing and casing), testing drilling equipment, and certifying the well’s integrity

. Although, for instanc e, the rule requires the use of two independent barriers, including one mechanical barrier, the rule does not mandate the specifications for the particular type of barrier. BSEE or commenters did not identify equivalent performance standards that provide the same level of reliability and well integrity and that can be implemented as quickly as the provisions in this rule.

The BOEMRE is carefully evaluating how to integrate performance based systems into our regulatory regime. This includes the SEMS (Safet y Environmental Management Systems) and the Safety Case. The first SEMS rule was published on October 15, 2010 (75 FR 63610) and a second SEMS proposed rule was published on September 14, 2011 (76 FR 56683). The Safety Case approach to risk management
ch ampioned by the International Association of Drilling Contractors (IADC) is also receiving careful consideration and study by BSEE.

Implementation of a performance based solution requires long lead times and careful strategic and tactical implementation. Because of the immediate need to address well design, testing and reliability issues, BSEE is relying on a combination of performance and design standards in the Safety Measures Rule.

37 BOP Equipment Reliability Joint Industry Project At A Glance , West Engineering Services, http://www.westengineer.com/pdfs/JipTrifoldr3.pdf

.92

Departures to the provisions in the Safety Measures Rule can be approved under the current regulations if the alternative procedures afford an equal or greater degree of protection, safety, or performance. Departures are discussed in the next section.



### Alternative 5, Exemptions from Rule Requirements
One alternative is to exempt small businesses from the requirements of this interim final rule. The “exemption” or “no action” alternative was not adopted by BSEE because of the overriding need to reduce the chance of a catastrophic blowout event. The ri sk is not lower for small entities and BSEE cannot compromise the safety of offshore personnel and the environment for any entity including small
businesses.

BOEMRE can approve departures to existing regulations when the departure would assure the contin ued safety of drilling operations. In 30 CFR 250.105 Departures means:

Approvals granted by the appropriate MMS representative for operating requirements/procedures other than those specified in the regulations found in this part. These requirements/proce dures may be necessary to control a well; properly develop a lease; conserve natural resources; or protect life, property, or the marine, coastal, or human environment.

There are several general and drilling specific regulatory provisions that identify the availability of departures. Those regulatory citations are:

30 C F R 250, Subpart A, General Information, Special Approvals

§ 250.142 How do I receive approval for departures? We may approve departures to the operating requirements. You may apply for a departure by writing to the District Manager or Regional Supervisor.

30 CFR Subpart D, Oil and Gas Drilling Operations, General Requirements

§ 250.409 May I obtain departures fro m these drilling requirements? The District Manager may approve departures from the drilling requirements specified in this subpart. You may apply for a departure from drilling requirements by writing to the District Manager. You should identify
and discu ss the departure you are requesting in your APD see §250.414(h)).

§ 250.414 What must my drilling prognosis include?

(h) A list and description of all requests for using alternative procedures or departures from the requirements of this subpart in one plac e in the APD. You must explain how the alternative procedures afford an equal or greater degree of protection, safety, or performance, or why you need the departures;

Although not a specific provision of the Safety Measures Rule, departures to the require ments in this rulemaking will be considered and may be approved if the alternative proposed method does not93

compromise safety and environmental protection. These provisions are available to both large and small companies.94



## Appendix B Natural Resource Dama ge Data

Table 36

- Dataset of Spill Costs: Restoration and Assessment Costs
Event Year of

Settlement Max Volume

(bbl) NRD plus

Assessment Costs (2009$/bbl)*
American Trader Inc. 2006 143 1,313
Anacortes 1998 952 491 Apex Houston Spill 2006 25,000 244
B.T. Nautilus 1994 6,024 816 Barge Morris J. Berman 2000 11,905 480 Barge RTC 380 1994 643 411
Bermuda Islander 2008 24 11,340
Blake IV and Greenhill Petroleum Corp. Well 25 1995 2,905 786

Bouchard Barge 120 2006 2,333
BP American Trader Vessel 1997 9,919 300

Chevron BLDSU #5, West Bay Field 1996 262 249

Chevron Perth Amboy Facility 2006 342

Chevron, HI 1999 982 2,189 Chiltipin Creek 1994 2,950 69
Cibro Savannah 1999 2,381 138 Cold Spring Harbor Barge 2004 2,357 ConocoPhillips Bayway 2005 250 El Segundo 1993 500 300 Equinox Cockrell

- Moran #176 well 2005 1,500 800

Evergreen International M/V Ever Reach Vessel 2003 298 3,021

Exxon Bayway 1991 13,500 905
Exxon Valdez 1991 261,905 5,005
Fish Creek 1993 714 3,511
International Petroleum Corporation (IPC) 2009 286 882

Chelsea Creek (Global Oil/Irving Oil Pipeline) 2006 524 20

Jahre Spray 1996 1,400 12195 Event Year of

Settlement Max Volume

(bbl) NRD plus

Assessment Costs (2009$/bbl)*
M/T Athos I 2009 6,271 16 M/T Kentucky 1995 310 81 M/TCommand Oil Spill 1999 71 59,181
M/V Cosco Busan 2010 1,262 1,585
M/V Fortuna Reefer 1997
M/V Kure 2008 108 33,890
M/V Kuroshima 2002 929 1,661
M/V New Carissa 2004 1,667 16,118
M/V Presidente Rivera 1993 5,952 426 M/V Selendang Ayu 2006 8,000 7 M/V World Prodigy 1993 7,000 119
M/VWestchester 2003 13,095 41
Martinez 1990 9,524 1,138
McGrath Lake 1997 2,071 635
Milos Reefer 1993 5,952 67
Neches River 1997 2,095 105

Nestucca 1991 5,500 609 North Cape Barge 1999 19,714 625 Northridge 1997 4,595 1,599
OCEAN 255/B

155/BALSA 37 Spill 1996 8,619 928

Ocean Energy/Devon Energy North Pass Storage Facility 2006 300 393

Oil and Crooked Creeks 1996 107 2,539 Olympic Pipeline Company
Event 2004 5,619 631

PEPCO Chalk Point Generating Station 2002 3,333 813

Pirates Cove 1996 600 2,333 Quinnipiac River 1996 119 334 Reedy River 1998 22,619 294 Santa Barbara, CA 1969 71,429 SS Cape Mohican Oil Spill 1998 2,286 1,761 Sugarland Run 1998 9,714 257
T/V Julie N 2002 4,277 34896 Event Year of

Settlement Max Volume

(bbl) NRD plus

Assessment Costs (2009$/bbl)* Tenyo Maru 1994 10,776 867 Tesoro, HI 2001 117 4,359 Texaco Pipeline Company Lake Barre oil spill 2000 6,548 87

Williams Field/Transcontinental Natural Gas Spill 2010 3,000 84

Yoncalla Creek 1995 143 1,505 * Where a spill has a range of sizes recorded, per

- barrel costs were calculated using the upper range.

Table 37

- Gulf Shrimp Landings, Revenue, and Price
Federal Permit No

Federal Permit Total

Average revenue per vessel ($) 199,111 22,429 74,847 Average landings per vessel (lbs) 67,386 13,160 29,247 Average price (dollars per lb) $2.95 $1.70 $2.56 Average price (dollars per lb) $2.87 $1.73 $2.07

Number of Vessels 1,388 3,290 4,678 Total revenue ($ millions) $276 $82 $358 Total landings (millions lbs) 94 47 141 Note: Table for Gulf shrimp only; excludes S. Atlantic shrimp Source: The Annual Economic Survey of Federal Gulf Shrimp Permit Holders: Report on the Design, Implementation, and Descriptive Results for 2007; NOAA Technical Memorandum NMFS

- SEFSC

- 590 (2009).97



## Appendix C Well Data

Table 38

– GOM Deepwater Wells by Water and Drilling Depth 

### Distribution of 4,133 GOM Wells Drilled in Water > 500 Feet by Drilling Date, Water Depth, and Well Depth

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

Water Depth (feet) Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500

- 1,500 140 900 607 61 15 1 1

- 1,725 1,500

- 3,000 39 205 349 253 71 5 1

- 923 3,000

- 5,000
21 153 324 218 123 77 17

- 933 5,000

- 7,500

- 39 121 123 82 45 10 1 421 7,500

- 10,000

- - 51 47 11 10

- - 119 >10,000

- - 1

- 1

- - - 2
All WD 200 1,297 1,453 702 303 138 29 1 4,123 >3,000 ft
21 192 497 388 217 132 27 1 1,475

Counts of GOM Wells Drilled before 1980 in Water >500 feet According to Well Drilled Depth

Water Depth (feet) Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500

- 1,500
11 83 32

- - - - - 126 1,500

- 3,000

- 3 5 1

- - - - 9 3,000

- 5,000

- - - - - - - - - 5,000

- 7,500

- - - - - - - - - 7,500

- 10,000 +

- - - - - - - - - All WD
11 86 37 1

- - - - 135 >3,000 ft

- - - - - - - - -98

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

Water Depth (feet) Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500

- 1,500 47 324 252 19 2

- - - 644 1,500

- 3,000 12 59 94 16

- - - - 181 3,000

- 5,000
1 3 25 1 1

- - - 31 5,000

- 7,500

- - 1 8

- - - - 9 7,500

- 10,000 +

- - - - - - - - - All WD 60 386 372 44 3

- - - 865 >3,000 ft
1 3 26 9 1

- - - 40

Counts of GOM Wells Drilled During the 1990's in Water >500 feet According to Well Drilled Depth

Water Depth (feet) Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500

- 1,500 55 334 230 28 8 1

- - 656 1,500

- 3,000 15 74 129 142 18 2

- - 380 3,000

- 5,000 10 60 106 72 21 2

- - 271 5,000

- 7,500

- 5 34 20 8 3

- - 70 7,500

- 10,000

- - 1 1

- - - - 2 >10,000

- - - - - - - - - All WD 80 473 500 263 55 8

- - 1,379 >3,000 ft 10 65 141 93 29 5

- - 34399

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

Water Depth (feet) Well Total Depth (thousands of feet) Totals

0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40

500

- 1,500 27 159 93 14 5

- 1

- 299 1,500

- 3,000 12 69 121 94 53 3 1

- 353 3,000

- 5,000 10 90 193 145 101 75 17

- 631 5,000

- 7,500

- 34 86 97 74 42 10 1 344 7,500

- 10,000

- - 50 44 11 10

- - 115 >10,000

- - 1

- 1

- - - 2
All WD 49 352 544 394 245 130 29 1 1,744 >3,000 ft 10 124 330 286 187 127 27 1 1,092100



## Appendix D Definitions

Baseline : describes the regulatory environment before promulgation of the Interim Final Rule.
The baseline is compared to regulatory environment following promulgation of the rule for the

cost

- benefit analysis

. Benefits : are the favorable effects of a policy or action.

Blowout : is an uncontrolled flow of reservoir fluids into the wellbore. A catastrophic blowout occurs when fluids flow to the surface. The most damage from a catastrophic blowout event is caused if the hydrocarbons ignite at the surface. If reservoir fluids flow into another formation and do not flow beyond the wellhead, the result is called an underground blowout because the well bridges over and seals itself . Similar to kicks, the BOP rams are designed to shut

- in the
well until control is reestablished. BOP (Blowout Preventer) Stack : Is a series of valves (or rams) at the wellhead that may be closed if the drilling crew loses control of formation fluids. Th ese valves are often referred to as BOP rams. A stack might consist of four to six ram

- type preventers and one or two annular

- type preventers. A BOP stack is used to ensure pressure control of a well.
Costs : Is the dollar values of resources needed to p roduce a good or service, and hence are not
available for use elsewhere. Compliance Cost is the expenditure of time or money needed to conform to government’s regulatory requirements. It may be defined as the sum of all opportunity costs incurred as a

re sult of the regulation. These opportunity costs consist of the value lost to society of all the goods and services that will not be produced and consumed if firms comply with the regulation and reallocate resources away from production activities and towa rds compliance with the regulation. External (social) costs are the costs the oil spill imposes on society regardless of who pays for them and in this analysis exclude the private (social) costs. Deepwater : While BOEMRE has traditionally defined deepwate r as greater than 1,000 feet, for the purposes of this analysis deepwater is defined as water depths where floating drilling rigs are used rather than gravity based rigs and where submersibles or ROVs must replace divers. This is generally at 300 to 500 o f water depth and also the depth where subsea BOPs are required on floating mobile drilling rigs. We use 500 feet of water depth for our baseline analysis.
Discount Rate : Per OMB Circular A

- 94, where appropriate all cost estimates are calculated
back to a net present value in 2010 dollars using a discount rate of 7 percent.
Kick : is a flow of fluids from a formation into the wellbore during drilling operations. A kick is caused by the pressure in the wellbore being less than that of the formation fluid s and most often happens during drilling operations from a depth other than the targeted reservoir. Kicks are most frequently controlled by increasing the drilling mud weight, circulating out the kick or using one
of the BOP rams to control the flow.101

Load ed Rig Rate: The loaded rig rate used in this analysis is the daily rate charged by the owner of the rig for use of the rig and the operating crew plus the operator’s engineers, supplies, supply craft and supporting contractors.
Net benefits : are calcula ted by subtracting total costs from total benefits. Oil Spill : An oil spill as referenced in this cost/benefit analysis is oil spilled as a result of a loss of well control event. An oil spill for this analysis excludes spills from production or logistic al activities if the spillage is unrelated to a loss of well control event. Private (social) costs: are the costs of the blowout and spill that the responsible party pays for containment and recovery of productive capability. Unloaded Rig Rate: The unloaded rig rate used in this analysis is the daily rate charged by the owner of the rig for use of the rig and the operating crew. It does not include supplies, supply craft, the operator’s drilling engineers or supporting contractors.102



## Appendi x E References
Alabama Department of Conservation and Natural Resources. 2010. “Conservation Department Designates Coastal Boating Closures, Idle Speed

- No Wake Areas.” Press release dated June 28, 2010. Accessed on

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

. American Association of Poison Control Centers. Accessed on

- line at: http://www.aapcc.org/dnn/NewsandEvents/PoisonCentersandtheGulfOilSpill/tabid/472/D efault.aspx
Bercha

, Frank G. 2008

. Alternative Oil Spill Occurrence Estimators and their Variability for the
Beaufort Sea

– Fault Tree Method , OCS Study MMS 2008

- 35 http://www.alaska.boemre.gov/reports/2008rpts/2008_035.pdf Bureau of Labor Statistics, U.S. Department of Labor. 2010. Career Guide to Industries, 2010

- 11 Edition, Mining. Accessed on

- line at: http://www.bls.gov/oco/cg/cgs004.htm (visited July 30, 2010). Centers for Disease Control and Prevention. 2010. Emergen cy Preparedness and Response,
Health Surveillance. Accessed on

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

. Chapm an, D. and W.M. Hanemann. 2001. Environmental Damages in Court: The American
Trader Case. In: The Law and Economics of the Environment . Anthony Heyes (Ed.). pp. 319

- 367. Department of Health and Human Services, Centers for Disease Control and Prevention, National Institute for Occupational Safety and Health. 2010. NIOSH Report of BP Illness and Injury Data (April 23

– June 6, 2010). Dunford, Richard W. and Miranda L. Freeman. 2001. A Statistical Model for Estimating Natural Resource Damages f rom Oil Spills. 2001 International Oil Spill Conference. Florida Fish and Wildlife Conservation Commission. 2010. “Oil forces partial fishing closure in Escambia County.” Press release dated June 13, 2010. Accessed on

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

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

- ul

- Hassan, Syed Nadim Ja fri, Shahid Ali Lutfi, Muhammad Masood Kadir and Nalini Sathiakumar. 2006. Acute Health Effects of the Tasman Spirit Oil Spill on Residents of Karachi, Pakistan. BMC Public Health , 6:84. Kochi, Ikuho, Bryan Hubbell, and Randall Kramer. 2006. An Empiri cal Bayes Approach to Combining and Comparing Estimates of the Value of a Statistical Life for Environmental Policy Analysis. Environmental & Resource Economics , 34:385

– 406. Liese, Christopher, Michael D. Travis, Diana Pina, and James R. Waters. 2009. The Annual Economic Survey of Federal Gulf Shrimp Permit Holders: Report on the Design,103

Implementation, and Descriptive Results for 2007. NOAA Technical Memorandum
NMFS

- SEFSC

- 590, 107 p. Louisiana Department of Wildlife and Fisheries (LDWF); Interactive Closu re Maps at http://www.wlf.louisiana.gov/oilspill/map/ Louisiana Department of Wildlife and Fisheries; Number of Shrimpers 1998

- 2005 http://www.wlf.louisiana.gov/pdfs/education/number_of_shrimpers_89_to_07.xls Louisiana Department of Wildlife and Fisheries, Office of Management and Finance (2000) The Louisiana Shrimp Industry; A Preliminary Analysis of the Industry’s Sectors http://www.wlf.louisiana.gov/pdfs/education/La.%20Shrimp%20Industry.pdf Lyons, Ronan A., J. Mark F. Temple, Daphne Evans, David L. Fone, and Stephen R. Palmer. 1999. Acute Health Effects of the Sea Empress Oil Spill. Journal of Epidemiology and Community Health , 53(5): 306

- 310. Mississippi Department of Environmental Quality and Mississippi Department of Marine
Resources. 2010. News release 10

- 94

- S B, dated July 19, 2010. “Mississippi Territorial Waters Open to Live Bait Shrimping and Recreational Catch

- and

- Release Hook and Line Fishing.” Morita, Akemi, Yukinori Kusaka, Yoji Deguchi, Akio Moriuchi, Yuko Nakanaga, Masayuki Iki, Shigekazu Miyazaki, an d Kazuo Kawahara. 1999. Acute Health Problems among the People Engaged in the Cleanup of the Nakhodka Oil Spill. Environmental Research

Section A , 81: 185

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

Im pact of Florida’s Beaches. Proceedings of the 14 th Biennial Coastal Zone Conference, New Orleans, LA, July 17

- 21, 2005. http://www.csc.noaa.gov/cz/CZ05_Proceedings/pdf%20f iles/Alpert.pdf National Survey of Recreation in the Environment. 2000. http://egisws02.nos.noaa.gov/socioeco/genericProfile.html?datasource=nsre2000 NOAA (Nati onal Oceanic and Atmospheric Association). Marine Recreational Statistics Survey. http://www.st.nmfs.noaa.gov/st1/recreational/index.html Palinkas, Lawrence A., Michael A. Downs, Joh n S. Petterson, and John Russell. 1993a. Social, Cultural, and Psychological Impacts of the Exxon Valdez Oil Spill. Human Organization

, 52(1): 1

- 13. Palinkas, Lawrence A., John S. Petterson, John Russell, and Michael A. Downs. 1993b. Community Pattern s of Psychiatric Disorders After the Exxon Valdez Oil Spill. Am J Psychiatry , 150(10): 1517

- 1523. Pearson, Walter. H, et al. (1996 ) “Assessment of Damages to Commercial Fisheries and Marine Environment of Fujairah, United Arab Emirates, Resulting from th e Seki Oil Spill of March 1994: A Case Study.” Yale F&ES Bulletin #103, p. 407

- 428.104

Pérez

- Cadahía, Beatriz, Anunciación Lafuente, Teresa Cabaleiro, Eduardo Pásaro, Josefina Méndez, and Blanca Laffon. 2006. Initial Study on the Effects of Prestige Oil on
Human Health. Environment International

. Posadas, Benjamin (2008) Economic Assessment of the Impacts of Hurricane Katrina on the Mississippi Commercial Fishing Fleet . Mississippi Agricultural & Forestry Experiment Station, Mississippi State University.

R obinson, Lisa A. 2007. How U.S. Government Agencies Value Mortality Risk Reductions. Review of Environmental Economics and Policy , 1(2): 283

- 299. Sabucedo, José M., Constantino Arce, Carmen Senra, Gloria Seoane, and Isabel Vázquez. 2010. Symptomatic Profile and Health

- Related Quality of Life of Persons Affected by the Prestige Catastrophe. Disasters , 34(3): 809

- 820. Texas Parks and Wildlife Department website. 2010. “BP Oil Spill in the Gulf of Mexico.”

Accessed on

- line at http://www.tpwd.state.tx.us/site/emergency/oil_spill/

. Travis. Michael D. and Wade L. Griffin. 2004. Update on the Economic Status of the Gulf of Mexico Commercial Shrimp Fishery.

U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National
Marine Fisheries Service. 2010. NOAA Technical Memorandum NMFS

- F/SPO

- 109. Fisheries Economics of the United States 2008; Economics and Sociocultural Status and
Trends Series

. Viscusi, W. Kip. 2005. The Value of Life. Discussion Paper No. 517. Harvard Law School. http://www.law.harvard.edu/programs/olin_center/papers/pdf/Viscusi_517. pdf Viscusi, W. Kip. 2010. The Heterogeneity of the Value of Statistical Life: Introduction and
Overview. Journal of Risk and Uncertainty , 40: 1

- 13.

Add itional References or Literature : Joint Industry Task Force to Address Offshore Operating Procedure s and Equipment, May 17, 2010, White Paper: Recommendations for Improving Offshore Safety http://www.noia.org/website/download.asp?id=38556 BOEMRE/USCG Report Regarding the Causes of the A pril 20, 2010 Mac ondo Well Blowout, September 14, 2011

, http://www.boemre.gov/pdfs/maps/DWHFINAL.pdf

DNV

– Beaufort Sea Drilling Risk Study Energy Report, Imperial Oil Resources Ventures Limited, DNV ref no: EP00485, Rev. 6, March 11, 2010, submitted to the Canadian

National Energy Board ( www.neb

- one.gc.ca ) https://www.neb

- one.gc.ca/ll

eng/livelink.exe/fetch/2000 /90463/589151/594086/594088/600443/609664/C

- 05

- 6C_

- _Appendix_A_Beaufort_Sea_Drilling_Risk_Study__

- _A1S2V8_.pdf?nodeid=609512&vernum=0 Executive Order 12866, Regulatory Planning and Review http://www.whitehouse.gov/sites/default/files/omb/inforeg/eo12866.pdf105

OMB Circular A

- 4, Regulatory Analysis http://www.whitehouse.gov/sit es/default/files/omb/assets/omb/circulars/a004/a

- 4.pdf
OMB Circular A

- 94, Guidelines and Discount Rates for Benefit

- Cost Analysis of Federal Programs http://www.whitehous e.gov/sites/default/files/omb/assets/a94/a094.pdf
NYT Article on t he replacement cost of the Deepwater Horizon which is estimated at $560

million. http://www.nytimes.com/gwire/2010/05/04/04greenwire

- warnings

- on

- backup

systems

- for

- oil

- rigs

- sounde

- 30452.html Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, Part III, Lessons Learned: Industry, Government, Energy Policy http://www.oilspi llcommission.gov/sites/default/files/documents/FinalReportPartIII.pdf Transocean announcement describing the t otal capital costs to be incurred for the construction of the drillship a re estimated to be $750 million. http://www.redorbit.com/news/business/1446859/transocean_inc_announces_agreement_ to_acquire_newbuild_ultradeepwater_drillship_under/index .html106



## Appendix F Voluntary Industry Measures Review

MEMORANDUM | 18 August 2010

TO Radford Schantz and Martin Heinze, BOEMRE

CC Debra Bridge, BOEMRE

FROM John Weiss, Industrial Economics, Incorporated

SUBJECT Review of Additional Literature with Potential Relevance to OECM Development,

Contract No. M09PC00036

Industrial Economics, Incorporated (IEc ) is engaged in the development of a new version of the Offshore Environmental Cost Model (OECM), a decisionmaking tool used by the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) as it develops five

- year leasing programs for oil

an d gas exploration and production on the outer continental shelf (OCS). An important component of this
effort is the review of literature relevant to the identification and evaluation of the environmental costs that the model will consider. Many of those co sts are the direct or indirect result of oil spills associated with OCS exploration and production activities. In the aftermath of the Deepwater Horizon event,
additional information has become available that BOEMRE has asked IEc to review for relevance an d potential application during OECM development. This memorandum describes the results of our review and analysis of one category of additional information, that associated with (1) the Department of the
Interior’s 30

- Day Report to the President, which des cribes recommended actions to reduce the probability of a similar event in the future, and (2) industry’s consideration of recommended voluntary safety and protection measures that would be designed to achieve the same objective.

In addition to reviewing r elevant information for its potential applicability to the specification of OECM inputs, IEc has compared the currently available descriptions of proposed voluntary measures to a set of proposed changes to the rules governing OCS oil and gas activities. BO EMRE is currently developing an analysis of the costs and benefits of the proposed rules, including the estimated incremental cost to industry to comply with new requirements. BOEMRE can use the results of the IEc analysis to determine whether industry’s r ecommendations provide a basis for any reconsideration of industry’s compliance costs (i.e., whether adoption and implementation of voluntary measures might shift the baseline against which BOEMRE should consider the incremental compliance costs).

DOCUMENT S REVIEWED IEc reviewed the following documents as part of this effort:

 Increased Safety Measures for Energy Development on the Outer Continental Shelf , U.S. Department of the Interior, May 27, 2010 (the “30

- Day Report”).107

 Proposed amendments to 30 Code of Federal Regulations (CFR) Part 250

– Oil and Gas and Sulphur Operations in the Outer Continental Shelf (as of August 6, 2010); these proposed amendments are a
direct result of the recommendations contained in the 30

- Day Report.

 White Paper: Recommendations for Improving Offshore Safety , prepared by the Joint Industry Task Force to Address Offshore Operating Procedures and Equipment, May 17, 2010.

 Draft report of the Joint Industry Task Force to Address Subsea Well Control and Oil Spill Response, July 6, 2010.

 Isolating Potential Flow Zones During Well Construction , American Petroleum Institute (API)
Recommended Practice 65

– Part 2, First Edition, May 2010 (referenced in the Joint Industry Task Force White Paper).

 Health, Safety and Environmental Case Gui delines for Mobile Offshore Drilling Units , International Association of Drilling Contractors (IADC), Issue 3.2.1, May 1, 2009 (referenced in the Joint Industry Task Force White Paper).

 Testimony of Andy Radford, API Senior Policy Advisor, before the Natio nal Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, July 12, 2010.

IEc did not complete a detailed review of API Recommended Practice 65

– Part 2 or the IADC guidelines, as they present a level of technical detail that is beyond the scope of the intended general comparison of proposed rules and voluntary measures. In addition, the July 6, 2010 draft report of the Joint Industry Task Force to Address Subsea Well Control and Oil Spill Response does not contain
recommendations for volun tary measures but rather the context for the Task Force’s near

- term and long

term efforts, and thus does not contribute to the IEc analysis.

To facilitate the analysis, IEc retrieved electronic versions of each section of 30 CFR Part 250 in which
BOEMRE is proposing a change and copied the text into a Microsoft Word document. Based on a careful review of the rulemaking document, IEc inserted, modified, or deleted text, using the redline/strikeout feature, to highlight the location and substance of each prop osed change. The resultant document served as the basis for a comparison between proposed regulatory changes and the industry recommendations for voluntary safety and protection measures.

RESULTS The results of the IEc analysis are described in Tables 1 and 2. Table 1 highlights the industry recommendations that BOEMRE explicitly addresses in its proposed rule changes. Table 2 lists selected additional industry recommendations that the proposed rul es do not address and that could result in additional industry operating costs.August 18, 2010

108

TABLE 1 COMPARISON OF RECOMMENDED INDUS TRY VOLUNTARY MEASUR ES TO PROPOSED CHANG ES IN 30 CFR PART 25 0

RECOMMENDED INDUSTRY VOLUNTARY MEASURE RELEVANT SECTION OF REGULATIONS PROPOSED REGULATORY CHANGE

Upon release, adopt AP RP 65 Part 2: Isolating Potential Flow Zones During Well Construction. 30 CFR 250.415(f) New requirement for a discussion of how the best practices described in API RP 65 Part 2 were evaluated in the casin g and cementing program.

Engage casing hanger latching mechanisms when casing is installed in the subsea wellhead. 30 CFR 250.423(b) New requirement to perform a pressure test after the intermediate and production casing strings are installed to verify that the casing hanger latching mechanisms or lock down mechanisms are engaged and the casing has been sealed.

Provide two independent barriers, including one mechanical barrier, for each flow path prior to displacement to underbalanced fluid columns. 30 CFR 250.420(a)(6) New requirement for a professional engineer to verify two independent tested barriers, including one mechanical barrier, across each flow path during well completion activities.
Perform negative tests to a differential pressure greater t han or equal to anticipated pressures after displacement. 30 CFR 250.423(c) New requirement to perform a negative pressure test after the intermediate and production casing strings are installed. Test procedures and criteria must be submitted with the APD for approval. Ensure shearable drillstring components are positioned in the shear rams during displacement. 30 CFR 250.442(a) New requirement for two BOPs, rather than one, equipped with a blind

- shear rams, with a further requirement that the blind

- shear rams are appropriately spaced to ensure that at least one cuts the drillpipe and seals the wellbore.

Ensure BOP can automatically close blind/shear ram(s) and close choke/kill line valves 30 CFR 250.442(f) Provide autoshear and deadman systems for dynamically positioned rigs.
Ensure ROV can close blind shear rams, pipe rams, casing shear rams, and choke and kill valves. Ensure ROV can unlatch the lower marine riser package. 30 CFR 250.442(d) When drilling with a subsea BOP system, the BOP must be equipped with ROV intervention capability; at a minimum, the ROV must be capable of closing all pipe rams, all shear rams, and unlatching the LMRP.2010

109

TABLE 2 SELECTED AD DITIONAL RECOMMENDED INDUSTRY VOLUNTARY MEASURES

 Deepwater mobile offshore drilling unit produces safety case, following guidelines established by the IADC.

 Develop Well Construction Interfacing Document to manage well construction activities and mitigate unexpected events that impact health, safety and the environment.

 Positively test each casing barrier to a pressure exceeding the highest estimated integrity of casing shoes below that barrier.

 Close blowout preventers during displacement to underbalanced fluid columns.

 Perform separate displacement operations for riser and casing. Monitor displacement volumes in and out.

 At prescribed intervals, conduct subsea testing of hydraulic function of rams and valves downstream of the trigger to simulate 1) unintended disconnect of lower marine riser package (LMRP); and 2) loss of surface control of the subsea BOP stack.

 Verify proper operation of the system by testing to MMS

- approved Application for Permit to Drill (APD) casing pressure below blind / shear rams after system activation.

 Arm the system when BOP stack is latched on the wellhead. Disarm and rearm only if approved through a formalized Management of Change process.

 Standardize ROV hot stab and receptacle per API Spec 17H. Standardi ze hot stab designs between drilling and production operations.

 Stage ROV tooling / external hydraulic power supplies strategically in Gulf of Mexico for rapid mobilization.

CONCLUSIONS
IEc has reviewed literature that has recently become available in the aftermath of the Deepwater Horizon event in order to determine whether and how it might suggest changes in the development of the new OECM. As part of this effort, IEc compared proposed reg ulatory changes with industry recommendations for safety and protection measures that industry could voluntarily adopt during the course of OCS oil and gas exploration and development activities.

None of the literature IEc reviewed suggests a need for any immediate changes in the methodologies or inputs currently associated with OECM development. However, since spill rates are an important model element, changes may be warranted in the future if and when new regulatory requirements or the voluntary adoption of new procedures or technologies result in measurable changes in the expected frequency of spill events.

The comparison of recommended voluntary industry measures with proposed changes to 30 CFR Part 250 indicates several areas of overlap, as noted above in Table 1. However, it is not possible at this time to conclude that the articulation of industry recomme ndations will necessarily translate into measurable110

changes in baseline industry costs against which BOEMRE would compare the cost to comply with new regulatory requirements. If, in the context of a benefit

- cost analysis, the measures in Table 1 were

assum ed to have been adopted, it would be appropriate to consider any associated costs as part of the baseline (i.e., the incremental cost to industry of the new regulations would be reduced). As BOEMRE considers additional regulatory changes, further compariso n to industry recommendations, including those listed in Table 2, would be warranted.