## Oil and Gas and Sulphur Operations **on the Outer Continental Shelf**

**– Requirements for Exploratory Drilling on the**  **Arctic Outer** 

**Continental Shelf Initial**  **Regulatory Im pact Analysis**  **RIN: 1082**  **- AA00** 

**NOTICE OF PROPOSED RULEMAKING DEPARTMENT OF THE INTERIOR**  **Bureau of Safety and Environmental Enforcement**

**(30 CFR Parts 250 and 254) Bureau of Ocean Energy Management** 

**(30 CFR Part 550) February**  **09 , 201**  **5**2



## Table of Contents 1. Introduction ................................ ................................ ................................ ................................ ........... 5 2. Need for Regulation ................................ ................................ ................................ .............................. 6 3. Alternatives ................................ ................................ ................................ ................................ ........... 9 4. Arctic OCS Economic Analysis ................................ ................................ ................................ ......... 10 a. Baseline Assumptions ................................ ................................ ................................ .................. 10 b. Costs ................................ ................................ ................................ ................................ ............. 13 c. Benefits ................................ ................................ ................................ ................................ ........ 14 d. Transfers ................................ ................................ ................................ ................................ ....... 17 e. Assumptions ................................ ................................ ................................ ................................ . 18 i. Affected Population of Operators and Drilling Operations ................................ .................... 18 ii. Wage Rates and Loaded Wage Factors ................................ ................................ ................... 21 iii. Daily Rig Operating Costs ................................ ................................ ................................ ...... 24 iv. BSEE Burden to Review Paperwork Submissions ................................ ................................ ... 24 5. Section -by - Section Analysis of Costs ................................ ................................ ................................ . 25 a. Additional Incident Reporting Requirements (§ 250.188) ................................ ........................... 26 b. Pollution Prevention Requirements (§ 250.300) ................................ ................................ .......... 27 c. Additional Requirements for Securing Wells (§ 250.402) ................................ ........................... 29 d. Additional BOP Pressure Testing Requirements (§ 250.447) ................................ ...................... 30 e. Real -time Monitoring Requirements (§ 250.452) ................................ ................................ ........ 31 f. Additional Information Requirements for APDs (§ 250.470) ................................ ...................... 32 g. Incorporation of proposed draft API RP 2N, Third Edition (§ 250.4 70) ................................ ..... 34 h. Additional SCCE Requirements (§ 250.471) ................................ ................................ ............... 35 i. Equipment Requirements ................................ ................................ ................................ ......... 37 ii. Stump Testing Requirements ................................ ................................ ................................ ... 38 iii. Well Design Change Information Requirements ................................ ................................ ..... 40 iv. Test and Exercise Requirements ................................ ................................ .............................. 41 v. Records Maintenance Requirements ................................ ................................ ....................... 41 vi. Documentation Requirements ................................ ................................ ................................ . 42 i. Relief Rig Requirements (§ 250.472) ................................ ................................ ........................... 43 j. Additional Auditing Requirements (§ 250.1920) ................................ ................................ ......... 49 k. Real -time Location Tracking Requirements (§ 254.80) ................................ ............................... 503

l. IOP Requirements (§ 550.204) ................................ ................................ ................................ ..... 54 m. Planning Information Requirements to Accompany EPs (§ 550.220) ................................ ......... 55 n. Industry Familiarization with the New Rule ................................ ................................ ................ 56 6. Summary of the Cost Analyses ................................ ................................ ................................ ........... 57 7. Break- Even Analysis ................................ ................................ ................................ .......................... 60 a. Dat a ................................ ................................ ................................ ................................ .............. 62 b. Method ................................ ................................ ................................ ................................ ......... 67 c. Results ................................ ................................ ................................ ................................ .......... 67 d. Qualitative Ben efits ................................ ................................ ................................ ...................... 69 e. Conclusion ................................ ................................ ................................ ................................ .... 73 8. UMRA ................................ ................................ ................................ ................................ ................ 734



## Abbreviations APD Application for Permit to Drill API American Petroleum Institute BBLs B arrels BLS Bureau of Labor Statistics BOEM Bureau of Ocean Energy Management BOP B lowout p reventer BSEE Bureau of Safety and Environmental Enforcement DOI Department of the Interior EO Executive Order EP Exploration Plan GO M Gulf of Mexico IOP Integrated Operations Plan MODU Mobile Offshore Drilling Unit OCS Outer Continental Shelf OMB Office of Management and Budget OSRP Oil Spill Response Plans PPCS P re -positioned capping stack RFA Regulatory Flexibility Act RIA Regulatory Impact Analysis SCCE Source Control and Containment Equipment SEMS S afety and Environmental M anagement S ystems UMRA Unfunded Mandates Reform Act of 19955

1. Introduction Changes to F ederal regulations must undergo several types of economic analyses . First, Executive Orders (E . O . ) 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select a regulatory approach that maximizes net benefits ( accounting for the potential economic, environmental, publ ic health, and safety eff ects ) . E . O . 13563 emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules, and promoting flexibility . Under E . O . 12866, an agency must determine whether a regulatory action is significant and, thus , subject to the requirements of the E . O . and Office of Management and Budget (OMB) review . Section 3(f) of E . O . 12866 defines a “significant regulatory action” as any rule that: (1 ) has an annual effect on the economy of $100 million or more, or adversely affects in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or S tate, local, or tribal governments or communities (also referred to as “economically significant”); (2) creates serious incon sistency or otherwise interferes with an action taken or planned by another agency; (3) materially alters the budgetary impacts of entitlement grants, user fees, loan programs, or the rights and obligations of recipients thereof; or (4) raises novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in E . O . 12866 . In addition , the Regulatory Flexibility Act of 1980 (RFA) requires agencies to consider the economic impact of regulatory changes on small entities . Finally, the Unfunded Mandates Reform Act of 1995 (UMRA) (Public Law 104 - 4) requires agencies to prepare a written assessment of the costs, benefits, and other effects of proposed or final rules that include a F ederal mandate likely to result in expenditure of $ 100 million or more annually (adjusted for inflation) by S tat e, local, or tribal governments in aggregate or by the private sector . In conducting analyses of the proposed rule , the Bureau of Ocean Energy Management ( BOEM ) and the Bureau of Safety and Environmental Enforcement ( BSEE ) provide the following summary:6

(1) We have determined that the proposed rule is a “ significant regulatory action” within the definition of E . O . 12866 because the estimated annual costs or benefits exceed $100 mill ion in at least one year of the analysis period; (2) We have determined that the proposed rule would affect operators and holders of F ederal oil and gas leases that could conduct exploratory drilling on the Arctic Outer Continental Shelf ( OCS ) , and an Initial RFA a

nalysis has been prepared for this proposed rule to discuss the potential impacts to small entities ; (3) We have determined that the proposed rule would not impose an unfunded mandate on S tate, local, or tribal governments as defined by the UMR A . We have determined that the proposed rule , if finalized, would impose a F ederal mandate that may result in the expenditure by the private sector of $100 million or more (adjusted annually for inflation) in any one year . This Initial Regulatory Impact Analysis (RIA) addresses requirements under the UMRA and E . O . s 13563 and 12866. BOEM and BSEE are requesting comments on the assumptions and data sources used in this Initial RIA . 2. Need for Regulation Although a comprehensive OCS oil and gas regulatory program exists , Department of the Interior ( DOI) engagement with partners and stakeholders reveals the need for new and revised regulatory measures for exploratory drilling by floating drilling vessels and jack up rigs ” (collectively known a s mobile offshore drilling units or MODUs) on the Arctic OCS. The U.S. Arctic region, as recognized by the United States and defined in the U.S. Arctic Research and Policy Act of 1984, encompasses an extensive marine and terrestrial area but this proposed rule focuses solely on the OCS within the Beaufort Sea and Chukchi Sea Planning Areas. BOEM and BSEE have undertaken extensive environmental and safety reviews of potential oil and gas operations on the Arctic OCS. These reviews, along with concerns expressed by environmental organizations and Alaska Natives, reinforce the need to develop additional measures7

specifically tailored to the operational and environmental conditions of the Arctic OCS. After considering the input provided by various partners and stakeholders and DOI’s direct experience from Shell’s 2012 Arctic operations, BOEM and BSEE have concluded that additional exploratory drilling regulations would enhance existing regulations and would be appropriate for a more holistic Arctic OCS oil and gas regulatory framework. This proposed rulemaking is intended to provide regulations to ensure Arctic OCS exploratory drilling operations are conducted in a safe and responsible manner that considers the unique condi tions of Arctic OCS drilling and Alaska Natives’ cultural traditions and need to access subsistence resources. The Arctic region is known for its oil and gas resource potential, its vibrant ecosystems, and the Alaska Native communities. The region is characterized by extreme environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing operations. These are key factors in considering the feasibility, practicality, and safety of conducting offshore oil and gas activities on the Arctic OCS. This proposed rule would add to, and revise existing regulations in 30 CFR p arts 250, 254, and 550 for Arctic OCS oil and gas activities. The proposed rule would focus on Arctic OCS exploratory drilling activities that use MODU s , and related operations , during the Arctic OCS open -water drilling season. This proposed rule would address several important issues and objectives, including ensuring that operators: ( 1 ) Design and conduct exploration programs in a manner suitable for Arctic OCS c onditions; ( 2 ) Develop an integrated operations plan (IOP) that would address all phases of their proposed Arctic OCS exploration program and submit the IOP to DOI, acting through its designee, BOEM, at least 90 days in advance of filing the Exploration Plan (EP); ( 3 ) Have access to, and the ability to deploy , Source Control and Containment Equipment while drilling below, or working below, the surface casing;8

( 4 ) Have access to a separate relief rig located so that it could timely drill a relief well , in the event of a loss of well control, under the conditions expected at the site ; ( 5 ) Have the capability to predict, track, report, and respond to ice conditions and adverse weather events; ( 6 ) Effectively manage and oversee contractors; and ( 7 ) Develop and implement Oil Spill Response Plans that are designed and executed in a manner suitable for the unique Arctic OCS operating environment and that have the necessary equipment, training, and personnel for oil spill response on the Arctic OCS. The proposed rule would further the N ation’s interest in exploring frontier areas, such as those in the Arctic region, and would establish specific operating models and requirements for the extreme, changing conditions that exist on the Arctic OCS. The proposed regulations would require comprehensive planning of operations, especially for emergency response and safety systems. The proposed rule would seek to institutionalize a proactive approach to offshore safety. A goal of the proposed rule is to identify possible vulnerabilities early in the planning process so that corrections could be made to decrease the possibility of an incident occurring. The requirements in the proposed rule also are designed to ensure that those plans would be executed in a safe and environmentally protective manner despite the challenges presented by the Arctic. 1 The following provisions of the proposed rule were identified to have a cost to industry : ( 1 ) Additional Incident reporting requirements ; ( 2 ) Additional p ollution prevention requirements ; ( 3 ) Additional requirements for securing wells ; ( 4 ) Additional blowout preventer ( BOP ) pressure testing requirements ;

1 An alternative for managing risk is to require operators to carry insurance to cover the social damages of a worst case scenario. Requiring insurance would help address the concern that operators may not be considering the social damages from an oil spill . Requiring insurance, however, is outside the scope of this proposed rule.9

( 5 ) Real -time monitoring requirements ; ( 6 ) Additional information requirements for Applications for Permit to Drill (APDs ) ; ( 7 ) Incorporation of proposed draft American Petroleum Institute (API) RP 2N , Third Edition ; (8) Additional SCCE requirements ; (9) Relief rig requirements ; (10) Additional Auditing requirements ; (11) Real -time location tracking requirements ; (12) IOP requirements ; (13) Additional requirements for EPs ; and (14) Industry familiarization with the rule. 3. Alternatives BOEM and BSEE have considered three alternatives for dealing with the safety and environmental concerns raised by exploration activities on the Arctic OCS: (1) Promulgat e the rule changes described in this proposed rule ; or (2) Promulgate the rule changes described in the proposed rule without including the 7 - day BOP pressure testing requirement for Arctic OCS exploratory drilling operations (in Section 250.447 of the proposed rule) ; or (3) Take no regulatory action and continue to rely on existing oil and gas regulations, industry standards , and operator prudence. BSEE has decided not to issue a proposed rule without the 7 - day BOP testing requirement. The additional testing requirement is intended to help ensure that BOPs deployed in the Arctic OCS function properly and reduce the risk of blowouts. BSEE has determined that the total cost to industry of including this requirement is $ 1 35 , 061 , 879 over the 10 - year analysis period ( assuming 7 percent discounting). The cost10

summary tables in Section 6 of this analysis present the total costs of the proposed rul e with and without the additional BOP pressure testing requirements . BOEM and BSEE have decided to move forward with this proposed rule, in lieu of taking no regulatory action, because relying on the regulatory status quo would not address the safety and environmental concerns raised by partners and stakeholders in the Arctic region and thus would not achieve the objectives of this proposed rule. In addition, the proposed rule would confer additional protections on the environment and Alaska Native cultural activities . 4. Arctic OCS Economic Analysis BOEM and BSEE evaluated the potential cost impacts of the proposed rule against the baseline. T he analysis reflects only the activities and capital investments require d by the proposed rule that represent a change from the baseline. This section provides an overview of the analysis of costs and benefits and the assumptions used to conduct the analysis.

a. Baseline Assumptions The baseline refers to existing regulatory requirements, industry standards, and operator prudence. Thus, the economic analysis excluded activities or capital investments that existing regulations require as well as impacts resulting from the incorporation of industry standards with which industry volu ntarily complies. The baseline also includes costs associated with requirements that BOEM or BSEE have previously routinely imposed in other regions under their existing regulatory authorities but does not include the costs described as follows : i. Relief Rig Capital Costs: The proposed rule requires Arctic OCS operators to have access to a separate relief rig located such that it could timely drill a relief well if a loss of well control were to occur and drilling a relief well becomes necessary. Although a relief rig was required by DOI during Shell’s 2012 Arctic operations, and although BOEM and BSEE anticipate that we would11

exercise our existing authorities to require a relief rig for any future exploratory drilling on the Arctic OCS, we chose no t to include the capital costs associated with staging a relief rig that may not be conducting exploratory drilling (i.e., a standby rig) in the baseline. Instead we conservatively chose to include such costs as part of the costs of the rule, in the detailed economic analysis contained in the Initial RIA. The costs are estimated at $276 million per year per standby rig. Based on Exploration Plans and other information, however, BOEM and BSEE believe that, in the future operators would likely designate a second operating rig to be a relief rig (instead of staging a dedicated standby relief rig) because, over time, the increased presence of multiple operating rigs on the Arctic OCS would make it easier for one operating rig to be designated as a relief rig for another operating rig. Nonetheless, because an operator may choose to deploy a dedicated standby relief rig, the economic analysis conservatively includes the estimated costs for a standby rig for 2015 and 2016. In addition, costs associated with documenting a relief rig plan are not included in the baseline for the analysis and are included in the economic analysis. ii. Relief Rig Activity Costs : The proposed rule would establish a 45 - day maximum limit on the time necessary to complete relief well operations under Section 250.472 . This provision effectively would require the cessation of exploratory drilling or other work below the surface casing far enough in advance of the expected return of seasonal ice to allow for completion and abandonment of a relief well. BOEM and BSEE - approved plans for 2012 Arctic operations required drilling operations in zones that can support the flow of liquid hydrocarbons in measurable quantities into the well to be concluded 38 days before November 1, based on satellite imagery showing the five - year historical average of earliest encroachment of sea ice over the applicant’s drill site and the estimated time required to drill a relief well . Thus , the baseline for12

this analysis includes this 38 - day requirement from 2012. Accordingly, the costs of the proposed 45 - day maximum timeframe include only the costs of the additional 7 days (45 days minus 38 days) not included in the baseline during which drilling or working below the surface casing could not take place . BSEE recognizes that the actual length of this limitation would depend on the operator’s specific plans for staging and deploying a relief rig and that, in some cases, the operator could demonstrate that it could complete a relief well in less than 45 days and thus would not need to cease drilling or working below the surface casing 45 days before the expected return of seasonal ice. However, BSEE has conservatively estimated the additional 7 - day costs of the limitation, based on the proposed 45 - day timeframe, since some operators may need to use the maximum amount of time . During this period, however, an operator may be able to conduct a number of different operations at the well site that do not involve work below the surface cas ing **.** Section 5 .i below discusses the challenges associated with estimating cost impacts associated with the additional 7 - day limitation (above the baseline) on work below the surface casing. 

### iii. BOP Pressure Testing Requirements: We do not include the 7 - day BOP pressure testing requirements in the baseline for the analysis because , although Shell agreed to this requirement as a condition of its 2012 operations, Shell did not end up conducting these BOP pressure tests during that operating season. T hus , we conservatively include the costs associated with the increased BOP pressure testing requirements in the analysis of the costs for Alternative 1. In addition, we analyzed the costs of the additional BOP pressure testing to help compare the costs for Altern ative 1 (the proposed rule with additional BOP testing) and Alternative 2 (the proposed rule without additional BOP pressure testing) , as discussed below and illustrated in Exhibits 23 and 24.13

b. Costs The “Section -by - Section Analysis of C osts” section belo w describes how we quantified and monetized the potential economic costs of the proposed rule . The section identifies all provisions that c ould result in increased labor requirements or capital investments from industry or government . 2 For the purpose of transparency, we include footnotes presenting the information on data inputs and the details of the calculations for each rule provision for which monetization is feasible . T he analysis covers 10 years (201 5 through 202 4 ) to ensure it captures important b enefits and costs that could result from the proposed rule . 3 A 10 - year period was used for this analysis because of the uncertainty associated with predicting industry’s activities and the advancement of technical capabilities. For example, over time, the costs associated with a p articular new technology may decrease as the technology is adopted more broadly. In other cases, an existing technology may be replaced by a lower - cost alternative as business needs drive technological innovation. Itis very dif ficult to predict, plan , or project costs associated with technological innovation due to unknown technological or business constraints that could drive a product into mainstream adoption or into obsolescence . The regulated community itself has difficulty in planning for technological innovation beyond a 10 - year time frame. Extrapolating results beyond this 10 - year time frame would produce more ambiguous results and , therefore , be disadvantageous in determining actual costs and benefits likely to result from this proposed rule. BOEM and BSEE concluded that this 10 -year analysis provides the best overall ability to reasonably forecast estimated costs and benefits likely to result from this proposed rule. When summarizing the costs and benefits, the estimated annual effects are presented , as well as the 10 - year discounted totals using discount rates of 3 and 7 percent following the guidance in OMB C ircular A 4, “Regulatory Analysis ,” September 17, 2003 .

2 The recordkeeping costs for this proposed rule are included in these cost estimates and in the Paperwork Reduction Act statement for the proposed rule, which addresses recordkeeping requirements only. 3 Circular A

– 4, http://www.whitehouse.gov/omb/circulars_a004_a - 4 .14

BOEM and BSEE welcome comments on this analysis , including potential sources of data or information on the costs and potential benefits of this proposed rule. The following proposed requirements would result in additional costs above the baseline: Incident Reporting Requirements; Additional Pollution P revention Requirements; Additional Requirements for Securing Wells; Additional BOP Pressure Testing Requirements; Real -time Monitoring Requirements; Additional Information Requirements for APDs; Incorporation of proposed draft API RP 2N , Third Edition ; 4 Additional SCCE Requirements; Relief Rig Requirements; Additional Auditing Requirements; Real -time Location Tracking Requirements; IOP Requirements; Planning Information Requirements to Accompany EPs; and Industry Familiarization with the New Rule. Exhibit s 23 and 24 present a summary of the costs of the proposed rule.

c. Benefits Although many of the benefits of the proposed rule

— based primarily on preventing or reducing the severity or duration of catastrophic oil spills

—are difficult to quantify, BOEM and BSEE have determined that the benefits would justify the rule’s potential costs and that proceeding with this propos al is appropriate . T he probability of a catastrophic oil spill is very low ; however , the Deepwater Horizon incident demonstrate d that even s uch low probability events can have devastating economic and environmental results when they occur . Moreover , this proposed rule would help achieve the National Arctic Strategy goals of protecting the unique and sensitive Arctic ecosystems and the subsistence needs, culture , and traditions of the Alaska Native communities. The proposed requirements

— which are specifically tailored to the Arctic OCS

— would provide additional clarity and specificity regarding the expectations of BOEM and BSEE for safe and responsible exploration of Arctic resources and the particular actions that lessees, owners , and operators must take to meet those expectations. Th e additional clarity and specificity provided by the

4 API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions” would be incorporated by reference in Section 250.198 of the proposed rule 

### .15

proposed rule is intended to help the oil and gas industry plan and more effectively conduct exploratory drilling o n the Arctic OCS , resulting in the development o f oil and gas with lower risk and fewer delays than under the existing rules. According to BOEM’s 2011 Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s Outer Continental Shelf (available at http://www.boem.gov/Oil - and - Gas - Energy - Program/Resource - Evaluation/Resource Assessment/2011_National_Assessment_Factsheet -pdf.aspx) , approximately 17.8 billion barrels of economically recoverable oil ( at a price of $110 per barrel) and about 50.1 trillion cubic feet of economically recoverable natural gas (at a price of $7.83 per million cubic feet) are in the Beaufort Sea and Chukchi Sea Planning Areas combined. Thus, the impact of production in the Arctic region on U.S. energy independence and energy security could be substantial. The proposed rule would benefit society and the environment by reducing the potential that incidents resulting in catastrophic oil spills would occur and, if an incident does occur , by reduc ing its severity or duration. 5 The objective of the proposed rule is to ensure safe and responsible oil and gas drilling on the Arctic OCS resulting in increased safety for personnel ; protection of the coastal, human, and marine environment s and species ; and reducing conflicts between OCS oil and gas activities and Alaska Natives ’ ability to conduct subsistence activities . T he magnitude of these benefits, however, is uncertain and highly dependent on the actual reduction in the probability of incidents and the increased effectiveness of stopping a spill underway . A catastrophic oil spill is characterized as a low probability, high consequence event because it is an event that occurs infrequently but has large consequences when it does occur. For low probability, high consequence events, knowing with any certainty the probability of an event actually occurring is difficult , as is precisely determining the reduction in the probability of occurrence that a proposed regulation actually would achieve . In addition, the consequences of an oil spill depend on several factors, including the type

5 Although this analysis focuses on the benefits of reducing the probability, duration, or severity of a catastrophic oil spill, BSEE re cognizes that similar benefits would occur with regard to significant but non - catastrophic oil spills. Those additional benefits are not quantified in this analysis since the BOEM Economic Analysis Methodology for the Five Year OCS Oil and Gas Leasing Program for 2012

–2017, on which this analysis is primarily based, addresses catastrophic oil spills.16

and amount of oil, the location of the spill, the areal distribution of the release, the sensitivity of the ecosystem affected, and the weather . B reak- even analysis is a method commonly used in regulatory analysis to estimate the minimum level of benefits that a regulation must achieve to be cost -beneficial, or to have benefits that are at least as large as its costs. For regulations that enh ance safety and protect the environment, break- even analysis often is conducted by determining the minimum level of consequence reduction needed for a regulation to break even. If the proposed rule exceeds this threshold, it would be cost -beneficial. The break- even analysis that follows describes the reduction in expected spill duration needed to generate certain quantifiable benefits equal to or greater than the estimated control costs associated with this rule. T he proposed rule also has benefits beyond what we captured in the break- even analyses. Due to both the uncertainty and difficulty of measuring these benefits, we do not offer a quantitative assessment of them ; instead, we present a qualitative discussion. Because BOEM and BSEE used a conservative approach in the valuation of a catastrophic oil spill, that is , the valuation included only selected costs of a catastrophic oil spill, the resulting measures from incurring (or avoiding) such an oil spill can be considered a lower bound of the true cost (or benefit) to society. Although we capture the environmental damage associated with a catastrophic oil spill, the analysis is limited because it considers only the environmental amenities that researchers could identify and monetize. Natural resource valuation is complex ; many factors contribute to how society values a resource, including but not limited to use and non -use values of the resources. Many use values can be derived by behavior and market transactions (for example, using the harvest value of yields in the Arctic region). Some use values, however, might not be related to a market and are, therefore, difficult to monetize. For example, Alaska Native communities place a high value on the cultural amenities related directly to the17

use of the regio n. Because communities do not trade cultural amenities in markets, we are unable to estimate a direct value for these resources. Non -use values are even harder to estimate; common non -use values include existence values and bequest values. Individuals plac e an added value on ecosystem health and environmental amenities by simply knowing that these amenities will be preserved and protected in the region even if those same individuals do not intend to visit the region. Bequest values relate to individuals’ placing a value on the preservation of the regions’ environmental amenities for future generations even if the individuals do not intend to use the resource themselves. Capturing these complex values is difficult because they are not traded in markets. Bec ause we are unable to monetize all aspects of the consequences of an oil spill, the estimate we used in the quantitative break- even analysis captures only a portion of the value to society from mitigating the consequences of a catastrophic oil spill. Although several components of this rulemaking would improve the coordination and monitoring of drilling and other exploration operations and are designed to prevent a spill, the most expensive components of this proposed rule are designed to reduce the severity or duration of a catastrophic oil spill, should one occur. By requiring local availability of SCCE, which is designed to either cap a well blowout or capture the flow, and codifying requirements from the 2012 drilling season , the duration and severity of impacts from a well blowout will be reduced. d. Transfers We identif

ied no transfer payments associated with the proposed rule . Transfer payments, as defined by OMB Circular A - 4, are payments from one group to another that do not affect total resources avail able to society . Transfer payments are associated with a distributional effect but do not result in additional economic benefits or costs to society .18

e. Assumptions We estimated the costs and benefits presented in this document using various data inputs . Some of these data inputs were common to many of the calculations, including the assumptions discussed below about the affected population of operators and drilling operations , wage rates and loaded wage factors , daily rig operating costs , and the burden f or BSEE to review paperwork submissions . i. Affected Population of O perators and Drilling O

perations Based on BOEM ’s and BSEE’s knowledge of operators engaged in, or likely to be engaged in, Arctic OCS exploration activities , we made several assumptions ab out the number of operators, rigs, and wells operating on the Arctic OCS over the 10 - year analysis period . We also made assumptions about the number of APDs, EPs, IOPs, and OSRPs that operators on the Arctic OCS would submit. Operators, Rigs, and Wells BOEM and BSEE assume that three operators would operate on the Arctic OCS over the 10 -year analysis period , with one operator conducting exploratory drilling beginning in 201 5 and two more operators conducting exploratory drilling beginning in 201 8 . This is BOEM and BSEE ’ s best projection of the number of operators expected to conduct exploratory drilling on the Arctic OCS based on current leases, plans and permits , and expectation s . For the total number of exploratory wells on the Arctic OCS, we assume two wells in 2015, four wells from 2016 through 2019, and six wells from 2020 through 2 024. SCCE and Resource Sharing T he proposed rule requires operators to have access to, and the ability to deploy promptly , SCCE while conducting Arctic OCS exploratory drilling or work below the surface casing. In the cost analysis, we assume that the operator conducting exploratory drilling beginning in 2015 already own s the required SCCE and that additional operator s will purchase or otherwise acquire access to the19

SCCE for operations in later years . We assume that the operator with two primary rigs in 2017 will use one set of SCCE equipment to satisfy the SCCE requirements for both of its rigs. We assume that , of the two operators entering in 2018, one will purchase the SCCE equipment, and the other will select the least - cost me ans to comply with the proposed rule and thus enter into resource sharing with an operator who has already purchased the SCCE equipment . We refer to this below as the central cost scenario. Because the industry does not currently engage in resource sharing on the Arctic OCS, BOEM and BSEE have no details on how the process would be conducted and whether or to what degree , for example, an operator would charge for access to equipment. The SCCE resource - sharing assumptions presented in the cost analysis section represent the most likely scenario based on BSEE’s knowledge of the industry . BSEE also considered a low - cost scenario and a high - cost scenario that vary the assumptions for resource sharing and purchase of SCCE by operators. These alternative scenarios are discussed here but are not included in the cost analysis section. BOEM and BSEE request comment on the costs and resource - sharing assumptions associated with these SCCE requirements. Fo r the high - cost scenario, we assume no resource sharing of SCCE between operators . We assume that one entity already owns the equipment while the other two entities will each need to buy the equipment in their first year of operation (2018). We assume that each operator experiences the annual deployment cost of the equipment. For the low - cost scenario, we assume that only the operator that currently owns the SCCE would have the equipment and that the other entities would engage in resource sharing of the e quipment. Under this scenario, there is no capital cost for the equipment because the initial operator already owns the equipment. Exhibit 1 summarizes the assumptions for each of the three scenarios. All scenarios assume compliance with the requirements o f the proposed rule, and the assumptions regarding20

resource sharing and purchase of SCCE vary as described above. We seek comments on the reasonableness of the assumptions presented in this section. **Exhibit 1 .**  **Source Control and Containment Equipment Assum ptions (**  

### § **250.471) Scenario**  **Number of SCCE Purchased**  **Number of SCCE Deployed**  **Number of Operators**

**Engaging in Resource Sharing**  Low Cost Scenario 0 1 2 Central Cost Scenario 1 2 1 High Cost Scenario 2 3 0 Section 5.h below describes the capital and labor costs associated with the purchase and redeployment of SCCE equipment. Exhibit 2 shows the difference in SCCE costs associated with Section 250.471(a) among the three SCCE scenarios . **Exhibit 2 .**  **10 -** **Year Discounted Total Equipment Costs**  **for Low, Ce ntral, and High SCCE Cost**  **Scenarios (§250.471(a))**  **Discounting Low**  **Central High**  **Difference Low**  **- Central**  **Difference**

**High -**  **Central A**  **B C**  **A −**  **B C**  **− B**  7% Discounting $9,018,279 $235,067,362 $461,116,446

− $226,049,084 $226,049,084 3% Discounting $10,543,331 $264,678,746 $518,814,161

− $254,135,415 $254,135,415 Submittals to BOEM and BSEE We make the following assumptions about submittals to BOEM and BSEE : (1) We assume that the number of wells drilled and the number of APD s submitted to BSEE will be equal to each other for each year of the analysis period ;21

(2) We assume that one EP will be submitted to B OEM in the first year of the analysis and two EP s in each following year . These assumptions reflect the fact that EPs can be submitted years in advance and can cover multi - year operations ; and (3) We assume that two IOPs and two OSRPs will be submitted in each year of the analysis period . We based all assumptions on our experience with recent and expected industry practices for operators on the Arctic OCS, including information submitted to BOEM and BSEE by lessees and operators and other available information related to planned or potential industry exploratory activities for the analysis period. We present these inputs in Exhibit 3. We seek comments on the reasonableness of the assumptions presented in Exhibit 3 . **Exhibit 3 .**  **Assumptions about the Affected Population of Operators and Drilling Operations Inputs**  1 **2015 2016**  **2017 2018**  **2019 2020**  **2021 2022**  **2023 2024**  Operators 1 1 1 3 3 3 3 3 3 3 Primary rigs 1 1 2 4 4 4 4 4 4 4 Standby relief rigs 2 1 1 0 0 0 0 0 0 0 0 Exploratory w ells drilled e ach year 2 4 4 4 4 6 6 6 6 6 Applications for p ermit to drill 2 4 4 4 4 6 6 6 6 6 Exploration p lans 1 2 2 2 2 2 2 2 2 2 Integrated operations p lans 2 2 2 2 2 2 2 2 2 2 Oil spill response p lans 2 2 2 2 2 2 2 2 2 2 1 These estimates are a maximum that BOEM and BSEE assume could be expected in any one year ; they should not be viewed as additive. For example, in 201 8 , up to three operators and up to four we lls could be expected. 2 W e refer to relief rigs that are not conducting exploratory drilling as “standby relief rigs, ” and these rigs are assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e. “primary rigs” or “operating rigs”). ii. Wage R ates and L oaded W age F actors Many of the calculations in this analysis used wage rates for Arctic OCS oil and gas workers and for BOEM and BSEE employees . For this analysis, we obtained median industry wage rates from the22

Bureau of Labor Statistics (BLS ) May 2012 Occupational Employment Statistics for the industry labor categories . We also obtained wage rates for BOEM and BSEE personnel from the Office of Personnel Management 2012 General Schedule for the government labor categories . Exhibit 4 presents these wages .23 **Exhibit 4 .**  **Compensation Rates Used in the Analysis Industry Occupation**  **Median Hourly Wage Rate**  **Estimated Hourly** 

**Compensation Rate**  **Details (Occupation Title,**

**Occupation Code, NAICS**  **/Location )**  Senior Engineer $73.32 $104.22 Architectural and Engineering Managers, 11 - 9041, 211100 Clerical/Administrative Staff $20.64 $29.34 Secretaries and Administrative Assistants, 43 - 6010, 211100 Manager $65.56 $93.19 General and Operations Managers, 11 - 1021, 211100 Mid - Level Engineer $67.48 $95.92 Petroleum Engineers, 17 - 2171, State of Alaska Skilled Laborer $40.00 $56.86 Based on BSEE’s knowledge of the industry Environmental Specialist $47.03 $66.85 Environmental Scientists and Specialists, 19 - 2041, 211100 Electrician $36.69 $52.15 Electrician , 47 - 2111, State of Alaska **Government Occupation Hourly Rate**  **Estimated Hourly**  **Compensation Rate**  **Details (GS Grade and**

**Step, Locality)** BSEE Mid - level Engineer $48.53 $82.02 13.5, State of Alaska BSEE Inspector $57.35 $96.92 14.5, State of Alaska BSEE Senior Engineer $57.35 $96.92 14.5, State of Alaska BSEE Administrative Staff $23.01 $38.89 7.5, State of Alaska BSEE Program Analyst $40.81 $68.97 12.5, State of Alaska BSEE Supervisory Engineer $67.46 $114.01 15.5, State of Alaska BOEM Regulatory Analyst $34.05 $57.54 11.5, State of Alaska BOEM Petroleum Engineer $40.81 $68.97 12.5, State of Alaska BOEM Geologist $18.57 $31.38 5.5, State of Alaska BOEM Chief, Plans Section $57.35 $96.92 14.5, State of Alaska BOEM Regional Supervisor $67.46 $114.01 15.5, State of Alaska Sources: B LS May

2012 Occupational Employment Statistics ; O ffice of Personnel Management 2012 General Schedule Locality Pay T ables.24

To account for employee benefits, we multiplied the hourly wage rates by appropriate loaded wage factors to generate hourly compensation rates. For industry employees, we used a private - sector loaded wage factor of 1.42 derived from the 2012 BLS index for salary and benefits. For BOEM and BSEE employees, we used a Federal loaded wage factor of 1.69 derived from a U.S. Department of Labor analysis of overhead costs (in the absence of a similar estimate for BOEM or BSEE). 6 We multiplied the hourly wage rates by the appropriate loaded wage factor to estimate the hourly compensation rates. iii. Daily Rig Operating Costs Some requirements in the proposed rule affect rig operations. To monetize the impacts of these requirements, we estimated the daily operating costs for affected rigs. Based on BSEE estimates and cost estimatio n methodologies from the BOEM Economic Analysis Methodology for the Five -Year OCS Oil and Gas Leasing Program for 2012

–2017 ( the “BOEM Case Study”) , 7 we assume that rigs on the Arctic OCS have a daily operating cost of $2,000,000. For the purposes of the analysis, we assume that the daily rig operating costs remain constant over the 10 -year analysis period. W e assume that the drilling season on the Arctic OCS lasts 138 days. iv. BSEE Burden to Review Paperwork Submissions For each paperwork submis sion, BOEM and BSEE estimate the labor hours needed on behalf of the industry to compile and submit the information. To estimate the corresponding burden for BSEE, we

6 The 1.69 index is derived by using the BLS index for salary and benefits plus a U.S. Department of Labor analysis of overhead costs averaged over agency emp loyees. 7 Source: U.S. Department of the Interior, Bureau of Ocean Energy Management, 2012. “Economic Analysis Methodology for the Five Year OCS Oil and Gas Leasing Program for 2012

–2017,” BOEM OCS Study 2012

–022, pages 67

–73, available at http://www.boem. gov/uploadedFiles/BOEM/Oil_and_Gas_Energy_Program/Leasing/Five_Year_Program/2012 - 2017_Five_Year_Program/PFP%20EconMethodology.pdf.25

assume that for every hour that industry devotes to compile and submit information, BSEE will need one half hour to review the submission. 8 , 9 5. S ection -by - Section Analysis of C osts The analysis presented in this document describes the potential costs of the proposed rule compared to the baseline (i.e., existing regulations and industry standards with which industry already complies) . The following requirements would result in a change from the baseline: ( 1 ) Additional Incident Reporting Requirements ; ( 2 ) Pollution Prevention Requirements ; ( 3 ) Additional Requirements for Securing Wells ; ( 4 ) Additional BOP Pressure Testing Requirements ; ( 5 ) Real -time Monitoring Requirements ; ( 6 ) Additional Information Requirements for APDs ; ( 7 ) Incorporation of proposed draft API RP 2N , Third Edition 10 ; ( 8 ) SCCE Requirements ; ( 9 ) Relief Rig Requirements ; ( 10 ) Additional Auditing Requirements ; ( 11 ) Real -time Location Tracking Requirements ; 8 The submissions to BOEM under Part 550 of the proposed rule do not follow this standard review

estimate because these submi ssions wo uld require a more time - intensive review by several employees. 9 BSEE based the one half - hour estimate on previous paperwork burden statements that assume that the government burden is half the industry burden (see the paperwork burden supporting statement 1014 - 0018). 10 API RP 2N, Third Edition, “Recommended Practice for Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions” would be incorporated by reference in Section 250.198 of the proposed rule .26

( 12 ) IOP Requirements ; ( 13 ) Planning Information Requirements to Accompany EPs ; and ( 14 ) Industry Familiarization with the New Rule . These requirements and their associated costs to industry and government are presented in the sections below . This Initial RIA closely mirrors the language of the proposed rule ; however, the proposed rule regulatory text reflects what would become legally binding if adopte d as a final rule . a. Additional Incident Reporting Requirements (§ 250.188) Proposed s ection 250.188(c) includes new incident reporting requirements for operators on the Arctic OCS . Operators would be required to provide an immediate oral report to the BSEE onsite inspector, if one is present, or to the Regional Supervisor of any sea ice movement or condition that has the potential to affect operations or trigger ice management activities, as well as the start and termination of such activities, and any “kic ks” or operational issues that are unexpected and could result in the loss of well control. Operators would also be required to submit a follow -up written report regarding any ice management activities undertaken , within 24 hours following completion of those activities. These requirements would help ensure that BSEE is notified in sufficient time to oversee the safety of an operator’s reactions and to prepare in the event that a response would be necessary due to a safety or environmental incident resulting from an ice event . These reporting requirements would result in labor costs to industry and to BSEE . We calculated the annual labor cost per rig by multiplying the time required for each report by the median hourly compensation rates for the labor categ ories most likely to complete these activities . The result was an27

annual labor cost to industry per rig of $ 1,146 . 11 To estimate the cost to BSEE to review these reports, BOEM and BSEE multiplied the total hours assumed to review these reports by the hourly compensation rates for the labor categories most likely to complete these activities . The result was an annual labor cost to BSEE per rig of $533 . 12 Exhibit 5 summarizes the annual costs for the incident reporting requirements. We seek comments on the reas onableness of the assumptions in this section.

**Exhibit 5 .**  **Additional I**  **ncident Reporting Requirements**  **(** 

### § **250.188)**

**Year Number of** 

**Rigs Industry** 

**Cost per Rig Annual Cost**  **Number of Rigs**  **Agency Cost**

**per Rig Annual Cost**  **A B**  **C = A × B D**  **E F = D x E**  2015

–2016 1 $1,146 $ 1 , 146 1 $533 $ 533 2017 2 $1,146 $2,293 2 $533 $1,066 2018

–2024 4 $1,146 $4,586 4 $533 $2,132 b. Pollution P revention Requirements (§ 250.300) Proposed s ections 250.300(b)(1) and 250.300(b)(2) include revised pollution prevention requirements for exploratory drilling operations on the Arctic OCS . Operators would be required to capture all petroleumbased mud and cuttings from operations that utilize petroleum -based mud. In addition, these subparagraphs clarify the Regional Supervisor’s discretionar y authority to require operators to capture all water -based mud s and associated cuttings from Arctic OCS exploratory drilling operations after completion of the hole for the conductor casing to prevent their discharge into the marine environment, based on factors including, but not limited to:

11 We assume that incidents for which there are new reporting requirements under the proposed rule would occur two times a year for each rig. We assume that industry senior engineers would spend 1.5 hours on the oral report and 4 hours on the w

ritten report. We multiplied the time spent on reporting by the median hourly compensation rate for senior engineers for an annual cost per rig associated with incident reporting of $1,146 ((2 ice movement incidents × (1.5 hours + 4 hours)) × $104.22). 12 Using assumptions similar to those for industry, we assume that the BSEE will review the oral and w ritten reports as submitted (i.e. twice per year). We assume that for every hour spent on a submission, BSEE would spend 1⁄2 hour to review . We multiplied the total industry burden per rig associated with these incident - reporting requirements (11 hours) by 1⁄2 to estimate 5.5 hours to review for a BSEE senior engineer. We multiplied the time spent on review by the compensation rate to estimate a $533 per rig cost to review (5.5 hou rs x $96.92).28

(1) The proximity of the exploratory drilling operations to subsistence activities; (2) The extent to which discharged mud or cuttings may cause marine mammals to alter their mi gratory patterns in a manner that interferes with subsistence activities; or (3) The extent to which discharged mud or cuttings may adversely affect marine mammals, fish, or their habitat. Addressing both environmental concerns and the concerns of Alaska Natives regarding the potential impacts of discharges of mud and cuttings, these pollution prevention requirements would help prevent or minimize the likelihood of environmental damage and interference with Alaska Native s’ subsistence activities from discharges of mud and cuttings . Th ese requirements would result in labor costs to industry associated with transporting and disposing of both water -based and petroleum -based mud and cuttings . We calculated the annual labor cost per rig by multiplying the time required for these activities by the median hourly compensation rates for the labor categories most likely to complete these activities . These calculations resulted in an annual labor cost of $4,245 per rig . 13 Exhibit 6 summarizes the annual cost for the pollution prevention requirements . We seek comments on the reasonableness of the assumptions in this section.

**Exhibit 6 .**  **Pollution Prevention Requirements (§**  **250.300) Year**  **Number of Rigs Cost**  **p er Rig**  **Annual Cost A**  **B C = A**  **× B**  2015

–2016 1 $4,245 $ 4 , 245 2017 2 $4,245 $8,491 2018

–2024 4 $4,245 $16,981

13 We assume that a skilled laborer on the rig crew and an industry senior engineer would spend, respectively, 60 and 8 hours annually to transport and dispose of mud and cuttings. We multiplied the median hourly compensation rates by the numb er of hours assumed to be spent for these labor categories and summed the results to obtain an annual labor cost of $4,245 ((60 hours × $56.86) + (8 hours × $104.22)) per rig.29

c. Additional Requirements for S ecuring W ells (§ 250.402) Proposed s ection 250.402(c) includes new requirements for securing wells for exploratory drilling operations on the Arctic OCS . Operators that move a drilling rig off a well prior to completion or permanent abandonment would be required to ensure that any equipment left on , near, or in a well bore that has penetrated below the surface casing is positioned in a manner to protect the well head and prevent or minimize the likelihood of compromising the down - hole integrity of the well or well plug effectiveness . Additionally, in areas of ice scour , operators would be required to use a well cellar or an equivalent means of minimizing the risk of damage to the wellhead . 14 These new requirements would help reduce the risk associated with damage to the well or to equipment associated with ice floe or other potential sources of damage . These requirements would result in labor costs to industry . We calculated the annual labor costs to industry associated with these requirements by multiplying the annual number of days of rig crew time assumed to be spent to conduct these activities by the daily rig operating cost . These calculations resulted in an annual labor cost of $ 3 ,000,000 per well . The well cellar requirements would result in capital and labor costs to industry for each well drilled . These capital and labor costs are estimated to be $2,000,000 per well. 15 Exhibit 7 summarizes the annual costs of the additional requirements for securing wells . BOEM and BSEE request comments on the costs associated with securing wells. We seek comments on the reasonableness of the assumptions in this section .

14 A well cellar is a hole excavated into the seafloor that can house well head equipment to provide protection against damage from ice scouring the seafloor. 15 We assume that the operator would move off each well once per year and that, for each occurrence, the rig crew wo uld spend 1.5 days to comply. We multiplied the number of days required per occurrence by the daily rig operating costs to obtain an annual labor cost of $3,000,000 (1.5 days × $2,000,000) per well. We assume a capital and labor cost to industry associated with the well cellar requirements of $2,000,000 per well.30 **Exhi bit 7**  **. Annual**  **Additional Requirements for Securing Well s**  **(§ 250.402)** 

**Year Number** 

**of Wells**  **Labor Cost**

**per Well Well Cellar** 

**Capital and**  **Labor Cost**  **per Well Annual Cost**  **A B**  **D E =**  **( A × B**  **) +**  **(A × D**  **)** 2015 2 $3,000,000 $2,000,000 $10,000,000 2016

–2019 4 $3,000,000 $2,000,000 $20,000,000 2020

–2024 6 $3,000,000 $2,000,000 $30,000,000 d. Additional BOP P ressure T esting Requirements ( 

### § 250.447) Proposed s ection 250.447(b) includes new requirements for pressure testing of BOP systems on the Arctic OCS . Operators conducting Arctic OCS exploratory drilling operations would be required to begin testing the BOP system before midnight on the seventh day following the conclusion of the previous test . This requirement would represent an increased testing frequency relative to the existing baseline requirement to begin testing the BOP system before midnight on the 14th day following the conclusion of the previous test . These requirements would result in annual operating costs to industry . We calculated the annual operating costs to industry associated with testing requirements by multiplying the assumed additional number of operational days spent annually on testing by the daily rig operating cost, resulting in an annual operating cost of $6,000,000 per rig . Although operators will perform these tests on each well, we assume that no rig will be drilling two wells simultaneously and , therefore , the cost of testing should be calculated per -rig rather than per -well . 16 Exhibit 8 summarizes the annual costs of the additional BOP pressure testing requirements . We seek comments on the reasonableness of the assumptions in this section.

16 Although the exact length of time actually required to perform each BOP test would depend on the specific circumstances applicable to each well, we assume that about 10 additional tests would be required each season under the proposed rule, and that a to tal of 3 additional operational days would be spent annually on testing as a result of the proposed requirement. We then multiplied that number of days by the daily rig operating cost to obtain an annual cost to industry, per rig, of $6,000,000 (3 days × $2,000,000).31

As an alternative to the proposed rule, BSEE considered not including these additional BOP pressure testing requirements for Arctic OCS exploratory drilling operations. (See Alternative 2 in Section 3 of this analysis.) BSEE has decided not to issue a proposed rule without the 7 - day BOP testing requirement. The additional testing requirement is intended to ensure that BOPs deployed in the Arctic OCS function properly and reduce the risk of blowouts. See Section 6 of this analysis for the total costs of the proposed rule with and without th e additional BOP pressure testing requirements .

**Exhibit 8 .**  **Annual Additional BOP Pressure Testing Requirements**  **(** 

### § **250.447) Year**  **Number of Rigs Cost**  **p er Rig**  **Annual Cost A**  **B C = A × B**  2015 1 $6,000,000 $ 6 ,000,000 2016

–2019 2 $6,000,000 $12,000,000 2020

–202 4 4 $6,000,000 $24,000,000

e. Real -time M onitoring Requirements (§ 250.452) Proposed s ection 250.452 outlines new real -time monitoring requirements for Arctic OCS exploratory drilling operations . Paragraph (a) includes requirements for real -time data gathering and monitoring capability for data on the BOP control system, the fluid handling systems on the rig, and the well’s downhole conditions ; and paragraph (b) includes requirements for onshore data transmission, monitoring, storage, and notification and availability to BSEE . These new requirement s result , in part, from recommendations from investigations of the Deepwater Horizon incident and would help to improve safety and oversight of operations . These monitoring and associated reporting requirements would result in labor and equipment costs to industry . We calculated the annual labor and equipment cost to industry associated with these requirements by multiplying the assumed average daily cost per rig to comply with these requirements by the number of operating days per year, resulting in an annual per -rig labor and equipment cost of32

$690,000. 17 , 18 Exhibit 9 summarizes the annual costs of the real -time monitoring and associated reporting requirements . We seek comments on the reasonableness of the assumptions in this section.

**Exhibit 9 .**  **Annual Real** **- time Monitoring Requirements**  **(** 

### § **250.452) Year**  **Number of Rigs Cost p**  **er Rig Annual Cost**  **A B**  **C = A × B** 2015

–2016 1 $690,000 $ 690,000 2017 2 $690,000 $1,380,000 2018

–2024 4 $690,000 $2,760,000 f. Additional I nformation Requirements for APDs (§ 250.470) Proposed s ection 250.470 would require operators to submit Arctic OCS - specific information with APDs for Arctic OCS exploratory drilling . Paragraph (a) would require operators to submit a detailed description of how the drilling unit, equipment, and materials will be prepared for service in Arctic OCS Conditions and in compliance with the requirements of proposed s ection 250.417 . 19 Under paragraph (b), operators would be required to submit a detailed descriptio n of all operations necessary in Arctic OCS Conditions to transition the rig from being under way to commencing drilling operations and from concluding drilling operations to being under way, as well as any anticipated repair and maintenance plans for the drilling unit and equipment . Paragraph (c) would require operators to submit well - specific drilling objectives , timelines , and updated contingency plans for temporary abandonment of the well . Under p aragraph ( d) , operators would be required to submit information on weather and ice forecasting capability for all phases of drilling operations . The proposed informational requirements in the new

17 The real - time monitoring estimate contains both the industry - reporting burden and the capital needs for the requirement. The PRA estimate for this provision only includes the industry - reporting burden and is a subset of this estimate. 18 We assume that a rig on the Arctic OCS operates for 138 days per year and that the average daily cost associated with these monitoring requirements would be $5,000, including equipment and labor. We multiplied the average daily cost by the number of operating days per year to obtain an annual labor and equipment cost per rig of $690,000 (138 days × $5,000). 19 A definition of “Arctic OCS Conditions” is provided in Section 250.105 of the proposed rule.33

section would be necessary to inform BSEE’s evaluation of APDs for Arctic OCS exploratory drilling operations . The requirement s under proposed section 250.470(a) - ( d) would result in labor costs to industry and BSEE . We calculated the labor costs to industry by multiplying the annual number of hours assumed to be spent consolidating and reporting information by the medi an hourly compensation rates for the labor categories most likely to complete these activities, resulting in an annual labor cost of $ 1,491 per rig and $ 1, 305 per well . 20 We calculated the labor costs to the Bureau by multiplying the annual number of hours assumed to be spent consolidating and reporting information by the hourly compensation rates for the labor categories most likely to complete these activities, resulting in an annual labor cost of $ 775 per rig and $ 678 per well. 21 Exhibit 10 and Exhibit 11 summarize the annual costs associated with these information requirements. We seek comments on the reasonableness of the assumptions in this section. **Exhibit 10 .**  **Information Requirements under**  **§ 250.470(a)**  **and (d)**  **for Applications for Permit to Drill**  **by Ri g** 

**Year Number** 

**of Rigs**  **Industry**

**Cost per Rig**  **Industry**

**Annual Cost Number of** 

**Rigs Agency Cost** 

**per Rig Agency** 

**Annual Cost A**  **B C = A × B**  **D E**  **F = D x E** 2015

–2016 1 $1,491 $ 1 , 491 1 $775 $ 775 2017 2 $1,491 $2,982 2 $775 $1,551 2018

–2024 4 $1,491 $5,964 4 $775 $3,101

20 We assume that costs associated with consolidating and reporting information as required under section 250.470(a) and (d) would be incurred per rig, while costs associated with section 250.470(b) - (c) would be incurred per well. We assume that consolidating and reporting the information required under section 250.470(a) and (d) wo uld require 10 hours and 6 hours of managerial time per rig, respectively. We assume that consolidating and reporting the information required under section 250.470(b) and (c) would require 10 hours and 4 hours per well, respectively. We multiplied the number of hours by the median hourly compensation rate for an industry manager to obtain an annual labor cost to industry of $1,491 per rig (16 hours × $93.19) and $1,305 per well (14 hours × $93.19). 21 We assume that for every hour industry spends to report and consolidate the information, BSEE spends 1⁄2 hour to review. We assume that 8 hours per rig (16 industry hours x 1⁄2) and 7 hours per well (14 industry hours x 1⁄2) would be required of a BSEE senior engineer to review the informati on. We multiplied the number of hours by the hourly compensation rate for a BSEE senior engineer to obtain an annual labor cost to BSEE of $775 per rig (8 hours × $96.92) and $678 per well (7 hours × $96.92).34

**Exhibit 11 .**  **Information Requirements under**  **§ 250.470(b)**  **and (**  **c )**  **for Applications for Permit to Drill**  **by Well**

**Year Number** 

**of Wells**  **Industry**

**Cost per Well**  **Industry**

**Annual Cost Number of** 

**Wells Agency Cost** 

**per Well**  **Agency**

**Annual Cost A**  **B C = A**  **× B D**  **E F = D x E**  2015 2 $1,305 $2,609 2 $678 $1,357 2016

–2019 4 $1,305 $5,219 4 $678 $2,714 2020

–2024 6 $1,305 $7,828 6 $678 $4,071 g. Incorporation of proposed draft API RP 2N , Third Edition (§ 250.470) S ection 250.470( g) would require operators to submit a detailed description of how the relevant aspects of proposed draft API RP 2N , Third Edition, “Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions” are addressed in planning exploratory drilling operations . The document also would be included in the list of documents incorporated by reference in Section 250.198 of the proposed rule . Proposed AP I RP 2N , Third Edition, is a voluntary consensus standard that will addresses the unique Arctic conditions that affect the planning, design, and construction of systems used in Arctic and sub -Arctic environments. This requirement would result in labor costs to industry and BSEE . We calculated the labor costs to industry associated with this requirement by multiplying the time required for documentation by the median hourly compensation rate for the labor category of individuals most likely to perform this work , resulting in a labor cost to industry per rig of $ 1,918 . We calculated the BSEE labor cost s per rig associated with this requirement by multiplying the time required for review of submittals by the hourly compensation rate for the labor category of individuals most likely to perform this work , resulting in a35

labor cost to BSEE per rig of $ 969 . 22 Exhibit 12 summarizes the annual costs associated with this requirement . We seek comments on the reasonableness of the assumptions in this section. **Exhibit 12 .**  **Annual Information Requirements for Applications for Permit to Drill**  **Related to API**  **RP 2N (**  

### § **25 0.470(g))** 

**Year Number** 

**of Rigs**  **Industry**

**Cost per Rig**  **Annual Cost Number of**  **Rigs Agency Cost** 

**per Rig Annual Cost**  **A B**  **C = A × B D**  **E F = D x E**  2015

–2016 1 $1,918 $ 1 , 918 1 $969 $ 969 2017 2 $1,918 $3,837 2 $969 $1,938 2018

–2024 4 $1,918 $7,674 4 $969 $3,877 h. Additional SCCE Requirements (§ 250.471) Proposed S ection 250.471 describes SCCE requirements for exploration wells drilled on the Arctic OCS . For operations using a MODU when drill ing or working below the surface casing , paragraph (a) requires operators to have access to a capping stack, a cap and flow system, and a containment dome, positioned to ensure that the SCCE will arrive within specified periods after a loss of well control . This equipment must also be able to b e deployed as directed by the Regional Supervisor pursuant to paragraph 250.471(g) of the proposed rul e. Paragraph (a)(2) would require that the cap and flow system be designed to capture at least the amount of hydrocarbons equivalent to the calculated wor s t case discharge rate referenced in the BOEM - approved EP . Paragraph (a)(3) would require that the containment dome have the capacity to pump fluids without relying on buoyancy. Paragraph (b) would require operators to conduct a monthly stump test of dry- stored capping stacks, and if using a pre -positioned capping stack (PPCS) , a stump test must be conducted prior to each installation on each well .

22 We assume that a mid - level engineer would spe nd 20 hours on the documentation associated with this requirement. We multiplied the number of hours by the median hourly compensation rate for mid - level engineers to obtain a labor cost to industry of $1,918 (20 hours × $95.92) per rig. We assume that a s enior BSEE engineer would spend 10 hours on the review of submittals associated with this requirement. We multiplied the number of hours by the hourly compensation rate to obtain a cost to BSEE per rig of $969 (10 hours × $96.92).36

Paragraph (c) would require operator s that propose to change their well design to include in their Application for Permit to Modify (as required by existing Section 250.465(a)) a reevaluation of their SCCE capabilities and a demonstration that their SCCE capabilities will meet the criteria in proposed Sec tion 250.470(f) under the changed well design. Paragraph (d) would require th e operator to conduct tests or exercises of the SCCE when directed by the Regional Supervisor . Paragraph (e) would require the operator to maintain records pertaining to testing, inspection, and maintenance of the SCCE for 10 years, and to make them available to BSEE upon request. Paragraph (f) would require the operator to maintain records pertaining to use of the SCCE during testing, training, and deployment activities for at least 3 years and to make them available to BSEE upon request. These requirements would reflect the need for operators conducting exploratory drilling on the Arctic OCS to be able to correct or contain any loss of well control as quickly as possible to minimize the impacts of oil pollution on the environment . The requirements would also address the need for Arctic OCS operators to plan for response redundancies and planning complexities given challenges associated with logistics and transit times to respond to a well control event on the Arctic OCS , difficulties associated with oil spill response operations in Arctic OCS Conditions , and limited ability on the Arctic OCS to summon additional source control and containment resources . Additionally, S ection 250.470( f ) would require operators who propose to use a MODU to conduct exploratory drilling operations below the surface casing on the Arctic OCS to provide with their APD information concerning their required SCCE capabilities, including a statement that the operator owns, or has a contract with a provider for , SCCE capable of controlling or containing the identified worst - case discharge (WCD ) . 23 Specifically, operators would be required to include : a detailed description of SCCE capabilities ; inventory of local and regional SCCE , supplies , and services owned by the operator or for which the operator has a contract with a provider ; and , where necessary, proof of contracts or membership

23 Calculation of the volume of oil associated with a WCD scenario varies from site to site. This information is required as part of the oil spill response plan for each facility under 30 CFR 254.47.37

agreements for SCCE or related supplies and services . Operators also would be required to include a detailed description of procedures for SCCE inspection , testing , and maintenance. In addition, operators would be required to provide a detailed description of plans to ensure that personnel are trained to deploy and operate the equipment and that they would maintain ongoing proficiency in source control operations . These APD documentation requirements for SCCE w ould help assure BSEE that operators conducting exploratory drilling are capable of controlling or containing a loss of well control under Arctic OCS C onditions 

### . i. Equipment Requirements The equipment requirements under proposed S ection 250.471(a) would result in capital and labor costs to industry . We assume that one -time capital and labor costs for operators that purchase this equipment would be $270,000,000 per SCCE purchased, and that the annual redeployment costs associated with these requirements would be $1,200,000 per SCCE deployed . BOEM and BSEE assume that operators would engage in resource sharing of SCCE due to the high costs of this equipment . We assume that

– over the course of the 10 -year analysis period - one entity currently owns the equipment, one entity would purchase this equipment , and one entity would share the resource s with another operator . We assume that only the entity that purchases the equipment experiences the capital SCCE costs , but both the entity that purchases the equipment and the entity that already owns the equipment experience an annual deployment cost . We assume that the operator with two primary rigs in 2017 will use one set of equipment to satisfy the SCCE requirements for both of its rigs. We do not assume additional costs to the entity that engages in resource sharing. T o estimate the SCCE capital and labor cost s to industry , we accounted for the number of purchased SCCE and the number of deployed38

SCCE on the Arctic OCS . 24 Exhibit 13 summarizes the annual capital costs of the SCCE requirements under proposed S ection 250.471(a) .

**Exhibit 13 .**  **Source Control and Containment Equipment Requirements** 

**(Capital Costs -**  

### § **250.471)**

**Year Number of** 

**SCCE Purchased**  **One -**  **time**

**Purchase Cost**  **p er**  **SCCE Number of** 

**SCCE Deployed**  **Annual**

**Deployment Cost**  **p er**  **SCCE Cost**  **Incurred in a**

**Year A**  **B C**  **D E = A × B + C × D**  2015

–2017 0 $270,000,000 1 $1,200,000 $1,200,000 2018 1 $270,000,000 2 $1,200,000 $272,400,000 2019

–2024 0 $270,000,000 2 $1,200,000 $2,400,000 1 We assume that one operator experiences the upfront costs while two operators experience the deployment costs of the SCCE requirements. Because the industry does not currently engage in resource sharing on the Arctic OCS, BOEM and BSEE do not have details on how the process will be conducted and whether , for example, an operator would charge for access to equipment. The SCCE resource sharing assumptions presented here represent the most likely scenario based on BSEE’s knowledge of the industry. BSEE also considered a low cost scenario and a high cost scenario that vary the assumptions for resource sharing and purchase of SCCE equipment by operators. See Section 4.e of this analysis for details on the costs associated with these scenarios. ii. Stump Testing Requirements We calculated a labor cost to industry per stump test for dry- stored capping stacks by multiplying the number of hours spent co nducting these tests by the median hourly compensation rate for the labor category of individuals most likely to perform this work, resulting in a labor cost to industry of $208 per stump test for a dry- stored capping stack . We calculated the labor cost per stump test for PPCSs by first

24 We assume that one - time capital costs associated with the SCCE availability requirements would be $270,000,000 per purchased SCCE. We assume that annual redeployment costs associated with these requirements would be $1,200,000 per deployed SCCE.39

multiplying the number of hours spent conducting these tests by the median hourly compensation rate for the labor category of individuals most likely to perform this work . We then multiplied the number of days of rig crew time assumed to be spent to conduct these activities by the daily rig operating cost and summed these costs to obtain a cost of $160,208 per stump test for a PPCS . 25 Exhibit 14 summarizes the stump test cost for the SCCE requirements .

25 We assume that a senior engineer would spend 2 hours for each stump test for a dry- stored capping stack. We multiplied the number of hours spent by the median hourly compensation rate for a senior engineer to obtain a labor cost per stump test for a dry - stored capping stack of $208 (2 hours × $104.22). We assume that each rig with a drystored capping stack would conduct monthly tests (July

– Novem ber) and that the operator entering in 2015 would use a dry - stored capping stack. Accounting for the frequency of testing for rigs with dry - stored capping stacks, we obtained an annual labor co st per rig of $1,042 (5 tests × 2 hours × $104.22). We assume a senior engineer and the entire rig crew would spend 2 hours on the stump tests for a PPCS. We calculated the labor costs to industry by first multiplying the time spent by a senior engineer by the median hourly compensation rate for senior engineers and then multiplying the hours of time for the entire rig crew by the daily operating cost for a rig on the Arctic OCS; the sum of these costs resulted in a labor cost to industry per stump test for a PPCS of $160,208 (2 hours × $104.22 + 0.08 days × $2,000,000). We assume one stump test for each PPCS before installation on a well for each new well in the industry and one stump test before deployment. We assume that the number of rigs using PPCSs would be the difference between the total number of rigs and the number of rigs using dry- stored capping stacks, and that each rig installing a PPCS would install one on each well.40

**Exhibit 14 .**  **Stump Tests within the Source Control and Containment Equipment**  **Requirements (**  

### § **250.471 (b)**  **)**

**Year Number of** 

**Rigs with Dry** **- Stored**  **Capping Stacks**  **Cost per**

**Dry****** **Stored Capping**  **Stack Number** 

**of Wells**  **with PPCSs**  **Cost per**

**Instal**   ** lation** **of P**  **P CS**  **Number**

**of New**  **P P**  **CSs Cost per**  **Deployment P**  **P CS**  **Annual**

**Cost A**  **B C**  **D E**  **F G =**  **( A**  **× B**  **) +**  **( C**  **× D**  **) +**  **( E**  **× F**  **)** 2015

–2016 1 $1,042 0 $160,208 0 $160,208 $ 1 ,0 42 2017 2 $1,042 0 $160,208 0 $160,208 $2,084 2018

–2019 2 $1,042 2 $160,208 2 $160,208 $642,918 2020

–2024 2 $1,042 4 $160,208 4 $160,208 $1,283,752

iii. Well Design Change Information Requirements We assume that the requirement to submit a reevaluation of SCCE in the event of any changes to well de s ign would result in labor costs to both the industry and BSEE . We calculated the labor costs to industry associated with this requirement by multiplying the time required for documentation by the median hourly compensation rate for the labor category of individuals most likely to perform this work, resulting in a labor cost to industry per well of $959 . We calculated the per -well labor costs for BSEE associated with this requirement by multiplying the time required for review of submittals by the hourly compensation rate for the labor category of individuals most likely to perform this work . This calculation resulted in a per -well labor cost to BSEE of $410 . 26 Exhibit 15 summarizes the annual costs associated with this requirement . We seek comments on the reasonableness of the assumptions in this section.

26 We assume that a mid - level engineer would spend 10 hours on the documentat ion associated with this requirement. We multiplied the number of hours by the median hourly compensation rate for mid - level engineers to obtain a labor cost to industry of $959 (10 hours × $95.92) per well. We assume that a mid - level BSEE engineer wo uld spend 5 hours on the review of submittals associated with this requirement, or half hour for every hour the industry spends to consolidate the information. We multiplied the number of hours by the hourly compensation rate to obtain a cost to BSEE per well o f $410 (5 hours × $82.02).41

**Exhibit 15 .**  **Information Requirements Associated with Well Design Changes**  **( §**  **250.471(c))**

**Year Number** 

**of Wells**  **Industry**

**Cost per Well**  **Annual Cost Number of**  **Wells Agency Cost** 

**per Well Annual Cost**  **A B**  **C = A × B D**  **E F = D x E**  2015 2 $959 $1,918 2 $410 $820 2016

–2019 4 $959 $3,837 4 $410 $1,640 2020

–2024 6 $959 $5,755 6 $410 $2,461

iv. Test and Exercise Requirements We also assume that the labor and equipment costs associated with the requirements for Regional Supervisor - initiated tests and exercises would be $500,000 per rig and that these tests would be conducted annually for all rigs in operation, including both the entity that purchased the SCCE equipment and the entities that are sharing the equipment . 27 Exhibit 16 summarizes the Regi onal Supervisor - initiated test and exercise costs within the SCCE requirements . We seek comments on the assumptions in this section. **Exhibit 16 .**  **Regional Supervisor -**  **i nitiated Tests and Exercises within the**  **Source Control and**

**Containment Equipment Requirements**  **( §**  **250.471(d)) Year**  **Number of Rigs Cost**  **p er Rig**  **Annual Cost A**  **B C = A × B**  2015

–2016 1 $500,000 $ 5 00 ,000 2017 2 $500,000 $1,000,000 2018

–2024 4 $500,000 $2,000,000

v. Records Maintenance Requirements We calculated the labor costs associated with the SCCE records maintenance requirements by multiplying the amount of time assumed to be spent on records maintenance by the median hourly compensation rate for the labor category of individuals most likely to perform these activities, resulting in an annual labor

27 We assume that Regional Supervisor - initiated tests and exercises for SCCE would be conducted annually and that labor and equipment costs associated with these activities would be $500,000 per rig.42

cost to industry per well of $1,174 . We calculated the labor costs to BSEE associated with these records maintenance requirements by multiplying the amount of time required to review records by the hourly compensation rate for the labor category of individuals most likely to perform this work, resulting in an annual labor cost to BSEE per well of $ 1,938 . 28 Exhibit 17 summarizes the record maintenance requirements within the SCCE requirements for both the industry and the government . We seek comments on the assumptions in this section.

**Exhibit 1 7**  **. Record Maintenance Requirements within the**  **Source Control and**

**Containment Equipment Requirements**  **( §**  **250.471(e))**

**Year Number of** 

**Wells Industry Cost** 

**p er**  **Well Annual** 

**Industry Cost**  **Number of**

**Wells Agency Cost** 

**p er**  **Well Annual** 

**Agency Cost**  **A B**  **C = A ×**  **B D**  **E F = D**  **× E**  2015 2 $1,174 $2,347 2 $1,938 $3,877 2016

–2019 4 $1,174 $4,694 4 $1,938 $7,754 2020

–2024 6 $1,174 $7,042 6 $1,938 $11,630 vi. Documentation Requirements We calculated the labor costs to industry associated with SCCE documentation by multiplying the number of hours assumed to be spent on these activities by the median hourly compensation rate for the labor category of individuals most likely to conduct this work, resulting in a labor cost to industry per APD of $ 5,755 . We calculated the labor costs to BSEE by multiplying the number of hours assumed to be spent reviewing the submittals by the hourly compensation rate for the labor category of individuals most

28 We assume that administrative staff would spend 40 hours per well on this required SCCE records maintenance. We multiplied the number of hours by the median hourly compensation rate for administrative staff to obtain an annual labor cost per well associated with these record maintenance requirements of $1,174 (40 hours × $29.34). We also assume that a BSEE Inspector would spend 20 hours per well to review these records, assuming that agency review takes 1⁄2 hour for every hour of industry burden. We multiplied the number of hours by the hourly compensation rate for a BSEE Inspector to obtain an annual labor cost per well of $1,938 (20 hours × $96.92).43

likely to conduct this work, resulting in an estimated labor cost to BSEE per APD of $ 2,461 . 29 Exhibit 18 summarizes the APD document requirements regarding SCCE for both the industry and the government. We seek comments on the assumptions in this section.

**Exhibit 18 .**  **AP D**  **D ocumentation**  **Requirements for Source Control and** 

**Containment Equipment (**  **§ 250.47**  **0 (f))** 

**Year Number of** 

**APDs Industry Cost** 

**per AP**  **D Annual** 

**Industry Cost**  **Number of**

**APDs Agency Cost** 

**per AP**  **D Annual** 

**Agency Cost**  **A B**  **C = A × B D**  **E F = D × E**  2015 2 $5,755 $11,510 2 $2,461 $4,921 2016

–2019 4 $5,755 $23,021 4 $2,461 $9,842 2020

–2024 6 $5,755 $34,531 6 $2,461 $14,764 i. Relief Rig Requirements (§ 250.472) Proposed s ection 250.472 describes the relief rig requirements for the Arctic OCS . Operators on the Arctic OCS , when conducting exploratory drilling or working below the surface casing, would be required to have a relief rig, different from their primary drilling rig, staged in a location such that it can arrive on site, drill a rel ief well, kill and abandon the original well, and abandon the relief well prior to expected seasonal ice encroachment at the drill site, but no later than 45 days after the loss of well control. The 45 - day maximum timeframe for completing a relief well would effectively limit the number of days an operator can drill or work below the surface casing at the end of each drilling season. This limitation on certain operations may result in some costs to operators from foregone activity , even though there are some operations that can be done at the well site at the end of the season that do not involve work below the surface casing. The relief rig must also comply with all other requirements of Part 250 for

29 We assume that industry mid - level engineers would spend 60 hours on these SCCE documentation requirements. We multiplied the number of hours by the median hourly compensation rate for mid - level engineers to obtain a labor cost of $5,755 (60 hours × $95.92) per APD. We also assume that a mid - level BSEE engineer would spend 30 hours to review these submittals. We multiplied the number of hours by the hourly compensation rate for mid - level engineers to obtain a labor cost to BSEE of $2,461 (20 hours x $82.02) per APD.44

drilling operations and be able to drill a relief well under anticipated Arctic OCS Conditions. Paragraph (a) also authorizes the Regional Supervisor to direct an operator , in the event of a loss of well control , to drill a relief well using the relief rig described in the operator’s APD. Proposed Section 250.470( e ) requires operators submitting APDs for exploratory drilling on the Arctic OCS to submit a detailed description with the APD of how they would comply with the requirements under proposed S ection 250.472 . Both the relief rig requirements and the SCCE requirements (discussed above) are fundamental to safe and responsible operations on the Arctic OCS, where existing infrastructure is sparse, the geography and logistics make it challenging to bring equipment and resources into the region, and the time available to mount response operations is limited by changing weather and ice conditions, particularly at the end of the drilling season. To estimate the capital costs associated with the relief rig requirements, BOEM and BSEE assume that the operator conducting exploratory drilling beginning in 2015 will have a standby relief rig 30 independent of their one primary rig in 2015 and 2016. We assume that a standby relief rig will be used during only one or two drilling seasons because, over time, we expect that the presence of multiple operating rigs on the Arctic OCS will make it easier for one operating drilling rig to be designated as a relief rig for another operating rig. In the third year of th e analysis period, we assume that the first operator would operate an additional primary rig, at which point the two primary rigs will serve as relief rigs for each other (i.e., beginning in 2017, no standby relief rig is assumed). For the two operators c onducting exploratory drilling beginning in 2018, we assume that these operators will rely on each other’s primary rigs as their respective relief rigs. For the first operator, there is a cost to the standby relief rig for the first two years of the analy sis period. We do not estimate any additional costs from this requirement for the two operators that begin to drill in 2018. To estimate the cost of operating a standby

30 We refer to relief rigs that are not conducting exploratory drilling as “standby relief rigs,” and these rigs are assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e. “primary rigs” or “operating rig s”).45

relief rig, we multiplied the number of operating days in a drilling season by the daily rig operating cost to estimate an annual per rig cost of $276,000,000. 31 The BOEM and BSEE estimate the cost assuming that there will be a standby relief rig separate from the primary drilling rig in 2 years of the analysis period based on the expect ed plans of current operators. We recognize that operator plans change and evolve over time and predictions of the next 10 years are not known with certainty. Exploratory Plans suggest that in the future operators will not use a dedicated standby relief rig, but instead will designate a second operating rig to serve as a relief rig. If, however, an operator chooses to deploy a dedicated standby relief rig to comply with regulatory requirements, it could incur costs of approximately $276 million per rig, per season. The BOEM and BSEE request comment on the costs and resource sharing assumptions associated with the relief rig requirements. T he proposed 45 - day maximum limit on the time necessary to complete the required relief rig activities under Section 250.472 would effectively require the cessation of exploratory drilling below or working below the surface casing far enough in advance of the expected return of seasonal ice to allow for completion and abandonment of a relief well. Condition s of the EP approval for Shell’s 2012 Arctic operations required drilling operations in zones capable of liquid hydrocarbons flowing in measurable quantities into the well to be concluded 38 days prior to November 1, based on satellite imagery showing the five - year historical average of earliest encroachment of sea ice over Shell’s drill site and the time estimated for Shell to complete relief well operations . We recognize that the requirement to have the capability to drill a relief well to permanently kill an outof - control well may lead to a reduction in the number of days during which operators can perform work below the surface casing during the drilling se ason. There will be costs and benefits associated with this requirement. Those costs (including “opportunity costs”) may also include costs resulting from a

31 We conservatively assume that a standby relief rig would cost the same amount as the primary rig to operate. We multiplied the number of operating days by the daily rig operating cost to obtain an annual cost per standby relief rig of $276,000,00 0 (138 days x $2,000,000).46

reduction in the number of wells that can be drilled during the term of the lease under which the operator is conducting exploratory drilling operations. This Initial RIA for the proposed rule discusses the challenges associated with estimating opportunity costs. Because the Arctic OCS is a frontier area for drilling operations, there are very few data points that would provide the basis for accurate estimates. Any attempt to calculate opportunity costs would have to take into account the significant number of uncertainties associated with exploratory drilling, the nature of the economic benefits sought to be achieved by such operations (e.g. booking reserves), and a variety of other factors. These factors will often depend upon the decisions an operator makes on how to conduct drilling operations during each drilling season and the nature of the opportunities for other productive use of the assets. Data available to BOEM and BSEE indicate that the estimated daily operating cost of a drilling rig located in the Arctic OCS is approximately $2 million. This estimate includes all of the costs assoc iated with operating a rig (e.g., including the costs of the rig crew). This figure is based upon an analysis of the daily costs of rigs currently operating in the Gulf of Mexico, adjusted significantly upward to account for the harsh operating conditions in the Arctic. The actual operating costs for a rig operating in the Arctic OCS will likely vary greatly from season to season. Industry data presented in the course of this rulemaking indicated that the fixed costs of drilling in the Arctic for one sea son are $1.2 billion, which, amortized over an entire 100 - day season of drilling, is equivalent to $12 million per day in sunk costs. 32 Any calculation of opportunity costs should include an estimated return on investment. Such a calculation could be bas ed on the OMB Circular A - 4 estimate of the average before -tax rate of return to

32 During a meeting conducted with OMB pursuant to E.O. 12866, Shell stated that its total costs for a 100 - day drilling season were $1.5 billion and that 80% of those costs ($1.2 billion) were “sunk.” Dividing these costs by 100 (the assumed length of the drilling season) yields an estimate of $12 million per day. These costs have not been independently validated by BOEM and BSEE, and it is not known if the industry figure provided already included the expected return on capital.47

private capital in the U.S. economy (7 percent) or could be based on the industry stated average return on capital (10 percent) . Any calculation of opportunity costs should als o estimate the number of days per season that the operator could not conduct work below the surface casing. While the proposed rule would impose a maximum period of 45 - days for a relief rig to deploy and complete a relief well and, thus, a maximum of 45 - day s during which work below the surface casing would not occur, the actual number of days during which an operator would not be able to conduct drilling or other work below the surface casing is subject to a number of variables. As discussed previously, w e estimate that it would take 20 days to prepare and transport a rig from the nearest U.S. deep water port (Dutch Harbor) to the farther well location (Beaufort leases), 20 days to drill the relief well, and five days to plug the uncontrolled well, test it , and move off the well site. Further, the actual time needed for completing a relief well operation would vary depending on a number of factors. For example, the estimated actual time needed would depend on how an operator proposes to stage a relief rig ; e.g ., if it chooses to deploy a dedicated standby relief rig or to designate a second operating rig as a relief rig. In the latter case, a relief rig operating in the near vicinity of the primary rig, as proposed by Shell in its revised Exploration Plan for 2015, 33 may be able to reach the site of a blowout and complete a relief well in as little as 25 days, assuming no transit time for the rig. Moreover, other work, which will likely have significant economic benefit, may continue under the proposed rule during the period that work below the surface casing is not allowed, providing economic benefits from other activities that could be conducted during this period (for example, in 2012, Shell drilled top holes during the period it was not allowed to dril l into hydrocarbon bearing zones). If the alternative work was of similar economic value, there would be no opportunity cost. However, it is likely the alternative work would have a lesser value than the forgone work, and thus only partially offset the opportunity cost.

33 http ://www.boem.gov/EP - PUBLIC - VERSION/48

The Initial RIA assumes that, during 10 years of exploratory drilling operations, primary rigs (up to four per season during 2018 - 2024) will conduct a total of 32 drilling campaigns. During those drilling campaigns, costs associated with each rig will be highly variable. Current estimates of these costs range from $ 2 million to $12 million per day. The breadth of this range, combined with the number of significant additional variables (number of days affected; rate of return), makes it difficult to estimate a range of annual opportunity costs. Additional data related to operating costs, forecasted positioning of relief rigs, the economic effect of operating two rigs in theater during the same season, and other significant variables may provide the basis for meaningful estimates of annual opportunity costs associated with the requirement that a relief rig be able to deploy and complete a relief well within 45 days of the end of the drilling season. We encourage comments on such estimat ed costs, as well as benefits, with supporting data, including data on the uses to which a primary rig could be put during the time it is not working below the surface casing. Any such estimates should, if appropriate, include estimated return on capital that would be forgone as a result of these requirements. T he documentation requirements under proposed Section 250.470( e ) would result in labor costs to industry and BSEE . W e assume that all entities must report on their chosen method for complying with the relief rig requirements for each primary rig . We assume that the relief rig documentation requirements would be a one -time cost for each rig . We calculated the labor costs to industry associated with the relief rig documentation requirements by multiplying the number of hours assumed to be spent documenting compliance by the median hourly compensation rates for the labor categories of the individuals most likely to perform this work, resulting in a one -time labor cost to industry per rig associated with relief rig documentation of $14,591 . 34

34 We assume that industry senior engineers would spend 140 hours to document compliance with relief rig requirements. We multiplied the number of hours by the median hourly compensation rate for senior engineers to obtain a one - time, per - rig labor cost to industry of $14,591 (140 hours × $104.22).49

We calculated the labor costs to BSEE associated with the relief rig documentation requirements by multiplying the number of hours assumed to be spent reviewing submittals by the hourly compensation rates for the labor categories of individuals most likely to perform this work . This calculation resulted in a one -time labor cost to BSEE of $ 5,741 per rig related to relief rig documentation . 35 Exhibit 19 summarizes the annual costs of the relief rig documentation requirements for both the industry and BSEE .

**Exhibit 19 .**  **Relief Rig**  **Documentation Requirements**  **( §**  **250.47 0(e)**  **)**

**Year Number of** 

**New Rigs**  **One -** **time Industry**

**Cost p**  **er Rig Industry** 

**Annual Cost**  **Number of**

**New Rigs**  **One -**  **time**

**Agency Cost p**  **er Rig**  **Agency**

**Annual Cost**  **A B**  **C = A ×**  **B D**  **E F = D**  **× E**  2015 1 $14,591 $ 14 , 591 1 $5,741 $ 5 , 741 2016 0 $14,591 $0 0 $5,741 $0 2017 1 $14,591 $ 14,591 1 $5,741 $ 5,741 2018 2 $14,591 $29,182 2 $5,741 $11,483 2019

–2023 0 $14,591 $0 0 $5,741 $0 j. Additional Auditing Requirements (§ 250.1920) Proposed s ection 250.1920 would increase the audit frequency and facility coverage for Arctic OCS exploratory drilling operations. While operators are generally required to conduct their SEMS audit every 3 years after their initial audit, BSEE believes it would be critical to perform a SEMS audit of Arctic OCS exploratory drilling operations and all related infrastructure each year in which drilling is conducted, because of the particularly challenging conditions and high -risk nature of those activities. We account for the costs associated with the increased audit frequency by assuming that t he incremental burden of additional audits will be incurred two out of every three years. 36 We calculate the cost of these

35 We assume that a BSEE mid - level engineer would spend 70 hours to review these submittals (1⁄2 hour for every hour of industry revie w burden). We multiplied the number o f hours by the hourly compensation rate for mid - level engineers to obtain a one - time labor cost to BSEE of $5,741 (70 hours × $82.02) per rig. 36 For simplification, we assume that the audit costs occur in the first two out of every three years. This is a conservative assumption; however, this does not imply that audits will necessarily happen in this sequence.50

audits by multiplying the total cost per audit for a high activity operator by the number of operators . We assume that the audit cost per operator to industry will be $129,000. 37 We assume that the audit cost per operator to BSEE will be $17,754. 38 Exhibit 20 summarizes these costs. We seek comments on the reasonableness of the assumptions in this section.

**Exhibit 20 .**  **Additional Audit** **ing Requirements**  **( §**  **250.1920)**

**Year Number of** 

**Audits Industry** 

**Cost per Audit**  **Industry**

**Annual Cost Number of** 

**Audit s**  **Agency Cost**

**per Audit**  **Agency**

**Annual Cost A**  **B C = A × B**  **D E**  **F = D × E** 2015 1 $129,000 $129,000 1 $17,754 $17,754 2016 1 $129,000 $129,000 1 $17,754 $17,754 2017 0 $129,000 $0 0 $17,754 $0 2018 3 $129,000 $387,000 3 $17,754 $53,262 2019 3 $129,000 $387,000 3 $17,754 $53,262 2020 0 $129,000 $0 0 $17,754 $0 2021 3 $129,000 $387,000 3 $17,754 $53,262 2022 3 $129,000 $387,000 3 $17,754 $53,262 2023 0 $129,000 $0 0 $17,754 $0 2024 3 $129,000 $387,000 3 $17,754 $53,262 k. Real -time L ocation T racking Requirements (§ 254.80) Proposed S ection 254.80 describes additional information requirements for the emergency response action plan section of the response plan for operators conducting exploratory drilling on the Arctic OCS .

37 This cost estimate originates from 30 CFR 250, Subpart S - Safety and Environmental Management Systems (SEMS), OMB Control Number 1014 - 0017. 38 In 30 CFR 250, Subpart S - Safety and Environmental Management Systems (SEMS), OMB Control Number 1014 - 0017, BSEE estimates that the burden for BSEE to review audits is 28,527 hours, with 10 percent of the hours for clerical support, 80 percent of the ho urs for a mid - level engineer, and 10 percent of the hours for a supervisory engineer. Because this regulation covers audits for 130 operators, we estimate that one audit would take 219 hours (28,527 hours ÷ 130 operators). To estimate the cost, we assume that a clerk would spend 22 hours (10% x 219), a mid - level engineer would spend 176 hours (80% x 219) and a supervisory engineer would spend 22 hours (10% x 219). To estimate the per - audit cost to BSEE, we multiplied the corresponding hourly compensation rates by the allocated hours to estimate a $17,754 per - audit cost (22 hours x $38.89 + 176 hours x $82.02 + 22 hours x $114.01).51

Only proposed Section 254.80(c) would impose a new burden on th e industry and BSEE , not already covered by other existing regulations and subsequent paperwork burden supporting statements . Paragraph (c) requires operators to describe how they would maintain an effective tracking and management system that is able to l ocate in real time all response equipment and personnel conducting response activities, or transiting to and from the response site(s), and to maintain a current picture of resources entering and exiting staging areas and the operational status of those re sources. This system would be essential to provide the Unified Command with information necessary to ensure that sufficient personnel and equipment would be available to meet the response needs. These information requirements would result in la bor costs to industry and BSEE . We calculated the labor costs to industry by multiplying the number of hours assumed to be spent on including this information in the response plan by the median hourly compensation rate for the labor category of individuals most likely to perform this work, resulting in a labor cost to industry of $ 401 per OS RP . We calculated the labor costs to BSEE by multiplying the number of hours assumed to be spent associated with these information requirements by the hourly compensation rate for t he labor category of individuals most likely to perform this work, resulting in a labor cost to BSEE per OSRP of $ 246 . 39 In addition to the reporting costs, BOEM and BSEE estimated the cost for complying with proposed Section 2 5 4.80(c) by using an Automatic Identification System (AIS) to track both equipment and personnel during the drilling season . Operators have the flexibility to choose which system would monitor their equipment and person ne l during the drilling season ; however, we use the AIS as a representative system. BOEM and BSEE estimated the cost per entity to have AIS device s on vessels and tracking devices on equipment and personnel based on the costs incurred by the initial operator . We recognize that 39 We assume that industry environmental specialists would spend 6 hours to include the required information in the response plan. We multiplied the number of hours by the median hourly compensation rate for environmental specialists to obtain a labor cost to industry per OSRP of $401 (6 hours × $66.85). We also assume that a BSEE mid - level engineer would spend 3 hours on these information requirements or 1⁄2 hour for every hour of industry burden. We multiplied the number of hours by the hourly compensation rates for mid - level engineers to obtain a labor cost to BSEE of $246 (3 hours × $82.02) per OSRP. We assume that a total of two OS RPs would be submitted by operators on the Arctic OCS each year.52

this cost will vary based on implementation for each operator . W e do not , however, have the additional information needed to determine the specific costs of each of the expected operators, which will vary by their size ( e.g., vessels, equipment, and personnel) . Using information on th e current tracking systems, we estimated cost per system including the purchase of tracking devices, the purchases of AIS devices, the installation of the tracking device and the AIS units, the monthly fee for tracking devices , and the annual fee for AIS s ervices . Exhibit 21 presents the unit cost s , the number of units, and the total cost for the AIS system. 40 We considered all costs to be upfront costs , except for the monthly fee for tracking devices and the annual fee for the AIS . BOEM and BSEE assume that operators would need to replace the AIS (including the main unit and tracking devices) every 8 years . BOEM and BSEE request comment on how often operators would need to replace the real -time tracking system.

40 We assume that an electrician will need to install the AIS unit onto vessels and that it will take 12 hours per device to install. We multiplied the hours spent by the electrician to install the device to obtain a cost per device installation of $626 (12 hours x $52.15). We assume that a crew mem ber would install the tracking devices on the equipment and it would take 1⁄2 hour per tracking device. We multiplied that by the median hourly comp ensation rate for a rig crew

mem ber to estimate an installation cost of $28 per device (1/2 hour x $56.86).53 **Exhibit 21 : Automatic Identification System Cos**  **ts per Entity (**  **§ 254.80(c))**  **AIS Cost Inputs p**  **er Entity Unit Cost**  **Number of Units**  **Total Cost** Purchase tracking/locator devices

– personne l $150 100 $15,000 Purchase tracking/locator devices - equipment $100 187 $18,700 Purchase AIS (small vessels) $1,000 6 $6,000 Purchase AIS (larger vessels) $3,000 4 $12,000 Tracking device installation (rig c rew installer) $28 187 $5,316 AI S installation ( e lectrician) $626 10 $6,258 Monthly fee for tracking/locator devices

– personne l 1 $10 100 $5,000 Monthly fee for tracking/locator devices

– equipment $10 187 $9,350 AI S annual fee (per user name) $1,000 25 $25,000 **Upfront Cost 2**  **$63,274 Annual Cost**  **$39,350** 1. We assume that the monthly tracking fees for both personnel and equipment occur during the five - month drilling season only . 2. We assume that operators pay the upfront cost at the start of every lifecycle or every 8 years. We estimated the AIS costs by multiplying the upfront costs by the number of operators each year . As shown in Exhibit 3 , we assume new operators in 2015 and 2018 . We also estimate the upfront cost to replace the AIS device and tracking units in 2022 for the original operator based on the 8 -year lifecycle cost of AIS . 41 We estimate the recurring cost of AIS by multiplying the recurring cost by the number of operators each year . Exhibit 22 present s details on the AIS costs . We seek comments on the reasonableness of the assumptions in this section.

41 We assume that training costs for AIS are already accounted for under SEMS requirements.54 **Exhibit 22 .**  **Real -** **time Location Tracking Requirements**  **( §**  

### 25 **4 .80(c))** 

**Year Number of** 

**New AIS**  **Upfront**

**Industry Cost**  **p er**  **Operator Annual Cost**  **Number of Active AIS**  **Annual**

**Industry Cost per**  **Operator Annual Cost**  **A B**  **C = A × B D**  **E F = D × E**  2015 1 $63,274 $63,274 1 $39,350 $39,350 2016

–2017 0 $63,274 $0 1 $39,350 $39,350 2018 2 $63,274 $126,549 3 $39,350 $118,050 2019

–2021 0 $63,274 $0 3 $39,350 $118,050 2022 1 $63,274 $63,274 3 $39,350 $118,050 2023

–2024 0 $63,274 $0 3 $39,350 $118,050 l. IOP Requirements (§ 550.204) Proposed S ection 550 .204 would require operators proposing to conduct exploratory drilling operations on the Arctic OCS to develop an IOP for each proposed exploratory drilling program on the Arctic OCS, and to submit the IOP to DOI, acting through its designee, BOEM, at least 90 days in advanc e of filing its EP. The IOP would need to describe how the proposed exploratory drilling program would be designed and conducted in an integrated manner suitable for Arctic OCS Conditions and would address each of the information requirements identified in proposed Section 550.204. In the IOP, operators would be required to include information on several aspects of operations: vessels and equipment (including general maintenance schedule), schedule and objectives of the exploratory drilling program (including contractor work on critical components, plans for abandonment , and timelines for each objective ), mobilization and demobilization operations (including tow plans suitable for Arctic OCS Conditions) , weather and ice forecasting capability, work to be performed by contractors, operational safety, preparations and plans for staging of oil spill response assets, efforts to minimize impacts of exploratory drilling operations on local community infrastructure, and the extent to which the project will rely on l ocal community workforce and spill cleanup response capacity . We assume the operator has previously gathered virtually all of this information in developing its approach for conducting exploratory operations and that the operator would55

be merely providing existing information under the umbrella of the IOP. The IOP process is intended to facilitate the sharing of information among the relevant Federal agencies and the State of Alaska , as well as to provide the public an early view of the operator’s plans . T he IOP process also provides the relevant agencies an early opportunity to engage in a meaningful and constructive dialogue with operators and each other. These information requirements would result in labor costs to industry and BOEM . We calculated the l abor costs to industry by multiplying the time assumed to be spent to compile and include the required information by the median hourly compensation rate for the labor category of individuals most likely to conduct this work, resulting in a labor cost to industry of $ 8,633 per IOP . We calculated the labor costs to BOEM by multiplying the time assumed to be spent reviewing the submittals by the hourly compensation rate s for the labor categories of individuals most likely to conduct this work, resulting in a labor cost to BOEM of $53,951 per IOP . 42 We seek comments on the reasonableness of the assumptions in this section.

m. Planning Information Requirements to A ccompany EPs (§ 550.220) Proposed S ection 550.220 includes additional information requirements for planning information that must accompany EPs for operators proposing to conduct exploration activities in the Alaska OCS Region . Paragraph (a) requires operators to have emergency plans to respond to a fire, explosion, personnel evacuation, or loss of well control, as well as a loss or disablement of a drilling unit, vessel, offshore vehicle, or aircraft . Paragraph (c) would require operators proposing exploration activities on the Arctic OC S to submit additional p lanning information to accompany EPs , including information on suitability 42 We assume that mid - level engineers would spend 90 hours to compile and include the required information in the IOP. We multiplied the number of hours by the median hourly compensation rate for mid - level engineers to obtain a cost to industry of $8,633 (90 hours × $95.92) per IOP. We also assume that several BOEM employees would review these documents, including, a regulatory analyst (120 hours), a petroleum engineer (120 hours), a geologist (160 hours), a BOEM Chief (160 hours) and a Regional Supervisor (16 0 hours). We multiplied the number of hours by the hourly compensation rate for each respective labor category to obtain a cost to BOEM of $53,951 per IOP (120 hours x $57.54 + 120 hours x $68.97 + 160 hours x $31.38 + 160 hour x $96.92 + 160 hours x $114. 01). We assume that operators on the Arctic OCS would submit a total of two IOPs each year.5 6

for Arctic OCS Conditions, ice and weather management, SCCE capabilities, deployment of a relief rig, resource sharing , and anticipated end of season dates . These information requirements will help to ensure, through thorough advanced planning, that operators are capable of operating safely in the extreme and challenging Arctic OCS Conditions. These information requirements would result in labor costs to indus try and BOEM . We calculated the labor costs to industry by multiplying the time assumed to be spent to compile and include the required information by the median hourly compensation rate for the labor category of individuals most likely to conduct this work, resulting in a labor cost to industry of $ 4,316 per EP . We calculated the labor costs to BOEM by multiplying the time assumed to be spent reviewing the submittals by the hourly compensation rate for the labor categories of individuals most likely to conduct this work, resulting in a labor cost to BOEM of $10,790 per EP . 43 We then accounted for the number of EPs that are expected to be submitted each year for operations on the Arctic OCS to obtain a total labor cost to industry of $ 82,012 and to BOEM of $ 205,013 . We seek comments on the reasonableness of the assumptions in this section.

n. Industry F ami liarization with the N ew R ule When the new regulation takes effect, industry would need to read and interpret the rule . Through this review, operators would familiarize themselves with the structure of the new rule and identify any new provisions relevant to their operations . Operators would also evaluate whether any new action must be taken to achieve compliance with the rule.

43 We assume that mid - level engineers would spend 45 hours to compile and include the required information for the EP. We multiplied the number of hours by the median hourly compensation rate for mid - level engineers to obtain a cost to industry of $4,316 (45 hours × $95.92) per EP. We also assume that several BOEM employees would review these documents including a regulatory analyst (24 hours), a petroleum engineer (24 hours), a geologist (32 hours), a BOEM Chief (32 hours) and a Regional Supervisor (32 hours). We multiplied the number of hours by the hourly compensation rate for each respective labor category to obtain a cost to BOEM of $10,790 per EP (24 hours x $5 7.54 + 24 hours x 68.97 + 32 hours x 31.38 + 32 hour x $96.92 + 32 hours x 114.01). We assume that operators on the Arctic OCS would submit one EP in the first year and a total of two EPs in each year after.57

Reviewing the new regulations would require staff time, imposing a one -time labor cost on industry . We estimated the one -time labor cost for industry familiarization with the rule at $1,042 per operator . 44 We seek comments on the reasonableness of the assumptions in this section. 6. Summary of the C ost Analyses Exhibit s 23 and 24 summarize the cost analysis . We present the costs for Alternative 1, the proposed rule with the BOP pressure testing requirements, and Alternative 2, the proposed rule without the BOP pressure testing requirements. Exhibit 23 summarizes the 10 -year average annual cost s (undiscounted) for the proposed rule by provision . Exhibit 24 summarizes the costs for both alternatives using discount rates of 3 percent and 7 percent . Similar to the analyses presented above, summations in Exhibit 23 and Exhibit 24 might not add because of rounding.

44 We assume that for each operator on the Arctic OCS, a senior engineer would spend 10 hours to review the new regulation. We multiplied the number of hours by the median hourly compensation rate for a senior engineer to obtain a one - time labor cost to industry per operator of $1,042 (10 hours × $104.22 ).58 **Exhibit 23 .**  **10 -** **Year Average Annual Costs by Provision (with no discounting)** 

**Provision 10**  **- year**  **Average Annual Cost**  **s : Alternative**  **1 (with 7**  **- day BOP testing**  **requirement) 10**  **- year**  **Average Annual Costs: Alternative**  **2 (without 7**  **- day BOP testing**  **requirement)** (a) Additional Incident Reporting Requirements $5,374 $5,374 (b) Pollution Prevention Requirements $13,585 $13,585 (c) Additional Requirements for S ecuring W ells $24,000,000 $24,000,0 00 (d) Additional BOP P ressure T esting Requirements $19,200,000 $0 (e) Real -time M onitoring Requirements $2,208,000 $2,208,000 (f) Additional Information Requirements for APDs $16,771 $16,7 71 (g) Incorporation of proposed draft API RP 2N , Third Edition $9,240 $9,240 (h) Additional SCCE Requirements $31,471,823 $31,471,823 (i) Relief Rig Requirements $55,208,133 $55,208,133 (j ) Additional Auditing Requirements $249,482 $249,482 (k) Real -time L ocation Tracking Requirements $121,044 $121,044 (l) IOP Requirements $125,167 $125,167 (m) Planning Information Requirements to A ccompany EPs $28,702 $28,702 (n) Industry F ami liarization with the N ew R ule $313 $313

**TOTAL $132,657,635**  **$113,457,635**59 **Exhibit 24 .**  **Summary of Monetized Costs 1,2** 

**Year Industry Costs:** 

**Alternative 1 (with**  **7 -**  **day BOP testing**  **requirement )**  **Industry Costs:**

**Alternative 2 (without**  **7 -**  **day BOP testing**  **requirement )**  **Government**

**Costs Total Costs:** 

**Alternative 1 (with 7**  **- day BOP**  **testing requirement)**  **Total Costs:**

**Alternative 2 (without 7**  **- day**  **BOP testing requirement)**  **A B**  **C D = A + C**  **E = B + C** 2015 $294,689,955 $288,689,955 $155,932 $294,845,887 $288,845,887 2016 $304,631,665 $298,631,665 $171,956 $304,803,620 $298,803,620 2017 $35,717,099 $23,717,099 $162,221 $35,879,320 $23,879,320 2018 $322,562,375 $298,562,375 $225,779 $322,788,154 $298,788,154 2019 $52,406,644 $28,406,644 $214,296 $52,620,941 $28,620,941 2020 $62,678,863 $38,678,863 $172,010 $62,850,873 $38,850,873 2021 $63,065,863 $39,065,863 $225,271 $63,291,135 $39,291,135 2022 $63,129,138 $39,129,138 $225,271 $63,354,409 $39,354,409 2023 $62,678,863 $38,678,863 $172,010 $62,850,873 $38,850,873 2024 $63,065,863 $39,065,863 $225,271 $63,291,135 $39,291,135 **Undiscounted 10**  **- year total**  **$1,324,626,328 $1,132,626,328**  **$1,950,018 $1,326,576,346**  **$1,134,576,346 PV**  **10 -** **year total with 3%**  **discounting $1,221,896,314**  **$1,057,816,579 $1,701,450**  **$1,223,597,763 $1,059,518,028**  **PV 10 -** **year total with 7%**  **discounting $1,110,686,488**  **$975,624,608 $1,441,797**  **$1,112,128,285 $977,066,405**  **Annualized with 3%**  **discounting $143,243,524**  **$124,008,373 $199,462**  **$143,442,986 $124,207,835**  **Annualized with 7%**  **discounting $158,136,768**  **$138,906,995 $205,279**  **$158,342,048 $139,112,275**  1 Totals might not add because of rounding. 2 The total 10 - year costs of the proposed rule are discounted using 3 and 7 percent discount rates. Discounting makes costs occurring in different periods comparable by expressing them in present value terms. Costs discounted at a higher rate are worth less in present value terms than costs discounted at a lower rate. This effect is observed for the proposed rule, with total costs with 3 percent discounting estimated at $ 1.2 b illion, and total costs with 7 percent discounting estimated at $ 1.1 b illion. In addition to the total costs, we also estimate the annualized costs using 3 and 7 percent discount rates. Annualizing total costs results in an estimate of the costs that would be incurred in each period (such as each year for 10 years) so that the sum of all these periodic costs would equal the total c ost. The impact of discounting annualized costs is the opposite of what is observed for total costs, with higher discount rates resulting in higher annualized costs. This opposite effect is observed because a higher discount rate reduces costs in future ye ars more than a lower discount rate, resulting in a higher annualized cost needed to equal the same total cost than if a lower discount rate was used. This effect is observed in the annualized cost estimates for the60

proposed rule, with annualized costs of $ 143 million and $ 158 million with 3 percent and 7 percent discounting, respectively. The reader should note that the costs to industry and the Government vary during the 10 - year analysis period. These changes occur due to a variety of factors including, b ut not limited to, new rigs entering the theaters, different equipment requirements and other similar factors that occur throughout the analysis period. 7. Break- Even Analysi s In the preceding section, we presented our estimate that the proposed rule would result in economic costs of $ 1.2 b illion under 3 percent discounting and $ 1.1 b illion under 7 percent discounting over 10 years under Alternative 1, the proposed rule . Although the economic and other benefits of the proposed rule

— based primarily on preventing or reducing the duration of catastrophic oil spills

—are difficult to quantify, BOEM and BSEE have determined that it is appropriate to proceed with this proposed rule . Although the probability of a catastrophic spill is very small , the Deepwater Horizo n oil spill demonstrate d that such low probability events can have devastating economic and environmental consequences . 45 W e use double the value of the cleanup cost estimates in the Gulf of Mexico to estimate the costs of cleanup in the Arctic OCS region because the costs of a spill in the Arctic OCS region are estimated to be much greater on a per -barrel basis than for a comparable spill in the Gulf of Mexico . 46 In addition, a spill in the Arctic OCS would impact both subsistence hunting and culture and traditions of Alaska Native communities, which the Deepwater Horizon oil spill did not have. Moreover , this proposed rule would help achieve the National Arctic Strategy goals of protecting the unique and sensitive Arctic ecosystems and the culture and traditions of the Native communities. The proposed requirements

— specifically tailored to the Arctic region

— would provide additional clarity 45 By its own account, BP has spent over $14 billion to date in cleanup operations related to the Deepwater Horizon spill. As explained in this Initial RIA, the costs and other consequences of a major spill in the waters of the Arctic OCS likely would b e greater than the costs and impacts for a comparable spill in the Gulf of Mexico, where response equipment and resources are more readily available than in the Arctic region. 46 See pages 62 and 63 of the BOEM Case Study for details on the Gulf of Me xico spill containment and clean - up cost assumptions. This approach of doubling the GOM cost estimate is consistent with the methodology used to estimate natural resource damages in the Beaufort and Chukchi Seas in the BOEM Case Study, which states, “While doubling of the GOM values may appear arbitrary, BOEM believes that damages from a catastrophic oil spill likely are some where in -between the Cook Inlet and the GOM per - barrel damages, so doubling the GOM values may overstate the damages in the Arctic, although the costs for any particular spill will vary widely.... Labor, materials, and transportation drive cleanup costs and each of these will be significantly more expensive in the Arctic.” (BOEM Case Study, p. 68).61

regarding BOEM’s and BSEE’s expectations for the safe and responsible exploration of Arctic resources and the specific actions that lessees, owners , and operators must take in order to meet those expectations. This additional clarity and specificity would help the oil and gas industry to plan and to conduct exploratory drilling more effectively in the Arctic OCS, which , in turn , would result in development of oil and gas with lower risk and fewer delays than under the existing rules. The proposed rule would benefit society and the environment by reducing the probability of incidents resulting in oil spills and, if an incident occur s , by reducing the duration and/or severity of the spill s . The objective of the proposed rule is to ensure safe and responsible oil and gas drilling on the Arctic OCS resulting in increased safety for personnel, protection of the marine environment and species, and removal of impediments to the Alaska Native subsistence use . The magnitude of these benefits, however, is uncertain and highly dependent on the actual reduction in the probability of incidents and the effectiveness of stopping or containing a spill already underway . A catastrophic oil spill is characterized as a low probability , high consequence event because it is an infrequent event but has large consequences when it does occur . For low probability, high consequence events, it is difficult to know with any certainty the probability of an event actually occurring, or to determine the reduction in the probability of occurrence that a propose d regulation would actually achieve . In addition, the consequences of an oil spill depend on several factors, including the type of oil, the amount of oil, the location of the spill, the areal distribution of the release, the sensitivity of the ecosystem affected, and the weather, among other factors . Due to these uncertainties , BOEM and BSEE coul d not perform a standard cost -benefit analysis to estimat e the net benefits of the proposed rule . As discussed above , we conducted a break- even analysis of the proposed rule because of the difficulties associated with estimating the benefits of reducing the probability and consequence s of low probability, high consequence events . For the proposed rule, we estimated a break- even number of avoided days of spilled oil if a catastrophic oil spill were to occur . In this section, we describ e the data, methods, and62

results of the break- even analysis. We also provide a qualitative discussion of the benefits of the proposed rule.

a. Data To estimate the potential consequences of a catastrophic oil spill , we used data from the BOEM Case Study to provide the estimated volume of oil (in barrels ) and the duration ( in days ) of a catastrophic spill occurring in the Chukchi and Beaufort Sea s under high - and low - severity oil spill scenarios . These examples are hypothetical outcomes based on expected exp loration and drilling on the Arctic OCS . Exhibit 25 presents the estimates for the volume and duration of a potential catastrophic spill on the Arctic OCS .63

**Exhibit 25 .**  **Total Volume and Duration of Potential Catastrophic Oil Spills in**  **Arctic OCS Location**  **Total Volume of Oil**  **(BBLs) Duration (Days)** 

**Low High**  **Low High**  Chukchi Sea 1,400,000 2,200,000 40 75 Beaufort Sea 1,700,000 3,900,000 60 300 To conduct the break- even analysis of the number of avoided days of spilled oil, we collected worst- case discharge data from two existing Shell OSRPs . The worst - case discharge data include discharge totals for the Chukchi and Beaufort Sea s with discharge amounts of 25,000 and 16,000 BBLs per day, respectively . These estimates do not reflect the expected volume of oil spilled if there w ere an oil spill but , instead , define a worst - case scenario for a spill on the Arctic OCS. We use d the Shell worst - case discharge estimates to estimate the number of avoided days of spilled oil needed to break- even , rather than the BOEM Case Study total catastrophic oil spill volume estimates presented in Exhibit 25, because Shell’s OSRPs provide daily worst- case discharge estimates. Next, we estimated the social cost of a barrel of oil spilled . Using the BOEM Case Study, we divided the per -barrel costs into three components: natural resource damages, value of lost hydrocarbons, and containment and cleanup cost s . Natural resource damages relate to the natural resources on the Arctic OCS that would be damaged by an oil spill . The value of the lost hydrocarbons reflect s the lost usable oil . Finally, spill containment and cleanup costs include all the resources (capital and labor) needed to contain the spill and clean up the site . These costs are all included in the social cost o f a barrel of oil as per the directive of OMB Circular A - 4, which is to include costs regardless of where , when , o r to whom the costs accrue . 47

47 Using both natural resource damages and containment and cleanup costs is consistent with the natural resource damages assessment methods described in the BOEM Case Study. This also accounts for any temporal or spatial distribution in the accrual of cleanup costs. For example, the cleanup on the coast may occur at a later time and different place than the initial spill.64

The BOEM Case Study used a “benefit transfer” method to estimate avoided costs specific to the Arctic OCS because no incidents have occurred on the Arctic OCS . Benefit transfer allows for previously estimated values to be customized and adapted to match a new context. The method is recommended by OMB Circular A - 4 as a next best alternative when collecting primary data is not possible . B ecause we have values on catastrophic spill s in a near by region (t

he Valdez o il spill) and in other regions (the Gulf of Mexico ( GOM) ) , we used the results of the BOEM Case Study benefit transfer to provide a next -best estimate of the cost of a potential catastrophic oil spill by transferring known values to the Arctic OCS . The BOEM Case Study developed these costs by first estimating the cost of a barrel of oil spilled for the GOM catastrophic spills based on histo rical data and the cost of a barrel of oil spilled for the Exxon Valdez oil spill in Alaska’s Prince William Sound . As noted above, many site - specific characteristics influence the severity of an oil spill . The Exxon Valdez oil spill occurred in a highly s ensitive region close to populat ed areas that support economic activity, including recreation, tourism, and commercial fishing . The Chukchi and Beaufort Sea s likely would have some similar environmental qualities ( although not identical) but the northern areas of Alaska do not support the same level of economic activity . For example, no significant commercial fishing occurs in the region , and the region supports relatively little tourism or recreation . In the BOEM Case Study, BOEM explained that the Exxon Valdez created an upper bound for a spill occurring in the northern seas of Alaska . In comparison to the Arctic OCS , the GOM varies greatly in climate , environment , and economic activity . Because the GOM already supports a variety of rigs and oil operations, the region has ready access to labor and capital in the event of an incident, thus minimizing the overall cost of an incident . If a spill occurs on the Arctic OCS , resources and labor would need to be deployed to the region, which would add to the cost of a cleanup . To estimate the cleanup and resource costs, the BOEM Case Study doubled the estimated cost for the GOM to reach an estimate that was greater than the GOM cost while still being lower than the Exxon Valdez cost . Based on regional differences, BOEM determined that doubling the GOM value would be the next -best estimate for costs in the Arctic OCS region . W e used the natural resource damage cost of65

$1,284 per barrel and the cleanup and containment cost of $5,714 per barrel as estimated for the Chukchi Sea and Beaufort Sea in the BOEM Case Study . Consistent with the BOEM Case Study, we used the $100 value of lost hydrocarbons per barrel, which is the value applied across all regions analyzed in the Case Study . In addition to the per -barrel cost, the BOEM Case Study also estimat ed subsistence losses and value of life and non - fatal injuries for the Arctic OCS . The BOEM Case Study used an $8.5 million value for a statistical life (VSL) based on the Regulatory Analy sis presented in the 2010 Drilling Safety Rule and assumed 8 deaths per incident based on the two historical incidents in the GOM. BOEM assumed an injury valued at $45,000 with 10 injuries for a catastrophic blowout. Using the annual local population harve sts for whales and value per kilogram harvested, the BOEM Case Study estimated the loss of subsistence in the Beaufort Sea and Chukchi Sea at $20.9 million and $68.6 million, respectively. 48 Using historical data from the GOM, the BOEM Case Study estimated the value of life lost and non - fatal injury per incident at $68.45 million and used this estimate as a proxy for all regions. The BOEM Case Study estimated these cost s on a per - incident basis because these costs are not dependent on the volume of oil spilled . Exhibit 26 summarizes the cost of a catastrophic oil spill on the Arctic OCS .

**Exhibit 26 .**  **Cost of a Catastrophic**  **Oil Spill on the Arctic OCS**  **Cost Per Barrel of Oil Spilled** Cleanup and containment cost $5,714 Natural resource damages $1,284 Value of lost hydrocarbons $100 **Total Cost per Barrel of Oil Spilled $7,098**  **One -** **time Cost per Spill** Total estimated Chukchi Sea subsistence los s es (1.5 years) $68,574,252 Total estimated Beaufort Sea subsistence los s es (1.5 Years) $20,850,495

48 BOEM notes that subsistence damages capture only a fraction of the cultural damages for Alaska Natives in this region. These losses relate to the value of the harvest but fai l to capture the cultural value of the region for Alaska Natives. The cultural value likely exceeds the market value attached to the subsistence harvest.66

Li ves lost and non - fatal injuries $68,450,000 **One -**  **time Cost per Spill in the Chukchi Sea $137,024,252**  **One -** **time Cost per Spill in the Beaufort Sea**  **$89,300,495** Next, we estimated the (quantifiable) total cost of a catastrophic spill by summing the variable costs and the one -time costs of a spill. To estimate the variable costs, we multiplied the cost per barrel of oil spilled (as shown in Exhibit 26) by the volume of oil spilled under each spill scenario (as shown in Exhibit 25) . 49 We summed the variable cost s with the one -time costs presented in Exhibit 26 for the Beaufort Sea and the Chukchi Sea. Exhibit 27 summarizes the catastrophic oil spill cost at the two locations under the high - and low - volume spill cases . **Exhibit 27 .**  **Catastrophic Oil Spill Costs ($**  **millions)**

**Location Total**  **Variable Costs**  **Total One**  **** **Time Costs**  **Total Spill Costs Low**  **High Low** **/ H** **igh Low**  **High A**  **B C**  **D = A +**  **C E = B**  **+ C**  Chukchi Sea $9,937.2 $15,615.6 $137.0 $10,074.2 $15,752.6 Beaufort Sea $12,066.6 $27,682.2 $89.3 $12,155.9 $27,771.5 Next, using the Shell OSRP s , we estimated the daily cost of an oil spill under the worst - case discharge . For this aspect of the analysis, we did not include the one -time per - spill costs (as presented in Exhibit 26) and only included the incremental cost s of an additional day of discharge . To estimate the daily cost of a spill at each location, we multiplied the barrels of oil spilled per day (as estimated in the Shell OSRP and presented in Exhibit 28) by the cost per barrel of oil spilled (as shown in Exhibit 26) . Exhibit 28 summarizes this calculation for both the Chukchi and B eaufort Sea s .

49 For example, for the Chukchi Sea low - volume case, we estimated the total cost of the spill to be the cost per barrel of oil multiplied by the number of barrels of oil spilled plus the total per - spill cost ($7,098 × 1,400,000 BBLs + $137,024,252). The total cost of the Chukchi low - volume case is, thus, $10,074,224,252. This process is repeated for both seas and for the high - and low - volume cases.67 **Exhibit 28 .**  **Cost of Oil Spilled Per Day**

**Location Barrels of Oil per Day**  **Cost per Barrel of Oil Spilled**  **Cost of Spill per Day A**  **B C = A**  **× B**  Chukchi Sea 25,000 $7,098 $177,450,000 Beaufort Sea 16,000 $7,098 $113,568,000 b. Method According to our analysis, the total quantifiable cost of a catastrophic spill would be between $10. 07 billion and $15. 75 billion in the Chukchi Sea and between $12. 16 billion and $27. 77 billion in the Beaufort Sea. We estimated the daily quantifiable cost of a worst - case discharge oil spill at $177.5 million for the Chukchi Sea and $113.6 million for the Beaufort Sea . We use d the worst - case discharge estimates from Shells’ OSRPs to estimate the number of avoided days of spilled oil needed to break- even , rather than the BOEM Case Study total catastrophic oil spill volume estimates (as presented in Exhibit 25 ) , because the OSRPs provide daily worst - case discharge estimates. In addition, although some provisions lower the overall risk of a spill, other provisions focus on a faster containment and cleanup after a spill has occurred . We estimate d the break- even num ber of avoided days of spilled oil by dividing the total net costs (i.e., costs minus cost savings) of the proposed rule by the per - day cost of spilled oil.

c. Results Using the estimated discounted costs at 3 and 7 percent and the quantifiable potential benefits (in terms of avoided costs of incidents) of the proposed rule , we calculated the break- even number of avoided days of spilled oil . This estimate reflects the number of avoided days of spilled oil needed for the proposed rule to achieve at least zero net benefits. Any avoided days of spilled oil greater than these bre ak- even points result in the proposed rule achieving positive net benefits , should a catastrophic spill occur . We also show the estimated total cost of a catastrophic oil spill relative to the total cost of the proposed rule. Exhibit 29 presents the (quantifiable) total cost of a spill and the 10 - year cost of the rule.68

**Exhibit 29 .**  **Total Cost of a Catastrophic**  **Oil Spill Compared to the 10 -** **year Cost of the Rule**

**Location Cost of a Spill**  **1 ($ millions)**  **10 -** **year Cost of the Rule ($ millions)**  **Low High**  **7% Discounting**  **3% Discounting**  Chukchi Sea $10,074.2 $15,752.6 $ 1,112 $ 1,224 Beaufort Sea $12,155.9 $27,771.5 $ 1,112 $ 1,224 1. Discounting does not apply to the cost of a spill because it is unknown if and when a spill would occur . As presented in Exhibit 29 , quantifiable costs of a spill in the Chukchi Sea range from $10.07 billion to $15.75 billion and in the Beaufort Sea from $12.1 6 billion to $27.77 billion. Quantifiable costs of a spill are more than the cost of the rule ; however, the probabili ty of a spill is very low. A catastrophic spill resulting from exploratory drilling on the Arctic OCS is highly unlikely due to the nature of the geology, the shallow water depth, and the simplicity of the wells. BOEM u sed available information to analyze the statistical probability of a catastrophic spill. However, due to the limited drilling history on the Arctic OCS, projections cannot be made with certainty. At the same time, the unquantifiable nature of many of the benefits sought to be achieved through this proposed rule ( e.g. , protection of the unique Arctic ecosystem, natural resources and Alaska Native cultural traditions) make the benefits side of the equation equally uncertain, and underestimated. Exhibit 30 presents the results of the break- even analysis for the avoided days of spilled oil .

**Exhibit 30 .**  **Break -**  **e ven Results**  **: Number of Days of Oil Spill Prevented** 

**Location Cost**  **of Spill**

**per Day ($ millions)**  **10 -** **Year Cost of the Rule ($ millions)**  **Break -**  **even Number of Days**  **7% D**  **iscounting 3%**  **D iscounting**  **7% D**  **iscounting 3%** 

**D iscounting**  **C = A × B 1**  **D E**  **F = D / C G = E / C**  Chukchi Sea $177.5 $ 1,112 $ 1,224 6 . 3 6 . 9 Beaufort Sea $113.6 $ 1,112 $ 1,224 9 . 8 10 . 8 1 A, B and C in this exhibit represent the same values as in Exhibit 28.69

As presented in Exhibit 30 , over the ten -year cost analysis period, the number of avoided or reduced days of a catastrophic oil spill needed to break- even is between 6 . 3 and 6 . 9 days for the Chukchi Sea and 9.8 and 10 . 8 days for the Beaufort Sea . To provide context, the BOEM Case Study estimates that the duration of a catastrophic incident in the Chukchi Sea would be between 40 and 75 days and an incident in the Beaufort Sea would be between 60 and 300 days . One of the key goals of the proposed SCC E and relief rig provisions is to reduce the duration of such a spill should one occur . BOEM and BSEE believe that this break- even analysis is an appropriate way to evaluate the costs and befits of the proposed rule under the circumstances. However, we invite comments on the assumptions, data and methods used in this break- even analysis. We also invite comments on whether there is a better alternative method for evaluating the costs and benefits. d. Qualitative Benefits We base d the break- even analyse s on the quantifiable avoided consequences of an oil spill , as represented by the number of fewer days of a catastrophic oil spill needed to justify the cost of the rule . In addition to reducing the quantifiable consequence s of a catastrophic oil spill, there are other benefits from the proposed rule . A catastrophic spill resulting from exploratory drilling on the Arctic OCS is highly unlikely due to the nature of the geology, the shal low water depth, and the simplicity of the wells. Despite the low likelihood of a catastrophic spill, the consequences would be severe and warrant efforts to reduce the risk further . For example, a catastrophic spill on the Arctic OCS would be very damaging to Alaska N ative s’ subsistence needs, and a humanitarian disaster for the region, while also potentially impeding future exploration and development in the region. In addition, many other non - quantifiable costs , mean that a spill of significant magnitude would be devastating to the region. Due to the uncertainty of these costs (and the corresponding benefits resulting from the proposed rule’s prevention or minimization of those costs ) , we do not present a quantitative assessment of these costs/ benefits and , instead, present a qualitative discussion .70

BOEM and BSEE have sought to quantify the benefits of the proposed rule to the extent possible. The break- even analysis presented above sought to assess the cost - effectiveness of the provisions of the rule in aggregate. Because BOEM and BSEE used a conservative approach in the valuation of an oil spill, the identified cost of an oil spill can be considered a lower bound of the true cost to society . Although we capture the environmental damage associated with a catastrophic oil spill, the analysis is limited because it only considers the environmental amenities that researchers could identify and monetize . Natural resource valuation is complex ; many factors contribute to how society value s a resource , including both use and non -use values of the resources . Many use values can be estimated by behavior and market transactions ( for example , using the harvest value of yields in the Arctic OCS region) . Many other u se values, however, might not be related to a market and are, therefore , difficult to monetize . For example, Alaska Native communities place a high value on the cultural amenities related directly to the use of the region . Because communities do not trade cultural amenities in markets, we are unable to estimate a direct value of these resources . Non -use values are much harder to estimate ; c ommon non -use values include existence values and bequest values . Individuals place a value on environmental amenities by knowing that preservation and protection of the region exists even if those individual s do n ot intend to visit the region . Bequest values relate to individuals placing a value on the preservation of regions for future generations even if they do not intend to use the resource themselves . Capturing these complex values is difficult because they are not traded in markets . Because we are unable to monetize all aspects of the consequences of an oil spill, the estimate we used captures only a portion of the value to society . Exhibit 31 presents the provisions of the proposed rule along with their primary benefit s; improving oversight of operations by Federal agencies, minimizing natural resource and ecosystem impacts, reducing the risk of a spill, improving containment of a spill, and a general benefit. The objective of the proposed rulemaking is to ensure safe and responsible oil and gas drilling on the Arctic OCS , which would result in increased safety for personnel, protection of the marine and coastal71

environment s and species, and removal of impediments to the Alaska Native s’ subsistence use . In addition , the proposed rule achieves better coordination among BSEE , BOEM , and other government agencies . For example, the information required in proposed Section 550.204 would facilitate interagency coordination between DOI and other relevant F ederal agencies , as recommended in the DOI “ Report to the Secretary of the Interior, Review of Shell’s 2012 Alaska Offshore Oil and Gas Exploration Program” (available at http://www.doi.gov/news/pressreleases/upload/Shell -report - 3 - 8 - 13 - Final.pdf ) .72 **Exhibit 31**  **. Qualitative Benefits by Provision Provision**  **Primary Benefit** (a) Additional Incident Reporting Requirements Improves oversight of operations by Federal agencies (b) Pollution Prevention Requirements Minimizes natural resource impacts (c) Additional Requirements for S ecuring W ells Reduces risk of a spill (d) Additional BOP P ressure T esting Requirements Reduces ris k of a spill (e) Real -time M onitoring Requirements Reduces risk of a spill (f) Additional Information Requirements for APDs Improves oversight of operations by Federal agencies (g) Incorporation of proposed draft API RP 2N Reduces risk of a spill (h) Additional SCCE Requirements Improves containment of a spill (i) Relief Rig Requirements Improves containment of a spill (j ) Additional Auditing Requirements Improves oversi ght of operations by Federal agencies (k) Real -time L ocation Tracking Requirements Improves oversight of operations by Federal agencies (l) IOP Requirements Improves oversight of operations by Federal agencies (m) Planning Information Requirements to A ccompany EPs Improves oversight of operations by Federal agencies (n) Industry F ami liarization with the N ew R ule General73

e. Conclusion The proposed rule would reduce both the overall risk of oil spill s on the Arctic OCS and the consequences of a spill if one were to occur . We conducted a break- even analysis of the benefits of the proposed rule. In addition, we included a qualitative discussion of potential benefits of the proposed rule that could not be quantified or monetized . The break- even analys i s showed that for the Chukchi Sea, a minimum reduction of 6 .3 to 6 .9 days for a catastrophic oil spill would result in a cost -beneficial rule over the ten -year study period . For the Beaufort Sea, we estimated that a minimum reduction of between 9 .8 and 10 . 8 days for a catastrophic oil spill would result in a cost -beneficial rule over the ten -year study period . Although the benefits of the proposed rule

— based primarily on preventing or reducing the duration or severity of catastrophic oil spills 50

—are difficult to quantify, BOEM and BSEE have determined that it is appropriate to proceed with this proposed rule . 8. UMRA This proposed rule would not impose an unfunded Federal mandate on State, local, or tribal governments but would, if finalized, create a private - sector mandate that could require expenditures exceeding $100 million in a single year by offshore oil and gas exploration companies operating on the Arctic OCS. The Initial RIA , the initial Regulatory Flexibility Act analysis for this proposed rule , and the proposed rule itself address applicable requirements of the UMRA, 2 U.S.C. 1501 et seq . Among other things, th e proposed rule, the Initial RIA , and/or the initial RFA :

50 “Catastrophic event” is defined in our analysis consistent with the BOEM Case Study, which defines it as “any high - volume, long - duration oil spill from a well blow - out, regardless of its cause (e.g. a hurrican e, human error, terrorism).” See Section 7 for additional details on assumptions about spill duration and magnitude that were included in calculating the benefits for the proposed rule.74

( 1 ) Identif

y the provisions of the Federal law (OCSLA and OPA) under which this rule is being proposed; ( 2 ) Inc ludes a quantitative assessment of the anticipated costs to the private sector (i.e., expenditures on labor and equipment) of the proposed rule ( included in Sections 5 and 6 above ) ; and ( 3 ) Include qualitative and quantitative assessments of the anticipated benefits of the proposed rule ( in cluded in Section 7 above ). In addition, because all anticipated expenditures by the private sector analyzed in the Initial RIA and the initial RFA analysis would be borne by the offshore oil and gas exploration industry in the Arctic OCS Region , the Initial RIA and initial RFA analysis satisfy the UMRA requirement to estimate any disproportionate budgetary effects of the proposed rule on a particular segment of the private sector. In addition, the Initial RIA describes BOEM’s and BSEE’s consideration of three maj or regulatory alternative s for dealing with the safety and environmental concerns raised by exploration activities on the Arctic OCS ( included in Section 3 above). BOEM and BSEE have decided to move forward with this proposed rule, in lieu of the other alternatives, because those alternatives would not as efficiently or effectively address the safety, environmental or sociocultural concerns raised by various stakeho lders on the Arctic OCS or achieve the objectives of this proposed rule. BOEM and BSEE have determined that the proposed rule would not impose any unfunded mandates or any other requirements on State, local , or tribal governments; thus, the proposed rule w ould not have disproportionate budgetary effects on such governments. Assuming, however, that the proposed rule mi ght result in budgetary effects on the Arctic OCS area, BOEM and BSEE have determined that accurately estimating such effects is not reasonably feasible . Because the proposed rule would not impose any requirements on any entities, other than companies engaged in Arctic OCS exploration activities, any budgetary effects in that area would be at least secondary results of actions or decisions75

taken by regulated (or unregulated) entities, based on a variety of circumstances (such as the price of oil, each entities’ overall financial health, and the prospects of success of any exploratory drilling) at the time. Because each of those factors is variab le and unpredictable, it is not feasible to estimate how those factors would affect an entity’s future decisions, or what impacts, if any, such decisions could have on future regional budgets. Similarly, BOEM and BSEE have determined that accurately estimating the potential effects, if any, of the proposed rule on the national economy (e.g., productivity, economic growth, employment, international competitiveness) is not reasonably feasible . The proposed rule, if finalized, would affect only exploratory dri lling activities on the Arctic OCS, and any potential impact on the national economy would depend on individual business decisions made by regulated entities (e.g., whether or not to hire new employees). Moreover, any such decisions would likely be either local or regional in effect and unlikely to have any significant national costs .