2169ss04

The Section 316(b) regulations for Phase III facilities (71 FR 35,006; June 16, 2006) require the collection of information from new offshore oil and gas extraction facilities which use a cooling water intake structure(s) that uses at least 25 percent of the water it withdraws for cooling purposes, and has a design intake flow greater than two (2) million gallons per day (MGD). Section 316(b) of the Clean Water Act (CWA) requires that any standard established under section 301 or 306 of the CWA and applicable to a point source must require that the location, design, construction and capacity of cooling water intake structure(s) at that facility reflect the best technology available for minimizing adverse environmental impact. Such impact occurs as a result of impingement (where fish and other aquatic life are trapped on structural components at the entrance to cooling water intake structures) and entrainment (where aquatic organisms, eggs, and larvae are taken into the cooling system, passed through the heat exchanger, and then pumped back out with the discharge from the facility).

The Section 316(b) Phase III rule establishes requirements under Subpart N for new offshore oil and gas extraction facilities. For these facilities, applicability criteria are found at § 125.131. The definitions provided under § 125.133 (amending the definitions at § 125.83) include new offshore oil and gas extraction facilities.

Under the Section 316(b) Phase III rule, new offshore oil and gas extraction facilities are required to submit application requirements consistent with § 122.21(r)(2), (3), and (4) and § 125.136(b) (Track I) or § 125.136(c) (Track II), respectively. In addition to the information requirements of the NPDES permit application, NPDES permits normally specify monitoring and reporting requirements to be conducted by the permitted entity. Monitoring is conducted in accordance with § 125.137 and is reported annually to the Director.^¹ Facilities are required to maintain records of all submitted documents, supporting materials, and monitoring results for at least three years (or as required by the Director).

Directors are required to review all materials submitted to them by the facilities within the scope of the Section 316(b) Phase III rule, confirm compliance with the rule, and issue NPDES permits with appropriate conditions to minimize adverse environmental impact associated with the use of the facilities’ cooling water intake structure(s).

The primary user of the data collected under the Section 316(b) Phase III rule is the EPA. State and local permitting authorities will not incur costs to administer the rule for new offshore oil and gas extraction facilities because these facilities are not under State jurisdiction. It is anticipated that other government agencies, both at the State and Federal level, as well as public interest groups, private companies, and many individuals will also use the data.

During the three years covered by this ICR, the information collection required by the Section 316(b) Phase III rule will involve responses from an estimated annual average of 37 facilities, with an annual average of 34,080 burden hours and $0.6 million (excluding labor cost). (See Section 6 and Exhibit A.11 in the Appendix for additional detail)

2. Need For and Use of the Collection

2(a) Need/Authority for the Collection

The information requirements of the Section 316(b) Phase III rule are necessary to ensure new offshore oil and gas extraction facilities comply with the rule, and thereby minimize adverse environmental impact resulting from impingement and entrainment losses due to the withdrawal of cooling water.

Section 316 was included in the Federal Water Pollution Control Act of 1972 for the express purpose of regulating thermal discharges and to address the environmental impact of cooling water intake structures. Moreover, section 316(b) is the only provision in the CWA that focuses exclusively on water intake. Section 316(b) provides that “[a]ny standard established pursuant to [CWA section 301] or [CWA section 306] and applicable to a point source shall require that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact.” Conditions implementing section 316(b) are and will continue under the Section 316(b) Phase III rule to be included in NPDES permits issued under section 402 of the CWA. Requirements for new offshore oil and gas extraction facilities are specified in Subpart N of Part 125.

The Section 316(b) Phase III rule establishes national requirements for new offshore oil and gas extraction facilities that meet the applicability requirements in § 125.131 and implements section 316(b) of the CWA as it applies to new offshore oil and gas extraction facilities as defined in § 125.133. The Section 316(b) Phase III rule does not apply to new onshore oil and gas extraction facilities that are currently regulated by section 316(b) Phase I requirements if these facilities meet the applicability criteria of the Section 316(b) Phase I regulations.

The Section 316(b) Phase III rule was issued under the authority of sections 101, 301, 304, 306, 308, 316, 401, 402, 501, and 510 of the Clean Water Act (CWA), 33 U.S.C. 1251, 1311, 1314, 1316, 1318, 1326, 1341, 1342, 1361, and 1370. For background information, rulings and court decisions affecting the Section 316(b) Phase III rule see Section III of the Preamble to the final rule (71 FR 35,006; June 16, 2006).

2(b) Practical Utility/Users of the Data

The Section 316(b) Phase III rule includes information that must be submitted to permitting authorities and data that will be collected and maintained on-site by the facility. Facilities should use the data to:

Characterize environmental conditions.
Determine appropriate design and construction technologies or operational measures.
Monitor the performance of design and construction technologies or operational measures.

Permitting authorities collect and use these data to verify that the appropriate compliance actions are selected and implemented. Under the Section 316(b) Phase III rule, EPA must maintain records compiled from the regulated facilities. Much of the basic information obtained from the NPDES permit application is stored in EPA’s Permit Compliance System (PCS) database and the new Integrated Compliance Information System (ICIS-NPDES) database. EPA stores basic notice of intent (NOI) information submitted for coverage under an NPDES general permit in the NOI database housed at the NOI Processing Center.

EPA uses the information collected to develop reports on permit issuance, backlog, and compliance rates. The Agency also uses the information to respond to public and Congressional inquiries, develop and guide its policies, formulate its budgets, assist States in acquiring authority for permitting programs, and manage the NPDES program to ensure national consistency in permitting. States can use this initial permit information along with the additional documentation and the annual reports to track facility monitoring, compliance violations, and enforcement activities.

Permittees must reapply for NPDES permits every five years. The permit renewal process is the primary mechanism for obtaining up-to-date and new information concerning on-site conditions. Although under the Section 316(b) Phase III rule new offshore oil and gas extraction facilities, as applicable, provide data from self-monitoring activities in annual reports to the permitting authority, these reports are a less comprehensive information gathering process than the permit application process. EPA will use permit renewal data to identify new species at risk or other potential concerns that could lead the permit writers to take the following actions:

Specify additional permit limitations.
Assess compliance with applicable standard requirements.
Place appropriate special conditions in permits.

Environmental and citizen groups are expected to use the data collected under the Section 316(b) Phase III rule to independently assess impingement and entrainment rates for affected water bodies in their location. In addition, the data will be useful to the scientific community for assessing the impact of cooling water intake structure(s) on recreational and commercial fisheries’ productivity and aquatic ecosystem health.

3. Non-duplication, Consultations, and Other Collection Criteria

3(a) Non-duplication

Given that the Section 316(b) Phase III rule applies to new offshore oil and gas extraction facilities, current data sources from existing facilities may already be available for the information required under the Section 316(b) Phase III rule. Therefore, it was important that EPA review existing data sources to identify currently available information on entities subject to section 316(b) regulation and to ensure that the data requested by the Section 316(b) Phase III rule are not otherwise accessible. The Section 316(b) rule requires collection of site-specific data on design, operation, and maintenance at the facility, as well as the biology in the vicinity of the intake structure. Data sources reviewed included: data collected by offices within EPA; data, reports, and analyses published by other Federal agencies; reports and analyses published by industry; and publicly available financial information compiled by government and private organizations. From this effort, EPA has determined that the information collection and reporting requirements considered in this ICR are not contained or duplicated in other routinely collected documents or reports.

3(b) Public Notice Required Prior to ICR submissions to OMB

This ICR was published in the Federal Register (74 FR 8527) on February 25, 2009. The notice included a request for comments on the content and impact of the information collection on the respondent universe. No comments were received.

3(c) Consultations

EPA undertook a wide-reaching outreach effort to collect information applicable to all rulemaking phases of Section 316(b), including Phase III. EPA conducted a program of outreach to stakeholders from the industry, public interest groups, State agencies, and other Federal agencies in the development of the final regulations. The outreach activities were intended to provide EPA with feedback on issues such as adverse environmental impact, best technology available, and the potential costs associated with the Section 316(b) Phase III rule. EPA Headquarters and Regional staff responsible for program oversight were contacted to provide revised information and data for this ICR.

3(d) Effects of Less Frequent Collection

EPA has concluded that less frequent data collection may fail to identify in a timely manner adverse environmental impact resulting from the operation of cooling water intake structure(s). In addition, less frequent collection would also hinder the ability of EPA and facility operators to take advantage of technological improvements in impingement and entrainment technologies as they occur, or to track long-term trends.

3(e) General Guidelines

The information collection requirements of the Section 316(b) Phase III rule are in accordance with the Paperwork Reduction Act guidelines at 5 CFR 1320.5(d)(2). Requests for supplemental information for the purposes of emergency response or enforcement activities are exempt from the Paperwork Reduction Act requirements.

3(f) Confidentiality

Applications for an NPDES permit and other respondent reports may contain confidential business information. However, EPA does not consider the specific information being requested by the Section 316(b) Phase III rule to be typical of confidential business or personal information. All confidential data will be handled in accordance with 40 CFR 122.7, 40 CFR Part 2, and EPA's Security Manual Part III, Chapter 9, dated August 9, 1976. Any claim of confidentiality must be asserted at the time of submission.

3(g) Sensitive Questions

Sensitive questions are defined in EPA’s ICR Handbook, Guide to Writing Information Collection Requests Under the Paperwork Reduction Act of 1995 as “questions concerning sexual behavior or attitudes, religious beliefs, or other matters usually considered private.” The requirements addressed in this ICR do not include sensitive questions.

4. The Respondents and the Information Requested

4(a) Respondents Standard Industrial Classification (SIC) and North American Industry Classification Systems (NAICS) Codes

Applicability criteria are found at § 125.131 for new offshore oil and gas extraction facilities. The definitions provided under § 125.133 (amending the definitions at § 125.83) include new offshore oil and gas extraction facilities. Use of a cooling water intake structure includes obtaining cooling water by any sort of contract or arrangement with an independent supplier (or multiple suppliers) of cooling water if the supplier or suppliers withdraw(s) water from waters of the United States. Use of cooling water does not include obtaining cooling water from a public water system or use of treated effluent that otherwise would be discharged to a water of the United States.

Respondents (i.e., SIC Major Group 13) under the Section 316(b) Phase III rule include new offshore oil and gas extraction facilities that are associated with large cooling water needs. The offshore oil and gas extraction facilities are classified under Standard Industrial Classification (SIC) codes 1311 and 1321, North American Industry Classification Systems (NAICS) codes 211111 and 211112.

4(b) Information Requested

The following sections provide details on data items requested and associated activities that the Section 316(b) Phase III rule requires respondents to undertake. The two principal respondent categories are facilities subject to the Section 316(b) Phase III rule and Directors.

New offshore oil and gas extraction facilities must submit information consistent with § 122.21(r) and § 125.136.

Although section 316(b) standards are implemented through NPDES permits, the Section 316(b) Phase III rule will not affect state Directors in a manner similar to other changes to NPDES program requirements. For new offshore oil and gas extraction facilities, the permitting process is handled directly by EPA Regions. Because these facilities are not under State jurisdiction, this burden is incurred by the Federal Government rather than the States, it is not included as part of the burden statement for state Directors.

Although under § 125.135, the Section 316(b) Phase III rule authorizes alternative requirements less stringent than those specified in § 125.134(a) through (d) if a facility can demonstrate that the costs of complying with the Section 316(b) Phase III rule would be wholly out of proportion to the costs considered by the Agency, and meet other criteria, EPA did not assess ICR costs or burden estimates for this provision since it is voluntary.

4(b)(i) Data Items, Including Record Keeping Requirements

Data items required by the Section 316(b) Phase III rule will be gathered for either record keeping or reporting purposes. NPDES permit application data items will be collected only during the year(s) prior to the beginning of each permit cycle and there are monitoring and inspection data that are required to be collected on a more frequent recurring basis. Discussions of all reporting requirements are listed below.

Reporting Requirements

New offshore oil and gas extraction facilities must submit data required under § 122.21(r)(2), (3), and (4), and velocity information, source waterbody flow information, and a Design and Construction Technology Plan as required under § 125.136(b) for Track I applications or data required under § 122.21(r)(2), (3), and (4), and Comprehensive Demonstration Study and source waterbody flow information as required under § 125.136(c) for Track II applications.

Although the Section 316(b) Phase III rule does not specifically require source water baseline biological characterization data from MODUs, the Director may request source water biological data from MODUs at his/her discretion.

Under the alternative requirements provision at § 125.135, new offshore oil and gas extraction facilities may request alternate requirements if the actual costs to the facility are wholly out of proportion to the costs considered by EPA in establishing the requirements or the requirements would result in significant adverse impacts on local water resources or energy markets. These facilities are required to submit a comprehensive cost evaluation study and a site-specific plan. However, EPA did not access ICR costs or burden for this option since it is voluntary.

The specific requirements for new offshore oil and gas extraction facilities are detailed under the Respondent Activities section below.

Annual Reporting Requirements

Facilities are required to provide monitoring records to the Director in the form of annual status report as required by § 125.137.

Record Keeping Requirements

All operators of new offshore oil and gas extraction facilities are required to keep records and to report information and data to the permitting authority to show compliance with any requirements to which they are subject. Records must be maintained for a period of at least three years from the date of permit issuance unless extended by the request of the Director. Each operator must maintain records of:

All data used to complete the permit application and show compliance with the requirements.
Any supplemental information developed under § 125.36.
Any compliance monitoring data submitted under § 125.137.

4(b)(ii) Respondent Activities

As mentioned above, respondents include new offshore oil and gas extraction facilities and Directors. Their information collection activities are described below.

Permit Application Activities

All facilities will need to perform start-up activities such as: reading the Section 316(b) Phase III rule, planning for the implementation of the rule, and training staff to perform various tasks necessary to comply with the rule. Activities performed during the permit application process will be performed only once during each ICR period. However, these application activities will be repeated again during the fifth year of the permit cycle as part of the permit renewal process.

Facility Activities

New offshore oil and gas extraction facilities are required to submit information consistent with § 122.21(r)(2), (3), and (4) and § 125.136. Facility activities are presented in Exhibit 1.

Exhibit 1. Facility Activities for Phase III New Offshore Oil and Gas Extraction

Activity Name
Start-up Activities
Permit Application Activities, Including Source Water Physical Data, Cooling Water Intake Structure Data and Source Water Baseline Biological Characterization Study
Source Waterbody Flow Information
Velocity Information (Track I)
Design and Construction Technology Plan (Track I)
Comprehensive Demonstration Study (Track II)

Activities that are required to report on source water physical data include: [§ 122.21(r)(2)]

Describing the physical configuration of the source waterbody where each cooling water intake structure is located, including areal dimensions, depths, salinity and temperature regimes and providing other documentation that supports the determination of waterbody type;
Preparing scaled drawings showing the physical configuration of the source waterbody;
Characterizing and documenting the hydrological and geomorphological features of the source waterbody;
Conducting physical studies to determine the intake’s area of influence within the waterbody and summarizing the results of such studies (including a description of methods used);
Preparing locational maps; and
Maintaining copies of these documents as well as copies of any information used in their development for a period of three years after submittal.

Activities that are required to report on cooling water intake structure data include: [§ 122.21(r)(3)]

Preparing a narrative description of the configuration of each cooling water intake structure and its location within the waterbody and in the water column;
Measuring and documenting the latitude and longitude of each cooling water intake structure in degrees, minutes, and seconds;
Developing a narrative that describes the operation of each cooling water intake structure, including design flows, daily hours of operation, number of days of the year in operation, and seasonal changes, if applicable;
Developing a flow distribution and water balance diagram for the facility that includes all sources of water to the facility, recirculating flows, and discharges;
Creating engineering drawings and locational maps in support of the cooling water intake structure descriptions mentioned; and
Maintaining copies of these documents as well as copies of any information used in their development for a period of three years after submittal.

Activities that are required to report under source water baseline biological characterization data include: [§ 122.21(r)(4)]

Characterize the biological community in the vicinity of the cooling water intake structure as well as the operation of the cooling water intake structures;
List of species (or relevant taxa) and their relative abundance in the vicinity of the cooling water intake structure, including any threatened or endangered species;
Identification of the species and life stages that would be most susceptible to impingement and entrainment.
Identification and evaluation of primary period of reproduction, larval recruitment, daily and seasonal activities, and period of peak abundance for relevant taxa; and
Documentation of any public participation or consultation (e.g. ESA) with Federal or State agencies.

For mobile offshore drilling units (MODUs), the Section 316(b) Phase III rule does not specifically require source water baseline biological characterization data, although the Director may request source water physical data from MODUs at his/her discretion.

Source Waterbody Flow Information

New offshore oil and gas extraction facilities located on an estuary or tidal river must submit source waterbody flow information as required under § 125.136(b)(2) or (c)(1). Facilities must also maintain records of all pertinent documents for a period of three years after submittal.

The information will be used to demonstrate to the Director that the facility’s cooling water intake structure meets the proportional flow requirements at § 125.134(b)(3) and § 125.134(c)(2). Calculations and guidance on determining the tidal excursion is found in the Preamble to the final Phase I Rule (68 FR 36,749; June 19, 2003) at Section VII.B.1.d.

Velocity Information (Track I)

New offshore oil and gas extraction facilities complying under Track I must submit velocity information as required under § 125.136(b)(1). Facilities must also maintain records of all pertinent documents for a period of three years after submittal. The information will be used to demonstrate to the Director that the facility’s cooling water intake structure meets the through-screen design intake velocity standard as required in § 125.134(b)(2). These requirements include specific provisions for facilities to design and construct each cooling water intake structure to a maximum through-screen design intake velocity of 0.5 ft/s.

Design and Construction Technology Plan (Track I)

Under Track I, if the facility is required to use design and construction technologies or operational measures in whole or in part to meet the requirements of § 125.134(b)(4) and/or (5) for new offshore oil and gas extraction facilities, it must submit a Design and Construction Technology Plan consistent with requirements at § 125.136(b)(3).

Comprehensive Demonstration Study (Track II)

If a facility chooses to be permitted under the requirements of Track II in § 125.134(c), it must perform and submit the results of a Comprehensive Demonstration Study. This information is required to characterize the physical and biological conditions (source water baseline) in the vicinity of the cooling water intake structure(s), characterize operation of the cooling water intake(s), and to confirm that the technology(ies) proposed and/or implemented at the cooling water intake structure reduce the impacts to fish and shellfish to levels comparable to those which would be achieved were the applicable requirements in § 125.134(b) implemented.

Recurring Activities

Biological Monitoring

New offshore oil and gas extraction facilities must conduct monitoring as required under § 125.137 of the Section 316(b) Phase III rule.

Impingement monitoring

The facility must conduct impingement monitoring, which involves collecting data on aquatic organisms trapped on the outer part of an intake structure or against screening devices during periods of cooling water withdrawal, to determine the taxa and abundance of impinged organisms. Specific monitoring activities may include:

Collecting samples to monitor impingement rates for each species over a 24-hour period, no less than once per month when the cooling water intake structure is in operation;
Enumerating impinged organisms;
Performing statistical analyses to summarize rates; and
Maintaining records of impingement monitoring results for at least three years.

Entrainment monitoring

The facility must conduct entrainment monitoring, which involves the collection of data on eggs, larvae, and other plankton incorporated with cooling water flow (entering and passing through a cooling water intake structure and into a cooling water system), to determine the taxa and abundance of entrained organisms. Specific activities may include:

Collecting samples to monitor entrainment rates for each species over a 24-hour period, no less than biweekly during the primary period of reproduction, larval recruitment, and peak abundance when the cooling water intake structure is in operation;
Enumerating entrained organisms;
Performing statistical analyses to summarize entrainment rates; and
Maintaining records of entrainment monitoring results for at least three years.

Velocity Monitoring

All new offshore oil and gas extraction facilities must conduct velocity monitoring no less than once per quarter. Velocity monitoring consists of a demonstration requirement based on the new facilities’ proposed designs, and a compliance monitoring requirement that verifies that the velocity limitation is being met.

Visual or Remote Inspections

All facilities must conduct visual inspections or employ remote monitoring devices during the period the cooling water intake structure is in operation. Visual inspections must be conducted at least weekly to ensure that any design and construction technologies required in § 125.134(b)(4), (b)(5), (c), and/or (d) are maintained and operated to ensure that they will continue to function as designed. Alternatively, the facility must inspect via remote monitoring devices to ensure that the impingement and entrainment technologies are functioning as designed. Specific activities may include:

Visually inspecting all installed technologies or, alternatively, inspecting via remote monitoring devices to confirm that the impingement and entrainment technologies are functioning as designed
Maintaining records of operational monitoring results for at least three years.

Status Report

All new offshore oil and gas extraction facilities submit their status report annually. Reporting and recordkeeping require:

Compiling biological monitoring records for each cooling water intake structure;
Compiling velocity and head loss monitoring records for each cooling water intake structure;
Compiling records of visual or remote inspections; and
Maintaining a copy of the report for a period of three years after its submission.

Director Activities

Although section 316(b) standards are implemented through NPDES permits, the Section 316(b) Phase III rule does not affect state Directors in a manner similar to other changes to NPDES program requirements. For new offshore oil and gas extraction facilities, the permitting process is handled directly by EPA Regions.

5. The Information Collected—Agency Activities, Collection Methodology, and Information Management

5(a) Agency Activities

EPA is responsible for overseeing implementation of the Section 316(b) Phase III rule. In addition, for new offshore oil and gas facilities, EPA is the permitting authority and therefore responsible for administering the program. Under these circumstances, EPA will perform the following activities:

EPA Regional Administrators must review, maintain records of, and make permitting determinations based upon all documents and reports submitted to them by the facilities.

EPA Regional Administrators must act to ensure the implementation of the Section 316(b) Phase III rule as required under § 125.139. Section 316(b) requirements are implemented for a facility through an NPDES permit. To successfully meet their responsibilities, EPA anticipates that Directors will be involved in reviewing application studies and developing permit conditions. Following receipt of a permit application, the Director will conduct the following activities as described below.

Application Activities

The Director will review materials submitted in accordance with § 125.134. The Director will review materials submitted by the applicant prior to each renewal period to determine if there have been any changes in facility operations or physical and biological attributes of the source waterbody. Any changes should be evaluated to determine the need for additional or more stringent conditions in the permit.

Permitting Activities

The Director must develop permit conditions following the review of the information submitted under § 125.136.

5(b) Collection Methodology and Management

The Section 316(b) Phase III rule provides minimum requirements regarding the type of information collected. Directors of NPDES programs are primarily responsible for determining which collection method and information management strategy are most appropriate. EPA will maintain some of the compliance data in its PCS/ICIS-NPDES databases. PCS and ICIS-NPDES are the national computerized management information systems that automate entry, updating, and retrieval of NPDES data and track permit issuance, permit limits and monitoring data, and other data pertaining to facilities regulated under NPDES. This technology reduces the burden to the permitting authority of gathering, analyzing, and reporting national permit and water quality data.

Permitting authorities (EPA regional offices) are responsible for reviewing permit applications, permits, monitoring reports, etc. to verify the accuracy of the data. Permitting authorities are also responsible for entering that data into PCS/ICIS-NPDES. Different authorities have different approaches for entering the data into PCS/ICIS-NPDES and different approaches for checking data quality. This includes the use of coding forms, double-entry, technical review, etc. Permit data can be accessed by the public in one of two ways:

Via the Freedom of Information Act (FOIA) by submitting a request to EPA or the State.
Via an on-line query using EPA’s Envirofacts Data Warehouse and Applications website at http://www.epa.gov/enviro/index_java.html. Accessing data via Envirofacts provides a method to combine PCS/ICIS-NPDES data with other EPA databases and mapping tools.

5(c) Small Entity Flexibility

The minimum design intake flow requirements in the Section 316(b) Phase III rule exclude all but one small entity from the compliance requirements. The affected facility is estimated to have a cost-to-revenue ratio of less than one percent.

EPA considers the information collection and reporting requirements to be the minimum necessary to ensure that the section 316(b) goal of “minimizing adverse environmental impact” is met. Because small entities constitute a very small share of the affected facilities and because only a small percentage of all small entities in the affected industries are subject to the Section 316(b) Phase III rule, providing them greater flexibility such as less frequent data collection and reporting requirements will not have a large effect on their overall burden, but could have an adverse impact on the effectiveness of the rule. Furthermore, because the reporting requirements differ by source waterbody type and compliance alternative selected, entities of all sizes have the flexibility to minimize their total compliance costs, including the costs and burden of information collection requirements.

5(d) Collection Schedule

Offshore oil and gas extraction facilities currently operate off the coasts of California and Alaska and throughout the Gulf of Mexico. Most activity currently takes place in the Gulf of Mexico. EPA expects that most new facility activity will also take place in this region.

EPA estimated that 19 new offshore oil and gas extraction facilities were issued permits during the first three years after promulgation. EPA anticipates that 13 of the facilities that received permits during the first ICR approval period will begin the process of renewing their permits in the second and third year of this ICR renewal period, and seven of those will complete their permit reapplication activities. EPA estimated that an additional 18 new offshore oil and gas extraction facilities will begin the permitting process during the ICR renewal period, and 18 will complete their permit application activities. There are 31 new offshore oil and gas extraction facilities that are expected to perform recurring monitoring and reporting activities during the ICR renewal period. Exhibit 2 presents the estimated implementation schedule for the 43 new offshore oil and gas extraction facilities, during the ICR renewal period.^²

Exhibit 2. Number of New Offshore Oil and Gas Extraction Facilities Assumed to Begin compliance with Information Collection: Requirements During the ICR Renewal Period by Year

Type of Activity	ICR Renewal Period
Type of Activity	Year 1	Year 2	Year 3
New Offshore Oil and Gas Extraction Facilities Beginning the NPDES Permit Application Process	6	6	6
New Offshore Oil and Gas Extraction Facilities Applying for an NPDES Permit	6	6	6
New Offshore Oil and Gas Extraction Facilities Beginning the NPDES Permit Renewal Process	0	7	6
New Offshore Oil and Gas Extraction Facilities Re-Applying for an NPDES Permit	0	0	7
New Offshore Oil and Gas Extraction Facilities Performing Annual Monitoring and Annual Reporting of Operations	19	25	31
Total Facilities Performing Activities (this includes facilities beginning application, application and/or annual activities). These will not be a sum of the lines above because some activities are performed at different times during the permit application cycle.	31	37	43

6. Estimating the Burden and Cost of the Collection

The following sections present the rationale, assumptions made, and results of EPA’s estimation of burden and costs for the implementation of the Section 316(b) Phase III rule. Specific respondent activities were detailed in section 4b(ii).

6(a) Estimating Respondent Burden

This section describes the burden estimates for facilities and Directors, as well as the methods used and assumptions made to derive them. Respondent activities are separated into those activities associated with the NPDES permit application and those activities associated with monitoring and reporting after the permit is issued. The reason for this is that the permit cycle is every five years, while ICRs are renewed every three years. Therefore, the application activities occur only once per facility during an ICR period, and so they are considered one-time burden for the purpose of this ICR. The monitoring and reporting activities that occur after issuance of the permit occur on a recurring basis. For estimates of permit renewal burdens see Exhibits A.1 (Renewal) and A.3 (Renewal) in the Appendix.

Facility Burdens

Information collection requires in-scope facilities to devote time (i.e., as measured by staff hours) and resources (e.g., copies of documents and report mailings) to produce the necessary NPDES permit applications, implementation plans, and annual status reports, as required. EPA expects that facility employees, including managers, engineers, engineering technicians, statisticians, biologists, biological technicians, draftsmen, and clerical staff, will devote time toward gathering, preparing, and submitting the various documents. To develop representative profiles of each employee’s relative contribution, EPA assumed burden estimates that reflect the staffing and expertise typically found in oil and gas extraction facilities. In doing this, EPA considered the time and qualifications necessary to complete a variety of tasks: reviewing instructions, planning responses, researching data sources, gathering and analyzing data, typing or writing the information requested, reviewing results, conferring with permitting authorities and expert consultants, and sending documents.

EPA assumed that velocity monitoring and visual or remote inspections of installed technology will be carried out by facility staff as part of the monitoring and reporting requirements. EPA anticipated that facilities will use contracted services to perform many of their required sampling and analyzing tasks. The contracted staff is likely to include project managers, biologists, statisticians, and biological technicians. The work done by these contracted employees will be done on-site on a regular basis. Therefore, the hourly burdens associated with their work are included in the overall burden estimates for each facility.

For each activity burden assumption, EPA selected time estimates to reflect the expected effort necessary to carry out these activities under normal conditions and reasonable labor efficiency rates. EPA assumed that the majority of the actual work performed by facility staff, such as researching, collecting, and analyzing data, as well as writing the documents, will be carried out by junior technical staff. Burdens associated with managerial and senior engineering staff include time for actions such as occasional or seasonal visits to supervise sampling efforts, as well as periodic review of lab results and documentation. EPA assumed that the facilities employ a drafter to perform computer aided drafting (CAD) operations. For contracted employees, EPA assumed that the majority of the work will be carried out by the biologists and the biological technicians.

EPA assumed that the new offshore oil and gas extraction facilities are able to use the Minerals Management Service (MMS) information for parts of their information collection.

Exhibit 3 provides a summary of the hourly burden estimates for facilities performing the NPDES permit application and permit renewal associated with the Section 316(b) Phase III rule. Exhibit 4 provides a summary of the hourly burden estimates for facilities performing recurring monitoring, and annual reporting activities. For a more detailed presentation of hourly burdens for facilities see Exhibits A.1 and A.2 in the Appendix.

Exhibit 3. Average per Facility Burden for each NPDES Permit Application and Permit Renewal Activity for New Offshore Oil and Gas Extraction Facilities

Activities	Permit Application Burden(hrs)	Permit Renewal Burden(hrs)
Start-up Activities	43	13
Permit Application Activities*	51	13
Source Waterbody Flow Information	38	11
CWIS Velocity Information*	150	45
Design and Construction Technology Plan	36	20
Source Water Baseline Biological Characterization Study	166	49
* Burden estimates have been corrected from the ones presented in the previous ICR to include some requirements in the final rule that were not accounted for in the previous ICR (developed based on the proposed rule). Permit Application Activities changed from 25 to 51 hours and CWIS Velocity Information activities are now accounted for.

The activities listed in the first column of Exhibit 4 correspond to the facility respondent activities outlined earlier in Section 4b(ii). All facilities are subject to the start-up and permit application activities listed in Exhibit 3. For the other listed activities only a subset of facilities are expected to perform them. The set of activities, that each facility is estimated to perform is based on the rule requirements that the facility is subject to and the type of waterbody from which it withdraws water. For a detailed presentation of the number of facilities performing each activity see Exhibits A.5 and A.6 in the Appendix.

Exhibit 4. Average Burden per Facility for Annual Monitoring and Reporting Activities for New Offshore Oil and Gas Extraction Facilities

Activities	Burden (hrs)
Biological Monitoring (Impingement)	530
Biological Monitoring (Entrainment)	370
Biological Monitoring (Entrainment, Alaska)	516
Velocity Monitoring	163
Visual Inspections	253
Annual Status Report Activities	223

Start-Up Activities

In Exhibit 3, the start-up burdens account for reading the published regulations, sample permits, and any guidance materials associated with the rule; determining the required staff and resources necessary to successfully complete the application process, and meet all monitoring and reporting requirements; and training staff to perform tasks required under the rule. It is assumed for the analysis that facilities will receive their permits at the beginning of the year. Thus, during the first year, facilities will perform permit application activities for their permits that are issued at the beginning of the second year. Facilities required to perform Source Water Baseline Biological Characterization Study will need to begin collecting monitoring data two to three years prior to submitting a permit application or use existing data from regional studies and supplement the data using newly conducted field studies. Furthermore, all facilities will begin the other permit application activities in the year just prior to receiving their issued permits. These start-up activities, applicable to all facilities, are assumed to be performed by facility management and junior technical staff.

Permit Application Activities

Permit application activities refer to the development and submittal of the required elements of the application for issuance of the NPDES permit.

As part of the permit application process, new offshore oil and gas extraction facilities will provide information on intake velocity, as well as the source water physical data, source water baseline biological characterization study, and cooling water intake structure data. EPA anticipates that much of the data required to characterize the waterbody and the cooling water intake structure has already been gathered by the facility, and that much of the actual facility burden is from deriving the requested information from this data.

The MMS requires offshore oil and gas extraction facility operators to submit information on cooling water intake structures as part of their drilling plans; therefore, much of the information required for the basic permit application requirements would have already been compiled. However, it is also assumed that the MMS information will not be completely sufficient to meet all the application information requirements.^³

To derive the source water physical data, EPA assumed that junior technical staff will work with a CAD operator to develop a description of the physical configuration of the source waterbody where the cooling water intake structure is located, including areal dimensions, depths, salinity, and temperature regimes. The CAD operator will produce scaled drawings showing the physical configuration of the source waterbody and prepare locational maps of the waterbody. The junior technical staff will use this information and available data to produce a report characterizing and documenting the hydrological and geomorphological features of the source waterbody. Depending on the extent of existing information it may be necessary for some facilities to conduct physical studies to determine the intake’s area of influence within the waterbody.

Cooling water intake structure data will be used to develop a report on the operation of the intake structure. EPA assumed that a CAD operator will assist junior technical staff in preparing a narrative description of the configuration of the cooling water intake structure and its location within the waterbody and in the water column, including measurements of the latitude and longitude of the cooling water intake structure. In addition, junior technical staff will develop a narrative that describes the operation of the cooling water intake structure, including design flows, daily hours of operation, number of days of the year in operation, and seasonal changes, if applicable. Management will review and revise this data.

Junior technical staff will also develop a narrative characterizing the facility’s cooling water system, which includes a flow distribution and water balance diagram for the facility depicting all sources of water to the facility and discharges. Management will review and revise this characterization. EPA also anticipates that the junior technical staff will perform engineering calculations for the source waterbody and cooling water intake structure documents. Management will review and revise these calculations.

Source Waterbody Flow Information

New offshore oil and gas facilities located in an estuary or tidal river must provide the mean low water tidal excursion distance and any supporting documentation and engineering calculations to show that their cooling water intake structure facility meets the flow requirements. EPA anticipates that most facilities have ready access to existing flow information. Junior technical staff are expected to gather existing information. Junior technical staff will perform engineering calculations and develop a report. Facility management will review and revise this information.

Velocity Information

New offshore oil and gas facilities must provide velocity information and any supporting documentation and engineering calculations to show their cooling water intake structure meets the velocity requirement. Junior technical staff are expected to gather data, develop a narrative, and perform engineering calculations, and a CAD operator will assist junior technical staff in performing the engineering calculations. Management will review the calculations and narrative.

Design and Construction Technology Plan

EPA assumed that the portion of the Design and Construction Technology Plan associated with evaluation of potential cooling water intake structure effects is conducted during the year prior to the issuance of the NPDES permit. EPA assumed that a CAD operator will delineate the hydraulic zone of influence, and that junior technical staff will assist the CAD operator, and management will review this work. Junior technical staff will perform engineering calculations to determine anticipated impingement rates, and develop narrative descriptions of the design and operation of all design and construction technologies or operational measures, used to meet the requirements to reduce impingement mortality. Management will review the calculations and write-up. Those facilities that need to address entrainment will spend approximately the same amount of time performing engineering calculations and developing a narrative description.

As part of the Design and Construction Technology Plan, facilities will include a site-specific evaluation of the technology(ies) and/or operational measures. This site-specific evaluation can be based on representative studies (i.e., studies that have been conducted at cooling water intake structures located in the same waterbody type with similar biological characteristics) and/or site-specific technology prototype studies. EPA assumed that, for the site-specific technology prototype studies, the facilities will conduct an on-site pilot study for the technology or operational measure.

Source Water Baseline Biological Characterization Study

The data is used to characterize the biological community in the vicinity of the cooling water intake structure and to characterize the operation of the cooling water intake structure. The data includes existing data (if available) supplemented with new field studies as necessary. In an effort to save costs, facilities within a given region may choose to conduct a regional study to collect this information as approved by the Director. EPA recognizes that many offshore oil and gas extraction facilities are regulated under NPDES general permits and that regional studies are often conducted as part of the general permit requirements. MODUs are exempt from this requirement.

There are no new facilities expected in California so there is no California regional study. There is one new facility expected in Alaska, so there is no regional study for Alaska either. Instead, the one facility was assumed to perform its own individual monitoring. Facilities in the Gulf of Mexico region are assumed to have already conducted a regional study. The burden and costs to develop this study were accounted for in the previous ICR. The results of the regional study are to be used by each in-scope Gulf of Mexico facility to complete their Source Water Baseline Biological Characterization Data requirements.

The installation of the remote monitoring device that facilities will use to comply with permit requirements is assumed to cost $23,140 per facility. This cost is presented under the Source Water Baseline Biological Characterization Data although it may not be directly linked to the development of such a study.

Recurring Facility Activities

The recurring activities for most facilities are biological monitoring, velocity monitoring, and conducting visual or remote inspections. Biological monitoring is assumed to be performed at one location on a monthly basis for impingement and on a biweekly basis for entrainment. Velocity must be monitored at initial facility startup, and thereafter, at the frequency specified in the NPDES permit, but no less than once per quarter. Furthermore, facilities must conduct visual inspections or employ remote monitoring devices. The facility must conduct inspections at least weekly or inspect via remote monitoring devices to ensure that impingement or entrainment technologies are functioning as designed. The monitoring and inspection results are analyzed and summarized in a yearly status report for new offshore oil and gas extraction facilities. For a more detailed account of the recurring burden for facilities see Exhibit A.2 in the Appendix.

Director Burdens

The Section 316(b) Phase III rule requires Directors to devote time and resources to review and respond to the NPDES permit applications; proposal, study and sampling plans; and annual status reports submitted to them as required.

Director Permit Issuance Activities

EPA expects that senior technical, junior technical and clerical staff at the EPA Regional offices will devote time toward gathering, preparing, and submitting the various documents. EPA assumed burden estimates that reflect the staffing and expertise used by States for the NPDES permit administration process. In doing this, EPA considered the time and qualifications necessary to complete various tasks such as: reviewing submitted documents and supporting materials, verifying data sources, planning responses, determining specific permit requirements, writing the actual permit, conferring with facilities and the interested public, and entering the permit information into the PCS/ICIS-NPDES databases. Exhibit 5 provides a summary of the hourly burden estimates for Directors performing various activities associated with the rule for new offshore oil and gas extraction facilities. For a more detailed presentation of Director hourly burdens, see Exhibit A.3 in the Appendix. Under the Section 316(b) Phase III rule, Directors will need to review information submitted by new offshore oil and gas extraction facilities for consistency with § 125.136 of the rule.

Exhibit 5. Average Director Burden for Activities for New Offshore Oil and Gas Extraction Facilities

Activities	Burden(hrs)
Director Permit Issuance Activities (per Facility)	229
Director Permit Re-Issuance Activities (per Facility)	104
Annual Director Activities (per Facility)	50

Monitoring Conditions

In determining the applicable monitoring requirements, the Director must require, at a minimum, that the permittee perform the monitoring established in § 125.137. The Director may modify the monitoring program based on changes to the physical or biological conditions in the vicinity of the cooling water intake structure. The requirement for modifying the monitoring program may be made when the permit is reissued. EPA assumed that junior technical staff review the facility’s monitoring requirements and make recommendations for modifying these requirements. Senior technical staff reviews and implements the recommendations. In addition, the Director may require continued monitoring based on results of monitoring done pursuant to the Verification Monitoring Plan, if applicable.

Record Keeping and Reporting

EPA assumed that clerical and junior technical staff will review the monitoring data and status report from the facilities regarding record keeping. Senior technical personnel will oversee their work.

Annual Director Activities

Facilities required to perform recurring biological monitoring, velocity monitoring, and conduct visual or remote inspections are required to submit an annual report, which details inspection and maintenance records for impingement and technology controls, and a detailed analysis of monitoring results. EPA assumed that Directors will use these reports to track facility compliance and to determine if a reduction in monitoring frequency is appropriate.

6(b) Estimating Respondent Costs

This section describes cost estimates for facilities and Directors, as well as the methods used to derive them. The cost estimates include initial permitting costs, recurring costs and permit renewal costs for facilities and Directors. Because of the five year permit cycle, facilities and Directors will incur permit renewal costs during the ICR renewal period. For detailed estimates of renewal costs, see Exhibits A.12 and A.13 in the Appendix.

6(b)(i) Estimating Labor Costs

The costs to the respondent facilities associated with the ICR activities can be estimated by multiplying the time spent in each labor category by an appropriately loaded hourly wage rate. All base wage rates used for facility labor categories were derived from the Bureau of Labor Statistic’s (BLS) Occupational Outlook Handbook 2008–2009. These reported labor rates were based on data from the year 2006 and are adjusted for inflation. Inflation factor was derived from the BLS Employment Cost Index and was used to adjust the Occupational Outlook Handbook labor rates to reflect labor rates for September of 2008.

Compensatory loading factors ranging from 35% to 53%, depending on the labor category, were used to account for any paid leave, supplemental pay, insurance, retirement and savings, and required and nonrequired benefits received by employees (BLS, 2004). EPA assumed an additional loading factor of 15% to account for general overhead costs directly attributable to facility employees performing work in support of the permit process. Expenses for contracted employees typically include higher overhead costs, as well as a fee to ensure profit for the contracting company. EPA assumed that the overhead for the contracted employees would be 50 percent (%) and the fee would be eight percent (%).

To represent the base labor rate for facility management, EPA used the average national salary for an engineering manager of $105,430 per year. This figure was divided by 2,080 hours to derive the hourly managerial wage rate of approximately $51 per hour. After adjusting this rate for inflation, compensation and overhead, the rate is approximately $96 per hour. The median annual salary of $46,810 for an engineering technician was used to represent the base labor rate for junior technical staff. After determining the hourly wage rate and adjusting for inflation and other factors, this labor rate was approximately $43 per hour. The median annual salary for a drafter performing CAD work was reported to be $20 per hour, and after adjusting and loading the rate it is approximately $38. The reported average annual salary for clerical workers was $24,690, and the fully adjusted and loaded hourly rate is approximately $20 per hour.

To represent the base labor rate for a contracted manager of monitoring work done on-site, EPA used the average national salary for a natural sciences manager of $100,080 per year, with a fully loaded rate of $116 per hour. The median annual salary for a statistician was $65,720 per year, with an adjusted hourly rate of approximately $74 per hour. Biologists and biological technicians had an average hourly pay of $28 and $17, and a fully loaded rate of $67 and $41, respectively.

Director Labor Costs

For Director costs, all of the base labor rates and compensation factors were derived from published employment cost trends for State and local government workers for the second quarter of 2004 (BLS, 2003). EPA chose the BLS labor category of white-collar professional specialist to represent the senior administrative and technical staff that would oversee and manage the NPDES permit program. The base hourly rate for this category was approximately $32 per hour, and after adjusting for compensation and inflation it is approximately $48 per hour.

Similarly, EPA chose the BLS labor category of white-collar professional technical to represent the junior technical staff that EPA expects to perform the majority of the actual NPDES permitting work. The reported base pay for this category was approximately $19 per hour, which becomes approximately $31 per hour after being adjusted for compensation, overhead, and inflation. The hourly wage for State government clerical workers was $14 per hour before adjustment, and approximately $24 afterward.

6(b)(ii) Estimating Capital and Operation and Maintenance Costs

A facility incurs capital/start-up costs when it purchases equipment or builds structures that are needed for compliance with the rule’s reporting and record keeping requirements and that the facility would not use otherwise. A facility incurs operation and maintenance (O&M) costs when it uses services, materials, or supplies that are needed to comply with the rule’s reporting and record-keeping requirements and that the facility would not use otherwise. Any costs for the operation and upkeep of capital equipment are considered O&M costs. Another type of O&M cost is for the purchase of contracted services, such as laboratory analyses. The purchase of supplies such as filing cabinets and services such as photocopying or boat rental are also considered O&M costs, and are referred to as other direct costs (ODCs).

For annual O&M costs, EPA again assumed that the analysis of impingement monitoring samples will be done on-site, while entrainment monitoring samples is performed by an outside laboratory. Laboratory analysis for entrainment samples is estimated to cost $3,610 per year per facility. The ODCs associated with biological monitoring are estimated to be approximately $790 per facility. EPA assumed that facilities will employ remote monitoring devices to monitor the equipment performance associated with impingement and entrainment. The capital cost for the remote monitoring device is estimated to be approximately $23,140 per facility.

In general, the labor costs and O&M costs reported in this analysis are assumed to represent typical average national cost estimates that are likely to be incurred by existing facilities and by permitting authorities. EPA attempted to take into account various factors such as decreases in labor efficiency that occur during extreme climate conditions, equipment down time, and the occasional sample that might need to be replaced because it was lost or spoiled during transport. Exhibit 6 provides a summary of facility level average labor costs, capital and O&M costs for permit application activities for new offshore oil and gas extraction facilities, over the three year ICR period.^⁴ For a more detailed presentation of all compliance costs for facilities, see Exhibits A.1 and A.2 in the Appendix.

Exhibit 6. Average per Facility Burden and Costs for each NPDES Permit Application Activity for New Offshore Oil and Gas Extraction Facilities

Activities	Burden (hrs)	Labor Cost (2008$)	Capital (2008$)	O&M (2008$)
Permit Application
Start-up Activities	43	$2,598	$0	$60
Permit Application Activities	51	$2,356	$0	$150
Source Waterbody Flow Information	38	$1,616	$0	$90
CWIS Velocity Information	150	$7,139	$0	$460
Design and Construction Technology Plan	36	$1,262	$0	$150
Source Water Baseline Biological Characterization Study	166	$9,268	$24,501	$0
Permit Renewal
Start-up Activities	13	$831	$0	$60
Permit Application Activities	13	$560	$0	$150
Source Waterbody Flow Information	11	$456	$0	$90
CWIS Velocity Information	45	$2,146	$0	$460
Design and Construction Technology Plan	20	$808	$0	$150
Source Water Baseline Biological Characterization Study	49	$2,760	$0	$0

Exhibit 7 provides a summary of facility level burden, average labor costs and O&M costs for recurring monitoring and reporting activities for new offshore oil and gas extraction facilities over the three year ICR period.^⁵ For a more detailed presentation of all compliance costs for facilities, see Exhibits A.1 and A.2 in the Appendix.

Exhibit 7. Average Burden and Costs per Facility for Annual Monitoring and Reporting Activities for New Offshore Oil and Gas Extraction Facilities

Activities	Burden (hrs)	Labor Cost (2008$)	O&M (2008$)
Biological Monitoring (Impingement)	530	$30,890	$12,360
Biological Monitoring (Entrainment)	370	$20,990	$18,280
Biological Monitoring (Entrainment, Alaska)	516	$28,812	$25,220
Velocity Monitoring	163	$6,833	$580
Visual Inspections	253	$11,617	$0
Annual Status Report Activities	223	$13,884	$910

Director O&M Costs

Under the Section 316(b) Phase III rule, EPA does not anticipate any O&M costs other than ODCs for Directors. Exhibit 8 provides estimates of average Director labor costs and ODCs for new offshore oil and gas extraction facilities.^⁶ For a more detailed explanation of Director costs, see Exhibit A.3 in the Appendix

Exhibit 8. Average Director Burden and Costs for Activities for New Offshore Oil and Gas Extraction Facilities

Activities	Burden (hrs)	Labor Cost (2008$)	O&M (2008$)
Director Permit Issuance Activities (per Facility)	229	$8,981	$360
Director Permit Re-Issuance Activities (per Facility)	104	$3,309	$360
Annual Director Activities (per Facility)	50	$1,798	$30

6(c) Estimating Agency Burden and Costs

EPA typically reviews NPDES permits in the early stages of implementation of new regulations. The new offshore oil and gas extraction facilities will submit their initial permit application or permit renewal to the EPA Region within which the facility will be located. Therefore, there are no additional costs incurred by the Federal government for these facilities.

6(d) Estimating the Respondent Universe and Total Burden and Costs

During the three years covered by this ICR, there are an estimated 43 facilities that the Section 316(b) Phase III rule would affect (see Exhibit 2). The regulation requires each respondent to comply with one or more provisions. In turn, each provision has numerous activities associated with it. Exhibits A.5 and A.6 in the Appendix provide an estimate of the number of respondents and responses expected for each provision of the rule during each year of the ICR renewal period. The annual estimates are based on the compliance schedule used to estimate the cost of the rule. In addition, Exhibits A.7 through A.10 in the Appendix provide a summary of the respondent burdens and costs for each year of the ICR renewal period. These estimates were calculated by multiplying facility and Director level burden and cost estimates in Exhibits A.1 through A.3 by the number of respondents performing each activity in Exhibits A.5 (see the Appendix).

6(e) Bottom Line Burden Hours and Costs Tables

This section provides a description of bottom line data collection and record keeping burden and cost estimates for implementation of the rule.

6(e)(i) Respondent Tally

The bottom line burden hours and costs for facilities and Directors are the total annual hours and costs collectively incurred for all activities during the ICR renewal period. Exhibit 9 shows a summary of the average annual number of respondents, burden hours, and costs for new offshore oil and gas facilities. The burden and cost for the three EPA regions handling the offshore oil and gas NPDES general permits is also included in Exhibit 9. These EPA regional offices are considered part of the Federal government, and the burden to the Federal government is typically considered separately from the burden to States and Facilities. However, it has been included here because of the regional offices role as the NPDES permitting authority. A more detailed summary can be found in Exhibit A.11 in the Appendix.

Exhibit 9. Summary of Average Annual Respondents, Burden, and Costs for Facilities and Directors for the ICR Renewal Period for New Offshore Oil and Gas Extraction Facilities

	Average Annual Respondents	Average Annual Burden (hours)	Average Annual Labor Costs (2008$)	Average Annual Capital and O&M Costs (2008$)	Total Average Annual Costs (2008$)
Facilities	37	34,080	$1,836,559	$597,053	$2,433,612
Directors (EPA Region)	3	2,867	$106,542	$3,750	$110,292
Totals	40	36,947	$1,943,101	$600,803	$2,543,904

6(e)(ii) Agency Tally

The bottom line burden hours and costs for the Federal agency are the total annual hours and costs collectively incurred for all activities during the ICR renewal period. Exhibit 10 provides a summary of the average annual agency burden hours, and costs. A more detailed summary can be found in Exhibit A.11.

Exhibit 10. Summary of Average Annual Agency Burden and Costs for the ICR Renewal Period for New Offshore Oil and Gas Extraction Facilities

	Average Annual Burden (hours)	Average Annual Labor Costs (2008$)	Average Annual O&M Costs (2008$)	Total Average Annual Costs (2008$)
Agency Totals	2,867	$106,542	$3,750	$110,292

6(f) Reasons For Change In Burden

The current approved ICR for the Section 316(b) Phase III new offshore oil and gas facilities was developed in 2006 and was part of the rulemaking documents. The 2006 ICR estimated an annual average respondent burden of 11,238 hours. This ICR estimates an annual average respondent burden of 34,080 hours, which represents a 3-fold increase (22,842 hours) in burden.

The change in burden results mainly from the shift from the approval period (EPA ICR No. 2169.01) to the permit implementation and renewal period of the Section 316(b) Phase III rule. Because NPDES permits are issued every five years, this ICR covers the last two years of the initial permit approval period (i.e., years four and five after promulgation) and the first year of the renewal period (i.e., year six after promulgation). In this first year of the renewal period facilities will be applying for a permit for the first time or re-applying for permit coverage that was obtained during the three years covered by the previous ICR. The activities to renew an NPDES permit are assumed to be less burdensome than those for issuing a permit for the first time.

The first year covered by this ICR corresponds to the year in which the 19 facilities permitted under the previous ICR must begin their biological monitoring activities. Six of those facilities will also begin velocity monitoring visual inspections^⁷, and annual status reports, accounting for an annual average of 20,845 (11,530 and 9,315 respectively) hours in this ICR that was not part of the 2006 ICR.

The previous ICR had an annual average of 8,665 hours for permit application activities. This ICR has 2,901 hours. The reduction is mainly because the regional studies have been completed and there is one less facility expected to apply for a permit in the next three years as compared to the previous three. This yields a net annual reduction of 5,764 hours for permit application activities. But some of the newly permitted facilities will in turn begin recurring activities (i.e., biological monitoring, velocity monitoring, visual inspections and annual status report) in year two of this ICR, accounting for an annual average of 7,382 hours in this ICR that was not part of the 2006 ICR.

The last contribution to the increase in burden comes from the permit renewal burdens and costs which were not in the first renewal ICR because more facilities are entering the renewal phase of their permit. In this ICR, 13 facilities that obtained permit coverage in the previous three years will begin their permit renewal activities, with seven of those expected to apply for a permit in the period covered by this ICR. This adds an annual average of 379 hours.

6(g) Burden Statement

The annual average burden for new offshore oil and gas facilities is 34,080 hours for an average of 37 facilities (see Exhibit A.11 in the Appendix). Hence, the annual average reporting and record keeping burden for the collection of information by facilities responding to the Section 316(b) Phase III rule is estimated to be 921 hours per respondent (i.e., an annual average of 34,080 hours of burden divided among an anticipated annual average of 37 facilities).

For new offshore oil and gas extraction facilities, the permitting process is handled directly by EPA Regions 4, 6, and 10. Since this burden is incurred by the Federal Government rather than the States, it is not included as part of the burden statement for State Directors.

Burden means the total time, effort, or financial resources expended by persons to generate, maintain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations are listed in 40 CFR Part 9 and 48 CFR Chapter 15.

To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including the use of automated collection techniques, EPA has established a public docket for this ICR under Docket ID No. EPA-HQ-OW-2008-0719, which is available for public viewing at the Water Docket in the EPA Docket Center (EPA/DC), EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The EPA/DC Docket Center Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Reading Room is (202) 566-1744, and the telephone number for the Water Docket is (202) 566-2426. An electronic version of the public docket is available for online viewing at http://www.regulations.gov. Use http://www.regulations.gov to submit or view public comments, access the index listing of the contents of the public docket, and to access those documents in the public docket that are available electronically. Once in the system, select “search,” then key in the docket ID number identified above. Also, you can send comments to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer for EPA. Please include the EPA Docket ID No. (EPA-HQ-OW-2008-0719) and OMB control number (2040-0268) in any correspondence.

1 Director means the Regional Administrator or an authorized representative. For the Section 316(b) Phase III rule EPA retains the authority to implement the NPDES program.

2 The 43 offshore oil and gas extraction facilities = 31 facilities conducting annual monitoring and reporting + 6 facilities beginning application process in year 1 + 6 facilities applying for a permit in year 1.

3 As a result of the availability of the MMS information, operators are assumed to spend approximately 75% less time than that a land based facilities. Estimates for land based facilities were developed for the Proposed Rule. (69 FR 68444, November 24, 2004)

4 EPA assumed that all new offshore oil and gas extraction facilities would pursue Track I application of the final rule because it is unknown how many facilities would select Track I or Track II for compliance. Hence the actual burden and cost estimates may be different than those presented here.

5 There are no capital costs associated with the annual monitoring and reporting activities.

6 There are no capital costs associated with the Director activities.

7 The burden to conduct visual inspections was not included in the previous 316(b) Phase III ICR. EPA is now correcting this and the burden is now accounted for.

File Type	application/msword
Author	Alejandro Escobar
Last Modified By	Albert
File Modified	2009-05-18
File Created	2009-05-18