1 

## Benefit-Cost Analysis for the Interim Final Rule on Increased Safety Measures for Energy Development on the Outer Continental Shelf

RIN 1010 AD68



# Bureau of Ocean Energy Management, Regulation and Enforcement

September 30, 20102 

## Table of Contents

EXECUTIVE SU MMARY ................................................................................................ 5 INTRODUCTION AND NEED FOR FEDERAL ACTION................................................ 8 HISTORICAL INFORMATION ABOUT BL OWOUTS................................................... 10 Shallow Water Dr illing Acti vity ................................................................................... 10 Deepwater Drilli ng Activi ty ......................................................................................... 11 Baseline Size and Duration of a Catast rophic Deepwater Bl owout Spill.................... 11 EXISTING AND NEW REGULA TORY PROV ISIONS .................................................. 12 Benefit-Cost Approac h............................................................................................... 18 BASELINE ASSUMPTIONS IN TH E BENEFIT-COST ANALYSI S.............................. 20 Baseline Estimates of Future Deepwater Drilli ng Activi ty .......................................... 21 Shallow Water Dr illing Acti vity ................................................................................... 22 Baseline Chance of Another De epwater Blowout Spill .............................................. 22 COMPLIANCE COSTS FOR THIS REGU LATION....................................................... 22 Seafloor Function Testing of ROV Inte rvention and Deadman Systems - Drilling ..... 23 Seafloor Function Testing of ROV Intervention and Deadman Systems – Workover/Com pletions.......................................................................................... 25 Negative Pressu re Tests ........................................................................................... 25 Installation of Dual Mechanical Ba rriers..................................................................... 26 Professional Engineer Certif ication for We ll Desi gn................................................... 26 Retrieval and Testing of a BOP Sta ck After a Well Cont rol Situat ion......................... 27 Third Party Certification of Shear Ram C apabili ty...................................................... 27 Summary of Annual Recurring Co sts......................................................................... 28 Voluntary Measures by Indus try ................................................................................ 29 AVOIDED PRIVATE-SO CIAL CO STS ......................................................................... 29 Damage to Dr illing Rig ............................................................................................... 29 Well Containment and Pluggi ng ................................................................................ 30 Hydrocarbon Losses.................................................................................................. 30 Fines and Criminal Penalti es ..................................................................................... 31 Summary of Avoided Priv ate-Social Costs ................................................................ 31 AVOIDED EXTERNAL-S OCIAL CO STS...................................................................... 32 Conceptual A pproach ................................................................................................ 33 Valuing Natural Re source Da mages .......................................................................... 34 Caveats and A ssumptions ..................................................................................... 39 Relationship between Natural Resource Damages and Spill Size and Type of Oil Spille d ................................................................................................................... 39 Valuing Commercial Fishery Lo sses.......................................................................... 40 Data Availa bility...................................................................................................... 40

Background..................................................................................................................... .40
Revenues....................................................................................................................... ..43 Operating Costs ...............................................................................................................4 7 Closures....................................................................................................................... ....50 

### Valuing Lost Recreatio n............................................................................................. 523 

### Recreational Fishing .............................................................................................. 53 Beach Recr eation................................................................................................... 54 Oil Spill Response and Da mage Assessment Costs ................................................. 56 Avoided Costs Associated with Reduced Loss of Life and Nonfatal Injuries ............. 58 Value of Statis tical Life........................................................................................... 58

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

### Other Health Effects .................................................................................................. 61 Avoided Costs Associated with Other Activi ties Linked Economically to Avoiding an Oil Spil l.................................................................................................................. 62 Summary – Avoided Exter nal-Social Costs ............................................................... 63 TOTAL ESTIMATED AVOIDED SO CIAL COSTS (B ENEFIT S) .................................. 64 SCENARIO ANALYSIS ............................................................................................... 64 Sensitivity of Co mpliance Co sts ................................................................................ 66 Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blow out Spil l ..................................................................................... 66 Alternat ives................................................................................................................ 67 Small Business Al ternativ es................................................................................... 68 CONCLUSION AND UNC ERTAINTI ES ....................................................................... 68 Appendix A Natural R esource Damage Data ........................................................... 71 Appendix B We ll Data ................................................................................................ 74 Appendix C De finitions.............................................................................................. 77 Appendix D Re feren ces............................................................................................. 79 Appendix E Voluntary I ndustry Measure s Review .................................................. 83



## Figures

Figure 1 - Historical Deepwater Wells (Greater than 500 feet) .................................................................. ...........21 Figure 2. Distribution of Dataset Spills by Response Costs per Barrel ($2009) .................................................. .35 Figure 3. Distribution of Spills, by NRD + Assessment Cost per Barrel ($2009) .................................................3 6 Figure 4. Distribution of Spills , by Total Spill Costs ($2009)................................................................. ................36 Figure 5. Oil Spill Liability Trust Fund Claims Requested and Paid (Sep 1972-Feb 2010)................................37 Figure 6 Gulf State Landings an d Revenue, 1999- 2008 (2 009$).................................................................... ........41 Figure 7 Average Annual Price per Po und (2009$)................................................................................ ................41 Figure 8 Gulf State Landing s, 1999-2008 (mmlbs) ................................................................................ .................42 Figure 9 Resident Louisiana Shrimpin g Licenses (Trawl, Butterfly Net, a nd Skimmer Net) So urce: Louisiana Department of Wild life and Fi sheries ........................................................................................... ..................43 Figure 10 Monthly Commercial Fishery Landi ngs (Texas, West Florida, Alabama)..........................................45 Figure 11 Monthly Commercial Fisher y Landings (Louisia na, Mississippi)........................................................4 5 Figure 12 Summer Commercial Fishery Landing Reve nues (West Florida, Mississippi, Alabama) .................46 Figure 13 Summer Commercial Fishery Landi ng Values (Louis iana, Texas) .....................................................464 

## Tables

Table 1 - 30 CFR 250 Subpart D Provisions...................................................................................... ......................13 Table 2 – Deepwater Rig Counts, Da y Rates, and An nual Drill Rates .............................................................. ...25 Table 3 – Estimated Recurring Cost Summary ..................................................................................... .................28 Table 4 - Summary of Estimated Av oided Private-So cial Costs................................................................... ........32 Table 5 Seven Gulf Coast Spills : Natural Reso urce Dama ges ...................................................................... .........38
Table 6 Gulf of Mexico Com mercial Fisherie s Data, 2008......................................................................... ............44
Table 7 Estimated 2010 Baseline Valu es for Gulf State Commercial Fisheri es ($ millions, t rend 2002-2008)..47 Table 8 Gulf Commercial Shrimping Costs as a Percentage of Revenues (simulated)........................................47 Table 9 Gulf Shrimping Flee t: Large and Sm all Ve ssels .......................................................................... .............48 Table 10 Large and Small Vessel Co ntributions to Gulf Commercial Fi shing Revenues (2009$ millions) .......49

Table 11 Estimated Baseline Profit s for 2010: Large and Small Gulf Commercial Fishing Vessels (2009$ millions) ...................................................................................................................... .......................................49
Table 12 Estimated Baseline Profit s for 2010: Gulf Coas t Commercial Fisheries (2009$ millions)...................50 Table 13 2010 Gulf Fishery Closures in Federal Exclusive Econ omic Zone (EEZ)............................................51
Table 14 Estimated Gulf Stat e Profits Lost to Closures........................................................................ ................52 Table 17 Average Number of Tr ips (May-July) (2005-20 09)........................................................................ .........53
Table 18. Estimated Number of Recreation Days (May-J uly)....................................................................... ........54
Table 19. Recreation Studies .................................................................................................. .................................56 Table 20 Cost of Sp ills by Fu el Type........................................................................................... .............................57 Table 21 Cost of Spills by Length of Sho reline O iled ........................................................................... ..................57
Table 22 Cost of Spills by Location............................................................................................ ..............................58 Table 23 Oil Spill Response Costs by Spill Volume .............................................................................. ..................58 Table 24 Selected Fatal Occupational Injury Rates by Industry, 2008............................................................ .....59 Table 25 Summary of Estimated Avoided External -Social Costs .................................................................... .....63 Table 26 - Summary of Private and External Social Costs ........................................................................ ............64
Table 27 - Dataset of Spill Costs: Restoration and Assessment Costs............................................................ .......71 Table 28 - Gulf Shrimp Land ings, Revenue, and Price............................................................................ ..............73 Table 29 – GOM Deepwater Wells by Water and Drilling De pth..................................................................... ....745 

## EXECUTIVE SUMMARY

This document describes the be nefit-cost analysis conducted for this interim rule, RIN 1010 AD68, Increased Safety Measures, Drilling Operati ons on the Outer Continental Shelf (OCS). It represents a joint effort by the BOEMRE Economi cs Division and the Office of Policy Analysis (OPA) in the Department of the Interior. The preamble to the regulation gives instructions for providing public comment on this analysis.

Various events around the world as well as the US over the years demonstrate that catastrophic oil spills can and do occur. The costs associated with such spills can be enormous. As a matter of policy, BOEMRE has decided that any reasonab le 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 se ven experts identified by the National Academy of Engineering, or identified by industry or acad emic experts in materials presented to BOEMRE as part of the public forums and information ga thering that the bureau has conducted since July 12, 2010.

While the estimated costs of this rulemaking, as reflected in the compliance costs of the enumerated requirements of approximately $180 million per year, have a strong foundation and are based on surveys of public and industry sources , quantification of the benefits is uncertain. The benefits are represented by the avoided costs of a catastrophi c spill, which are estimated under the stipulated scenario as being $16.3 billio n per spill avoided. These regulations will
reduce the likelihood of another bl owout and associated spill, but the risk reduction associated with the specific provisions of this rulemaking cannot be quantified because there are many complex factors that affect the risk of a blowout event. As noted by the Se cretary of the Interior in his July 12 decision memo suspending certain drilling activities, drill ing accidents can have a profound, devastating impact on the economic a nd environmental health of a region. The
measures codified in this rule will reduce the likelihood of such an event in the future, at a cost that is not prohibitive, and theref ore this rulemaking is justified.

The purpose of a benefit-cost analysis is to pr ovide policy makers and others with detailed information on the economic consequences of th e regulatory requirements. The benefit-cost analysis for this rule was conducted using a s cenario analysis. This analysis considers a regulation designed to reduce th e likelihood of a catastrophic o il spill. The costs are the compliance costs of imposed regulation. If anot her catastrophic oil spil l is prevented, the6 

### benefits are the avoided costs as sociated with a catastrophic oil spill (e.g., reduction in expected natural resource damages owing to the reduction in likelihoo d of failure).

Avoided cost is an approximation of the “true” benefits of avoiding a catastrophic oil spill. A benefits transfer approach is used to estimate the avoided costs. The benefits transfer method estimates economic values by transferring existin g benefit calculations from studies already completed for another location or issue to the case at hand. Accordingly, none of the avoided costs used in this analysis of hypothetical catastrophic spills rely upon, or should be taken to represent, our estimate for the BPDH event commencing on April 20, 2010.

Three new requirements account fo r virtually all of the comp liance costs imposed by this regulation (1) use of dual mechanical barriers in addition to cement barriers in the final casing string to prevent hydrocarbon flow in the event of cement failure , (2) applicati on of negative pressure tests to all intermediate and the production casing strings to ensure their proper installation, and (3) maintenance of standby ROV capability to close BOP rams and testing that capability after the BOP has been installed on the sea floor. BOEM RE estimates that these three requirements will impose compliance costs of approximately $174 million per year, representing 95 percent of the total annual compliance costs of $183 million associated with this rulemaking. These cost estimates were developed by BOEMRE based on public data s ources and confidential information provided by several offshore operators and drilling companies.

On the benefit side, the avoi ded costs for a hypothetical deep water blowout resulting in a catastrophic oil spill are estimated to be about $1 6.3 billion (in 2010 dollars) 1 

### . Most of this amount derives from detailed cleanup estimates developed by OPA us ing damage costs per

1 We note that the estimates of avoided damages contained in this document, while a useful tool for the purpose of this benefit-cost exercise, are not re levant in calculating damages for any particular oil spill, including the BPDH spill. Although the hypothetical spill discussed in this document is si milar in volumetric magnitude to recent estimations of the amount of oil released as a result of the BPDH event, damages are highly specific to a particular event, and depend on a multitude of complex and interacting factors. This report addresses a hypothetical Gulf of Mexico spill that is not intended to correspond to any real event, and whose characteristics have been designed to permit modeling and analysis, rather than being designed to re flect to the facts of a specific event or set of events. This document is also not able to incorporate scientific da ta relating to the specific circumstances of a particular spill or to any other specific spill, among other limitations of the m odel and analysis applied in this report. Moreover, the nature of the economic analysis contained in this document, and the space limitations of this document, have required that a number of potential factors be excluded from the scope of the analysis, or have entailed other changes. Additionally, the estimate of potential costs avoided used in this analysis do not reflect an assessment or quantification of the costs of injury or fatality resulting from the BPDH event. As such, the damage and cost estimates presented herein should not be considered reliabl e monetary assessments associ ated with the BPDH event. This document is only intended to provide a cost-benefit analysis for a defined regulatory purpose, and is not intended to be used, and should not be used, for any other purp ose or in any other situation. In particular, estimates contained in this report are not intended to be used, no r are of any relevance, in litigation relating to damages resulting from the BPDH spill or any other spill.7 

### barrel measures found in historical spill data (f rom all sources including pipeline, tanker, and shallow water as well as deepwater wells) and fro m aggregate damage measures contained in the legal settlement documents for past spills a pplied to a catastrophic deepwater spill of hypothetical size. The rest of th is avoided cost amount represents the private costs for blowout containment operations. In sum, three component s 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-pl ugging actions plus lost hydrocarbons.

The above estimate of compliance costs is somewh at uncertain. This is the case primarily because the $183 million annual estimate is perhap s higher than the actual costs that will be incurred by society from this rule because industry is volun tarily undertaking some steps following the BPDH event that overlap those in th is regulation. The Joint Industry Task Force
draft recommendations include use of mechanical barriers and negative pressure tests. Voluntary action, perhaps spurred on as well by revised liability expect ations and increased insurance prospects, means the incremental costs associated with these overlapping measures are not truly imposed solely by the new regulations . Less incremental requi red costs reduce the improvement in reliability necessa ry for expected benefits to c over the cost of complying with the new regulations. On the benefit side, th e total avoided cost estimate of $16.3 billion (representing a measure of expected benefits for avoiding a future ca tastrophic oil spill) is highly
uncertain because of the limited historical data upon which to judge th e 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 meas ure employed reflects only those outlays that we have been able to calculate based primarily upon factors derived from past oil spills. Possible losses from human health effects or reduced prop erty 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 histor ical data on catastr ophic offshore blowouts.

Based on the occurrence of only a single catast rophic blowout, the number of GOM deepwater wells drilled historically (4,123) , and the forecasted future drilling activity in the GOM (160 deepwater wells per year), the baseline risk of a catastrophic blowout is estimated to be about once every 26 years. Combining the baseline likelihood of occurrence with the cost of a hypothetical spill implies that the expected a nnualized spill cost is about $631 million ($16.3 billion once in 26 years, equally likely in any 1 year). To balance the $183 million annual cost imposed by these regulations with the expected bene fits, the reliability of the well control system needs to improve by about 29 percent ($183 million / $631 million). We have found no studies that evaluate the degree of act ual improvement that could be expected from dual mechanical barriers, negative pressure tests, a nd a seafloor ROV function test.8 

## INTRODUCTION AND NEED FOR FEDERAL ACTION

The interim rule amends drilling regulations related to well cont rol in response to recommendations in the Increased Safety Measur es Report (Safety Measures Report) that DOI sent to the President on May 27, 2010 2 

### . This regulation will affect all lessees and operators undertaking drilling operations on the OCS. The Safety Measures Report identified four items for emergency rulemaking: (1) Develop secondary control system requirements; (2) Establish new blind-shear ram redundancy requirements; (3) Establish new deepwater well control procedure requirements; and (4) Adopt safety case requirements for fl oating drilling operations on the OCS.

The provisions of this interim final rule address items 1) secondary control system requirements and 3) deepwater well control procedure requirem ents. The rule does not include 2) new blindshear ram redundancy requirements and 4) safe ty case requirements for floating drilling operations. These and other items in the Safe ty Measures Report require further study by industry and Interior Strike Teams to determine their efficiency and effectiveness. Measures
considered beneficial will be considered for future notice and comment rulemaking.

In general, procedures for maintaining or regain ing well control can be divided into primary and secondary measures. Primary measures include items such as the use of drilling mud, casing and cementing to keep the well under control. These requirements will strengthen primary well control barriers thereby reducing the likelihood th at secondary barriers, like the BOPs, will be
needed. Secondary measures include the BOP stack and it s redundant control devices to seal the well and prevent environmental or safety impacts in the case of a blowout event. The interim rule also requires increased testing of secondary measures including a check of remotely operated vehicle (ROV) intervention capability and deadma n switch on the seafloor to better assure backstop activation of the subsea BOP, should th e need arise. These requirements provide greater protections against a cata strophic blowout event. Effective secondary measures eliminate or reduce the urgency of completing a relief we ll to stanch the flow of oil after a blowout.

The Secretary of the Inte rior (Secretary) has the duty to en sure that operations on the Outer Continental Shelf (OCS) are managed in a safe manner, under the authority of the OCS Lands Act (OCSLA). Section 21(b) of the OCS Lands Act provides guidance on the discharge of this duty as follows.

2 Available at: http://www.doi.gov/deepwaterhorizon/loader.c fm?csModule=security/getfile&PageID=335989 

### the Secretary . . . shall require, on all new drilling and production operations and, wherever practicable, on existing operations the use of the best available and safest technologies which the Secret ary determines to be economically feasible, wherever failure of equipment w ould have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clea rly insufficient to justif y the incremental costs of utilizing such technologies

.

The BOEMRE carries out this duty through regulations, the terms and conditions of leases, conditions of explorat ion and development plan appr oval, and inspections of OCS oil and gas operations. A lthough current regulations exte nsively address shallow and deepwater drilling operations, the BPDH event and related investigations revealed that those regulations insufficiently protect th e environment and thos e conducting operations
on the OCS under certain situations.

There are other rationales for this regulation. The first relates to the uncer tainty associated with actual damages and related magnitude of liability for those damages, and how that uncertainty may adversely influence operator behavior. Another rationale relates to information asymmetries. The current ex post compensation regime perhaps provi des too little information to regulators regarding the effec tiveness of safe operating incen tives embodied in the existing regulatory regime. A more prescriptive regime could assist in this regard by providing society with greater transparency and assurance that safety measures on all operations perform as expected. Lastly, because of stat utory liability limits and the potential to avoid liability by declaring bankruptcy, offshore operators may take certain risks and cost-cutting actions absent explicit federal requirements rela ting to safety and the environm ent because of the potential to
avoid some or all of the liability.

The regulatory changes published in these new drilling regulations are designed to reduce both the frequency of a catastrophic spil l and the severity of its impa ct (through a shorter period of discharge). The frequency of deep water well control events (blowout s) that could lead to a spill does not appear to have changed materially over time. BOEMRE data shows that blowout frequencies on the OCS have stabilized at abou t 1 for every 275 deepwater wells over the last several decades (see the Baseline, Section - Chance of another Spill for a more in-depth discussion). Thus, while a greate r number of deepwater wells are being drilled in ever deeper water depths, this history indica tes that normal evolution of de epwater practices may not have materially reduced the chance of a blowout event. Moreove r, a blowout may pose more problems in deepwater where drilling a relief well is likely to take longer. Hence prescriptive10 

### regulations are being instituted to increase the co ntrol measures that will manage and contain a blowout event with a grea ter degree of reliability.

We recognize that liability im plications and increased insura nce costs may compel changes by drilling companies independent of these regulations. Acco rdingly, BOEMRE commissioned an
outside assessment of the voluntar y measures proposed by Joint Indus try Task Forces (JITFs) as compared to these regulations. (See Appendix E). While the work of the JITFs is not complete
and the lessons learned or other measures have not been implemented, an assessment of existing JITF proposals serve as guidance on how much of the additional costs industry may incur are not really imposed by the new regulations. Joint Indu stry Task Force draft recommendations include
use of mechanical barriers and negative pressure tests which ha ppen to account for a substantial share of the compliance costs we attribute to the interim rule . We did not adjust for these potential voluntary actions, so for this reason our compliance cost estimate may be higher than the actual costs imposed by this rule.

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



## HISTORICAL INFORMATION ABOUT BLOWOUTS

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



## Shallow Water Drilling Activity While blowouts actually occur more frequently in shallow water, the consequences and spill damage resulting from a blowout tends to be less than in deep water due to the generally lower reservoir pressure, the greater prevalence of ga s rather than oil, and the presence of more
accessible surface BOPs with diverters. BOEMRE has recorded 6 GOM shallow water blowouts resulting in a spill of hydrocarbons from 1990-2010. The total volume spilled is estimated to be
132 barrels of oil or condensate ov er these last two decades. If we go back another 20 years to 1970, we add another 6 spills for total hydroc arbon spill volume of 138.5 barrels from 12 blowout events over the last 40 years in the GOM. Since 1970 there have been 32,339 shallow
water wells drilled in the GOM and since 1990 there have been 13,675 shallow water wells11 

### drilled. Over this period there have been severa l major revisions to the drilling regulations and some of these regulatory changes have specifica lly addressed drilling risks in shallow water.

The compliance costs for this regulation fall over 90 percent on deepwater wells. Thus, in our analysis the baseline chance of another spi ll and the calculation of avoided costs focus exclusively on a scenario in which hypothetical catastrophic deepwater blowout events may occur randomly at some periodic rate based on the historical evidence.



## Deepwater Drilling Activity
BOEMRE has obtained these historical dataon deepwater drilling from its Technical Information Management System database. There have been 4,123 wells spudded between 1973 and mid-2010 not counting bypasses in water depths of at least 500 feet.

There have been 20 OCS deepwater blowouts in th e history of the program with 3 resulting in a spill during drilling operations. Only one deep water blowout has resulted in a spill of a catastrophic size. The other two deepwater bl owout spills were estimated to be 11 and 200
barrels of crude/conde nsate spilled.

The 20 deepwater blowouts aver age one blowout for about ever y 200 deepwater wells drilled on the OCS. The average number of wells be tween blowouts increased until about 1990 but has
since leveled off at about one for every 275 deepwater wells.



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

The baseline size and duration of the catastrophic spill used in this analysis is taken from the National Incident Command’s (“ NIC”) updated estimate of August 2, 2010 of the BPDH spill. The scientific team charged by the NIC with dete rmining flow rate concluded that 53,000 barrels of oil per day were leaking from the well im mediately before closur e by the capping stack on July 15, 2010. Measurements and modeling showed that , as a result of deplet ion of the reservoir, the daily flow rate decreased over the 87 days prio r to the capping of the well; the scientific team estimated at the beginning of the spill, the flow rate was 62,000 barrels per day. BOEMRE is using the estimate of 53,000 barrels a day for 90 days as the figure upon which to base the estimated avoided costs for this regulatory analysis. While a catastrophic deepwater spill may12 

### have a higher flow rate in a worst-case scen ario, the 53,000 barrels a day for 90 days is a reasonable proxy for regulatory cost-benefit analysis purposes. This scenario results in an oil spill of 4.77 million barrels.



## EXISTING AND NEW REGULATORY PROVISIONS

This interim rulemaking will revise selected sect ions of 30 CFR 250 subparts D, E, F, O, and Q as related to the drilling of new wells. As in most benefit-cost analysis studies a full compliance scenario is assumed and analyzed for the base line and new regulatory requirements. We expect only a portion of the proposed changes in Subpart D will add material capital or operating costs (some of which will be significant) to the drilling of new OCS wells. 3 

### Table 1 compares the existing 30 CFR 250 Subpart D provis ions with the new provisions. We expect that all of these requirements can be implemented immediatel y using existing equipment and established practices. Those changes that wi ll impose significant costs include:
1. Seafloor function testing of ROV interven tion and deadman systems; 250.449(j) and (k), 250.516(d) and 250.616(h).
2. Negative pressure testing of intermed iate and production ca sing strings; 250.423(c).
3. Installation of dual mechanical barriers for the final casing string; 250.420(b).
4. Professional engineer certific ation that the well design is appropriate for expected well bore conditions; 250.420(a).
5. Retrieval and testing of BOP after a shear ram has been activated in a well control situation; 250.451(i).

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

3 Identical costly new requirements for subsea function testing of ROV intervention during drill operations (Subpart D) also apply to well completion (Subpart E) and workover (Subpart F) operations.13 Table 1 ‐ 30 CFR 250 Subpart D Provisions
EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

- Requires the operator to evaluate the best practices according to API
RP 65-Part 2 and submit a written description for the evaluation. - Written description must include
the mechanical barriers and cementing practices the operator will use for each casing string. 30 CFR §250.415(f) Evaluate best practices in
API RP 65-
Part 2 - No evaluation required

- API RP 65 Part 2 addresses cementing practices and factors affecting cementing success. - No meaningful

cost

- Schematics of all control systems, including primary controls, secondary controls, and pods for the BOP system must be
submitted. 30 CFR §250.416(d) Submittal of
schematics of
all control systems for
BOP stack - Schematic of BOP system showing inside diameter of BOP stack, number and type of preventers, location of
choke and kill lines - Location of the controls must be
included - No meaningful

cost

- Information that the
blind-shear ram is capable of shearing the pipe - Verification that the blind-shear
rams installed in the BOP stack are capable of shearing the drill pipe in
the hole under maximum anticipated surface pressure. - Independent third party certification will require a small cost per well

- Independent third party must be a technical classification society or an API licensed manufacturing, inspection, certifi cation firm, or licensed professional engineering
firm. 30 CFR §250.416(e) Independent third party
verification

to ensure
blind-shear

rams are capable of cutting the drill pipe
used - No independent third party certification required

- Independent third party must not
be the OEM. - Will add moderate

costs

30 CFR §250.418(i) Submit qualifications
of independent third parties
with APD - No independent third party certification required - Description of qualifications in
accordance with §250.416 (e) - No meaningful

cost14 EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

- PE will verify there are two independent barriers - Small cost per well if performed by an independent third
party
- No cost if PE
certification is done
in house 30 CFR §250.420(a) (6) Professional Engineer
verification
of well casing and cementing

program - No PE verification required

- Verify the casing cementing design is appropriate for the purpose it was intended under expected wellbore conditions - Assumed that some majors would verify in-house; smaller operators will use third party

- Installation of dual
mechanical barriers
is estimated to take
30 minutes.

- Estimated
additional float
valve cost of $20,000 30 CFR §250.420(b) (3) Dual
mechanical
barriers - No requirement - Operator must install dual
mechanical barriers in addition to cement in the final casing string
and document to BOEMRE.

- Dual float valves, or one float valve and a mechanical plug.

- Will add significant costs to regulation - PE will verify there are two independent barriers - Small cost per well if performed by an independent third
party
- No cost if PE
certification is done
in house

- Assumed that some majors would verify in-house; smaller operators will use third party 30 CFR §250.420(a) (6) Professional Engineer
verification
of well casing and cementing

program - No PE verification required

- Verify the casing cementing design is appropriate for the purpose it was intended under expected wellbore conditions

- Will add significant costs to regulation15 EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

- Perform a pressure test on all casing strings (except drive/structural) according to 250.423 (a) - Pressure tests are already required, no extra equipment
time

- Each pressure test only takes a few
minutes 30 CFR §250.423(b) (2) Pressure test on the casing
seal assembly

- No requirement to

ensure proper installation of the casing in the subsea
wellhead - Additional pressure test for the intermediate and production casing strings on the casi ng seal assembly to ensure proper installation of the casing in the subsea wellhead.

- No meaningful

cost

- Negative pressure
test will take 90
minutes for each required string of casing 30 CFR §250.423(c) Negative
pressure test - No negative pressure test required - Perform a negative pressure test to ensure proper installation of intermediate and production casing strings

- Will result in significant costs for the regulation

30 CFR §250.442(e) Maintain
ROV and a
trained crew - ROVs used for visual inspection every 3 days; 250.446(b) - Required to maintain an ROV and trained crew on each floating rig on a continuous basis. - All rigs are
assumed to have an
ROV on board. This regulation will not
add additional costs - ROV must be capable of shutting in the well during emergency
situations - Regulation does not require a timed test, therefore
current ROVs will be capable of performing all required functions.

30 CFR §250.442(f) Provide an
autoshear
and deadman system for dynamically positioned rigs - No
autoshear/deadman system requirement - All dynamically positioned rigs
must have an autoshear and deadman system - Industry standard for dynamically positioned rigs to
have
autoshear/deadman
systems - No meaningful

cost16 EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

30 CFR §250.442(g) Barriers on
BOP control panels to
prevent
accidental
disconnect
functions - No two-handed requirement - Incorporate enable buttons oncontrol panels to ensure twohanded operations for all critical
functions. - No meaningful

cost

30 CFR §250.442(h) Label subsea
BOP control panel - No labeling requirement - Clearly label all control panels, such as hydraulic control panels
and ROV interface on the BOP - No meaningful

cost

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

cost

- Written procedures for operating
the BOP stack and LMRP 30 CFR §250.442(i) Develop
management system for
BOP

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

30 CFR §250.442(j) Training for
BOP equipment - No training requirement - Train BOP personnel in deepwater well control theory and practice in accordance with 30 CFR 250, Subpart O - No meaningful

cost

30 CFR §250.446(a) Document
maintenance
and inspections
to BOP
system - No documentation requirement - BOP maintenance and inspections must meet or exceed provisions of Section 17.10 and
18.10 - No meaningful

cost17 EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

- No initial test on the
seafloor - All ROV intervention functions must be tested during the stump test and one set of rams during the
initial test on the seafloor - Initial test on the
seafloor is not industry standard 30 CFR §250.449(j) Subsea
function test
for ROV
intervention
on a subsea
BOP stack

Additional stump testing requirements - Stump test BOP stack - ROV hot stabs must be function tested and capable of actuating at least 1 set of pipe rams, 1 set of blind-shear rams and unlatching
the LMRP - Operator must examine all
surface and subsea well control equipment to ensure that it is properly maintained and capable of shutting in the well during emergency operations - ROV seafloor test
is estimated to take
about 24 hours

- Will add significant costs

30 CFR §250.449(k) Autoshear/D
eadman
function test - No required function

test - The autoshear and deadman systems must be function tested during the stump test and during
the initial test on the seafloor. - No meaningful

cost

30 CFR §250.451(i) Emergency
activation of
blind or casing shear

rams - No required action - If the blind-shear or casing shear
rams are activated in a well control situation, the BOP must be retrieved and fully inspected and
tested - Emergency situation only, will incur significant loss of rig time

- No approval requirement - Approval required from DistrictManager before displacing killweight drilling fluid from the
wellbore - No meaningful

cost District Manager approval for displacing kill-weight drilling fluid - Submit reasons for displacing and provide detailed procedures of displacement process. 30 CFR §250.456(j)

- Follow procedures in 250.45618 EMERGENCY SUBPART D INTERIM FINAL RU LE PROVISIONS Regulation Summary Existing Regulatory
Provisions New Regulatory Provisions Cost

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

- ROV hot stabs must be function tested and capable of actuating at least 1 set of pipe rams, 1 set of blind-shear rams and unlatching
the LMRP 30 CFR §250.516(d) (8) Subsea
function test
for ROV
intervention
on a subsea
BOP stack - Stump test BOP stack
before installation

- Operator must examine all
surface and subsea well control equipment to ensure that it is properly maintained and capable of shutting in the well during emergency operations - Will add costs for well completions operations

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

- ROV hot stabs must be function tested and capable of actuating at least 1 set of pipe rams, 1 set of blind-shear rams and unlatching
the LMRP 30 CFR §250.616(h) (1) Subsea
function test
for ROV
intervention
on a subsea
BOP stack - Stump test BOP stack
before installation

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



## Benefit-Cost Approach
The purpose of this benefit-cost analysis is to meet the requirement s of Executive Order 12866 (Regulatory Planning and Revi ew) and OMB Circular A-4 by providing policy makers and others with detailed information on the consequences of the regulatory requirements. This rule is considered major and economically significant b ecause it is expected to impose annual costs on the economy of more than $100 million.19 

### A benefit-cost analysis require s estimating the net benefits a ssociated with the rule. Net
economic benefits are total benefits less total cost s. The benefits from this rulemaking include the reduced potential for catastrophic deep water blowouts and resulting damage as a consequence of stricter well control requirement s. Costs include compliance costs associated with the specific provis ions of the rule, such as wider use of best well design practices, extra testing and certification requirements, along with any additional administrative costs anticipated
as a result of the rule.

A benefit-cost analysis is differe nt from an economic impact analys is. The effects measured in a benefit-cost analysis reflect di rect first-order real resource market outcomes, such as more abundant or higher valued outputs and the acco mpanying enhancement of consumer utility, along with the costs imposed by the regulatory acti on as expressed in terms of the market value of the scarce factors of production needed to comp ly with the rulemaking. In contrast, while an economic impact analysis could include these ou tput measures as well, it tends to focus upon broad macroeconomic measures, such as nati onal income, employment, wages, and revenue transfers, among others, as they may be relate to specific industries a nd geographical locations associated with the regulatory requirements. Anecdotal economic impact information is provided for commercial fisheries impacts consistent with the avoided cost estimate for this analysis.

The approach used in this benefit-cost report ut ilizes consumer surplus measures to estimate avoided-cost impacts on recreation, and producer surplus measures to estimate avoided-cost impacts on industry, i.e., the benefits of the re gulatory action, rather than measuring these benefits from disparate economic considerations such as lost wa ges and employment in affected industries (hotels, restaurants, charter fishing boats, etc.). Estimated output impacts do not
account for the value of the increased envir onmental benefits (or reduction in potential environmental damages) that accrue to indivi duals, as part of consumer surplus.

In the case of this interim rule, we have not been able to quantify the extent to which the new safety measures required by this rulemaki ng can be expected to reduce the chance of another catastrophic oil spill. A study by Det Norske Veritas for the Canadian National Energy Board titled Beaufort Sea Drilling Risk Study dated March 11, 2010 used a fault tree analysis methodolog y to develop estimates of the ch ange in the probability of a
blowout associated with seve ral secondary well control meas ures like enhancements to
the BOP. We have not discovered sufficien t data that would allow adapting that methodology to the change in the probability of blowout associated with the enhanced primary well control measures in this rulema king. Nor have we found other studies that20 

### evaluate the degree of improvement that c ould be expected from enhanced barriers, pressure tests, and a seafloor ROV function check.

The preamble to the interim rule has re quested comments on th e availability of appropriate well design reliability studies. If such studies are identified, their results will be included in future analysis.



## BASELINE ASSUMPTIONS IN THE BENEFIT-COST ANALYSIS

The baseline for this rulemaking is the world without these new regulations. The “no action” baseline is the recent Gulf of Mexico deepwater o il and gas activity levels and the historical rate of events up to and including the April 20, 2010 BPDH blowout. The BPDH spill is the first U.S. Gulf of Mexico catastrophic deepwater bl owout spill. While there have been other OCS spills and blowouts, the requirement s in this interim rule are primarily focused on deepwater and designed to prevent or more quick ly control deepwater blowouts. Estimates of potential natural resource damages are based on a spill volume sim ilar to the most recent government estimate of the BPDH blowout spill volume but in all othe r respects are derived from information not specific to this spill. Estimates are also consis tent with projections of future GOM deepwater drilling activity 4



### .

We estimated the baseline rates of deepwater blowouts, injuries, fatalities a nd spills directly from
historical data. This baseline assumes that i ndustry has not voluntarily implemented additional safety and protection measures as a result of the lessons learned from the BPDH spill. This assumption may understate likely future blow out chances under exis ting regulations since industry can be expected to implement some new safety measures on its own. Because of this uncertainty about many of these changes, difficu lty of quantifying them and the time limitations under which this analysis must be conducted fo r the emergency interim rulemaking, we did not adjust the baseline for any volunt ary measures. A further discu ssion of voluntary measures can be found in the section on Compliance Costs for this Regulation.

4 The damage and loss estimates in this analysis are purely hypothetical and do not provide values applicable to the BPDH event. They are not pertinent to the BPDH event because they rely on dollar per barrel factors derived
from a number of earlier spills. These dollar measures vary widely across the different spills in the sample set so the average is not relevant to any actual spill. The exception is for well containment costs cited directly by BP and extrapolated to a hypothetical GOM deepwater catastrophic blowout event postulated in this analysis. Otherwise,
there is insufficient information available at this time to determine the magnitude of the costs that could have
been avoided, including natural resource damages, from the BPDH event. Moreover, the estimate of potential

costs avoided used in this analysis do not reflect an assessment or quantification of the costs of injury or fatality resulting from the BPDH event. As such, the damage and cost estimates presented herein should not be
considered reliable monetary assessments associated with the BPDH event.21 

## Baseline Estimates of Future Deepwater Drilling Activity The key drilling input for this benefit-cost an alysis is the future number of GOM deepwater wells. BOEMRE projected average deepwater drilling activity for 2011 – 2030 in the Central and Western GOM using 6 differe nt methods and then calculat ed the 20-year average to determine a reasonable drilling projection. Th e component projections were based on recent trends in drilling, leasing, aggregate produc tion forecasts and other available data.

BOEMRE estimates that there will be an averag e of 160 deepwater wells drilled annually over the next 20 years. The drilling of 160 deepwater wells per year is used to estimate the expected
interval before another catastr ophic blowout similar to the BPDH. This projection was divided into 112 wells drilled from floating rigs and 48 from rigs on deepwater production platforms.
The recent historical annual well count 5 

### is shown in the following figure.

DW Wells >500 ft (historical)

0 50 100 150 200 250 300

19

9 4
1 9 95 19 9 6 19 9 7
1 9 98 19 9 9 2 0 00 20 01 2002 20 03 20 04 2005 20 06 2007 2008 20 0 9 2010

YearWells

DW Wells >500 ft

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



### The GOM deepwater is generally expected to fo llow a progression similar to the GOM shelf. That means most of the remaining deepwater wells will be drilled farther from shore. Because of the extremely high cost of explor ing and developing deep and ultra-deep prospects, the number of wells drilled in the deeper water depths is unlikely to again reach the peak set in 2001-2002.

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

counts also exclude well completion and workover operations which involve re

‐ entering a wellbore and re

‐ deploying of BOPs and ROVs.22 

## Shallow Water Drilling Activity
While the greatest cost imposed by this regulation will affect deepwater drilling activities using MODUs, new regulatory testing a nd casing requirements apply to wells drilled both in shallow water and deep water. Future regulatory complia nce costs for shallow water wells are estimated using the 2009 GOM shallow water drilling activity rate of 186 we lls a year and the additional costs imposed on shallow wells by this regulation.



## Baseline Chance of Another Deepwater Blowout Spill
The baseline chance of another catastrophic deepwater blowout spil l uses only deepwater drilling, blowout and spill data on the U.S. federa l OCS. BOEMRE has obt ained this historical data from its Technical Information Management System database. There have been 4,123 wells spudded between 1973 and mid-2010 not counting bypasses in water depths of at least 500 feet.

There have been 20 OCS deepwater blowouts in th e history of the program with 3 resulting in a spill during drilling operations. Only one deep water blowout has resulted in a spill of a catastrophic size. The other two deepwater bl owout spills were estimated to be 11 and 200
barrels of crude/conde nsate spilled.

The 20 deepwater blowouts aver age one blowout for about ever y 200 deepwater wells drilled on the OCS. The average number of wells be tween blowouts increased until about 1990 but has
since leveled off at about one for every 275 deepwater wells.

Using the estimated 160 new deepwater wells that will be drilled annually, a catastrophic blowout spill under current regula tions and practices is estimated to be 1 in 4,123 wells. This implies a baseline major spill once every 26 years under current deepwater drilling rates. A sensitivity analysis was conducted on this baselin e probability assumption. The results of that analysis can be found in the sect ion titled Scenario Analysis.



## COMPLIANCE COSTS FOR THIS REGULATION

This section addresses the main compliance costs resulting from this regulation. The compliance costs fall primarily on lessees and operators ope rating on the federal OCS because the emergency rule raises drilling costs for every new deepwa ter well on the OCS. These new requirements add mechanical barriers to well design requirements and time for testing several features during drilling operations. BOEMRE estimates that each year the seven activities discussed in this section will add $183 million to the cost of operations on the OCS. For purposes of calculating23 

### annual costs associated with this rule, we assume that in an av erage year operato rs will drill 160 deepwater wells and 186 shallow wells on the fede ral OCS as well as complete 17 workover and completion operations on successful (wet) exploratory wells.



## Seafloor Function Testing of RO V Intervention and Deadman Systems - Drilling
Current regulations at 30 CFR 250.449(b) require a stump test of the subsea BOP system. In a stump test, the subsea BOP system is placed on a simulated wellhead (the stump) on the rig floor. The BOP system is tested on the stump to ensure the BOP is functioning properly. New
section § 

### 250.449 (j) requires that all ROV interventi on functions on the subsea BOP stack must be tested during the stump test and one set of ra ms must be tested by an ROV on the seafloor.
New section § 

### 250.449 (k) requires that the au toshear and deadman syst ems be function tested during the stump test, and the deadman system test ed during the initial test on the seafloor. The initial test on the seafloor is performed as s oon as the BOP is attached to the subsea wellhead.

BOEMRE assumes it is industry standard to have ROVs on boar d. 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 mee ting this requirement, therefore we reasonably assume all rigs have ROVs. BOEMRE also assumes dynamically positioned rigs have autoshear/deadman systems. BOEMRE has data showing that all dynami cally 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 auto shear/deadman system.

These new requirements will confirm that a well will be secured in an emergency situation and prevent a possible loss of well c ontrol. Autoshear and deadman control systems activate during an accidental disconnect or loss of power respec tively. The ROV test requirement will ensure that the dedicated ROV has the capacity to close a BOP ram on the sea floor. The deadmanswitch test on the seafloor verifies that the well bore closes automa tically if both hydraulic pressure and electrical communi cation are lost with the rig.

BOEMRE conducted a survey to investigate the pot ential impact of subsea ROV testing. Several drilling contractors, lease opera tors and equipment manufacturers were asked: “How long would it take to function test the ROV to verify that the ROV could be used to close one set of blindshear rams, one set of pipe rams, and disconnect the LMRP?” Results averaged about 24 hours of lost rig time to perform these subsea tests.24 

### However, the interim regulation only requires one set of rams and the deadman system to be tested on the seafloor; not two rams (one pipe ram/one blind-shear ram) nor disconnecting the LMRP. Although the 24 hour survey average is an overestimate based on th e interim regulations, the additional stump testing requirements and the deadman system seafloor tests are estimated to
take about the same amount of time as the extra ram test and LMRP disconnect. 6 

### Using the additional stump tests and deadman seafloor test as a proxy for the extra ram test and LMRP disconnect, BOEMRE maintains the 24 hours of lost rig time for costing purposes. The regulation will not affect platform rigs or shallow wells since they do not use subsea BOPs or
ROVs.

Multiplying the number of estimated MODU wells each year (112) by the weighted average day rate ($916,622) yields a total estimated compliance cost for this provision of $102.66 million

. Table 2 reports the number of the various kinds of deepwater drilling rigs operating in the Gulf of Mexico and the rig (day) rate s used to calculate the cost of the extra 24 hour added to drill time. The rig rate was taken from RIGzone and in creased (loaded) to reflect the assumed cost of the assorted support contractors on the rig whose services are not covered in the day rate. The loaded day rate is appropriate because BOP and negative pressure tests for intermediate casings cannot be scheduled with accuracy and occur in the middle of the drilling operations. The
subsea BOP is not lowered to the seafloor until after the surface casi ngs are set (maybe 10-30 days into the drilling) when the increased down-hole pressure and risks for gas kicks and blowouts are possible. Most deepwater wells are drilled more than 100 miles offshore and contractors and supplies that cont ribute to the loading of the da y rate are contracted for the duration of the drilling operation. Part of the r eason that crews stay on the rig for 2 weeks at a time is that round trips to shore are expensive, so “unloading” a nd “reloading” for a day is likely to cost more than maintaining capability at th e ready. Additionally, de lays and problems occur frequently during drilling operations and it is standard practice to maintain the contractor and company capability available to resume operations as soon as the problem is resolved.

6 The ROV stump test components are not considered becaus e they are not expected to significantly increase testing time. Some operators simulate the hydraulic flow of an ROV to perform the stump test on the BOP stack, while others use an actual ROV to stump test the BOP stack; this regulation removes the option of simulating hydraulic flow and require the use of an ROV during the stump test.25 Table 2

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

Drillship 11 $1,000,000 33

Deep Semisubmersible 21 $923,953 63

Low Semisubmersible 4 $715,792 16

MODU Total or Weighted
Average 36 $916,622 112

Platform 10 $400,000 48



## Seafloor Function Testing of ROV Intervention and Deadman Systems – Workover/Completions
Current regulations do not require subsea ROV f unction testing of the BOP during workover or completions operations. New sections 250.516(d )(8) and 250.616(h)(1) requi re testing of ROV
intervention functions and the autoshear/deadman systems during the stump test, and a function
test of at least one set of rams and the deadma n system on the seafloor. These sections extend the requirements added to deepwater drilling operations (discussed in the previous section) to well completion operations and workover operations using a subsea BOP stack. Successful exploratory wells are typically temporarily aband oned until additional equipment is installed to produce the reservoir. When the operator is pr eparing to produce the well it is often completed using a different rig or redeployment of the or iginal rig. This testing time for completion operations is estimated to also be 24 hours. Th is is in addition to th e 24 hours testing time discussed in the previous secti on for selected wells. BOEMRE data shows that two-thirds of deepwater wells drilled are exploratory wells, an d approximately 23% of exploratory wells are completed. Using our estimate of 112 MODU wells each year results in an additional 17 subsea BOP tests from workover and completions opera tions. Using a weighted average of MODU day rates from Table 2, 17 redeployments of a BOP will cost $15.47 million

. 

## Negative Pressure Tests
Section 30 CFR 250.423 currently requires a positive pressure test for each string of casing, except for the drive or structural casing string. This test confirms that fluid from the casing string is not flowing into the formation. New section § 

### 250.423 (c) requires that a negative pressure test be conducted for all intermediate and production casing strings. This test will reveal whether gas or fluid from outside the casi ng 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 cas ing and cement. While some companies conduct26 

### negative pressure tests on selected casing strings as a best practice, we do not have the data available in an easily accessible da tabase to determine the frequency at which this occurs. Based on typical industry procedures, we estimate each new negative pressure test will take approximately 90 minutes for each casing string. We also estimate that on average deepwater wells use one production and four intermedia te casing strings and shallow wells use one production and two intermediate casing strings.

Ninety minutes is equivalent to 0.0625 days. Using the weighted average of the MODU day rates in Table 2, and a platform day rate of $400,000, 0.0625 days times 5 casing strings times 112 MODU wells and 48 platform wells yields an annual average additional costs in deepwater
for this test of $38.08 million . A loaded day rate of $200,000 for a shallow water rig (jackup) times 0.0625 days times 3 casing strings for each of 186 wells adds another $6.975 million to the extra cost for the universal requirement for the negative pressure test.



## Installation of Dual Mechanical Barriers
Current regulations do not requir e the installation of dual mechanical barriers although this requirement can be considered the use of best available and safety technology (BAST) per § 250.107(d). For this benefit-cost analysis this requirement is considered new because the government had not previously specified this technology in the regulations. New regulatory
section § 

### 250.420 (b)(3) requires the operator install dual mechanical barriers in addition to cement barriers for the final casing string. Thes e barriers prevent hydrocar bon flow in the event
of cement failure at the bottom of the well. Th e operator must document the installation of the
dual mechanical barriers and submit this doc umentation to BOEMRE within 30 days after installation. These new requireme nts will ensure that the best casing and cementing design will be used for a specific well. Dual mechanical ba rriers may include two float valves, or one float valve and one mechanical plug. Based on in-house expertise, BOEMRE estimates that all wells will require a second mechanical barrier. We estimate an average cost of $20,000 for each

mechanical barrier and 30 mi nutes of installation time.

For the 112 MODU wells each year , these parameters yield $2.24 million for the barriers (112 times $0.02 million) plus [2.08% of a day (half hour divided by 24 hours) times the weighted average day rate from Table 2 times 112 wells] $2.14 million in installation costs. Similar calculations for 48 platform and 186 shallow water wells yields a total annual compliance cost of $10.3 million for this requirement.



## Professional Engineer Certification for Well Design
Current regulation 30 CFR 250.420(a) specifies well casing and cementing requirements but does not require verification by a Professiona l Engineer although ve rification could be
considered the use of best available and safety technology (BAST) per § 250.107(d). New27 

### regulatory section § 

### 250.420 (a)(6) requires that well casing and cementing specifications must be certified by a Professional Engine er. The Professional Engineer wi ll verify that the well casing and cementing design is appropria te for the purpose for which it is intended under expected
wellbore conditions. This verification will add assu rance that the appropriate design is used for the well thus decreasing the like lihood of a blowout. We assume that many of the larger companies will verify the well design using in-house expertise for little or no extra cost. Other companies will hire a third-party professional engineering firm. Since a majority of deepwater leases are owned by large entities, BOEMRE assumes that 50% of future deepwater wells and all shallow water wells will incur an additional cost for a third party professional engineer certification of the well design. Based on an info rmal survey of drilli ng contractors and lease operators, BOEMRE estimates that the extern al certifications w ill cost about $22,500 each.

For MODU wells, those parameters yield $1.26 million (112 times 50% times $0.0225 million), for platform wells $0.540 million , and for shallow water wells $4.185 million

. 

## Retrieval and Testing of a BOP St ack After a Well Control Situation
Current regulations do not specifically address BOP inspection following use of the blind-shear ram or casing shear ram, although a prudent opera tor would tend to conduct such an inspection to meet the regulatory standard for BOPs. Surface inspection following shear ram activation may not have been enforced by the government or conducted by the entire industry absent a more specific regulatory requiremen t; therefore this analysis considers the surface inspection to be a new cost. New regulation § 

### 250.451(i) requires that if a blind- shear ram or casing shear ram is activated in a well control situation where the pipe is sheared, the BOP stack must be retrieved, fully inspected and tested. This provisi on will ensure the integrity of the BOP and that the BOP will still function and hold pressure after the event. This activity, when triggered, will add about 13 days to drilling time. A ccording to a Det Norske Veritas study 7 

### , out of 5,611 deepwater wells, there were 12 situations where either the blind-shear or casing shear ram was activated; this implies on e activation for every 515 wells dri lled. We estimate 112 wells drilled per year from drillships or semisubmersibles ; therefore we expect 0.22 (112/515) relevant activities per year for costing pur poses. At the day rates quoted in Table 2, 13 days times a 22% annual chance of occurrence yields $2.61 million expected annual compliance cost for this provision.



## Third Party Certification of Shear Ram Capability
Section 30 CFR 250.416(e) require s information verifying that BOP blind-shear rams are capable of cutting through any dri ll pipe in the hole under maximum anticipated conditions. This regulation has been modified to require the BOP verification be conduc ted by an independent

7 Det Norske Veritas. Beaufort Sea Drilling Risk Study

. March 11, 2010.28 

### third party. The independent third party provid es an objective assessment that the blind-shear rams can shear any drill pipe in the hole if the shear rams are functioning properly. This confirmation will be required for both subsea an d surface BOPs, thereby adding a small cost to each well drilled. While these standards are not a new regulatory requirement, independent
verification and submission of th at verification was apparently not enforced by the government; therefore this analysis consider s the independent verification to be a new cost. Based on inhouse expert judgment, we assume this will add $3,250 to the cost of each well. Applied to 346 wells per year, this yields a compliance cost estimate of $1.1245 million for this provision.



## Summary of Annual Recurring Costs

Table 3 summarizes the cost estimates for these recurring cost categories for three subgroups of wells affected by the new regulations.

Table 3

– Estimated Recurring Cost Summary

MODU Wells (112/yr) Fixed
Platforms

(48/yr) Shallow
Wells (186/yr) Cost
Shares Regulation Recurring Costs:

Total ($MM) Total ($MM) Total ($MM)

250.449(j)(k) Subsea ROV function testing (drilling) 102.7 0.0 0.0 56%

250.516(d)(8), 250.616(h)(1) Subsea ROV function testing (workover/completions) 15.5 0.0 0.0 8%

250.423(c) Test casing strings for proper
installation 32.1 6.0 7.0 25%

250.420(b)(3) Installation of dual mechanical
barriers 4.4 1.4 4.5 6%

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

250.451(i)(j) Emergency cost of activated shear
rams or LMRP disconnect 2.6 0.0 0.0 1%

250.416(e) Independent third party shear
certification 0.4 0.2 0.6 1%

Estimated Cost per year: 158.8 8.1 16.3 $ 183.1

Estimated Cost per well: 1.42 0.17 0.0929 

### The regulations impact well costs differently de pending on the category of drilling rig and type of well being drilled. As can be observed in Table 3, deepwater wells drilled by platform rigs and shallow wells drilled by jackups will incur lo wer incremental costs, primarily because they use surface BOPs while wells drilled by MODU’s (drillships and semisubmersibles) will incur the greater incremental cost due to the new subsea BOP requirements.



## Voluntary Measures by Industry Some part of the roughly $183 in annual compliance cost total may not be rightfully assigned to the regulation as industry is undertaking a numbe r of steps following the BPDH event that may overlap those in this regulation. An indepe ndent analysis by Industr ial Economics Inc. (See Appendix E) indicates overlap exists for the me chanical barriers and negative pressure test provisions. However, these actions by indus try are voluntary and, as such, not subject to enforcement. For these reasons, we have not ad justed the compliance co st estimate to account for these potential actions, but acknowledge that our cost estimate may overstate compliance
costs for this reason.



## AVOIDED PRIVATE-SOCIAL COSTS

The objective of this section is to describe the avoided private-social costs resulting from a catastrophic oil spill in the Gulf of Mexico. Priv ate-social costs as define d in this analysis are the costs incurred by the lessees and operator co ntractors based on the actual property loss and containment costs emerging from a catastrophi c blowout on their rig and OCS lease. The avoided private-social costs include damage to the drilling rig, costs for containment and plugging of the blowout well and the value of hydro carbons lost as a result of a blowout spill. Costs for clean-up of spil led oil are considered external-social costs in this analysis since they
are incurred off the lease and are focused on m itigating the external costs to society from a catastrophic blowout event. Estim ates of external-social costs are provided in the section on
Avoided External-Social Costs. The combinati on of private-social co sts and external-social costs equal the social avoided 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 se misubmersible drilling rigs reportedly cost about $560 million and a drillship $750 million. In addition to the BPDH event where the drilling rig sank, there is only one other deepwater blowout event with rig damage and fatalities. This blowout occurred on September, 1984 in Green Canyon, Conoco (Zapata Lexington Drilling Rig). Salient points of that event include:30 

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

• While the blowout bridged (i.e., closed off on its own by cave in or material falling in the well bore) and did not spill oil, the explos ion did cause $15 million of damage to the drilling rig.

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

For a prospective catastrophic blowout event, BO EMRE 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 8 

### ) and the cost of a new drillship ($750 million 9 

### ). We take this as the expected loss if the rig is destroyed. Additionally, we assume there is an equal likelihood of damaging but not sinking the rig, with resulting damage estimated at $26 million ($15m in 1984$ from the Zapata Lexington rig accident, infl ated to 2010$). The calculation used to estimate the expected damage/lo ss of the drilling ri g per catastrophic spi ll 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 pr ovided by the North America BP Investor Relations desk on July 23, 2010 for the BPDH event. In a phone call, BP stated the company had spent a total of $4.3 billion through July 22, 2010 whic h is approximately 90 days af ter the explosion. Of the $4.3 billion, $200 million had been spent on the tw o relief wells and $900 million on other source control efforts (e.g., failed ROV intervention effo rts, containment structures, etc.). BOEMRE
assumes that while the oil will flow for 90 da ys 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 extr apolated to 120 days yields $1.467 billion per catastrophic spill event

. 

## Hydrocarbon Losses
In addition to the well containment efforts, privat e-social costs include the market value of the lost oil and gas as a result of an uncontrol led blowout event. BOEMRE assumes that a deepwater well that has suffered an uncontrolled blowout would flow 53,000 barrels of oil a day

8 May 4, 2010, The replacement cost of the Deepwater Horizon is estimated at $560 million. http://www.nytimes.com/gwire/2010/05/ 04/04greenwire-warnings- on-backup-systems-for-o il-rigs-sounde-30452.html

9 Total capital costs to be incurre d for the construction of the drills hip are estimated to be $750 million http://www.redorbit.com/news/business/1446 859/transocean_inc_announces_a greement_to_acquire_newbu ild_ultradeepwater_drillship_u nder/in dex.html31 

### for 90 days. This equates to 4.77 million barrels of oil spilled 10 

### . While some oil may be captured through various skimming systems, the overw helming 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 mode st size of the hypothetical extrac tion costs of the lost oil. Accordingly, assuming a market oil price of $70/barre l, the value of lost crude oil is estimated to
be $334 million

.

In the deepwater Gulf of Mexico oil averages 80 percent and natural gas the other 20 percent of hydrocarbon production on a BOE basis. If the oil spilled is 4.77 million barrels, associated natural gas would be another 1.19 million BO E or 6.92 million MMBtu, implying a total of 5.96
million BOE is lost 11 

### . For computing the value of lost na tural gas, BOEMRE estimates a market value of $4.00/MMBtu for a tota l lost value of almost $28 million

.



## Fines and Criminal Penalties
The Clean Water Act provides for fi nes against the responsible part y for an oil spill. In the context of benefit-cost analysis, fines and othe r penalties not specifically for natural resource damages or other social costs in curred by society are considered “transfer payments.” These transfer payments simply move funds from the responsible party to the government. Transfer payments do not involve real reso urce costs and are therefore ex cluded from the avoided benefitcost estimate for this rulemaking.



## Summary of Avoided Private-Social Costs
Table 4 summarizes the avoided private costs estima ted for this analysis, stated in 2010 dollars. Note that only about one-sixth of the private cost total is from lost hydrocarbon values which the lessees would have realized had the spill not occurred.

10 See footnote number.

11 5.8 MMBtu per BOE.32 Table 4 ‐ Summary of Estimated Avoided Private

‐ Social Costs 

### Private-Social Cost Estimated Value Damage/loss of Drilling Rig 338,000,000 Well Containment, 120 days 1,466,666,667 Lost Crude Oil, 4.77 million barrels 333,900,000 Lost Natural Gas, 6.92 million MMBtu 27,666,000 Total: $2,166,232,667



## AVOIDED EXTERNAL-SOCIAL COSTS

This section evaluates (in quant itative terms where possible) th e 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 exte rnal-social costs estimated in this section are combined with the estimated private-social cost s summarized in the table above to provide the estimate ($16.3 billion) of avoided social costs (benefits) used in this analysis. External-Social costs associated with oil spills may include loss of property value, natural resource damages, health effects, litigation costs, non-use values, loss of consumer surplus from recreational users, loss of producer surplus from commercial fishin g or shell-fishing businesses, welfare effects associated with price changes in seafood markets, operational disruptions at marinas, commercial ports, or Naval facilities, temporary or permanen t displacements of families or businesses, and reduction of supply of water fo r certain industrial purposes. 12



### The main categories of external-social costs consid ered 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 focu ses on these categories of avoided social costs because information appropriate to a benefit-cost analysis is readily avai lable to estimate their magnitude from studies and historical data. Reca ll that costs for the containment and the killing

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

‐ water fed
desalination plant located in Tampa Bay, and one planned for San Antonio.33 

### of an uncontrollably flowing well, damage to drilling equipment from a blowout, and lost hydrocarbons have already been discussed in the section on External-Private Costs.

Three main factors affect the economic value of th e avoided external-social costs of an oil spill: the spill’s location, the time of year it occurs, and the type of oil spilled. Spill location and timing affect all categories of costs. Spills near locations with sensitive biota, significant fishery resources or recreational areas, or in locations wh ere 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 deep water biota. Timing also has situation-specific effects. A spill occurring near bird habitats during nesting or breeding season might be associated with greater natural resource damages, while a spill occurring near a shrimp fishery during harvesting season would be associated with larger fishery-related costs.

The specific type of oil affects the amount of cleanup needed and the amount of natural resource damages incurred. Light oils naturally dissi pate and evaporate quickly—requiring minimal cleanup—but are highly toxic and cr eate severe environmental impacts. Heavy oils do not evaporate, and therefore may require intensive st ructural and shoreline cleanup. While they are less toxic than light oils, heavy oils can harm waterfowl and fur-bearing mammals through coating and ingestion. Each spill’ s cost reflects the particular mi x of these factors, and no factor is clearly predictive of the outcome.



## Conceptual Approach
Typically, the external-social co st of damages to natural reso urces, fisheries and recreational
areas is evaluated after a spill has occurred and subsequent to the completion of response activities. This evaluation includes collecting data that allow assessing th e nature and extent of the damages (both spatially and ove r time) to all of the impacted resources relative to the prespill baseline and then, where possible, monetizing the damages using economic techniques designed to value resources that are not typically bought and sold in markets. In concept, damages include use and non-use values, for exampl e, both the value of a trip to the beach now and the value of being able to take such a trip in the future.

For the proposed regulation, this level of info rmation is not readily available. Baseline information such as the number, timing, duration, and location of potentia l spills during the period of analysis are not known. In addition, while baseline projections for the number of future deepwater wells drilled are assumed for th is benefit-cost analysis , it is not possible to forecast the timing, magnitude, duration, and traject ory of future spills. This introduces a considerable degree of uncertainty into estimate s of the value of the avoided costs associated with the proposed regulation. The analysis addresses this unc ertainty by providing a range of34 

### values associated with different categories of avoided costs, and reporti ng averages or most likely values to determine point estimates for calculations.

Given the limited information available to eval uate the avoided natural resource costs, the technique used in this analysis falls into the cate gory of “benefit transfer.” This technique can be implemented in a variety of ways, ranging from simply transferring values from sufficiently similar studies, to adapting willingness-to-pay functions for new site-specific changes in environmental conditions, prices, and other values. In situations where time or resources do not permit extensive data collection or primary res earch, benefit transfer may be an appropriate technique for evaluating the magnitude of econom ic benefits. There are many caveats that accompany use of this approach, the most importa nt perhaps being the extent to which the study site/situation is similar to the study from wh ich the values are to be transferred.

As discussed in the Baseline section of this an alysis, BOEMRE estimated the probability of a catastrophic spill based on the history of deepwate r blowout events and the resulting spills on the Federal outer continental shelf (OCS).

The BOEMRE estimates that about 160 new deep water wells will be drilled annually over the
next several decades. BOEMRE also assumes that the baseline scenario includes one catastrophic deepwater spill every 26 years, with the probability of a spill in any given year during the period of analysis being 3.85%. In th is analysis, the hypothetica l spill is assumed to be 4.77 million barrels of oil. The analysis does not assume a specific grade of crude oil for future spills, although oil from a deepwater GOM blowout would likely be a sour light crude typical in the GOM. The type of oil spilled affects spill dispersion and clean-up costs.



## Valuing Natural Resource Damages

The avoided costs for natural resource dama ges depend on the particular circumstances associated with an oil spill. Natural resource damages from prior oil spills (excluding the BPDH spill) were used to inform the cost-benefit analys is 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 settle ments associated with these even ts. For the purposes of this benefit-cost analysis, the values contained in the legal settleme nt documents represent the best
source of available information on the moneta ry value of the natu ral resource damages associated with coastal oil spills. Settlement amounts reflect compromise s based on factors other than the actual amount of damages, such as litigati on risk with respect to legal issues in the case or the ability of parties to support protract ed, complex litigation. Further, although this information is useful for the purpose of a bene fit-cost analysis, it should not be relied on to35 

### determine the amount of natural resource damage s associated with any particular oil spill, including the BPDH spill.

The dataset includes 62 coastal spills, none of whic h occurred a significant distance offshore. While vessel-related spills have previously occurre d offshore, primarily in foreign waters, there is little information available on the associated natural resource damages. Similarly, little
information is available on natural resource da mages associated with blowouts occurring in foreign waters. Information on the spills containe d 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-barre l 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 co sts in the dataset, with the majority of spills below $10 million, and a la rge number below $1 million;

• Figure 5 shows a histogram of claims request ed and claims paid out by the U.S. Coast
Guard from the National Pollution Trust F und. The majority of these are below $10,000 per claim; many are below $1,000 per claim.

Figure 2. Distribution of Dataset Spills by Response Costs per Barrel ($2009)36 Figure 3. Distribution of Spills, by NRD + Assessment Cost per Barrel ($2009)

Figure 4. Distribution of Spills, by Total Spill Costs ($2009)37 Figure 5. Oil Spill Liability Trust Fund Claims Requested and Paid (Sep 1972

‐ Feb 2010)



### The 62-spill dataset is charac terized by a wide range of vol umes spilled (24 to 262,000 barrels) as well as a wide range of per-barrel natu ral resource damages ($7 to $76,000 per barrel). 13 

### The vast majority of the spills were 10,000 barrels or less. As stated, this data set does not include the BPDH spill. For the 62 spills, the average m onetary value of the natural resource damages (including assessment costs) was about $3,700 per barrel, the median sp ill was about $850 per barrel, and the standard deviation was about $11 ,300 per barrel. The per-barrel damage values are related to both spill si ze and type of hydrocarbon.

Of the 62 spills, 10 spills occurr ed in the Gulf region. Natura l resource damages (including assessment costs) for the Gulf spills range fr om $49 to $1,287 per barrel (in 2010 dollars), with an average of $456, per barrel, a median of $244 pe r barrel, and a standard deviation of $470 per barrel. For this analysis of a hypothetical catastro phic oil spill, we selected seven Gulf spills that appear most germane. Summary information on these seven spills is reported in Table 5. The average damages across these spills were $604/bbl, which is used as a conservative estimate for our avoided cost calculations. The Ocean 255 spi ll was highest-damage Gulf spill prior to April 2010, and the only non-crude oil spill in the Gulf data.

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

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

‐ per

‐ barrel damages.38 

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

Table 5 Seven Gulf Coast Spills: Natural Resource Damages


### Event Volume spilled (bbls) NRD+Assessement Costs $/bbl $2010 Injured Resources

OCEAN 255/B155/BALSA 37 Spill 8,619 1,287 366 birds, 2117 sea turtles, 5.5 acres mangroves, 255 acres seagrasses, 0.85 acres salt marshes, 0.22 acres oyster beds, 20 linear miles seawalls, surface waters, 1.34 acres bottom sediments and 39,827 cubic yards of oiled sands (13 linear miles) Blake IV and Greenhill Petroleum Corp. Well 25 2,905 1,122 Intertidal marshes, marine and estuarine fish, bottom dwelling species, birds, sediments Equinox Cockrell-Moran #176 well 1,500 891 1,221 acres saltmarshes, Birds/Wildlife, 12 acres mangroves, 21 acres subtidal sediments, recreational activities Chevron BLDSU #5, West Bay Field 262 346 200 Acres Fresh Water Marsh Vegetation, Birds/Wildlife Ocean Energy/Devon Energy North Pass Storage Facility 300 424 120 acres freshwater marsh

Texaco Pipeline Company Lake Barre oil spill 6,548 109 4,237 acres of marshes, 7,465 finfish and shellfish, 333 birds, M/VWestchester 13,095 49 Oiled shoreline and surface waters; lost recreational use of the Mississippi River. Average per Event 60439 

### Caveats and Assumptions The analysis includes the follo wing caveats and assumptions:

• The estimate of natural resource damages from the table above, while a useful tool for the purpose of this cost-benefit exercise, is not to relevant in calcu lating damages for any particular oil spill, including the BPDH spill.

• For the purposes of this exercise, it is assu med that the average natural resource damage value for Gulf cases per barrel spilled, equal to $604 from the table above, is a reasonable approximation of the value of avoided natura l resource damages for a spill significantly larger than the cases contained in the datase t of natural resource damage cases. It is worth noting, however, that a future catastr ophic spill could result in a significantly higher natural resource damage value per barr el spilled, depending on the circumstances. In the Exxon Valdez oil spill, which resulted in a release of 261,905 barr els of oil, natural resource damages plus assessment costs aver aged $5,005 per barrel (2 009 dollars). See Appendix A.

• Total damages for a given hypothetical event are a linear function of the amount spilled.

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

• The injured resources for the cases in the da taset are similar to the resources potentially damaged from a large Gulf spill in the future.

• This analysis translates estimated avoided costs into dollar-per-barrel values. This metric
is useful because barrels are a common meas ure of spill volume. However, the wide variation in social spill costs across events is noted. In short, the damages ultimately depend on the characteristics of an individual sp ill as noted earlier in the reference to the Exxon Valdez spill.



## Relationship between Natural Res ource Damages and Spill Size and Type of Oil Spilled
Similar to previous analysis by Dunford and Fr eeman (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 analys is used the log of natural reso urce damage and assessment costs (in $/barrel) as the dependent variable. Independ ent (explanatory) variable s included the type of oil spilled (with dummy variables included for cr ude, diesel and gasoline), a time trend, the log of the volume of oil spilled (in barrels), and a du mmy variable indicating if the oil spill occurred in California. The regression results explain a reasonable amount of variation in the sample; however, the predictive ability of th e model appears to be better fo r small size spills. The model is able to predict costs for smaller spills in the sample reasonably well, although predictions of larger spills in the sample result in smaller valu es than expected. Based on the historic spill data40 

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



## Valuing Commercial Fishery Losses
Commercial fishing as an industr y must be differentiated from ot her types of fishing, such as recreation, “subsistence” consumption, or info rmal sale. One appr oach to calculating commercial fishing profits 14 

### requires tallying revenue earne d by industry operators, and subtracting operating costs. Oper ating costs include labor costs, such as wages for harvesting and processing; and non-labor costs such as fuel and supplies.

The commercial fishing industry in cludes various species of aquatic life (shrimp, crabs, oysters, finfish) and types of economic ac tivity (fishermen, processors/clean ers, dealers, marinas, support facilities). Impacts to the industry from an oil sp ill can be expected to a ffect 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 pub lic reluctance to consume fish from the region. This approach for assessing damages related to an oil spill requires iden tifying changes in catch rates, prices, fishing areas, and methods employed.



## Data Availability

Background
The Gulf States include, from West to East, Texa s, Louisiana, Mississippi, Alabama and Florida. The region’s shrimp landings are the nation’s largest: 188.3 million pounds, for 73 percent of the national total (Fisheries of the United States 2008). The region landed approximately 30 percent of the total blue crabs for the nation (48.7 million pounds) in 2008. The Gulf region leads the nation in the production of oysters, some 67 percent of the nation’s total.

Gulf fishery total landings (in pounds) and the revenues from those landings have tended to fall over the past decade, as shown in Figure 6. Prices do not appear to contribute to the decline in revenues. For the top ten commercial species, which together account for over 96 percent of

14 We use producers’ profits as a proxy for producer surplus.41 

### annual harvests, prices show no steady downward tr end in Figure 7, while la ndings of all species show moderate declines in Figure 8.

Figure 6 Gulf State Landings and Revenue, 1999

‐ 2008 (2009$) Note: Data include landings for Florid a’s Gulf coast and Atlantic coast.
Source: NMFS Fisheries Economic s of the United States 2008.

$0 $2 $4 $6

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2 0 0 9 $ p e r L b Crab, Stone

Tunas

Snapper, Red

Oyster

Groupers

Shrimp

Crawfish

Crab, Blue

Mullets

Menhaden

Figure 7 Average Annual Price per Pound (2009$)
Source: NMFS Fisheries Economic s of the United States 2008.42 1 10 100 1,000 10,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 L a n d i n g s ( M i l l i o n L b s ) Menhaden

Shrimp

Crab, Blue

Oyster

Mullets

Groupers

Crab, Stone

Snapper, Red

Tunas

Crawfish

Figure 8 Gulf State Landings, 1999

‐ 2008 (mmlbs) Notes: Data include landings for Florida’s Gulf coast and Atlantic coast. Crawfish landings for 2000 totaled 393,000 lbs.
Source: NMFS Fisheries Economic s 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 de cline since the 1980s and may not be a good
indicator of the overall commerci al fishing industry in the Gu lf. Louisiana accounts for about 50% of Gulf Coast shrimp landings. By 2007 resi dent shrimping licenses in Louisiana had fallen
to less than one-third of their 1989 value, as shown in Figure 9.43 Figure 9 Resident Louisiana Shrimping Licenses (Trawl, Butterfly Net, and Skimmer Net)

Source: Louisiana Department of Wildlife and Fisheries



### Revenues
In calculating producer surplus, we estimated gr oss revenues using the gr oss value of landings, multiplying pounds of fish landed by the wholesale price for that fish. The National Oceanic and Atmospheric Administration ( NOAA) provides summary data on the value of commercial
fisheries in the Gulf of Mexi co, as shown in Table 6.44 Table 6 Gulf of Mexico Commercial Fisheries Data, 2008 

### Texas Louisiana Mississippi Alabama West Florida Total

Shrimp Volume (million lbs) 63.9 89.0 8.6 17.2 9.9 188.5 Value (million $) 157.1 130.3 17.1 38.4 23.3 366.3 Crabs (Blue crabs) Volume (million lbs) 2.3 39.8 0.5 1.8 2.6 47.3 Value (million $) 2.6 31.1 1.0 1.5 3.3 38.7 Oysters Volume (million lbs) 2.7 12.6 2.6 0.7 2.4 20.4 Value (million $) 8.8 38.2 6.9 0.1 5.3 59.5 Finfish (and other) Volume (million lbs) 3.7 759.3 190.2 5.4 34.7 993.4 Value (million $) 7.7 64.0 19.2 4.1 50.5 145.6

Source: NOAA Fisheries Economics of the U.S.

These data were accessed on

‐ line at http://www.st.nmfs.noaa.gov/st5/public ation/fisheries_economics_2008.html#



### NOAA’s National Marine Fisheries Service (NMFS) data on weights and values of landings exhibit strong seasonality: Figure 10 and Figur e 11 show a pronounced peak in each State’s landings during one or two summ er months each year; Figure 12 and Figure 13 show revenues by State during the summer months. This seasonal ity indicates that the timing of closures and population impacts should be consider ed in an analysis of oil spil l damages. The seasonality is also rather stable, 15 

### suggesting that reasonable future mont hly harvest values might be inferred from the data. We used the early summer m onths which correspond to the high revenue season for convenience rather than employing more sophisti cated assumptions to reflect the seasonality.
This choice deviates from our usual practice of using conser vative assumptions to generate avoided social costs, but the values involved are so small relative to other social costs that further efforts in this regard do not appear warranted.

15 Within

‐ month coefficients of variation for May, June, July and August are below 0.45 for all five Gulf States over 1997 through 2008, and below 0.37 outside of Mississippi. The variation is lower still (outside of Mississippi) for

2002 through 2008: below 0.26 for all months.45 0 5 10 15 20 25

M i l l i o n l b

Texas

Florida, West

Alabama

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

0 50 100 150 200 250 300 350

M i l l i o n l b

Louisiana

Mississippi

Figure 11 Monthly Commercial Fishery Landings (Louisiana, Mississippi)46 $0 $5 $10 $15 $20

M i l l i o n ( 2 0 0 9 $ )

Florida, West

Mississippi

Alabama

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

$0 $20 $40 $60 $80

M i l l i o n ( 2 0 0 9 $ )

Louisiana

Texas



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

Baseline monthly landings values were estimated separately for each month of 2010 by sorting the 2002-2008 data by month, and finding the monthl y trend for each State using ordinary least squares. These values are reported in Table 7.47 Table 7 Estimated 2010 Baseline Values for Gulf State Commercial Fisheries ($ millions, trend 2002

‐ 2008) 

### Texas Louisiana Mississippi Alabama West Florida May $12.0 $29.8 $0.9 $2.5 $8.5

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

Operating Costs

Liese et al. (2009) performed a cash-fl ow analysis based on a sa mple 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 spanni ng -$4,138 to +$9,446. This wide confidence interval, which includes zero, suggests that while the average vessel may be earning positive net revenues, there are at least some vessels that are earning negative ne t revenues. This was observed in spite of the fact that “the e ffective economic environment actually improved somewhat from 2006 as shrimp prices increased proportionally more than fuel prices. However, with the liquidity constraint implied by a nega tive cash flow and followi ng many marginal years, it seems the average vessel simply did not have th e ability to exploit this improvement and had to cut its overall effort (Liese et al. 2009).

Travis and Griffin (2004) had pr edicted the improvement noted by Liese in a simulation that assumed that variable costs as a percentage of revenues would fall for Gulf commercial shrimping. Their assumptions are given in Table 8.

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



### 2002 2007 2010-2018 (lowest-cost period) Large Vessels (at least 60 feet long) 98% 78% 75% Small Vessels (<60 feet long) 114% 96% 93%

Liese’s 2007 survey results can be used to make some inferences about how the Gulf fleet is divided between “large” and “small” vessels. Th ey found 12% of the fleet was less than 50 feet long, and 56% of the fleet was more than 75 feet long. For the 31% of the sample that was 50 to 75 feet long, the average length was 65 feet. We assume that vessels are evenly distributed by size within this category, so that half the vessels (16 percent of the fleet) are longer than 65 feet.
Of the 16% of vessels that are 50 to 65 feet long, two-thirds of th e vessels are 50 to 60 feet long,48 

### and one-third of the vessels are 60 to 65 feet long. Tallying the proportions below 60 feet indicates that 23 percent of th e fleet consists of “small” ve ssels (by Travis and Griffin’s definition), while 77% of the fleet consists of “l arge” vessels. These results are summarized in Table 9, where the same approach is used to apportion the total fleet shrimp landings and landings revenue.

Table 9 Gulf Shrimping Fleet: Large and Small Vessels



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

< 50 feet 50 feet to
60 feet 60 feet to
65 feet 65 feet to
75 feet > 75 feet < 60 feet >= 60
feet
% of
Fleet
Vessels 12% 10% 5% 16% 56% 23% 77%

% of
Fleet Shrimp Landings 4% 10% 5% 15% 66% 14% 86%
% of
Fleet Landings
Revenue 3% 9% 5% 14% 69% 12% 87% *A small percentage (0.2 percent) of the landings revenue is from non-shrimp landings.

As shown in Table 9, the smallest vessels in Lies e’s survey (those less th an 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 receiv e 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 fl eet, but bring in 66% of the la ndings, and receive 69% of the landings revenue. We preserve this imbalance when we switch to the 60-foot designation for “large” vessels.

The proportions of Gulf commercial shrimp landi ng revenues going to large and small vessels is combined with the baseline revenue projections in Table 7 to determine the contribution of each
vessel class to baseline revenues for the entire commercial fishing industry (see Table 10). We then apply the assumptions from Travis and Gri ffin (2004) about variable costs as a percentage49 

### of revenues to determine baseline profits accruing to each vessel class (see Table 11). Finally, in Table 12 the results for large and small vessels ar e summed together to find the 2010 baseline for total industry pr ofits by month.

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

### Vessels Texas Louisiana Mississippi Alabama West Florida May Fleet $12.0 $29.8 $0.9 $2.5 $8.5 Large $9.2 $22.9 $0.7 $1.9 $6.5 Small $2.8 $6.9 $0.2 $0.6 $2.0
June Fleet $11.7 $43.6 $6.5 $7.6 $7.2 Large $9.0 $33.6 $5.0 $5.9 $5.5 Small $2.7 $10.0 $1.5 $1.7 $1.7 July Fleet $23.2 $29.3 $6.6 $6.4 $5.8 Large $17.9 $22.6 $5.1 $4.9 $4.5 Small $5.3 $6.7 $1.5 $1.5 $1.3

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

### Vessels Texas Louisiana Mississippi Alabama West Florida May Large $2.3 $5.7 $0.2 $0.5 $1.6 Small $0.2 $0.5 $0.0 $0.0 $0.1
June Large $2.3 $8.4 $1.3 $1.5 $1.4 Small $0.2 $0.7 $0.1 $0.1 $0.1 July Large $4.5 $5.6 $1.3 $1.2 $1.1 Small $0.4 $0.5 $0.1 $0.1 $0.1

The calculations presented in Table 11 assume th at all Gulf commercial fishing operations have similar cost structures, namely that variable co sts average 75% of revenu es for large vessels, or
93% for small vessels. This is a conservative estimate: commercial shrimping is a high-cost industry, and other types of fishing are likely to have lower costs. Applying this percentage to the 2010 baseline revenues from Table 7 gi ves the 2010 baseline profits in Table 12.

If labor used in commercial fish ing is not easily redeployed to alte rnatives, i.e., it does not have an opportunity cost, then this lost labor would also be in cluded 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 es timate. Even counting all lost fishing revenue adds only one percent to our to tal avoided cost estimate.50 Table 12 Estimated Baseline Profits for 2010: Gulf Coast Commercial Fisheries (2009$ millions) 

### Texas Louisiana Mississippi Alabama West Florida May $2.5 $6.2 $0.2 $0.5 $1.8
June $2.4 $9.1 $1.4 $1.6 $1.5 July $4.8 $6.1 $1.4 $1.3 $1.2 August $6.9 $7.4 $1.0 $1.8 $2.5

Closures
Gulf fishery closures in the Federal Exclusiv e Economic Zone (EEZ) are tracked over time in Table 13. As of July 21, 2010, about a third of Fede ral waters in the central Gulf were closed, while Texas had not experienced any closures, and shrimping seas on in the western Gulf opened as usual on July 15. 16 

### The eastern edge of the Gulf has also remain ed open, and Florida has closed only about 20 miles of the coastline near Pensacola. 17 

### All of Alabama State coastal waters (outside of Mobile Bay) have been closed to commerci al fishing since June 24, though some shrimping and catch-and-release fishing are allowed. 18 

### On July 20, Mississippi State coastal waters re-opened to live-bait shrimping and catch-and-release fishing. 19 

### As of July 5, about half of Louisiana oyster harvest areas we re closed, as was about half of the Louisiana coastline (from Oyster Bayou to the Mississippi border) for commerci al fishing. A smaller set of areas was closed to recreational fishing. 20

16 Texas data were taken from the Texas Parks and Wildlife Department website “BP Oil Spill in the Gulf of Mexico”

at http://www.tpwd.state.tx.us/site/emergency/oil_spill/.

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

June 13, 2010.

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

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

20 Louisiana closure data were taken from the Interactive Closure Maps on the website of the Louisiana Department of Wildlife and Fisheries (LDWF) at http://www.wlf.louisiana.gov/oilspill/map/.51 Table 13 2010 Gulf Fishery Closures in Federal Exclusive Economic Zone (EEZ) 

### Closure Date (2010) Percent Coverage of Gulf EEZ Days Closure was in Effect Effective Days of Full EEZ Closure 2-May 2.8% 5 0.1 7-May 4.5% 4 0.2 11-May 6.6% 1 0.1 12-May 7.3% 2 0.1 14-May 8.0% 3 0.2 17-May 10.0% 1 0.1 18-May 18.9% 3 0.6 21-May 19.8% 4 0.8 25-May 22.4% 3 0.7 28-May 25.1% 3 0.8 31-May 25.6% 1 0.3 May 2010 Subtotal 3.9
1-Jun 31.4% 1 0.3
2-Jun 36.6% 2 0.7
4-Jun 32.3% 1 0.3
5-Jun 32.5% 2 0.7
7-Jun 32.3% 9 2.9
16-Jun 33.4% 5 1.7
21-Jun 35.9% 2 0.7
23-Jun 32.5% 5 1.6
28-Jun 33.2% 6 2.0
June 2010 Subtotal 10.9
4-Jul 33.5% 8 2.7
12-Jul 34.8% 1 0.3
13-Jul 34.7% 10 3.5
23-Jul 23.8% 8 1.9 July 2010 Subtotal 8.4 May-July 2010 Total 23.2

source: http://sero.nmfs.noaa.gov/Closur eSizeandPercentCoverage.htm

We applied the “effective days of full EEZ clos ure” 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 adjace nt 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 shif t profits to that particular point in time.52 Table 14 Estimated Gulf State Profits Lost to Closures 

### Days of
Closure Days in

Month 2010 Baseline Profits (LA, MS, AL), millions (2009$) Lost profits,
millions (2009$) May 3.9 31 $6.9 $0.9

June 10.9 30 $12.0 $4.4 July 7.7 31 $8.8 $2.2 Total $27.8 $7.5

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



## Valuing Lost Recreation
Recreation activities are often affected when oil sp ills result in contamination of coastal or ocean resources. These damages can result in value losses to consumers who either are unable or choose not to participate in a gi ven recreation activity due to th e contamination or do participate but have a lower quality experien ce than if there was no contamina tion. 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 va lue for a particular t ype of recreation trip.

Economists use consumer surplus, or the differen ce between what an individual is willing to pay for a good and what they actually pay for it, to ar rive at these recreation values. Since market price data is lacking for the value of recrea tional activities, these values are inferred from consumer behavior (such as the costs incurred to travel to the recreation site) or from individual stated preferences about their w illingness to pay for the resource. Ideally, survey-based data
would be collected from individu als to obtain information about th e value that they place on the resource in a particular geographic location a nd the value loss incurred from an oil spill. However, when it is not feasible to undertake an origin al study to obtain these values, the benefit transfer approach is often used. Benefit transfer is a method th at applies values obtained from previous studies to a new situation wher e primary data has not been collected.

In this section, benefit transfer is used to produce estimates of the va lue of lost recreation associated with a catastrophic oil spill event in the Gulf of Mexico for recreational fishing and
beach recreation. Other recreational activities such as scuba diving, snorkeling and boating are likely to be affected as well but estimates for thos e activities are not included in this analysis due to lack of information about the impacts and po tential overlap among activities. In order to arrive at an estimate of the impact of a catastr ophic oil spill, several assumptions are required53 

### about the size, duration and location of the spill. In this analysis , the spill is assumed to result from a catastrophic blowout event in the GOM. In addition, this analysis does not account for the substitution of less desirable or more costly recreation sites for those that are affected by the spill.



### Recreational Fishing

In order to estimate the value of lost recreational fishing trips, historic data on the total number of trips is first required. Hi storic data from the NOAA Marine Recreational Fishing Statistics Survey (MRFSS) for the Gulf Coast Region including Alabama, Mississippi, Louisiana, and Western Florida (data for Texas was not available) was used to arrive at an estimate of number of trips over a three month period including May, J une 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 wa s obtained (Table 15).

Table 15 Average Number of Trips (May

‐ July) (2005

‐ 2009) 

### Area Number of Trips Alabama 572,907 West Florida 4,576,280 Louisiana 1,455,094 Mississippi 384,055 Federal EEZ 679,261 Total 7,667,597

Source: NOAA Marine Recreational Fishing Statistics Survey

The number of effective days of full closure (see Table 13) was then applied to the average number of trips per day for each month to estimat e the number of trips lo st during the period of closure. Effective days of closure for the Fede ral EEZ were also applied to each of the States due to lack of specific data on St ate water closures. This is like ly 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 th roughout the region). If suitable substitutes ar e available, it is likely that the decrease in number of trips w ould be smaller than if fewer substitutes are
available.54 

### Benefit transfer was then used to value the lost recreational fishing trip s. Consumer surplus estimates (in dollars per activity day) were obtai ned from previous non-market valuation studies of recreational fishing in the Gulf Coast region. All values were converted to current (2010) dollars, and an average value of $54.48/day was obtained from the 7 studies considered. This value was multiplied by the number of trips lost fo r State waters in each state and the Federal
EEZ to arrive at total estimated consumer su rplus over the three-month period. The total recreation value lost over the peri od is estimated to be $111.8 million. In this catastrophic spill scenario, we assume the impacts discussed resu lt from a spill of 4.8 millio n barrels. Dividing the recreation value lost by the num ber of barrels spilled gives a value loss of $23.43 per barrel.



### Beach Recreation Historic data on the annual number of visitor days for beach recreation in the Gulf Coast States was obtained from the 2000 National Survey of Recreation in the Environment (NSRE) conducted by the U.S. Forest Service and NOAA. In order to estimate the number of visitor days in May, June and July, the monthly visitation data from Gulf Islands Nati onal Seashore (located in MS and FL) was used to estimate the percen tage of visitation during this three month period (48%) and this percentage was applied to the annual state visitation da ta. For the State of Florida, information from Murley et al. (2005) was used to estimate the percentage of beach
recreation visits that occur on th e western coast (25.7%). The estimated recreation days in each state during the period are shown in Table 16.

Table 16. Estimated Number of Recreation Days (May

‐ July) State Recreation Days

Alabama 5,683,200
West Florida 21,853,224
Louisiana 1,939,200 Mississippi 4,161,600
Texas 16,910,400
Total 50,547,624



### Ideally, in order to estimate th e number of recreation days lost, actual visitation data would be collected from beach surveys or over flight surv eys during the affected period and compared to average visitation levels for that time of year. In the absence of actual visitor counts, certain assumptions must be made to estimate the recreati on days lost. In this case, the percentage of oiled shoreline in each state as of July 22, 2010 was used to approximate the percentage of recreation days in each state that were affected (12% in AL, 2% in FL, 5% in LA, 30% in MS and 0% in TX). This is likely to be an unde restimate for much of the area because the total55 

### shoreline used to calculate the percentage of ar ea affected includes areas that are not used for
beach recreation.

Although most beaches along the Gulf Coast may re main 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 consum er surplus due to decr eased quality of the recreation activity. We assume a 20% loss in qu ality for each recreation day affected, following Chapman and Hanemann (2001).

Consumer surplus values for beach recreation per activity day were obtained from 8 studies conducted in the Gulf Coast region. All values were converted to current (2010) dollars and averaged to obtain a value of $88.47 per activity day. This value was then multiplied by the number of recreation days in each state to arri ve at a total consumer surplus value for beach recreation during the three month period. Using these values, we estimate a loss in the value of beach recreation of $75.5 million over the period , or $15.82 per barrel for a spill of 4.8 million

barrels. It should be noted that these estimates do not explicitly account for the availability of substitute beach sites, or the differences in beha vior of local versus out of state visitors. If suitable substitutes are available, it is likely th at the decrease in consumer surplus would be
smaller than if fewer substitutes are available.

As with the commercial fishing analysis, we used selected characteristics of the BP spill as a proxy for a future catastrophic spill simply for anal ytical convenience. Th ese factors include the closure periods and time of year. The minor size of the recreational fishi ng and beach use values relative to the total social cost estimate did not ju stify devoting further effort to refining the spill circumstances such as randomizing time of year or adjusting for fishing trip substitution.56 Table 17. Recreation Studies

Recreational Fishing

Year State Reference

1991

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

1991 Gulf of Mexico Gillig et al., 2000

1991 Florida Leeworthy, 1990

1992 Florida Bell et al., 1982

1999 Louisiana Bergstrom et al., 2004

1990 Florida Bell, 1992

1988 Florida McConnell and Strand, 1994

Beach Recreation

Year State Reference

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

1984 Florida Bell and Leeworthy, 1986

1984 Florida Bell and Leeworthy, 1986

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

1990 Florida (Clearwater Beach) Leeworthy and Wiley, 1994

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

1984 Florida Bell and Leeworthy, 1990

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



## Oil Spill Response and Damage Assessment Costs
Response or removal expenditures include rescue and rehabilitation of personnel and wildlife, salvage of infrastructure, clea nup of oil from aquatic and terr estrial areas, and hearings and investigations into causes of a spill. Removal costs incl ude the equipment used in the response—skimmers to pull oil from the water, booms to contain the oil, airplanes for aerial observation or dispersant appl ication—as well as salaries, travel and lodging costs for responders. Response expenditures can be incurr ed by: Federal, State, Tribal governments; industry; non-governmental organi zations; private companies; and foreign entities. Response
costs exclude the wellhead containment costs to secure and kill the uncontrolled flow from a well blowout. Although technically “response costs” under the Oi l Pollution Act (OPA), those containment costs are considered private-social co sts for this analysis and covered in the section on Avoided Private-Social Costs. Damage asse ssment costs can include costs associated with data collection and analysis required to evalua te the impacts of the sp ill relative to pre spill
conditions.

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

Entities ), OMB considered benefits of vessel re sponse plans and double-hu ll vessels by valuing57 

### avoided spills at $2,000 per barrel, noting that “This is double the sum of the most likely estimates of environmental damages plus cleanup costs contained in a pub lished journal article.”

Estimates of response costs can also be found in the literature. Table 18 presents estimates in current dollars of oil spill clea nup costs by oil type; Table 19 pres ents estimates by kilometer of shoreline oiled; Table 20 presents estimates by proximity to shore. Table 21 presents information by spill volume. 21

Table 18 Cost of Spills by Fuel Type 

### Oil Type US Spills (2010 $/bbl)
No. 2 diesel fuel 638

Light crude 554
No. 4 fuel Data not available No. 5 fuel 1,539 Crude 2,570 Heavy crude 3,733 No. 6 fuel 3,198 Per-unit cleanup costs by degree of shoreline oiling
Source: Etkin, June 2000



### .

Table 19 Cost of Spills by Length of Shoreline Oiled 

### Shoreline

Length Oiled US Spills (2010 $/bbl)
0-1 km 468 2-5 km 1,060 8-15 km 1,866 20-90 km 2,684 100 km 4,832 500 km 9,197

21 Etkin, D. June 2000. Worldwide Analysis of Marine Oil Spill Cleanup Cost Factors. Presented at Arctic and Marine Oil Spill Program Technical Seminar; Etkin, D. 2001. Comparative Methodologies for Estimating on Water Response Costs for Marine Oil Spills, International Oil Spill
Conference.58 Table 20 Cost of Spills by Location 

### Location US Spills (2010 $/bbl) In-port 6,033 Nearshore 4,437 Offshore 1,217

Source: Etkin, 2001



### .

Table 21 Oil Spill Response Costs by Spill Volume 

### Spill Volume (bbls) Total Cost ($2010) $ per bbl ($2010) 240 203,803 856 2,400 2,072,094 870 12,000 10,953,217 920 120,000 46,885,858 394 240,000 90,476,930 380

Source: Etkin, 2001



### .

For the purposes of the benefit-co st analysis it is assumed that one third of the response efforts
occur nearshore and two-thirds offshore. Th e weighted average of the near- and offshore response cost estimates presented above is $2,300 per bbl.



## Avoided Costs Associated with Reduced Loss of Life and Nonfatal Injuries
There have been 20 blowouts from deepwater wells, with 2 resulting in injuries or fatalities.
Those two events are a 1984 blowout with 4 fa talities 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 thes e 2 cases as values for a hypot hetical catastrophic deepwater
blowout.



### Value of Statistical Life The proposed regulation, because it is anticipa ted to reduce the probability of catastrophic blowout events, is likely to reduc e the risk of premature death of rig workers. The oil and gas extraction industry is characterized by a relativ ely 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). The59 

### fatality rate for oil and gas extraction workers is high compared to many ot her industries, with a rate of 23.4 fatalities per 100,000 full-time equivalent workers (Table 22).

Table 22 Selected Fatal Occupational Injury Rates by Industry, 2008 

### Industry Fatality Rate (per 100,000 Full-Time

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

Oil and gas extraction 23.9 Transportation and warehousing 14.9
Construction 9.7 Protective service occupations (includes protective service occupations such as fire fighters, law enforcement) 9.1

Manufacturing 2.5 Management, professional, and related occupations 1.6

Finance, insurance, real estate and leasing 1.1

Source: Bureau of Labor Statistics, 2010.



### The benefits of occupational risk reduction are us ually measured using the concept of “value of statistical life” (VSL). The VSL concept is ba sed on individual willingne ss to pay for reductions in small risks of premature death and not on the pr esent value of future earnings. In concept, the VSL is the measurement of the sum of society’s willingness to pay (WTP) for one unit of fatal risk reduction, which is society’s willingness to pay for reducing each individual’s risk by a
small amount.

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

• Voluntary/involuntary;

• Ordinary/catastrophic;

• Delayed/immediate;60 

### • Natural/man-made;

• Old/new;

• Controllable/uncontrollable;

• Necessary/unnecessary; and

• Occasional/continuous.

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

Income has been found to have a clear and measur able effect on the VSL: as income increases, WTP for risk reductions usually increases. While this effect could be measured both crosssectionally (across individuals or subpopulations) and longitudina lly (over time), most studies are cross-sectional. However, using different VSL estimates for individuals with different
incomes is controversial and has raised issues about the equitabl e treatment of richer and poorer segments of the population in policy decisions (Robinson, 2007). Some recent studies only consider samples from extremely dangerous jobs, such as police officers. Workers in these jobs may have different risk preferen ces and face risks much higher th an those evaluated in typical environmental policy contexts (Kochi, 2006). Other recent research has examined how VSL varies with age, how it varies between males and females, and how worker heterogeneity may impact VSL.

A large number of estimates of VSL exist in th e academic literature. This literature involves either explicit or implicit valuati on of fatality risks, and generally involves the use of estimates of VSL from studies on wage compensation fo r occupational hazards, on consumer product purchase and use decisions, or from an emerging literature using stated preference approaches. Values reported have varied over time, geogra phic location, and worker heterogeneity. VSL estimates from under $1 million to around $3 million th at 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 va ry 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 ra nge of $4 million to $9 million.

EPA recommends that the central estimate of $7.4 million ($2006), updated to the base year of the analysis, be used in all benefits analyses that seek to quantify mortality risk reduction benefits regardless of the age, income, or ot her population characteri stics of the affected population. This approach was vetted and endorsed by the Agency when the 2000 Guidelines for Preparing Economic Analyses were drafted. A recent report of the EPA’s Science Advisory61 

### Board (SAB) concluded that the available lite rature does not support ad justments of VSL for most factors. However, the panel did support ad justments to reflect ch anges in income (EPA allows the adjustment of VSL based on increase s in future income but not on cross-sectional differences in income), adjustments for inflat ion and time lags in th e occurrence of adverse
health effects.

VSL Value Used in Offshore Safety Regulation
For the purpose the analysis to estimate the a voided 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). A lthough oil rig workers are involved in an inherently risky occupation, base d on the lack of consensus in previous research focused on adjusting VSL values for occupational risk, the EPA VSL recommendation was chosen for this analysis.

Based on the estimated value of 8 deaths per bl owout event, using a VSL value of $8 million, for a 4.8 million barrel spill, the loss of life value from a blowout would be $13/barrel.

Nonfatal Injuries
On average, workers value non-fatal loss injuri es on the job at values ranging from $20,000 to $70,000 per expected job injury. Thus, for example, a worker at the high end of this range would require $2,000 to face a one-in-25 chance of being injured that year (Viscusi, 2005).

We estimate an average value of job injuries at $45,000 per injury. With 10 injuries expected per catastrophic blowout event, a 4.8 million barre l spill would result in an estimated cost of $0.09 per barrel.



## Other Health Effects
The Centers for Disease Control and Prevention (C DC) report that the Gulf Coast oil spill has the potential to affect human hea lth. CDC and the Gulf States have a plan to track symptoms 22


### occurring in the affected communities and will be able to investigate whether there is an association between symptoms a nd the oil spill. As of July 20, 2010, the American Association of Poison Control Centers repo rts receiving 843 “exposure calls” involving someone exposed to an oil-spill related toxin (e.g., oil, dispersant, food contamination).

Human health effects from oil spills include s hort-term physical effects from exposure of cleanup workers and residents of the ar ea, mental health effects on workers and residents, as well as

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

.62 

### long-term effects. However, the research on health effects of oil spills is limited to date. There has been some evidence of acute physical effects and psychological effects in a number of cases. For example, CDC’s National Institute for Occupa tional Safety and Health reports 186 injuries
and 80 illnesses 23 

### among spill responders in the Gulf. Ho wever, evidence of long-term health effects is lacking. Much of the research on the physical effects of oil spills has been conducted
outside of the United States. Some researchers have found evidence that oil spills affect the health of individuals involved in clean-up activit ies (Pérez-Cadahía et al. 2006), residents in the immediate vicinity of a spill (Janjua et al. 2006, Lyons et al. 1999), and residents involved in clean-up efforts (Morita et al. 1999 ). Physical effects on resident s 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). Pé rez-Cadahía et al. (2006) show evidence of cytogenetic damage
and alterations in hormonal status.

Evidence of mental health effects have been s hown for the Exxon Valdez and Prestige oil spills (Palinkas et al. 1993a, Palinkas et al. 1993b, Sabuce do et al. 2010). Palinkas et al. (1993a) show links between the oil spill and increased rates of depression, anxiety and post-traumatic stress disorder, and declines in subsistence activities and traditional social relationships. Sabucedo et al. (2010) show similar results with greater psyc hopathological symptoms in individuals living
closer to the location of th e 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 acc rue beyond the area directly impacted. These costs will be incurred by busine sses and households that are linke d economically to coastal areas or to activities occurring in areas damaged by th e spill. The oil spill may result in reduced producer surplus, lost producer surplus on products or services that are no longer produced, or some combination of the two. The magnitude and timing of any reduced producer surplus is difficult to predict, however the larger the spil l and the more extensive its geographic impacts the larger the potential for producer surplus losses. The lost producer surplus associated with economic losses is not quantified for this analysis due to the uncertainties associated with the scope, magnitude, and timing.

23 As of June 6, 2010; mostly contusions/abrasions and heat stress.63 

## Summary – Avoided External-Social Costs

Table 23 summarizes the estimated avoided external -social costs of the h ypothetical catastrophic blowout spill conditional on the spill being prec luded from occurring. Spill costs that are avoided could be much higher if all costs discus sed previously could be monetized. Efforts to quantify even rough estimates for those rows left bl ank in the table by refere nce to other oil spills were not fruitful because such private settlement s are not reported publicly. Nevertheless, given
the relative size of those sub-elements that could be monetized, the findings indicate that recreation, fishing and mortality losses are quite small compared to the costs for spill cleanup, damage assessment, and the imputed value of natural resource damages. Thus, provision for the lingering effects which an oil spill might have on fishing losses is not likely to affect the overall
results.

Table 23 Summary of Estimated Avoided External

‐ Social Costs

Cost Avoided Cost

for 1 Hypothetical Spill Social Cost Category

($ per bbl) (4.8 mm bbl)

Natural Resource Damages $604 $2.88 billion

Recreational Losses (Recreational Fishing and Beach Recreation) $42 $0.20 billion

Commercial Fishing Losses $2 $0.01 billion

Value of Life and Nonfatal Injury $13 $0.06 billion

Other Health Effects Not
Quantified

Oil Spill Response & Damage

Assessment Costs $2,300 $10.97 billion

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

response assets Not
Quantified

Price effects in seafood markets Not
Quantified
Property values Not
Quantified

TOTAL $14.12 billion64 

## TOTAL ESTIMATED AVOIDED SOCIAL COSTS (BENEFITS)

Table 24 combines the conditional avoided private-social and external-social costs from Table 4 and Table 23. This is the potential benefit per catastrophic spill in the baseline from fully eliminating the possibility of a spill.

Table 24 ‐ Summary of Private and External Social Costs 

### Social Cost Category Conditional
Avoided Cost
Amount Expected Avoided Cost Given 1 Spill in 25.8 years (3.85% probability of a spill each year) Private Costs $2.17 billion $84.1 million
External Costs $14.12 billion $547.3 million
Total: $16.29 billion $631.4 million

The policies being promulgated can reduce, but not necessarily eliminate, the occurrence of a catastrophic spill and hence the resulting spill co sts. Since the compliance costs are fully represented by annual expense outla ys, it is convenient to express the expected avoided costs on an annual basis as well. Moreover, the coincide nt 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 discount ed 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 obs ervation, the number of deepwater wells drilled (4,123), and the anticipated annual number of futu re deepwater wells to be drilled (160), the
baseline risk absent this rule is estimated to be 1 event in 26 year s for this benefit-cost analysis. The compliance requirements in this rule will partly reduce the expect ed annualized spill costs by reducing the spill frequency, thereby increasing the expected interval between such spills and hence spreading the conditional spill costs over more years. The resulting reduction in the expected annualized spill costs represents th e social costs avoided associated with the hypothetical spill scenario owing to the provisions in this rule.



## SCENARIO ANALYSIS

In order to compare the relative magnitudes of th e expected benefits and costs associated with avoiding a blowout resulting in catastrophic oil spill, the agency examined several scenarios based on extending historical information on d eep water blowouts. Given the paucity of65 

### information on specific effectiveness of vari ous measures and the likelihood of another catastrophic blowout, this approach aims to identify scenarios in which the expected benefits justify the expected costs.

The hypothetical spill from Table 24 

### gives us an avoided social cost of $16.3 billion for a major event. The compliance cost s of this regulation from Table 3 

### give an annual compliance cost of $183 million per year. The baseline assumptions esta blish that there was 1 major event for every 4,123 deepwater wells and we assume an average of 160 wells will be drilled annually. Under these circumstances, a major event is projected to occur at an average rate of approximately once every 26 years. 24



### Using the avoided social cost of $16.3 billion and dividing it by the rate of a major event, one per every 26 years, we calculate an annual avoide d cost of $631 million. To calculate the required proportional improvement in spill frequency for th e expected benefits to equal the costs of regulation, we divide the compliance costs by the annualized avoided costs. An annual compliance cost of $183 million divided by annualiz ed avoided costs of $631 million suggests a finding of a 29 percent improvement in spill fr equency when expected benefits justify the expected compliance costs.

By varying selected important inputs in reas onable ways, we can provide a range for the scenarios under which expected benefits justify the costs of the regulation.

1) The compliance costs are lowered by about 50% to $97 million reflecting productivity improvements, and raised by about 100% to $352 million reflecting more frequent compliance problems and wo rk stoppages during dr illing operations, as
discussed in the next section. 2) The population of deepwater we lls subject to a future ca tastrophic blowout spill is limited to those in water deeper than 3,000 feet, where the spill size and consequences (but not the spill probability) from a blowout are estimated to be greater. For the purpose of conducting this sensitivity analysis only, we employed the historical population of 1,475 wells drilled in the GOM at a water depth of 3000 feet or greater to set the baseline risk, and forecast that an average of 110 wells will be drilled each year at this depth. Elaboration of this scenario is provided in the Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blowout Spill.

24 4123 wells divided by 160 wells per year gives us 25.8 years, or 26 years.66 

## Sensitivity of Compliance Costs

A lower compliance cost estimate of $97 million annually assume s the industry can achieve longer term productivity improvements for the requirements in this regulation. The lower compliance cost estimate for the sensitivity analysis is determined by taking 1⁄2 of the ROV testing time (12 hours) for the subsea BOP on the stack and seafloor for drilling and workover/completions operations and 1⁄2 of the cas ing strings required (an average of 2.5 strings tested for deepwater wells and 1.5 strings tested fo r shallow wells) for the negative pressure test. Additionally, we include only the capital cost of the second mech anical barrier and exclude the 30 minutes of lost rig time due to installati on from the baseline estimate and assume the frequency of emergency activation of the BOP is halved. Over time, companies will improve the efficiency of conducting these tests, improve technology to use fewer casing strings and find other methods to improve lost productivity; how ever, a 50 percent improvement appears unlikely to be achieved in the near term. Using this lower compliance cost of $97 million, divided by the annual avoided cost of $631 million, the required pr oportional improvement in spill frequency is found to be 15 percent.

An upper compliance cost estimate of $352 million annually assumes that the time required for conducting the tests for this regulation were underestimated due to unforeseen and time consuming problems encountered through the additional requirements imposed by this regulation. The higher compliance cost estimate for the sensitivity analysis is determined by doubling the ROV subsea BOP testing time for dr illing and workover/completion operations and doubling the time needed to complete negative pre ssure tests for all intermediate and production casing strings. The subsea BOP stack testing components would take a full 48 hours and each negative pressure test would take 3 hours in this scenario. Additionally, the lost rig time for installing the second mechanical barrier would be doubled to 60 minutes and the frequency of the emergency activation of the subsea BOP st ack would occur twice as often. The upper bound annual compliance cost consistent with these assumptions is found to be $352 million annually. Using this upper compliance cost of $352 million, divided by the annual avoided cost of $631 million, the required proportional improvement in spill frequency is found to be 56 percent.



## Sensitivity of Population of Deepwater Wells and Drilling Activity Subject to a Catastrophic Blowout Spill
To analyze the sensitivity of the population of deepwater wells and drilling activ ity, along with the underlying effect on the baselin e risk assumption, we identified the water depth at which the consequences of a blowout event may be more se vere. In the baseline analysis we used a 500 foot water depth demarcation since it is the upper limit of jackup rigs and where subsea BOP
stacks start to be used for MODUs. While there is no specific water depth demarcation for an increase in the consequences of deepwater blow out, wells which are dr illed at a water depth67 

### greater than 3,000 feet may have an increased potential for a catast rophic event due to changes in the surrounding geology and reservoirs as well as greater difficulty mitigating the consequences of an uncontrolled flowing well. The changes in the geological formations allow for greater accumulation potential with porous and permeable sands at these depths and result in higher flow
rates. Thus the reservoirs at de pths greater than 3000 feet are ge nerally more prolific than their shallow water counterparts.

It is important to note that th e probability of a blowout is not greater beyond 3,000 feet water depth and based on OCS drilling history is actu ally lower than shallower water depths. However, the consequences of an uncontrolled bl owout event in deeper water depths are more likely to be catastrophic because of the addi tional complications of the water depths as demonstrated by the BPDH event.

Historically, there have been 1,475 GOM wells dril led in water depths of greater than 3,000 feet, with approximately 1,100 wells in the past 10 years. This gives a 1/1475 probability of a catastrophic blowout spill event, and about 110 wells drilled per year. At this rate, one event occurs every 13.4 years in this alternat e scenario. 25



### By dividing the expected avoided social co st of $16.3 billion by th e alternate scenario catastrophic event rate of 13.4 y ears per event, the annual avoide d cost is $1.216 billion. Taking the compliance costs of $183 million per year, divi ded by the alternate annual avoided costs of $1.216 billion per year, results in a required pr oportional improvement in spill frequency of 15 percent for the benefits to justify th e costs in this alternate scenario.



## Alternatives
This interim final rule implements selected safe ty measures recommended in the report entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (Safety Measures Report), dated May 27, 2010. Given the cr itical nature of the BP Deepwater Horizon (BPDH) explosion and resulting oil spill and the apparent inadequacy of existing well control procedures and BOP requirements, the Safety Measures Report recommended that BOEMRE address some items through an emergency rulema king. The requirements in this interim final rule include practices related to well c ontrol, including well casing and cementing, ROV intervention, unplanned disconnect s, recordkeeping, well comple tion, and well plugging. These requirements were determined by the Secretary to be urgently needed to protect worker safety
and the OCS environment.

Other measures recommended in the Safety Measur es Report but not include d in this emergency interim rulemaking include additional blind sh ear and casing ram requirements, enhanced ROV

25 1475 wells drilled divided by 110 wells per year equals 13.4 years.68 

### intervention capability, increased accumulator capacity for op erating BOPs and safety case requirements for floating drilling operations. Th ese and other items in the Safety Measures Report require further study by indus try and Interior Strike Teams to determine their efficiency
and effectiveness. Measures considered benefi cial will be considered for future notice and comment rulemaking.



## Small Business Alternatives
Two alternatives to ease impacts on small busines s were considered. One alternative is to exempt small businesses from the requirements of this interim final rule. A second alternative is to delay the implementation timelines to comply w ith the regulation. Both of these alternatives are being rejected by BOEMRE because of the overriding need to reduce the chance of a catastrophic blowout event. We do not believe it is responsible for a regulator to compromise the safety of offshore personnel and the environm ent for any entity including small businesses. Offshore drilling is highly technical and can be hazardous; any delay may increase the interim risk of OCS drilling operations. Additionally, more than 90 percent of the costs will be imposed on deepwater lessees and operators where small businesses only hold 12 percent of deepwater leases. Every operator and drilling contractor both large and small must meet the same criteria for drilling operations regardless of company size . However, the overwhelming share of the cost imposed by this regulation will fall on companies drilling deepwater wells, which are predominately the larger companies. Nonetheles s, small companies as both lease-holders and contractors serving lease-hol ders will bear meaningful costs under this regulation.

To better understand the economic impact of this rule on sm all entities, the BOEMRE will conduct a supplemental Initial Re gulatory Flexibility Analysis (IFRA) to examine in greater detail the impact of this regul ation on the small entities. We are requesting comments on the economic analysis for this interim final rule a nd this rulemaking’s impact on small entities. The supplemental IFRA will be made ava ilable to the public when completed.



## CONCLUSION AND UNCERTAINTIES

The BOEMRE has analyzed the costs and benefits of this interim rule using data available at the time of this rulemaking under various scenarios to assess when expected benefits might justify the expected costs. Under different assumptions about the magnitude of costs and benefits, we assessed how the frequency and the magnitude of future blowouts resulting in catastrophic spills should change for the expected benefits to justify the compliance costs.

Future long term studies should be conducted to assess th e likely effectiveness of these increased safety measures, using statistical analysis of historic informa tion on existing well configurations69 

### and testing practices. Cross-se ctional data that are now colle cted but not captured in the BOEMRE TIMS data base may enable studies that assess how requireme nts for extra subsea ROV and deadman testing, widespread use of negativ e pressure tests, dual mechanical barriers in the final casing string, along with the remaining it ems required in this rulemaking, could improve well control performance. Parent hetically, such data are availabl e to conduct statistical tests on prospective BOP enhancements which are not include d in this rule. Absent the ability to conduct these studies of the key features that are included in this rule, we turn to possible refinements in
the baseline assessments.

We can also expect the risk and impact of a deepwater catastrophic blowout will be lessened by other factors not specifically addressed in this benefit-cost analysis. Industry and government reaction to this spill has a dded experience that will improve planning, response and technology used to mitigate spill effects before a relief well is completed. However, the nature and impact of these changes are not easily qua ntifiable at this stage of the investigative process and are not
included in the bene fit-cost baseline.

One area of further study involves the voluntar y measures being recommended by the Joint Industry Task Forces. If the American Petroleu m Institute’s (API) Reco mmended Practices (RP) are published and incorporated in to BOEMRE regulations, we woul d consider those RP’s to be part of the inherent cost of sound well design and best practice drilling operations. In this
circumstance the RP’s would not be considered a new compliance cost for the purposes of this benefit-cost analysis. Rather, the benefits and costs would be included in our baseline for this analysis. Therefore, to the extent that vol untary measures recommende d by the Industry Joint Task Forces become API RP’s and are incorp orated into BOEMRE regulations, the actual compliance costs imposed by this rule would be reduced. As a result, the required proportional improvement in spill reliability necessary for th e benefits from the expected costs avoided by these provisions to exceed their compliance costs would be lowere d, unless the voluntary
measure also reduced the baseline risk of a spill under current regulations by a proportionally equal or greater amount than the reduction in costs.

Another area for further inquiry involves determining the impa ct and cost of a catastrophic deepwater oil spill. Future studies and analyses are necessary to more fully reflect all the effects of a catastrophic deepwater blowout on the natu ral and human environments in the Gulf of
Mexico. We also note that the basis for our da mage 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 esti mates of the individual cost elements of a hypothetical deepwater spill imply that the resulti ng social costs vary significantly from our70 

### hypothetical $16.3 billion benefit estimate, then the fu ture analysis should be adjusted to reflect
the new estimate.71 

## Appendix A Natural Resource Damage Data

Table 25 ‐ Dataset of Spill Costs: Restoration and Assessment Costs 

### Event Year of Settlement Max Volume (bbl) NRD plus Assessment Costs (2009$/bbl)* American Trader Inc. 2006 143 1,313
Anacortes 1998 952 491 Apex Houston Spill 2006 25,000 244 B.T. Nautilus 1994 6,024 816 Barge Morris J. Berman 2000 11,905 480 Barge RTC 380 1994 643 411 Bermuda Islander 2008 24 11,340
Blake IV and Greenhill Petroleum Corp. Well 25 1995 2,905 786

Bouchard Barge 120 2006 2,333
BP American Trader Vessel 1997 9,919 300

Chevron BLDSU #5, West Bay Field 1996 262 249

Chevron Perth Amboy Facility 2006 342

Chevron, HI 1999 982 2,189 Chiltipin Creek 1994 2,950 69 Cibro Savannah 1999 2,381 138 Cold Spring Harbor Barge 2004 2,357 ConocoPhillips Bayway 2005 250 El Segundo 1993 500 300 Equinox Cockrell-Moran #176 well 2005 1,500 800

Evergreen International M/V Ever Reach Vessel 2003 298 3,021

Exxon Bayway 1991 13,500 905 Exxon Valdez 1991 261,905 5,005 Fish Creek 1993 714 3,511
International Petroleum Corporation (IPC) 2009 286 882

Chelsea Creek (Global Oil/Irving Oil Pipeline) 2006 524 2072 

### Event Year of Settlement Max Volume (bbl) NRD plus Assessment Costs (2009$/bbl)* Jahre Spray 1996 1,400 121 M/T Athos I 2009 6,271 16 M/T Kentucky 1995 310 81 M/TCommand Oil Spill 1999 71 59,181 M/V Cosco Busan 2010 1,262 1,585
M/V Fortuna Reefer 1997 M/V Kure 2008 108 33,890 M/V Kuroshima 2002 929 1,661 M/V New Carissa 2004 1,667 16,118 M/V Presidente Rivera 1993 5,952 426 M/V Selendang Ayu 2006 8,000 7 M/V World Prodigy 1993 7,000 119 M/VWestchester 2003 13,095 41 Martinez 1990 9,524 1,138 McGrath Lake 1997 2,071 635 Milos Reefer 1993 5,952 67 Neches River 1997 2,095 105 Nestucca 1991 5,500 609 North Cape Barge 1999 19,714 625 Northridge 1997 4,595 1,599
OCEAN 255/B155/BALSA 37 Spill 1996 8,619 928

Ocean Energy/Devon Energy North Pass Storage Facility 2006 300 393

Oil and Crooked Creeks 1996 107 2,539 Olympic Pipeline Company
Event 2004 5,619 631

PEPCO Chalk Point Generating Station 2002 3,333 813

Pirates Cove 1996 600 2,333 Quinnipiac River 1996 119 334 Reedy River 1998 22,619 294 Santa Barbara, CA 1969 71,429 SS Cape Mohican Oil Spill 1998 2,286 1,761 Sugarland Run 1998 9,714 25773 

### Event Year of Settlement Max Volume (bbl) NRD plus Assessment Costs (2009$/bbl)* T/V Julie N 2002 4,277 348 Tenyo Maru 1994 10,776 867 Tesoro, HI 2001 117 4,359 Texaco Pipeline Company Lake Barre oil spill 2000 6,548 87

Williams Field/Transcontinental Natural Gas Spill 2010 3,000 84

Yoncalla Creek 1995 143 1,505 * Where a spill has a range of sizes recorded, per-barrel costs were calculated using the upper range.

Table 26 ‐ Gulf Shrimp Landings, Revenue, and Price


### Federal Permit No Federal Permit Total

Average revenue per vessel ($) 199,111 22,429 74,847 Average landings per vessel (lbs) 67,386 13,160 29,247 Average price (dollars per lb) $2.95 $1.70 $2.56 Average price (dollars per lb) $2.87 $1.73 $2.07

Number of Vessels 1,388 3,290 4,678 Total revenue ($ millions) $276 $82 $358 Total landings (millions lbs) 94 47 141 Note: Table for Gulf shrimp only; excludes S. Atlantic shrimp Source: The Annual Economic Survey of Federal Gulf Shrimp Permit Holders: Report on the Design, Implementation, and Descriptive Results for 2007; NOAA Technical Memorandum NMFS-SEFSC-590 (2009).74 

## Appendix B Well Data

Table 27

– GOM Deepwater Wells by Water and Drilling Depth 

### Distribution of 4,133 GOM Wells Drilled in Wate r > 500 Feet by Drilling Date, Water Depth, and Well Depth

Counts of All GOM Wells Drilled in Water >5 00 feet According to Well Drilled Depth Well Total Depth (thousands of feet) Water Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 Totals

500-1,500 140 900 607 61 15 1 1 - 1,725 1,500-3,000 39 205 349 253 71 5 1 - 923 3,000-5,000 21 153 324 218 123 77 17 - 933 5,000-7,500

- 39 121 123 82 45 10 1 421 7,500- 10,000 - - 51 47 11 10 - - 119 >10,000

- - 1 - 1 - - - 2
All WD 200 1,297 1,453 702 303 138 29 1 4,123 >3,000 ft
21 192 497 388 217 132 27 1 1,475

Counts of GOM Wells Drilled before 1980 in Wat er >500 feet According to Well Drilled Depth Well Total Depth (thousands of feet) Water Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 Totals

500-1,500 11 83 32 - - - - - 126 1,500-3,000

- 3 5 1 - - - - 9 3,000-5,000

- - - - - - - - - 5,000-7,500

- - - - - - - - - 7,500- 10,000+ - - - - - - - - - All WD 11 86 37 1 - - - - 135 >3,000 ft

- - - - - - - - -75 Counts of GOM Wells Drilled During the 1980's in Water >500 feet Accord ing to Well Drilled Depth Well Total Depth (thousands of feet) Water Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 Totals

500-1,500 47 324 252 19 2 - - - 644 1,500-3,000 12 59 94 16 - - - - 181 3,000-5,000 1 3 25 1 1 - - - 31 5,000-7,500

- - 1 8 - - - - 9 7,500- 10,000+ - - - - - - - - - All WD 60 386 372 44 3 - - - 865 >3,000 ft 1 3 26 9 1 - - - 40

Counts of GOM Wells Drilled During the 1990's in Water >500 feet Accord ing to Well Drilled Depth Well Total Depth (thousands of feet) Water Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 Totals

500-1,500 55 334 230 28 8 1 - - 656 1,500-3,000 15 74 129 142 18 2 - - 380 3,000-5,000 10 60 106 72 21 2 - - 271 5,000-7,500

- 5 34 20 8 3 - - 70 7,500- 10,000 - - 1 1 - - - - 2 >10,000

- - - - - - - - - All WD 80 473 500 263 55 8 - - 1,379 >3,000 ft 10 65 141 93 29 5 - - 34376 Counts of GOM Wells Drilled After 1999 in Wat er >500 feet According to Well Drilled Depth Well Total Depth (thousands of feet) Water Depth (feet) 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 Totals

500-1,500 27 159 93 14 5 - 1 - 299 1,500-3,000 12 69 121 94 53 3 1 - 353 3,000-5,000 10 90 193 145 101 75 17 - 631 5,000-7,500

- 34 86 97 74 42 10 1 344 7,500- 10,000 - - 50 44 11 10 - - 115 >10,000

- - 1 - 1 - - - 2
All WD 49 352 544 394 245 130 29 1 1,744 >3,000 ft 10 124 330 286 187 127 27 1 1,09277 

## Appendix C Definitions

Baseline : describes the status quo sc enario (“the world absent the new regulation”). The baseline is compared to “the world with the regulation" for the cost-benefit analysis
Benefits : are the favorable effects of a policy or action.
Blowout : is an uncontrolled flow of reservoir fluids into the wellbore. A catastrophic blowout
occurs when fluids flow to the surface. The most damage from a cata strophic blowou t 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 ki cks, the BOP rams are designed to shut-in the
well until control is reestablished. BOP (Blowout Preventer) Stack : Is a series of valv es (or rams) at the wellhead that may be closed if the drilling crew loses control of forma tion fluids. These valves are often referred to as BOP rams. A stack might consist of four to six ram-type preventers and one or two annular-type preventers. A BOP stack is used to ensure pressure control of a well.
Costs : Is the dollar values of resources needed to produce a good or service, and hence are not
available for use elsewhere. Compliance Cost is the expenditure of time or money needed to conform to government’s regulatory requirements. It may be defined as the sum of all opportunity costs incurred as a result of the regulation. These opportunity costs consist of the va lue lost to society of all the goods and services that will not be produced and consumed if firms comply with the regulation and reallocate resources away from production activities and towards compliance with the regulation. External (social) costs are the costs the oil sp ill imposes on society regardless of who pays for them and in this analysis exclude the private (social) costs. Deepwater : While BOEMRE has traditionally defined deepwater as greater than 1,000 feet, for the purposes of this analysis deepwater is defined as water depths where floating drilling rigs are used rather than gravity based ri gs and where submersibles or ROVs must replace divers. This is generally at 300 to 500 of water depth and also the depth where subsea BOP’s are required on floating mobile drilling rigs.
Discount Rate : Per OMB Circular A-94, where appropria te 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 wellb ore being less than that of the formation fluids and most often happens during drilling opera tions from a depth other than the targ eted reservoir. Kicks are most frequently controlled by increasi ng the drilling mud weight, circulat ing out the kick or using one
of the BOP rams to control the flow.78 

### Loaded Rig Rate: The loaded rig rate used in this an alysis is the daily rate charged by the owner of the rig for use of the rig and the operating crew plus the operator’s engineers, supplies, supply craft and supporting contractors.
Net benefits : are calculated by subtracting total costs from total benefits. Oil Spill : An oil spill as referenced in this cost/benefit analysis is oil spilled as a result of a loss of well control event. An oil spill for this an alysis excludes spills from production or logistical activities if the spillage is unrelat ed to a loss of well control event. Private (social) costs: are the costs of the blowout and spi ll that the responsible party pays for containment and recovery of productive capability. Unloaded Rig Rate: The unloaded rig rate used in this an alysis is the daily rate charged by the owner of the rig for use of the rig and the opera ting crew. It does not include supplies, supply craft, the operator’s drilling e ngineers or supporting contractors.79 

## Appendix D References

Alabama Department of Conservation and Na tural Resources. 2010. “Conservation Department Designates Coastal Boating Closures, Idle Sp eed-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 Cont rol Centers. Accessed on-line at: http://www.aapcc.org/dnn/NewsandEvents/Pois onCentersandtheGulfOilSpill/tabid/472/D efault.aspx Bureau of Labor Statistics, U.S. Department of Labor. 2010. Career Gu ide to Industries, 2010- 11 Edition, Mining. Accessed on-line at: http://www.bls.go v/oco/cg/cgs004.htm (visited July 30, 2010).
Centers for Disease Control and Prevention. 2010. Emergency Preparedness and Response,
Health Surveillance. Accessed on-line at: http://www.bt.cdc.gov/gulfoilspill2010/ 2010gulfoilspill/health_s urveillance.asp

. Chapman, D. and W.M. Hanemann. 2001. Environmental Damages in Court: The American
Trader Case. In: The Law and Economics of the Environment . Anthony Heyes (Ed.). pp. 319-367. Department of Health and Human Services, Centers for Disease Control and Prevention, National Institute for Occupational Safety and Health. 2010. NIOSH Report of BP Illness and Injury Data (April 23 – June 6, 2010). Dunford, Richard W. and Miranda L. Freema n. 2001. A Statistical Model for Estimating Natural Resource Damages from Oil Spills. 2001 International Oil Spill Conference.
Florida Fish and Wildlife Conser vation Commission. 2010. “Oil forces partial fishing closure in Escambia County.” Press release date d 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 Jafr i, Shahid Ali Lutfi, Muhammad Masood
Kadir and Nalini Sathiakumar. 2006. Acute Health Effects of the Tasman Spirit Oil Spill on Residents of Karachi, Pakistan. BMC Public Health , 6:84. Kochi, Ikuho, Bryan Hubbell, and Randall Kramer . 2006. An Empirical Bayes Approach to Combining and Comparing Estimates of the Valu e of a Statistical Life for Environmental Policy Analysis. Environmental & Resource Economics , 34:385–406. Liese, Christopher, Michael D. Travis , Diana Pina, and James R. Waters. 2009. The Annual Economic Survey of Federal Gulf Shrimp Permit Holders: Report on the Design, Implementation, and Descriptive Results for 2007. NOAA Technical Memorandum NMFS-SEFSC-590, 107 p. Louisiana Department of W ildlife and Fisheries (LDWF); Interactive Closure Maps at http://www.wlf.louisiana.gov/oilspill/map/80 

### Louisiana Department of Wildlife and Fisheries; Number of Shrimpers 1998-2005 http://www.wlf.louisiana.gov/pdfs/e ducation/number_of_shrimpers_89_to_07.xls Louisiana Department of Wildlife and Fisherie s, Office of Management and Finance (2000) The Louisiana Shrimp Industry; A Preliminar y 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 Evan s, 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 Envi ronmental Quality and Mississi ppi Department of Marine Resources. 2010. News release 10-94-SB, da ted July 19, 2010. “Mississippi Territorial Waters Open to Live Bait Shrimping and R ecreational Catch-and-Release Hook and Line Fishing.” Morita, Akemi, Yukinori Kusaka, Yoji Deguchi, Akio Moriuchi, Yuko Nakanaga, Masayuki Iki, Shigekazu Miyazaki, and Kazuo Kawahara. 1999. Acute Health Problems among the People Engaged in the Cleanup of the Nakhodka Oil Spill. Environmental Research

Section A , 81: 185-194. Murley, J., L. Alpert, W.B. Stronge, and R. Dow. 2005. Tourism in Paradise: The Economic Impact of Florida’s Beache s. Proceedings of the 14 th 

### Biennial Coastal Zone Conference, New Orleans, LA, July 17-21, 2005. http://www.csc.noaa.gov/cz/CZ05_Pr oceedings/pdf%20files/Alpert.pdf National Survey of Recreation in the Environment. 2000. http://egisws02.nos.noaa.gov/socioeco/gen ericProfile.html?datasource=nsre2000 NOAA (National Oceanic and Atmospheric Associati on). Marine Recreational Statistics Survey. http://www.st.nmfs.noaa.gov/st1/recreational/index.html Palinkas, Lawrence A., Michael A. Downs, John S. Petterson, and John Russell. 1993a. Social, Cultural, and Psycholog ical Impacts of the Exxon Valdez Oil Spill. Human Organization

, 52(1): 1-13. Palinkas, Lawrence A., John S. Petterson, John Russell, and Michael A. Downs. 1993b. Community Patterns of Psychiatric Disorders After the Exxon Valdez Oil Spill. Am J Psychiatry , 150(10): 1517-1523. Pearson, Walter. H, et al. (1996 ) “Assessment of Damages to Commercial Fisheries and Marine Environment of Fujairah, United Arab Emir ates, Resulting from the Seki Oil Spill of March 1994: A Case Study.” Yale F&ES Bulletin #103, p. 407-428. Pérez-Cadahía, Beatriz, Anunciación Lafuente , Teresa Cabaleiro, Eduardo Pásaro, Josefina Méndez, and Blanca Laffon. 2006. In itial Study on the Effects of Prestige Oil on
Human Health. Environment International

.81 

### Posadas, Benjamin (2008) Economic Assessment of the Impac ts of Hurricane Katrina on the Mississippi Commercial Fishing Fleet . Mississippi Agricultural & Forestry Experiment Station, Mississippi State University. Robinson, Lisa A. 2007. How U.S. Government Agencies Value Mortality Risk Reductions. Review of Environmental Economics and Policy , 1(2): 283-299. Sabucedo, José M., Constantino Arce, Carmen Senr a, Gloria Seoane, and Isabel Vázquez. 2010. Symptomatic Profile and Health-Related Qual ity 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 th e 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 Ocean ic 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 th e Value of Statistical Life: Introduction and
Overview. Journal of Risk and Uncertainty , 40: 1-13.

Added References: Joint Industry Task Force to Address Offshor e Operating Procedures and Equipment, May 17, 2010, White Paper: Recommendations for Improving Offshore Safety http://www.noia.org/webs ite/download.asp?id=38556 DNV – Beaufort Sea Drilling Risk Study Energy Report, Imperial Oil Resources Ventures Limited, DNV ref no: EP00485, Rev. 6, March 11, 2010, submitted to the CanadianNational Energy Board ( www.neb-one.gc.ca ) https://www.neb-one.gc.ca/lleng/livelink.exe/fetch/2000/ 90463/589151/594086/594088/600443/609664/C-05-6C_- _Appendix_A_Beaufort_Sea_Drilling_Risk_Study__- _A1S2V8_.pdf?nodeid=609512&vernum=0 Executive Order 12866, Regulator y Planning and Review http://www.whitehouse.gov/sites/de fault/files/omb/inforeg/eo12866.pdf OMB Circular A-4, Regulatory Analysis http://www.whitehouse.gov/sites/default/f iles/omb/assets/omb/circulars/a004/a-4.pdf OMB Circular A-94, Guidelines and Discount Rates for Benefit- Cost Analysis of Federal Programs http://www.whitehouse.gov/sites/de fault/files/omb/assets/a94/a094.pdf82 

### NYT Article on the replacement cost of the Deepwater Horizon which is estimated at $560

million. http://www.nytimes.com/gwire/2010/05/ 04/04greenwire-warnings-on-backupsystems-for-oil-rigs-sounde-30452.html Transocean announcement describing the total capital costs to be incurred for the construction of the drillship are estimated to be $750 million. http://www.redorbit.com/news/business/ 1446859/transocean_inc_a nnounces_agreement_ to_acquire_newbuild_ultradeepw ater_drillship_under/index.html83 

## Appendix E Voluntary Industry Measures Review

MEMORANDUM | 18 August 2010

TO Radford Schantz and Martin Heinze, BOEMRE

CC Debra Bridge, BOEMRE

FROM John Weiss, Industrial Economics, Incorporated

SUBJECT Review of Additional Literature with Po tential 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 decisionmaki ng tool used by the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) as it develops five-year leasing programs for oil and gas exploration and production on the outer continen tal shelf (OCS). An important component of this
effort is the review of literature relevant to the identification and evaluation of the environmental costs that the model will consider. Many of those costs are the direct or indirect result of oil spills associated with OCS exploration and productio n activities. In the aftermath of the Deepwater Horizon event,
additional information has become available that BO EMRE has asked IEc to review for relevance and potential application during OECM development. This memorandum describes the results of our review and analysis of one category of additional informatio n, that associated with (1) the Department of the Interior’s 30-Day Report to the President, which de scribes recommended actions to reduce the probability of a similar event in the future, and (2) industry’ s consideration of recommended voluntary safety and protection measures that would be designed to achieve the same objective.

In addition to reviewing relevant information for its potential appli cability to the specification of OECM inputs, IEc has compared the currently available descr iptions of proposed voluntary measures to a set of proposed changes to the rules governing OCS oil and gas activities. BOEMRE is currently developing an analysis of the costs and benefits of the proposed rules, including the estimated incremental cost to industry to comply with new requirements. BOEMRE can use the results of the IEc analysis to determine whether industry’s recommendations provide a basis for any reconsideration of industry’s compliance costs (i.e., whether adoption and implementation of voluntary measures might shift the baseline against which BOEMRE should consider the incremental compliance costs).

DOCUMENTS REVIEWED IEc reviewed the following documents as part of this effort:

• Increased Safety Measures for Energy Devel opment on the Outer Continental Shelf , U.S. Department of the Interior, May 27, 2010 (the “30-Day Report”).84 • Proposed amendments to 30 Code of Federal Regulations (CFR) Pa rt 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, Ma y 2010 (referenced in the Joint Industry Task Force White Paper).

• Health, Safety and Environmental Case Guid elines 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 A dvisor, before the National Commission on the BP Deepwater Horizon Oil Spill and O ffshore Drilling, July 12, 2010.

IEc did not complete a detailed review of AP I 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 We ll Control and Oil Spill Response does not contain recommendations for voluntary measures but rather th e context for the Task Force’s near-term and longterm efforts, and thus does not contribute to the IEc analysis.

To facilitate the analysis, IEc retrieved electronic ve rsions 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, modi fied, or deleted text, using the redline/strikeout feature, to highlight the location and substance of each proposed change. The resultant document served as the basis for a comparison between proposed regulat ory 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 propo sed rules do not address and that could result in additional industry operating costs.August18,201085TABLE 1 COMPARISON OF RECOMMENDEDINDUSTRY VOLUNTARY MEASURES TO PROPOSED CHANGES IN 30 CFR PART 250RECOMMENDED INDUSTRY VOLUNTARY MEASURERELEVANT SECTION OF REGULATIONSPROPOSED REGULATORY CHANGEUpon release, adopt AP RP 65 Part 2: Isolating Potential FlowZones During Well Construction.30 CFR 250.415(f)New requirement for a discussion of how the best practicesdescribed in API RP 65 Part 2 were evaluated in the casingand cementing program.Engage casing hanger latchingmechanisms when casing isinstalled in the subsea wellhead.30 CFR 250.423(b)New requirement to perform a pressure test after theintermediate and production casing strings are installed toverify that the casing hangerlatching mechanisms or lockdown mechanisms are engaged and the casing has beensealed.Provide two independent barriers, including one mechanicalbarrier, for each flow path prior to displacement tounderbalanced fluid columns.30 CFR 250.420(a)(6)New requirement for a professional engineer to verify twoindependent tested barriers, including one mechanicalbarrier, across each flow pathduring well completionactivities.Perform negative tests to a differential pressure greater thanor equal to anticipated pressures after displacement.30 CFR 250.423(c) New requirement to perform a negative pressure test afterthe intermediate and production casing strings are installed.Test procedures and criteria must be submitted with the APDfor approval.Ensure shearable drillstring components are positioned in theshear rams during displacement.30 CFR 250.442(a) New requirement for two BOPs, rather than one, equippedwith a blind-shear rams, with a further requirement that theblind-shear rams are appropriately spaced to ensure that atleast one cuts the drillpipe and seals the wellbore.Ensure BOP can automatically close blind/shear ram(s) andclose choke/kill line valves30 CFR 250.442(f) Provide autoshear and deadman systems for dynamicallypositioned rigs.Ensure ROV can close blind shear rams, pipe rams, casingshear rams, and choke and kill valves. Ensure ROV canunlatch the lower marine riser package.30 CFR 250.442(d) When drilling with a subsea BOP system, the BOP must beequipped with ROV intervention capability; at a minimum,the ROV must be capable of closing all pipe rams, all shearrams, and unlatching the LMRP.TABLE 2 SELECTED ADDITIONAL RECOMMENDED INDUSTRY VOLUNTARY MEASURES

• Deepwater mobile offshore drilling unit pr oduces safety case, following guidelines established by the IADC.

• Develop Well Construction Interf acing Document to manage well construction activities and mitigate unexpected events that impact health, safety and the environment.

• Positively test each casing barrier to a pressu re 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 ca sing. 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 surfac e control of the su bsea BOP stack.

• Verify proper operation of the system by test ing 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 Ma nagement of Change process.

• Standardize ROV hot stab and receptacle per API Spec 17H. Standardize hot stab designs between drilling and production operations.

• Stage ROV tooling / external hydraulic power su pplies 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 propo sed regulatory changes with industry recommendations for safety and protection measures that industry could voluntarily adopt during the course of OCS oil and gas exploration and development activities.

None of the literature IEc reviewed suggests a n eed 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 ch anges in the expected frequency of spill events.

The comparison of recommended voluntary industry meas ures with proposed changes to 30 CFR Part 250 indicates several areas of overlap, as noted above in Ta ble 1. However, it is not possible at this time to conclude that the articulation of industry recomme ndations will necessarily translate into measurable87 changes in baseline industry costs against which BOEM RE would compare the cost to comply with new regulatory requirements. If, in the context of a be nefit-cost analysis, the measures in Table 1 were assumed to have been adopted, it would be appropriate to consider any associated costs as part of the baseline (i.e., the incremental cost to industry of the new regulations would be reduced). As BOEMRE considers additional regulatory changes, further co mparison to industry recommendations, including those listed in Table 2, would be warranted.