A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to all Boeing Model 747 series airplanes was published in the Federal Register on April 29, 2003 (68 FR 22641). That action proposed to require a one-time inspection to determine whether the outer cylinder of the wing landing gear has certain part numbers, and replacement of the outer cylinder of the wing landing gear with a new, improved, or reworked part if necessary. That action also proposed to require removal of the load evening system, if such a system is installed.

Interested persons have been afforded an opportunity to participate in the making of this amendment. The FAA has duly considered the comments received.

One commenter supports the proposed AD.

Several commenters request that we revise paragraph (a) of the proposed AD to allow operators to perform a records review to determine whether a subject part is installed on the airplane. One commenter, the manufacturer, notes that this alternative should be available to operators because the subject part numbers have not been delivered on a new airplane for more than 20 years. Another commenter states that a review of its tracking system shows that the subject part numbers are not in its stock or were deleted when certain airplanes in its fleet were retired from service.

We concur with the commenters' request. If an operator has a tracking system that records the detailed part number for the outer cylinder of the wing landing gear ( i.e. , not just a higher-level assembly) for the Model 747 airplanes in its fleet, a records review is an acceptable method of complying with paragraph (a) of this AD. We have revised paragraph (a) of this AD accordingly.

One commenter requests that we revise paragraphs (b) and (d) of the proposed AD to acknowledge that Boeing Service Bulletin 747-32-2472, dated November 30, 2000, does not specify changing the part number of the outer cylinder of the wing landing gear. (Paragraph (b) of the proposed AD states that the rework procedures described in the referenced service bulletin include, among other things, changing the part number of the outer cylinder. Paragraph (d) of the proposed AD prohibits installation of the subject part numbers after the effective date of the AD.) The commenter suggests changing the wording of paragraph (b) of the proposed AD to specify marking the outer cylinder to indicate that the referenced service bulletin has been accomplished. The commenter suggests changing the wording of paragraph (d) of the proposed AD to prohibit installation of a part that has not been (inspected, reworked, and) marked to indicate that the referenced service bulletin has been accomplished.

We concur with the commenter's request and have revised paragraphs (b) and (d) of this AD accordingly.

After careful review of the available data, including the comments noted above, we have determined that air safety and the public interest require the adoption of the rule with the changes previously described. We have determined that these changes will neither increase the economic burden on any operator nor increase the scope of the AD.

On July 10, 2002, the FAA issued a new version of 14 CFR part 39 (67 FR 47997, July 22, 2002), which governs the FAA's airworthiness directives system. The regulation now includes material that relates to altered products, special flight permits, and alternative methods of compliance. However, for clarity and consistency in this final rule, we have retained the language of the NPRM regarding that material.

Since the issuance of the proposed AD, we have reviewed the figures we have used over the past several years to calculate AD costs to operators. To account for various inflationary costs in the airline industry, we find it necessary to increase the labor rate used in these calculations from $60 per work hour to $65 per work hour. The cost impact information, below, reflects this increase in the specified hourly labor rate.

There are approximately 1,106 airplanes of the affected design in the worldwide fleet. We estimate that 256 airplanes of U.S. registry will be affected by this AD. It will take approximately 1 work hour per airplane to accomplish the inspection to determine whether subject part numbers are installed, at an average labor rate of $65 per work hour. Based on these figures, the cost impact of this inspection on U.S. operators is estimated to be $16,640, or $65 per airplane.

We estimate that 225 airplanes in the worldwide fleet, and 66 airplanes of U.S. registry, are equipped with the subject outer cylinders that will require further action. It will take approximately 12 work hours per airplane to accomplish the chrome removal and inspections for cracking or heat damage, at an average labor rate of $65 per work hour. Based on these figures, the cost impact of these actions on U.S. operators is estimated to be $51,480, or $780 per airplane.

For airplanes subject to removal of the load evening system, it will take approximately 240 work hours per airplane, at an average labor rate of $65 per work hour. Based on the best data available, we estimate that necessary parts will cost $2,392. Based on these figures, the cost impact of the removal of the load evening system is estimated to be $17,992 per airplane.

The cost impact figures discussed above are based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES.

This amendment adopts a new AD for MD Helicopters, Inc. Model MD900 helicopters. This action requires installing a fail-safe device; and, thereafter, before the first flight of each day, checking for bent clips, taut lanyards, or piston rod movement. If any of these conditions are found, this AD requires replacing the control rod assembly with airworthy parts before further flight. This amendment is prompted by an accident report of fatigue failure of the piston rod in the spring capsule of the control rod assembly. This condition, if not corrected, could result in failure of the piston rod and subsequent loss of control of the helicopter.

The FAA has reviewed MD Helicopters, Inc. Service Bulletin SB900-094, dated March 17, 2004 (SB), which describes procedures for installing a fail-safe device to prevent separation of the piston rod from the spring capsule if a fracture occurs. The SB also describes a daily pilot check of the piston rod and fail-safe device after installing it.

This unsafe condition is likely to exist or develop on other helicopters of the same type design. Therefore, this AD is being issued to prevent fatigue failure of the piston rod and subsequent loss of control of the helicopter. This AD requires:

• Installing a fail-safe device on or before September 17, 2004, or based on specified hours time-in-service (TIS) of the control rod assembly, whichever occurs first.

• Before the first flight of each day, after installing a fail-safe device, unzipping the ceiling panel in the baggage compartment and checking for bent clips on the outer bell-crank assembly, taut lanyards connected to clips, and movement of the piston rod. An owner/operator (pilot), holding at least a private pilot certificate, may perform these checks. Pilots may perform these checks because they require no tools and can be done equally well by a pilot or a mechanic. However, the pilot must enter compliance with these requirements into the helicopter maintenance records by following 14 CFR 43.11 and 91.417(a)(2)(v).

• If the bellcrank assembly has taut lanyards, bent clips, or the piston rod moves in any direction, replacing the control rod assembly with an airworthy control rod assembly before further flight.

Mechanics perform the actions following the SB described previously. The short compliance time involved is required because the previously described critical unsafe condition can adversely affect the controllability or structural integrity of the helicopter. Therefore, installing a fail-safe device is required before further flight for those helicopters that have a control rod assembly with 790 or more hours TIS, and this AD must be issued immediately.

Since a situation exists that requires the immediate adoption of this regulation, it is found that notice and opportunity for prior public comment hereon are impracticable, and that good cause exists for making this amendment effective in less than 30 days.

The FAA estimates that this AD will affect 29 helicopters and take about 0.5 work hour to install a fail-safe device at an average labor rate of $65 per work hour. The daily check requires only a minimal amount of time and, therefore, the costs are negligible. Required parts will cost about $322 per helicopter. Based on these figures, we estimate the total cost impact of the AD on U.S. operators to be $10,280.50.

Although this action is in the form of a final rule that involves requirements affecting flight safety and, thus, was not preceded by notice and an opportunity for public comment, comments are invited on this rule. Interested persons are invited to comment on this rule by submitting such written data, views, or arguments as they may desire. Communications should identify the Rules Docket number and be submitted in triplicate to the address specified under the caption ADDRESSES. All communications received on or before the closing date for comments will be considered, and this rule may be amended in light of the comments received. Factual information that supports the commenter's ideas and suggestions is extremely helpful in evaluating the effectiveness of the AD action and determining whether additional rulemaking action would be needed.

Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the rule that might suggest a need to modify the rule. All comments submitted will be available in the Rules Docket for examination by interested persons. A report that summarizes each FAA-public contact concerned with the substance of this AD will be filed in the Rules Docket.

Commenters wishing the FAA to acknowledge receipt of their mailed comments submitted in response to this rule must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. 2004-SW-10-AD.” The postcard will be date stamped and returned to the commenter.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

The FAA has determined that this regulation is an emergency regulation that must be issued immediately to correct an unsafe condition in aircraft, and that it is not a “significant regulatory action” under Executive Order 12866. It has been determined further that this action involves an emergency regulation under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979). If it is determined that this emergency regulation otherwise would be significant under DOT Regulatory Policies and Procedures, a final regulatory evaluation will be prepared and placed in the Rules Docket. A copy of it, if filed, may be obtained from the Rules Docket at the location provided under the caption ADDRESSES.

A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to all Short Brothers Model SD3 series airplanes was published in the Federal Register on June 14, 2004 (69 FR 32922). That action proposed to require testing for stiffness of the aft pintle pin bushing of the main landing gear (MLG), and inspecting and measuring the aft pintle pin bushings of the MLG for damage, and for out-of-limit dimensions of the bushing bore. That action also proposed to require corrective action if necessary.

Interested persons have been afforded an opportunity to participate in the making of this amendment. No comments were submitted in response to the proposal or the FAA's determination of the cost to the public.

The FAA has determined that air safety and the public interest require the adoption of the rule as proposed.

We consider this proposed AD interim action. If final action is later identified, we may consider further rulemaking then.

The FAA estimates that 108 airplanes of U.S. registry will be affected by this AD, that it will take approximately 30 work hours per airplane to accomplish the required actions, and that the average labor rate is $65 per work hour. Based on these figures, the cost impact of the AD on U.S. operators is estimated to be $210,600, or $1,950 per airplane.

The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES .

A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to certain Gulfstream Aerospace LP Model Galaxy and Model Gulfstream 200 airplanes was published in the Federal Register on April 29, 2004 (69 FR 23458). That action proposed to require a one-time detailed inspection of the wing flap actuators for proper bonding of the flap actuator fairings to the lower skin of the wings, and related corrective or preventative actions.

Interested persons have been afforded an opportunity to participate in the making of this amendment. No comments have been submitted on the proposed AD or on the determination of the cost to the public.

Although Gulfstream Aerospace LP Alert Service Bulletin 200-57A-161, Revision 1, dated November 7, 2002, shows November 5, 2002, as the date of the original issue of the service bulletin, the actual date of the original issue of the service bulletin is November 6, 2002. There are no other revisions of this service bulletin. We have revised Paragraph (d) of this AD to specify the original issue date of the service bulletin as November 6, 2002.

After careful review of the available data, including the comments noted above, the FAA has determined that air safety and the public interest require the adoption of the rule with the changes described previously. The FAA has determined that these changes will neither increase the economic burden on any operator nor increase the scope of the AD.

The FAA estimates that 60 airplanes of U.S. registry will be affected by this AD, that it will take approximately 13 work hours per airplane to accomplish the required actions, and that the average labor rate is $65 per work hour. Required parts will be supplied free of charge by the manufacturer. Based on these figures, the cost impact of the AD on U.S. operators is estimated to be $50,700, or $845 per airplane.

The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES .

A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to all Short Brothers Model SD3 series airplanes was published in the Federal Register on June 2, 2004 (69 FR 31049). That action proposed to require installing a new warning annunciator light on the central warning panel and revising the Normal Procedures Section of the Aircraft Flight Manual to provide the flightcrew with procedures related to the new light.

Interested persons have been afforded an opportunity to participate in the making of this amendment. No comments were submitted in response to the proposal or the FAA's determination of the cost to the public.

The FAA has determined that air safety and the public interest require the adoption of the rule as proposed.

The FAA estimates that 125 airplanes of U.S. registry will be affected by this AD, that it will take approximately 30 work hours per airplane to accomplish the required actions, and that the average labor rate is $65 per work hour. Required parts will cost approximately $4,800 per airplane. Based on these figures, the cost impact of the AD on U.S. operators is estimated to be $843,750, or $6,750 per airplane.

The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES.

A proposal to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) to include an airworthiness directive (AD) that is applicable to all BAE Systems (Operations) Limited Model Avro 146-RJ series airplanes was published in the Federal Register on March 24, 2004 (69 FR 13760). That action proposed to require replacing the existing digital flight guidance computer(s) (DFGC) with a new flight computer(s).

Interested persons have been afforded an opportunity to participate in the making of this amendment. Due consideration has been given to the comments received.

Two commenters state that the unsafe condition and results specified in the AD are derived from an incorrect combination of two completely unrelated conditions. Both commenters state that the premature flare condition is due to erroneous radio altimeter data provided to the DFGCs being undetected. One of the commenters, the airplane manufacturer, states that inappropriate force that the pilot applied to the control stick resulted from the flightcrew's uncertainty as to whether the autopilot was engaged or not. The commenter requests that the Summary and Discussion sections of the proposed AD be rewritten to reflect that the two unsafe conditions are unrelated. The other commenter, the DFGC manufacturer, requests that the body of the proposed AD be rewritten to reflect that the two unsafe conditions are unrelated.

The FAA agrees that the premature flare condition and application of inappropriate force to the control stick are unrelated. Therefore, we have rewritten the statement of unsafe conditions in the Summary and body of the AD to reflect the commenters' statements. However, the Discussion section of the AD is not repeated in the final rule, so no change to the final rule is necessary in that regard.

One commenter, the DFGC manufacturer, requests that the wording of paragraph (a) of the proposed AD describing the replacement of the “existing * * * DFGC” with a “new DFGC(s) * * *” be revised to read “a modified DFGC.” The commenter states that the unsafe conditions result from erroneous data from external sources being supplied to DFGCs that are in perfect working order. The commenter indicates that specifying replacement of an existing DFGC with a new DFGC implies that the DFGC was seriously flawed and required a major redesign. The commenter states that only minor software adjustments were necessary to enhance DFGC monitoring capabilities and no redesign was needed to address the unsafe conditions. Following the same reasoning, the commenter requests that the heading of paragraph (a) be changed from “Replacement” to “Modification.”

We understand the commenter's position and agree that clarification is necessary. DFGCs returned to the manufacturer for upgrade, then returned to service certainly have been modified. However, we do not agree that the word “new” carries such negative impact, since any new DFGC produced by the manufacturer will also contain the upgrade. Therefore, the wording of the summary of the section and paragraph (a) of this AD has been changed to read “with a new or modified DFGC(s).”

We do not agree that the heading of paragraph (a) should be changed from “Replacement” to “Modification.” Though the DFGC is being switched for an upgraded DFGC, and will itself be upgraded by the manufacturer for return to service, the DFGC is still being replaced with another DFGC, not modified by the operator. No change to the final rule is necessary in this regard.

After careful review of the available data, including the comments noted above, the FAA has determined that air safety and the public interest require the adoption of the rule with the changes described previously. The FAA has determined that these changes will neither increase the economic burden on any operator nor increase the scope of the AD.

The FAA estimates that 36 airplanes of U.S. registry will be affected by this AD, that it will take approximately 1 work hour per airplane to accomplish the required actions, and that the average labor rate is $65 per work hour. Required parts will cost approximately $4,250 per DFGC (some airplanes may have 2 DGFCs). Based on these figures, the cost impact of the AD on U.S. operators is estimated to be between $4,315 and $8,565 per airplane.

The cost impact figure discussed above is based on assumptions that no operator has yet accomplished any of the requirements of this AD action, and that no operator would accomplish those actions in the future if this AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations adopted herein will not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this final rule does not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this action (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A final evaluation has been prepared for this action and it is contained in the Rules Docket. A copy of it may be obtained from the Rules Docket at the location provided under the caption ADDRESSES.

On November 24, 2003 in Release No. 33-8340, 1 we added paragraph (b) to Item 5 of Form 10-Q  2 and Item 5 of Form 10-QSB, 3 which requires companies to disclose information regarding changes to the procedures by which security holders may recommend nominees to the company's board of directors. In Release 33-8400 (the “Adopting Release”), 4 we adopted amendments to these items that inadvertently deleted paragraph (b). These amendments clarify that paragraph (b) is not deleted from Item 5 of Forms 10-Q and 10-QSB.

Also, the regulatory text in the Adopting Release states that, with regard to disclosures under Item 2.01 of Form 8-K, Completion of Acquisition or Disposition of Assets, disclosure of the identity of the source of funding need only be made when a material relationship exists between the company and the person from whom the assets were acquired. However, the release discussion is inconsistent with the regulatory text inasmuch as the release discussion indicates that disclosure of the source of funding must be made if a material relationship exists between the company and the source of funding. We are revising the regulatory text to be consistent with the release discussion, which was our original intent and consistent with commenters' remarks.

In addition, in the Adopting Release, we adopted amendments to add three checkboxes to the cover of Form 8-K to allow companies to satisfy specified overlapping Form 8-K and Regulation M-A disclosure obligations in a single filing on Form 8-K. These amendments add a fourth checkbox to allow a company to satisfy the disclosure requirements of Rule 13e-4(c), 5 the Regulation M-A provision for issuer tender offers, by including that disclosure in a Form 8-K. Also, to clarify that a Form 8-K report that satisfies the filing requirements of Rule 14a-12(b)  6 must contain all of the information required by Rule 14a-12, we are revising the reference in the newly adopted second checkbox to remove the paragraph (b) designation.

These amendments also redesignate paragraphs (a)(5)(1) and (2) of Item 5.01 of Form 8-K, Changes in Control of Registrant, as paragraphs (a)(5)(i) and (ii). A further correction pertains to Item 5.05(c) (formerly Item 10) of Form 8-K, Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics, which provides that a company need not file a Form 8-K report regarding a waiver from, or amendment to, its code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions if it posts the required disclosure on its Web site. 7 We are correcting this item to state that a company disclosing an amendment to, or waiver from, such code of ethics on its Web site must do so within four business days after the date on which the code is amended or the waiver is granted in order to comply with paragraph (c) of the item, rather than within five business days of such date. 8 We intended the deadline to parallel the general Form 8-K four business day filing deadline.

In Item 1.03 of Form 8-K, Bankruptcy or Receivership, we are revising the reference to the Bankruptcy Act to refer instead to the U.S. Bankruptcy Code  9 to acknowledge the revisions made by the Bankruptcy Reform Act of 1978. Also, in the instructions to Forms S-2 and S-3, we are changing incorrect references to Section 12  10 of the Exchange Act to refer to Section 13  11 instead.

Finally, we are correcting revisions to Item 5(a) of Form 10-K which erroneously included previously deleted regulatory text permitting the exclusion of sales made under Regulation S. 12

Under the Administrative Procedure Act (“APA”), notice of proposed rulemaking is not required when an agency, for good cause, finds “that notice and public procedure thereon are impracticable, unnecessary, or contrary to the public interest.”  13 The correcting amendments to Form 8-K are technical changes that correct cross-references, correct paragraph numbering, conform the text to the stated intent of the Commission, replace text accidentally removed, and delete text previously removed. For these reasons, the Commission finds that there is no need to publish notice of these amendments. 14 The APA also requires publication of a rule at least 30 days before its effective date unless the agency finds otherwise for good cause. 15 For the same reasons described with respect to opportunity for notice and comment, the Commission finds there is good cause for the amendments to take effect on August 23, 2004.

As published, the final regulations contain errors which are in need of clarification.

Accordingly, the publication on March 25, 2004 of the final rules (Release No. 33-8400) relating to the addition of new Form 8-K disclosure requirements and acceleration of the filing date for that form, which was the subject of FR Doc. 04-6332, is corrected as follows.

1. On page 15618, first column, eleventh line, revise the reference “Section 12” to read “Section 13”.

2. On page 15618, second column, fifth line of paragraph I.A.3.(a) under General Instructions , revise the reference “Section 12” to read “Section 13”.

3. On page 15619, first column, second line of the second checkbox, revise the reference to “14a-12(b)” to read “14a-12”.

4. On page 15619, first column, third line of the second checkbox, revise the reference to “(17 CFR 240.14a-12(b))” to read “(17 CFR 240.14a-12)”.

5. On page 15619, first column, add the following checkbox above the General Instructions .

“[] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))”

6. On page 15620, second column, fourth line of paragraph (a) under Item 1.03 Bankruptcy or Receivership, revise the reference “Bankruptcy Act” to read “U.S. Bankruptcy Code”.

7. On page 15620, third column, revise paragraph (e) under Item 2.01Completion of Acquisition or Disposition of Assets to read as follows:

“(e) if the transaction being reported is an acquisition and if a material relationship exists between the registrant or any of its affiliates and the source(s) of the funds used in the acquisition, the identity of the source(s) of the funds unless all or any part of the consideration used is a loan made in the ordinary course of business by a bank as defined by Section 3(a)(6) of the Act, in which case the identity of such bank may be omitted provided the registrant:”

8. On page 15625, third column, redesignate paragraphs (a)(5)(1) and (a)(5)(2) of Item 5.01 as paragraphs (a)(5)(i) and (a)(5)(ii).

9. On page 15627, first column, fifth line of paragraph (c) of Item 5.05, revise the word “five” to read “four”.

10. On page 15628, first column, revise amendatory instruction 20.f. to read:

“f. Revising Item 5(a);”.

11. On page 15628, first column, first line under “Item 5. Other Information,” designate the paragraph as paragraph (a).

12. On page 15628, in the second column, revise amendatory instruction 21.f. to read:

“f. Revising Item 5(a);”.

13. On page 15628, second column, first line under “Item 5. Other Information,” designate the paragraph as paragraph (a).

14. On page 15628, third column, eighth through eleventh lines in paragraph (a) under “ Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ,” remove the phrase “other than unregistered sales made in reliance on Regulation S (17 CFR 230.901 through 230.905)”.

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly.

1. On November 25, 2003, the Federal Energy Regulatory Commission issued a Final Rule adopting Standards of Conduct for Transmission Providers (Order No. 2004 or Final Rule)  1 which added Part 358 and revised Parts 37 and 161 of the Commission's regulations. The Commission adopted Standards of Conduct that apply uniformly to interstate natural gas pipelines and public utilities (jointly referred to as Transmission Providers) that were subject to the former gas Standards of Conduct in Part 161 of the Commission's regulations or the former electric Standards of Conduct in Part 37 of the Commission's regulations. 2 Under Order No. 2004, the Standards of Conduct govern the relationships between Transmission Providers and all of their Marketing and Energy Affiliates. On April 16, 2004, the Commission affirmed the legal and policy conclusions on which Order No. 2004 was based, granted and denied rehearing and offered clarification in Order No. 2004-A. 3

2. In this order, the Commission addresses the requests for rehearing and/or clarification of Order No. 2004-A. As discussed below, the Commission grants rehearing, in part, denies rehearing, in part, and provides clarification of Order No. 2004 and 2004-A.

3. Chief among the clarifications are that (1) Local distribution companies (LDCs) may release or acquire capacity in the capacity release market without becoming Energy Affiliates; (2) the Energy Affiliate exemption for LDCs extends to LDCs serving state-regulated load at cost-based rates that acquire interstate transmission capacity to purchase and resell gas only for on-system sales; (3) an LDC division of an electric public utility Transmission Provider will not be treated as an Energy Affiliate if it qualifies for the LDC exemption under § 358.3(d)(6)(v); (4) LDCs that otherwise qualify for the LDC exemption under § 358.3(d)(6)(v) do not change their status by responding to emergencies; however, each emergency activity shall be posted; (5) natural gas processors do not become Energy Affiliates by virtue of purchasing and transporting gas on affiliated Transmission Providers for plant thermal reduction purposes; (6) processors, gatherers, intrastate pipelines and Hinshaw pipelines may purchase gas for operational purposes and make de minimus sales as required to remain in balance without becoming Energy Affiliates; (7) service companies that do not engage in any activities described in §§ 358.3(d)(1), (2), (3) or (4) on their own behalf and whose employees assigned, dedicated or working on behalf of a particular entity are subject to the Standards of Conduct as if they were directly employed by that entity are not Energy Affiliates; (8) an affiliate that purchases natural gas solely for its own consumption is not an Energy Affiliate by virtue of those purchases; (9) § 358.4(a)(5) does not prohibit senior officers who are Transmission Function Employees from receiving transmission-related information; (10) Transmission Providers need not post the identity of shared physical field infrastructure, such as substations, that do not house any employees; (11) posted logs of discretionary waivers need not disclose customer names; (12) all officers of the Transmission Provider as well its employees with access to transmission information or information concerning gas or electric purchases, sales or marketing must be trained concerning the requirements of the Standards of Conduct; (13) Transmission Providers need not post notice of or transcribe scoping meetings for purposes of the Standards of Conduct; and (14) a Transmission Provider that has a division that operates as a functional unit is not required to maintain separate books and records for that unit.

4. The Commission provided a detailed background of this proceeding in Order Nos. 2004 and 2004-A, which it will not repeat here.

5. Thirty-five petitioners requested rehearing and/or clarification of Order No. 2004-A. 4

6. On May 10, 2004, in Houston, Texas, the Commission hosted a Technical Conference to provide additional informal guidance on implementing the Standards of Conduct. Approximately 230 individuals participated in the conference, which was also audiocast. As a result of the conference, industry groups have been working to bring together Chief Compliance Officers in a collaborative fashion.

7. The Final Rule and the Order on Rehearing identified a number of changes in the energy, natural gas, power and transmission markets that supported the need for enhancing the Standards of Conduct, including, but not limited to, open-access transmission, unbundling, changing commodity markets, increased mergers, convergence of gas and electric industries, asset management, electronic commodity trading and an increase in the number of power marketers or entities with market-based rate authority.

8. El Paso and INGAA request rehearing and repeat the arguments they previously made that the Standards of Conduct requirements in Order No. 2004 (and 2004-A) are overbroad and unsupported by substantial evidence. NGSA and Sempra filed comments stating that they support most aspects of the Standards of Conduct.

9. For the reasons discussed in Order Nos. 2004 and 2004-A, the Commission denies the requests for rehearing. As the Commission previously stated, the Final Rule is needed to address the Commission's statutory mandate to prevent unduly discriminatory transmission service under sections 4 and 5 of the Natural Gas Act (NGA) and sections 205 and 206 of the Federal Power Act (FPA). Order Nos. 2004 and 2004-A are needed to guide the behavior of Transmission Providers towards all of their affiliates who compete with non-affiliates for access to transmission capacity and compete in the wholesale commodity markets.

10. Entergy, Kinder Morgan, Southern and Xcel have requested that the Commission postpone the date for Transmission Providers to comply with the requirements Order No. 2004. The Commission is deferring the implementation date by three weeks and Transmission Providers are required to comply with the Standards of Conduct by September 22, 2004.

11. Section 358.3(a) defines a Transmission Provider as: “(1) Any public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce; or (2) Any interstate natural gas pipeline that transports gas for others pursuant to subpart A of part 157 or subparts B or G of part 284 of this chapter.”

12. NASUCA repeats its previous request for rehearing arguing that the Commission should classify Hinshaw  5 or intrastate pipelines as Transmission Providers under the Standards of Conduct. NASUCA argues that section 311 of the Natural Gas Policy Act of 1978 (NGPA)  6 authorizes the Commission to condition the certificates that authorize Hinshaw and intrastate pipelines to engage in transmission transactions. NASUCA claims that intrastate pipelines have the same incentives to transfer market power to their Energy Affiliates as do other Transmission Providers. NASUCA argues that requiring the independent functioning of employees would limit the opportunities for intrastate pipelines to give preferential treatment to marketing affiliates that compete with non-affiliated shippers on intrastate pipelines. NASUCA claims that discriminatory intrastate transactions have the potential to distort wholesale markets and may fall between the cracks of federal and state regulation.

13. For the reasons discussed in Order No. 2004-A (at P 36), the Commission denies NASUCA's request for rehearing and will not classify intrastate and Hinshaw pipelines as Transmission Providers under the Standards of Conduct. The Commission encourages shippers who are treated in a discriminatory fashion by an intrastate or Hinshaw pipeline that is providing service under section 311 of the NGPA to contact the Enforcement Hotline or file a complaint with the Commission.

14. AGA, National Fuel—Distribution and Questar-Gas argue that LDCs should not be considered Transmission Providers as a result of transporting interstate natural gas under Order No. 63 Certificates. The Commission agrees and stated as much in Order No. 2004-A. 7 To the extent an LDC is also a Hinshaw pipeline with Order No. 63 certificate authorization, it is not an Energy Affiliate unless it engages in Energy Affiliate activities beyond those allowed pursuant to § 358.3(d)(6)(v).

15. The Final Rule defined Energy Affiliate in § 358.3(d) as an affiliate that:

(1) Engages in or is involved in transmission transactions in U.S. energy or transmission markets; or

(2) Manages or controls transmission capacity of a Transmission Provider in U.S. energy or transmission markets; or

(3) Buys, sells, trades or administers natural gas or electric energy in U.S. energy or transmission markets; or

(4) Engages in financial transactions relating to the sale or transmission of natural gas or electric energy in U.S. energy or transmission markets.

(5) An LDC division of an electric public utility Transmission Provider shall be considered the functional equivalent of an Energy Affiliate.

(6) An Energy Affiliate does not include:

(i) A foreign affiliate that does not participate in U.S. energy markets;

(ii) An affiliated Transmission Provider or an interconnected foreign affiliated natural gas pipeline that is engaged in natural gas transmission activities which are regulated by the state, provincial or national regulatory boards of the foreign country in which such facilities are located;

(iii) A holding, parent or service company that does not engage in energy or natural gas commodity markets or is not involved in transmission transactions in U.S. energy markets; or

(iv) An affiliate that purchases natural gas or energy solely for its own consumption and does not use an affiliated Transmission Provider for transmission of natural gas or energy; or

(v) A state-regulated local distribution company that acquires interstate transmission capacity to purchase and resell gas only for on-system customers, and otherwise does not engage in the activities described in §§ 358.3(d)(1), (2), (3) or

(4), except to the limited extent necessary to support on-system customer sales and to engage in de minimus sales necessary to remain in balance under applicable pipeline tariff requirements.

16. Several petitioners repeat previous requests for an outright exemption for LDCs and all their activities. For the reasons discussed in Order No. 2004-A, the Commission denies this request.

17. AGA, Cinergy, Duke, Questar-Gas, Gulf South and National Fuel—Distribution seek rehearing and reconsideration of the Commission's decision to exempt from Energy Affiliate status only those LDCs that do not participate in wholesale market functions such as hedging. Some petitioners argue that the Commission should allow LDCs to participate in financial markets and to hedge to support on-system sales. Petitioners argue that hedging and capacity release are essential functions that allow LDCs to control costs and ensure reliability. Petitioners argue that capacity release, like de minimus sales, allows LDCs to balance their upstream transmission capacity commitments throughout the year and minimize costs to retail ratepayers. In addition, some petitioners argue that the de minimus exception for balancing sales is too vague.

18. The Commission is retaining the current version of the rule with some clarification. Specifically, an LDC would not be able to engage in financial or futures transactions or hedging without becoming an Energy Affiliate. As stated in Order Nos. 2004 and 2004-A, the Commission is concerned that transmission information could be valuable in the financial and futures markets and could be unduly preferential to an Energy Affiliate. Although several petitioners urge the Commission to narrow the definition of Energy Affiliate to permit LDCs to participate in futures markets or hedging to the extent necessary to support on-system sales, it is virtually impossible to distinguish between financial or futures transactions in a speculative market versus those needed to support on-system sales.

19. With respect to LDCs' participation in the capacity release market, the Commission did not intend to restrict the capacity release market and clarifies that LDCs may release or acquire capacity in the capacity release market without becoming Energy Affiliates. KM Pipelines requested rehearing of the Commission's statement in Order No. 2004-A, that its affiliated LDC makes off-system sales and therefore falls squarely within the definition of Energy Affiliate. (Order No. 2004-A at P 105.) KM Pipelines argue that its affiliated LDC, KMI, only makes purchases or sales of gas that are “necessary to support on-system customer sales” and does not make “off-system sales.”

20. KM Pipeline's request for rehearing on this issue has identified to the Commission an error in the regulatory text of § 358.3(d)(6)(v) of the Commission's regulations, which references both “on-system customers” and “on-system customer sales.” The Commission will revise the regulatory text at § 358.3(d)(6)(v) so that the term “on-system sales” is consistently used. We intend this correction to limit the LDC exemption to LDCs serving state-regulated load at cost-based rates, and not LDCs competing in competitive retail markets.

21. With respect to KM Pipelines's specific request, although the Commission erroneously labeled KMI's activities as “off-system,” the Commission finds that KMI nonetheless may not qualify for the LDC exemption. The Commission is concerned that an LDC which also acts as a competitive retail service provider in a state-approved retail access program could use preferential access to interstate transmission system to frustrate other competitive merchants seeking to serve the same customers. Affiliated retail merchant functions will compete against other non-affiliated retail merchants for upstream pipeline capacity, storage services, and the best gas purchase alternatives available in the wholesale energy market. Also, a competitive retail merchant has a strong profit motive in this line of its business. 8 While the Commission supports retail competition under state approved programs, the Commission must also ensure fair and non-discriminatory access to interstate transmission and storage services to all who participate in competitive retail markets.

22. In Order No. 2004-A, the Commission stated that an LDC division of an electric Transmission Provider would be treated as an Energy Affiliate. 9

23. AEP and EEI request rehearing arguing that the Commission has shown no potential for affiliate abuse relating to the sharing of employees, facilities, or information between an LDC division and its affiliated electric Transmission Provider. Because an LDC division that makes only on-system sales and does not participate in other Energy Affiliate activities is not defined as an Energy Affiliate, this question only pertains to LDC divisions that are making off-system sales or participating in Energy Affiliate activities. The Commission will revise the regulatory text to reflect the Commission's intent that an LDC division would not be treated as an Energy Affiliate to the extent that it qualifies for the LDC exemption at § 358.3(d)(6)(v).

24. With respect to LDCs that are Energy Affiliates, the Commission denies rehearing. If an LDC division provides natural gas to an electric generator in exchange for power and then sells the power, the LDC division would unduly benefit from preferential access to electric transmission information and competitors would be unduly disadvantaged. Application of the Standards of Conduct ensures that the affiliated LDC has no more information than unaffiliated competitors.

25. Entergy, Cinergy and National Grid request the Commission to clarify that both gas and electric LDCs qualify for an exemption from the definition of Energy Affiliate in § 385.3(d)(6)(v). They note that the Commission's revision to § 358.3(d)(6)(v) focuses on LDCs that are natural gas distributors and does not reference electric LDCs. They argue, however, that elsewhere in Order No. 2004-A, the Commission implied that LDC includes both natural gas and electric retail operations. They argue that provided a Transmission Provider's marketing and sales unit is treated as an Energy Affiliate, the Transmission Provider's bundled electric retail distribution function should not be treated as an Energy Affiliate. Therefore, they request the Commission to revise § 358.3(d)(6)(v) to reflect that a state-regulated LDC that acquires interstate transmission capacity to purchase and resell gas or electricity only for on-system customers is not an Energy Affiliate.

26. The Commission denies these requests for rehearing. This is one instance where the Commission's Standards of Conduct Rules were modified to reflect differences in the gas and electric industries. Gas LDCs make de minimus sales and purchases of gas to maintain line pack and keep their systems in balance. Electric LDCs do not make sales to stay in balance but instead they purchase ancillary services from the Transmission Provider or adjust generation. Electric utilities, therefore, do not need a de minimus exception for balancing.

27. AGA asks the Commission to exempt LDCs' responses to emergency situations. AGA argues that LDCs should not become Energy Affiliates in the event they make off-system sales, or take other actions in the wholesale market place in response to emergencies. The Commission clarifies that LDCs do not change their status under the LDC exemption by responding to emergencies. The LDC should inform its affiliated Transmission Provider of the emergency and the Transmission Provider is directed to comply with the requirements of § 358.4(a)(2) and post on the OASIS or Internet Web site, as applicable, each emergency activity of the LDC, within 24 hours of such emergency.

28. In Order No. 2004-A at P 97, the Commission clarified that gatherers and processors affiliated with interstate pipelines are not Energy Affiliates in certain circumstances. Further, the Commission ruled that if a gatherer or processor merely provides a gathering or processing service and only purchases natural gas to supply operational needs (such as compression fuel), and does not engage in other transmission-related activities, then it is not an Energy Affiliate. The Commission explained that when gatherers and processors engage only in gathering and processing, they provide services to wholesale market participants but do not compete with them. Order No. 2004-A further held that an affiliate may use an affiliated Transmission Provider to transport power or gas for its own consumption without becoming and Energy Affiliate as defined in the rule. See Order No. 2004-A at P 118.

29. El Paso requests that the Commission confirm that to the extent a processor purchases gas for plant thermal reduction (PTR) purposes, it is doing so to supply its operational needs and is not an Energy Affiliate. El Paso further requests that the Commission clarify that the transportation of gas for PTR purposes is not an activity that would make a processor an Energy Affiliate. The Commission grants this requested clarification.

30. CenterPoint, Duke Energy, El Paso and INGAA argue that it is arbitrary and capricious for the Commission to recognize that gatherers and processors affiliated with interstate transmission providers may purchase gas for operational purposes, but not to acknowledge that such entities also may engage in sales of gas for similar reasons. The Commission will grant clarification that processors and gatherers may purchase gas for operational purposes and make de minimus sales as required from time to time to remain in balance without becoming Energy Affiliates. The regulatory text will be modified to reflect this ( see discussion of § 358.3(d)(6)(vi) infra ).

31. CenterPoint also argues that gatherers and processors should be exempt from the definition of Energy Affiliate if they buy and sell gas from their own facilities and act as nominating/scheduling agents. CenterPoint argues that the ability to buy gas at the wellhead and resell it is a critical aspect of the gathering business model because the gatherer knows that a specific volume of gas will be gathered at a particular point and is better able to ensure maximum utilization of its investment in pipeline gathering facilities. CenterPoint claims that such certainty improves the affiliated gatherer's ability to plan and implement expansion of its gathering system.

32. The Commission denied rehearing on this point in Order No. 2004-A, and CenterPoint offers no basis for the Commission to reconsider its determination there. 10 To the extent a gatherer aggregates supply produced by others and resells that gas to the wholesale market, the gatherer is clearly acting as a marketer, and the Transmission Provider must treat it as such. To the extent CenterPoint wishes to continue to pursue its business model as a field aggregator it is not prohibited from doing so, but it must comply with the separation required of Transmission Providers and their Energy Affiliates.

33. In the Final Rule and the Order on Rehearing, the Commission concluded that producers that perform Energy Affiliate activities as described in § 358.3(d) are not exempt from the definition of Energy Affiliate.

34. Shell Offshore and Shell Gas disagree with the Commission's decision not to include a producer exemption in the new Part 358 Standards of Conduct. For the reasons stated in Order No. 2004-A, rehearing is denied. 11

35. Shell Offshore argues that because two Commissioners voted to grant rehearing of Order No. 2004 and include a producer exemption there was no majority for the Energy Affiliate definition in § 358.3(d). Shell Offshore argues that defining a producer that performs Energy Affiliate functions as an Energy Affiliate under the rule contravenes the requirement in the Department of Energy Authorization Act that Commission actions must be approved by a majority vote of the Commission. Shell Offshore requests a stay of Order No. 2004 until a valid rehearing order is issued.

36. The Commission denies Shell Offshore's request for stay. Shell Offshore states that two Commissioners voted to include a producer exemption. This is incorrect. Commissioner Brownell, in her dissent in part, stated that she would have retained the existing exemption under Order No. 497 for affiliated producers. Commissioner Kelliher, in his dissent in part, would have, among other things, expanded the scope of the LDC exemption and granted an exemption for Part 157 pipelines. He did not, however, state that he would have granted an exemption for affiliated producers. Nonetheless, the decision to define producers (as well as gatherers, processors, intrastate pipelines and Hinshaw pipelines) that perform Energy Affiliate functions as Energy Affiliates was originally made in Order No. 2004 with a 2-1 majority vote of the Commission. As there was no majority to exempt producers from the definition of Energy Affiliate on rehearing in Order No. 2004-A, producers have no blanket exemption from the definition of Energy Affiliates.

37. Shell Offshore and Shell Gas disagree with the Commission's decision not to include a producer exemption in the new Part 358 Standards of Conduct. Shell Offshore argues that there is no evidence to support the Commission's decision to expand the Standards of Conduct to cover “traditionally exempt entities such as producers shipping solely their own production.” Shell Offshore argues that the two Gas Daily articles cited in Order No. 2004-A were published after the issuance of Order No. 2004, were not in the record of this proceeding, were not available for public comment, are not relevant to the elimination of the producer exemption, and have been misinterpreted by the Commission in reaching its conclusions. Shell Offshore argues that, at best, the articles stand for the proposition that producers hold pipeline capacity only to fill the void left from the collapse of the marketers.

38. The Commission denies rehearing of a blanket exemption for producers shipping solely their own production. We do not accept Shell Offshore's argument that the Commission should categorically exempt a producer when it is shipping solely its own production over the affiliated pipeline. Such a scenario does not eliminate the possibility of the producer being in a position to take undue advantage of preferential access to transmission system information. 12

As the Commission stated in Order No. 2004:

Producers that are selling energy are competing with other non-affiliated shippers for access to the pipelines' transmission systems. Whether a producer is selling gas from its own production or from the production of another, it is competing with non-affiliates for access to the pipeline's transportation system. 13

Producers, as first sellers of natural gas, are always in a position to potentially benefit from preferential access to transmission system information. 14 While producers can and sometimes do conduct business in ways that minimize that potential, such as when a producer sells all of its gas under firm fixed-price, long-term contracts at the wellhead, such strategic decisions are choices that producers may change at will.

39. The Commission's use of the Gas Daily articles in Order No. 2004-A was neither inappropriate nor misplaced. The articles merely illustrate the point that producers have a significant presence in the wholesale commodity marketplace. 15 Producers sell significant quantities of natural gas at points downstream of the producing fields, and preferential access to transmission system information would unduly prefer their wholesale merchant function activities whether they are first sales or sales for resale.

40. While the Commission will deny rehearing, there may be circumstances where an individual interstate natural gas pipeline with an affiliated producer can demonstrate that the Commission's general concerns do not apply in a particular case. The Commission will consider requests for exemptions or waiver of the Standards of Conduct on a case-by-case basis.

41. In the Order on Rehearing, the Commission clarified that intrastate and Hinshaw pipelines affiliated with interstate pipelines are not Energy Affiliates in certain circumstances. The Commission stated that to the extent Hinshaw pipelines are state-regulated LDCs, make no off-system sales and do not engage in any of the activities described in § 358.3(d), they are not Energy Affiliates. However, the Commission also stated that if a Hinshaw pipeline makes off-system sales or participates in Energy Affiliate activities, it is an Energy Affiliate. See Order No. 2004-A at P 93. If an intrastate pipeline makes sales of natural gas, holds transmission capacity or engages in Energy Affiliate activities, it is an Energy Affiliate. See Order No. 2004-A at P 94.

42. Duke Energy, El Paso and INGAA request rehearing and urge the Commission to permit intrastate and non-LDC Hinshaw pipelines to make purchases and sales for operational reasons without triggering Energy Affiliate status. INGAA and El Paso argue that forcing only affiliates to rely exclusively on cash-out mechanisms to balance places them at a distinct disadvantage compared to any other company that must balance.

43. The Commission grants rehearing on this point. We agree with INGAA and El Paso that intrastate and Hinshaw pipelines should be permitted to make de minimus sales and purchases of natural gas to keep their systems in balance without becoming Energy Affiliates on account of that balancing. The Commission will codify in a new section (§ 358.3(d)(6)(vi)) as follows: A producer, gatherer, Hinshaw pipeline or an intrastate pipeline that makes incidental purchases or sales of de minimus volumes of natural gas to remain in balance under applicable pipeline tariff requirements and otherwise does not engage in the activities described in §§ 358.3(d)(1), (2), (3) or (4).

44. Duke Energy adds that intrastate and non-LDC Hinshaws should also be permitted to hedge financial risk without triggering Energy Affiliate status. The Commission denies rehearing. Duke Energy's request that intrastate and Hinshaw pipelines be permitted to hedge financial risk is denied because hedging financial risk is a commodity function. There is no reason that entities performing that commodity function should have preferential access to transmission information.

45. In Order Nos. 2004 and 2004-A, the Commission stated that service companies that do not engage in energy or natural gas commodity markets and are not involved in transmission transactions in U.S. markets are not Energy Affiliates. See Order No. 2004 at PP 52-58 and Order No. 2004-A at PP 108-115. The Commission also stated that if a Transmission Provider utilizes a service corporation or other subsidiary as a mechanism for employment, all employees assigned, dedicated or working on behalf of a particular entity, such as a Transmission Provider or Energy Affiliate, are subject to the Standards of Conduct as if they were directly employed by the Transmission Provider or Energy Affiliate. See Order No. 2004-A at P 110. However, in Order No. 2004-A, the Commission also noted that agency agreements can be used to aggregate control over transmission capacity and clarified that a service company may act as agent for its affiliated Transmission Provider, Marketing or Energy Affiliate without becoming an Energy Affiliate so long as the service company is involved in only non-energy'related activities. The Commission also stated that if the service company/agent is involved in energy-related activities, it is an Energy Affiliate. See Order No. 2004-A at P 115.

46. EEI, INGAA, AEP, Cinergy, Entergy, Southern and Xcel argue that service companies should not become Energy Affiliates simply by acting as agents for energy-related activities. EEI claims that many service companies would have to be split in to two separate service companies and urges the Commission to allow employees to function separately within the service company by observing the Standards of Conduct. AEP argues that service companies are not Energy Affiliates unless the service companies are also entering into energy-related contracts on their own behalf. AEP also suggests that another alternative would be to prohibit the service company from entering into energy-related agreements on behalf of both the Transmission Provider and its Marketing/Energy Affiliates. Cinergy argues that the Commission has not provided any support for prohibiting an SEC-approved service company from acting as agent for its affiliates with respect to energy-related activities. Several petitioners urge the Commission to state that service companies are not Energy Affiliates provided they maintain the separation of functions requirements when acting on behalf of a Transmission Provider or Energy Affiliate. Southern argues that the Public Utility Holding Company Act of 1935 (PUHCA) requires service companies to act on behalf of all their affiliates.

47. The Commission grants clarification, in part. Petitioners raise a valid point that the language in P 115 swallows the exception described in Order No. 2004 and the previous paragraphs in Order No. 2004-A. In addition, although Order No. 2004-A expressed some concern about service company employees acting as agents for energy-related transactions, such service company employees will be subject to the Standards of Conduct, and the Commission will treat them as if they were directly employed by the Transmission Provider or Marketing/Energy Affiliate. Accordingly, the Commission adopts petitioners' requests and excludes service companies from the definition of Energy Affiliate unless they are engaging on their own behalf in any energy-related transactions covered under §§ 358.3(d)(1), (2), (3) or (4) and on the condition that the service company employees assigned, dedicated or working on behalf of a particular entity are subject to the Standards of Conduct as if they were directly employed by that entity.

48. Section 358.3(d)(6)(iii) excludes from the definition of Energy Affiliate, a holding, parent or service company that does not engage in energy or natural gas commodity markets or is not involved in transmission transactions in U.S. energy markets. In Order No. 2004- A, 16 the Commission noted in response to a question from Kinder Morgan Pipelines that it would consider individual requests if a parent company/LDC can demonstrate an acceptable level of independent functioning by an LDC division.

49. Kinder Morgan Pipelines request clarification that its parent company will not lose the exemption from Energy Affiliate status afforded by § 358.3(d)(6)(iii) due to the fact that its parent company is an LDC which participates in wholesale energy and capacity markets to serve on-system load, as long as its LDC operations also qualify for the exemption afforded in § 358.3(d)(6)(v). Kinder Morgan Pipelines argue that the Commission erroneously concluded that its LDC function made off-system sales in concluding that Kinder Morgan Pipelines' parent company did not qualify for the parent company exemption. 17 Kinder Morgan Pipelines argue that its parent company/LDC does not make off-system sales, and therefore should qualify for the exemption afforded LDCs.

50. The Commission clarifies that a parent or holding company will not lose the exemption from Energy Affiliate status provided by § 358.3(d)(6)(iii) if it is also an LDC, as long as the LDC qualifies for the LDC exemption provided by § 358.3(d)(6)(v). However, as noted in our earlier discussion, Kinder Morgan Pipelines' LDC operations, to the extent they include service to competitive retail markets, at market-based prices would not qualify for the LDC exemption of § 358.3(d)(6)(v).

51. Section 358.3(d)(6)(iv) excludes from the definition of Energy Affiliate, “an affiliate that purchases natural gas or energy solely for its own consumption and does not use an affiliated Transmission Provider for transmission of that natural gas or energy.” In Order No. 2004-A, the Commission clarified that an affiliate buying gas or power for its own consumption “may use an affiliated Transmission Provider,” and cautioned that “the Transmission Provider must treat the affiliate as an Energy Affiliate unless the gas or power is for its own consumption.” See Order No. 2004-A at P 118.

52. To reflect the Commission's intent, INGAA requests that the Commission revise the regulatory text of § 358.3(d)(6)(iv) to delete the words “and does not use an affiliated Transmission Provider for transmission of that natural gas or energy.” The Commission agrees that the regulatory text at § 358.3(d)(6)(iv) needs to be revised to reflect the Commission's clarifications in Order No. 2004-A. However, the specific change suggested would not fully reflect the Commission's intent because it is overly broad. Accordingly, the Commission will revise § 358.3(d)(6)(iv) to read as follows:

(iv) An affiliate that purchases natural gas or energy solely for its own consumption. “Solely for its own consumption” does not include the purchase of natural gas or energy for the subsequent generation of electricity.

53. One of the most significant elements of the Standards of Conduct is the requirement that Transmission Providers function independently of their Marketing and Energy Affiliates. The independent functioning of the Transmission Provider limits its ability to give its Marketing and Energy Affiliates unduly preferential service or access to information. Therefore, § 358.4(a)(1) requires the transmission function employees of the Transmission Provider to function independently of the Transmission Provider's Marketing or Energy Affiliates' employees. 18 In Order Nos. 2004 and 2004-A, the Commission codified certain exceptions that permit a Transmission Provider to share certain categories of employees with its Marketing or Energy Affiliate. Specifically, a Transmission Provider may share with its Marketing and/or Energy Affiliates: (1) Support employees and field and maintenance employees;  19 (2) senior officers and directors who are not Transmission Function Employees;  20 and (3) risk management employees that are not engaged in Transmission Functions of sales or commodity functions. 21 However, the Commission has also stated that although certain categories of employees are permitted to be shared, the Commission will look to employees' actual functions and duties to determine whether the Transmission Provider is appropriately applying this exemption to particular employees. See Order No. 2004-A at P 131.

54. In Order No. 2004, the Commission stated that it would allow senior officers and directors who do not engage in transmission functions, or have day-to-day duties and responsibilities for planning, directing, organizing or carrying out transmission-related operations, to maintain such positions with the Transmission Provider and its Marketing or Energy Affiliates. The Commission, however, cautioned that shared executives may not serve as conduits for sharing transmission, customer or market information with a Marketing or Energy Affiliate.

55. In Order No. 2004-A, the Commission codified the exemption for senior officers and directors in the regulatory text. 22 In addition, the Commission revised the regulatory text in § 358.4(a)(5) to better reflect that the Commission did not intend to restrict corporate governance functions. 23

56. AGA, INGAA, LPPC, NiSource, Southern and Xcel requested clarification regarding the sharing of senior officers and directors. Southern claims that it is still unclear regarding which officers and directors can be shared. NiSource argues that Transmission Providers should be permitted to share senior officers and directors serving policy roles that do not involve day-to-day transmission operations with their Energy Affiliates and make it clear that such senior officers and directors may communicate with their counterparts employed by the Energy Affiliates. AGA queries whether a senior officer or director who approves a limited number of transactions or investments or who is involved in corporate planning (capacity expansion), as opposed to day-to-day planning for transmission is a Transmission Function Employee. LPPC seeks clarification that senior officers and directors may, upon occasion, review and execute transmission function or energy affiliate transactions when such transactions exceed the delegated authority for middle management to approve.

57. Permitting the sharing of high-level officers and directors is a balance between the Commission's requirement to have a Transmission Provider function independently of its Marketing/Energy Affiliates and the need for the company to have officers and directors who are accountable, can exercise their fiduciary responsibilities and can engage in corporate governance functions. High-level officers and directors have significantly different roles and responsibilities at various Transmission Providers. To the extent that senior officers or directors conduct transmission functions or are involved in planning, directing or organizing transmission functions, the officers' or directors' status does not automatically exempt them from also being a Transmission Function Employee.

58. INGAA requests clarification and regulatory text revisions that § 358.3(a)(5) does not prohibit senior officers of the pipeline who are Transmission Function Employees from receiving transmission-related information. The Commission so clarifies, and will clarify the regulatory text to indicate that § 358.3(a)(5) pertains to shared senior officers and directors.

59. Section 358.4(a)(4) codifies the Commission's historical policy of allowing Transmission Providers to share field and maintenance personnel with their Marketing and Energy Affiliates. In Order No. 2004-A, the Commission clarified that shared field and maintenance employees include field supervisors who do not take part in advance planning for facility closures or are involved in shutting down facilities based on economic reasons. The Commission also clarified that the field and maintenance employees' exception applies to technicians, mechanics and their immediate supervisors who are responsible for electric transmission activities. See Order No. 2004-A at PP 145 and 146.

60. Shell Offshore questions whether it is permissible to share second-level supervisors, some of whom are located onshore, that “control” a gas pipeline's operations such as shutting in production on a platform.

61. Without reviewing the specific job descriptions for Shell Offshore's second-level supervisors, the Commission cannot generically state whether these individuals are permissibly shared field and maintenance personnel. The field and maintenance personnel exception was developed to allow the sharing of employees who would not be in a position to give undue preferences to Energy Affiliates either by sharing information or through physical control of facilities.

62. Shell Offshore may request that the Commission address its specific configuration in an individual filing in which it describes in detail the duties and functions of affected employees.

63. Order No. 2004 prohibits the sharing of risk management employees who are operating employees of either Transmission Providers or their Marketing or Energy Affiliates. 24 The Final Rule also prohibits risk management employees from being conduits for improperly sharing information because they are in a position to use transmission, customer and market information to give Marketing and Energy Affiliates undue advantages. In Order No. 2004-A, the Commission codified an exception in § 358.4(a)(6) that permits Transmission Providers to share risk management employees that are not engaged in transmission functions or sales or commodity functions with their Marketing and Energy Affiliates. The Commission also stated that it is permissible for the risk management function to: (1) Manage corporate-wide business risk exposure of the corporation and/or its affiliates; (2) evaluate business risk exposure for third parties on an aggregate basis; (3) manage overall corporate investment for the entire corporation; (4) approve expansion projects; and (5) establish spending, trading and capital authorities for each business unit. See Order No. 2004-A at P 153. However, the Commission stated that the risk management function is not permitted to assess creditworthiness of a particular customer under a pipeline's tariff. Id. This is consistent with the Commission's previously articulated policy, in which the Commission held that the “act of deciding whether a potential shipper can become an actual shipper by satisfying the creditworthiness requirements under [a pipeline's] tariff is a transportation function.”  25 Finally, in Order No. 2004-A, the Commission emphasized that the risk management function cannot be used to share information with Marketing or Energy Affiliates that the Transmission Provider is prohibited from sharing under § 358.5(a). The limitations on shared risk management functions or employees are intended to prevent unduly discriminatory behavior in favor of a Marketing or Energy Affiliate. See Order No. 2004-A at P 154.

64. Duke Energy, EEI and INGAA request additional clarification and/or rehearing regarding the employees engaged in risk management functions for Transmission Providers and their Marketing/Energy Affiliates.

65. EEI claims that the Commission should permit the sharing of certain critical functions, such as risk management, because such employees must be knowledgeable and have intimate knowledge of their companies, the customers and the various issues affecting transmission service and retail/wholesale energy sales. Duke Energy expressed concern because Commission Staff stated at the May 10, 2004, Technical Conference that under the Standards of Conduct, risk management employees would be prohibited from engaging in certain activities or receiving certain information. Duke Energy requests clarification that the Standards of Conduct will not restrict the essential functions of corporate risk management.

66. INGAA claims that for a corporate risk management group to be able to function, it must be able to understand, and obtain information from all business units concerning their business and their business strategies. INGAA is concerned that the Commission allows the risk management group to evaluate risk, but will not allow the risk management group to take action on the risks because such action would make the risk management employees operating employees of an Energy Affiliate. INGAA also requests clarification whether the risk management personnel would be allowed to direct action (subject to a no conduit rule) to minimize risk.

67. INGAA also requests clarification that the corporate risk management unit is permitted to receive creditworthiness information from the pipeline, evaluate and communicate the results of that creditworthiness analysis to the pipeline. In INGAA's view, the corporate risk management unit could communicate to an Energy Affiliate that a particular company had exceeded its corporate-wide credit limit or that the customer's credit rating had been downgraded, but could not inform the Energy Affiliate that the particular company had not paid its pipeline transportation fees or had acquired significant amounts of additional pipeline capacity.

68. The Commission is denying the requests for clarification. Sharing of risk management functions is permitted to allow companies to assess corporate-wide risk. It is not intended to allow the shared risk management employees to serve as operators of Transmission Providers or Marketing/Energy Affiliates. Therefore, shared risk management employees should not direct Transmission Providers' or Marketing/Energy Affiliates' responses to the risks they identify. A shared risk management employee cannot decide whether a transmission customer receives service, sets prices, or sets other rates, terms or conditions of transmission service, such as a specific amount of collateral a non-creditworthy shipper must post before receiving service. A shared risk management employee may: (1) Manage corporate-wide business risk exposure of the corporation and/or its affiliates; (2) evaluate business risk exposure for third parties on an aggregate basis; (3) manage overall corporate investment for the entire corporation; (4) approve expansion projects; and (5) establish spending, trading and capital authorities for each business unit. 26

69. Furthermore, the Commission is troubled by the implication, as suggested by INGAA, that in the absence of specific tariff authority a Transmission Provider might use communications from a corporate-level risk management group as a reason to deny service to particular customers. A Transmission Provider's creditworthiness process must be described in its tariff so that the Commission may determine whether any use of corporate-wide credit review and screening processes are just and reasonable and not unduly discriminatory.

70. INGAA and others requested clarification of Order No. 2004 regarding the classification of lawyers as Transmission Function Employees. In Order No. 2004-A, the Commission stated that “if lawyers participate in transmission policy decisions on behalf of a Transmission Provider, the Commission considers that activity as a Transmission Function and the lawyer is a Transmission Function Employee. For example, a lawyer who participates in a decision on whether the Transmission Provider should seek a contract with a customer is acting as a Transmission Function Employee. If, however, the lawyer is asked to implement the Transmission Provider's business decision and negotiate a contract with that customer, the lawyer would not be a Transmission Function Employee.” See Order No. 2004-A at P 157.

71. EEI, Entergy, INGAA and Sempra request rehearing and/or additional clarification on when lawyers become Transmission Function Employees. Specifically, EEI requests that the Commission clarify that lawyers acting in their traditional and fiduciary role of providing advice to their clients can continue to be shared employees and be housed in shared services legal departments. Entergy repeats some of its previous rehearing requests and seeks further guidance on the Commission's clarification on when lawyers become Transmission Function Employees. Specifically, Entergy points out that lawyers are often called upon by individuals involved in business decisions to provide legal opinions regarding regulatory requirements and the impact of those requirements on business decisions. Entergy seeks clarification that the provision of legal advice to a business person does not constitute a Transmission Function or Energy Affiliate activity, and does not render the employee as improperly shared between the Transmission Provider and Marketing or Energy Affiliate. Entergy also seeks clarification whether Order Nos. 2004 and 2004-A mandate separate legal departments, physical separation of lawyers within such departments, or lack of physical access by Energy Affiliate employees to legal department offices or floors where there are lawyers who meet the definition of Transmission Function Employee.

72. INGAA requests the Commission to clarify that a Transmission Provider's lawyer's participation in a Transmission Provider's business decisions is for the exclusive or predominant purpose of rendering legal or regulatory advice, and that such lawyers are not treated as Transmission Function Employees. INGAA argues that a lawyer whose participation is limited solely or predominantly to rendering legal or regulatory advice should not be considered a Transmission Function employee because s/he is not “conducting” transmission system operations or planning, directing or organizing transmission-related operations. INGAA claims the court affirmed the Commission's previous determination that lawyers could be shared by stating that “professionals such as attorneys and accountants are regularly entrusted with information which they must hold confidential from other clients, the public and even other personnel in their own firms or companies.”  27 Finally, INGAA identifies cases, in the context of attorney-client privilege, which distinguishes the lawyer's traditional role as a legal advisor in business decisions.

73. Sempra expresses concern whether shared services lawyers and other shared services personnel who help develop and advocate policy in public forums are deemed Transmission Function Employees for purposes of the Standards of Conduct. Sempra queries whether the lawyer who drafts pleadings, provides legal and regulatory advice relating to public policy positions but does not have transmission information can be shared. Sempra also queries whether shared services lawyers who advise Transmission Function Employees on legal and regulatory requirements associated with business operations should be deemed Transmission Function Employees. If a lawyer performs some Transmission functions, is s/he dedicated to that function and can no longer be shared.

74. The Commission clarifies that lawyers may provide legal or regulatory advice in their traditional roles without becoming Transmission Function Employees. However, to the extent that they conduct transmission functions, or are involved in planning, directing or organizing transmission functions, the lawyers' status as “lawyers” does not exempt them from also being Transmission Function Employees. If a lawyer performs some Transmission Functions, then s/he is dedicated to that function, and cannot be shared with the Marketing or Energy Affiliate. Lawyers who help develop and advocate policy in public forums are not necessarily Transmission Function Employees. Such advocacy may fall within the lawyers' traditional role of publicly representing their clients' positions.

75. In many instances, lawyers have a significant amount of access to the Transmission Providers' transmission, customer and marketing information. Lawyers, like other employees or agents, are prohibited from being conduits for improperly sharing information between a Transmission Provider and its Marketing or Energy Affiliates. See 18 CFR 358.5(b)(7). Lawyers, like other Transmission Provider employees are expected to restrict access to transmission, customer or market information using appropriate measures, such as locked file rooms/drawers and password protection for computer files. Securing the Transmission Providers' information will limit the ability of Marketing/Energy Affiliate employees to improperly obtain access to information while visiting the legal department offices or floors where lawyers work. The Commission is not mandating separate legal departments or physical separation of lawyers within a legal department, although either of those measures might simplify compliance. A Transmission Provider's organizational chart should reflect any sharing of lawyers. Shared office space should also be identified as required by § 358.4(b)(2).

76. Section 358.4(b) requires all Transmission Providers to post information, including organizational charts and job descriptions, with respect to Marketing and Energy Affiliates on their OASIS or Internet websites. The Transmission Provider is also required to update the organizational charts and job descriptions within seven business days of a change. In Order No. 2004-A, the Commission explained that the purpose of posting organizational charts and job descriptions is to provide a mechanism for the Commission and market participants to determine whether the Transmission Provider is functioning independently of its Marketing and Energy Affiliates.

77. On rehearing, NiSource argues that the Commission should: (1) Make clear that Transmission Providers need only post information identifying the particular support units (non-Transmission Function Employees) that are shared with their Energy Affiliates; (2) clarify that Transmission Providers are not required to post full organizational charts for their service companies or shared support units; and (3) not require that Transmission Providers post organizational charts for non-affiliated companies that may provide certain non-transmission related services to the Transmission Provider.

78. As the Commission stated in Order No. 2004-A (at P 163), the Transmission Provider must post an organizational chart that identifies the parent corporation with the relative position in the corporate structure of the Transmission Provider, Marketing and Energy Affiliates. The Transmission Provider is not required to post detailed organizational charts for the shared non-Transmission Function support units, but these units must be identified as shared in the organizational chart that identifies the corporate structure of the Transmission Provider and its relative position to the parent company and other Marketing/Energy Affiliates.

79. Similarly, the Transmission Provider must include the service company in the organizational chart that identifies the corporate structure. With respect to whether a detailed organizational chart is also required for a service company, the answer depends on the functions that the service company is performing. If the service company is performing transmission functions, additional detail is required. As the Commission stated in Order No. 2004-A at P 163, there may be instances where a corporation should post both functional and structural organizational charts to accurately reflect its operations. NiSource may seek specific guidance from the Commission on the information to include in its organizational chart postings with respect to service companies.

80. With respect to NiSource's last request, the Commission clarifies that Transmission Providers are not required to post organizational charts regarding non-affiliated companies that may provide non-transmission functions for the Transmission Provider.

81. Section 358.4(b)(3)(iii) provides that, for all employees who are engaged in transmission functions for the Transmission Provider and marketing or sales functions or who are engaged in transmission functions for the Transmission Provider and are employed by any of the Energy Affiliates, the Transmission Provider must post the name of the business unit within the marketing or sales unit or the Energy Affiliate, the organizational structure in which the employee is located, the employee's name, job title and job description in the marketing or sales unit or Energy Affiliate, and the employee's position within the chain of command of the Marketing or Energy Affiliate.

82. On rehearing, INGAA argues that as written, § 358.4(b)(3)(iii), which requires the posting of all shared employees engaged in transmission functions, appears to contradict the independent functioning requirement in § 358.4(a) by suggesting that employees engaged in transmission functions for the Transmission Provider can be employees of an Energy Affiliate. INGAA, therefore, requests the Commission to reword § 358.4(b)(3)(iii) to avoid contradicting § 358.4(a), or if the Commission so intended, to clarify under what non-emergency circumstances an Energy Affiliate employee may perform transmission functions for the Transmission Provider. The Commission denies the request for clarification. Section 358.4(b)(3)(iii) is intended to identify the shared employees of Transmission Providers which have received exemptions of the independent functioning requirements of the Standards of Conduct. 28

83. Section 358.4(b)(v) requires the Transmission Provider to post on the OASIS or Internet website the name(s) and address(es) of potential merger partner(s) as affiliates within seven days after the potential merger is announced.

84. INGAA and Enbridge urge the Commission to clarify that the seven-day posting requirement is only triggered by a public announcement, when, and to the extent, such an announcement is required by other applicable law, such as the securities laws administered by the Securities and Exchange Commission (SEC). They argue that the Commission should clarify that Order No. 2004-A does not impose any new, independent obligation to publicly announce a proposed merger.

85. As noted by INGAA, mergers are customarily subject to various contingencies that must be satisfied prior to consummation. The Commission clarifies that it is not imposing a new, independent obligation to publicly announce a proposed merger in advance of applicable SEC requirements. However, once a public announcement has been made, the Transmission Provider must post the name(s) and address(es) of potential merger partner(s) and related Energy Affiliates on the OASIS or internet Web site.

86. Section 358.4(c) requires a Transmission Provider to post notices of employee transfers on the OASIS or Internet Web site. In Order No. 2004-A, the Commission clarified that the requirement is intended to capture the transfers between a Transmission Provider on the one hand and its Marketing or Energy Affiliates on the other.

87. NiSource requests clarification whether the Commission is requiring the posting of transfers between Energy and Marketing Affiliates. The Commission clarifies that it is not requiring the posting of transfers between Energy and Marketing Affiliates. The posting requirement applies only to transfers involving both a Transmission Provider and an Energy or Marketing Affiliate.

88. Section 358.4(b)(2) requires Transmission Providers to post the facilities shared with Marketing or Energy Affiliates.

89. Allegheny, AEP and NiSource request clarification on the information that needs to be posted with respect to shared facilities. ITC and NiSource assert that Transmission Providers should not be required to post all field facilities that are shared by a Transmission Provider and Marketing/Energy Affiliate. Similarly, Allegheny seeks clarification as to what shared facilities need to be identified. It claims that if a Transmission Provider has spun off generation to an affiliate, shared facilities would include every substation where such generation interconnects with the Transmission Provider. Allegheny and ITC request that the Commission clarify that the types of facilities that are required to be posted are office buildings and computer systems, and not physical infrastructure (such as substations or other transmission equipment that do not house transmission personnel).

90. The Commission grants the requests for clarification. Transmission Providers need not post notice of shared physical field infrastructure such as substations or other transmission equipment that is not housed with any employees.

92. Questar Pipeline claims, as a procedural matter, that the requirement to post exercises of discretion was a “new” burden that was not disclosed in the rulemaking proceeding or to the Office of Management and Budget. The Commission rejects Questar Pipeline's argument as incorrect. The Commission included the proposed regulatory text for § 358.5(c)(4) in the NOPR and in the regulatory text of Order No. 2004. See NOPR, FERC Stats. & Regs., Proposed Regulations 1999—2003 ¶ 32,555 at 34,096 and in proposed regulatory text and Final Rule at P 162 and in regulatory text. Moreover, Questar Pipeline's request is untimely because all requests for rehearing of the Final Rule were due within 30 days of its issuance (by December 29, 2003). See section 19a of the NGA, 15 U.S.C. 717r (2000) and section 313 of the FPA, 16 U.S.C. 825l(a) (2000).

93. AGA, Duke Energy, El Paso, INGAA and Questar Pipeline each sought additional clarifications on implementation of the requirement to post exercises of discretion. INGAA and Duke Energy are concerned that the Order No. 2004 requirement is much broader than the former Standards of Conduct and would apply to any number of Gas Tariff provisions which use discretionary terms such as “may,” “may in its discretion,” and “may use its best efforts.” Petitioners are concerned that it could be a burden if a pipeline has to post every discretionary action and might result in the pipelines reducing service flexibility. El Paso argues that the Commission should clarify that the discretionary posting requirement only applies where the pipeline exercises such discretion with regard to a shipper requirement under its FERC Gas Tariff.

94. INGAA requests that the waiver log posting not apply to the following discretionary activities: (1) Operational activities; (2) when the service itself has a discretionary component; or (3) when posting is already mandated by regulation or tariff provision.

95. INGAA also argues that with respect to some tariff provisions, for example those involving interruptible service, discretion is an inherent part of the service. INGAA notes that for some exercises of discretion, the Commission has already required or approved posting obligations, e.g. , curtailment of interruptible services, discounts or issuance of operational flow orders.

96. AGA, INGAA, and Questar Pipeline request clarification that the posting requirement does not apply where a pipeline exercises flexibility, the pipeline's tariff specifies the flexibility that is available and all parties are on notice (through the tariff) that the flexibility is available. For example, correction of an invoice due to a mutual mistake of fact or additional nomination opportunities if the pipeline can accommodate such requests on a best efforts basis. AGA is concerned that this requirement will present a disincentive for pipelines to provide valued flexibility to any customer.

97. Finally, Questar Pipeline urges that the Commission not require the posting of discretionary waivers where the posting might reveal customers' identity or sensitive business information. For example, if a pipeline makes a negative determination of a customer's credit, is the pipeline required to post on its website a log detailing the circumstances and manner in which it determined to deny credit or require collateral. Questar Pipeline is concerned about the impact that such a posting might have on a customer's dealings with other creditors.

98. The Commission clarifies that when a posting is already mandated by the tariff or other requirement, such as operational flow orders, available capacity or curtailments, the requirement to post exercises of discretion will not trigger a duplicate posting requirement. 30 Also, in response to Questar Pipeline, a posting need not reveal confidential customer information or sensitive business information. Rather, a Transmission Provider shall post information regarding the date of its action and the type of discretion it exercised ( e.g. , a creditworthiness determination) without revealing the name of the customer.

99. INGAA's request not to post waivers logs with respect to pipeline operations, such as determinations of available capacity, has merit. The Commission's regulations at § 284.13 already require the posting of capacity information. But, INGAA's request not to post waiver logs with respect to services that have discretionary components is too broad. The purpose of this rule, which is to allow non-affiliates to determine whether they have been treated in a non-discriminatory manner, would not be achieved under INGAA's service proposal. The way in which a pipeline exercises its discretion in providing services is valuable information in assessing its compliance with the non-discrimination requirements of the NGA. As El Paso acknowledges, exercises of discretion with respect to shipper requirements should be posted.

100. Section 358.4(e)(5) requires a Transmission Provider to train all of its employees and sign an affidavit certifying that they have been trained regarding the Standards of Conduct. In Order No. 2004-A, the Commission revised the regulatory text to state that electronic certification is an acceptable substitute for an affidavit to permit Transmission Providers to use computer-based training.

101. In Order No. 2004-A, the Commission stated that one of the goals of training a broad group of employees is to ensure that employees with access to information about transmission, energy, power, gas or marketing functions understand the restrictions on sharing information and the prohibition on acting as a conduit for sharing information. Therefore, the Commission clarified that for employees without access to information about transmission, energy or natural gas functions training would not be required.

102. Questions at the May 10th Technical Conference and petitions for clarification reveal that some Transmission Providers are still unclear about which employees must be trained. See requests of CenterPoint, EEI, El Paso, INGAA, NiSource, Texas Gas and Xcel. Petitioners urge the Commission to acknowledge that employees without access to information regarding transmission, energy or gas functions need not be trained and that only employees with access to transmission information or information about gas or electric purchases or sales or marketing must be trained. The Commission so clarifies, and as discussed below, will revise the regulatory text accordingly. In addition, the Commission denies EEI's suggestion that the decision to train Marketing or Energy Affiliate employees or other Transmission Provider employees should be left to the discretion of the Transmission Provider.

103. The Commission clarifies that all officers and directors of the Transmission Provider, as well as its employee with access to transmission information or information concerning gas or electric purchases, sales or marketing functions must be trained. For those employees without access to transmission information or information concerning gas or electric purchases, sales or marketing functions, however, training will not be required.

104. CenterPoint urges the Commission to clarify that the Transmission Provider is obliged to distribute Standards of Conduct material to the employees of the Transmission Provider and Marketing and Energy Affiliates, but is not obliged to train the employees of the Marketing or Energy Affiliates. At PP 181 and 184 of Order No. 2004-A, the Commission stated that Transmission Providers are not required to train employees of their Marketing or Energy Affiliates, but must distribute the Standards of Conduct to those employees with access transmission information or information regarding gas or electric purchases or sales or marketing either in paper copy or electronically. Marketing and Energy Affiliates should train their employees to ensure that they understand and observe the Standards of Conduct requirements.

105. INGAA, Texas Gas, Westar and Xcel note that the regulatory text is inconsistent with the preamble language in Order No. 2004-A because the regulatory text requires the training of all employees, yet the discussion in Order No. 2004-A stated that training was not required for all employees.

106. Finally, EEI, Texas Gas and Xcel ask the Commission to delete the “affidavit” requirement and, as was discussed at the May 10th Technical Conference, require adequate documentation in a reasonable form, such as electronic certification or sign in sheets.

107. The Commission will grant the requests and revise the regulatory text of § 358.4(e)(5) as follows:

Transmission Providers shall train officers and directors as well as employees with access to transmission information or information concerning gas or electric purchases, sales or marketing functions. The Transmission Provider shall require each employee to sign a document or certify electronically signifying that s/he has participated in the training.

108. Generally, §§ 358.5(a) and (b) prevent a Transmission Provider from giving its Marketing or Energy Affiliate unduly preferential access to transmission, customer or marketing information. The Commission has also established several specific exemptions from the information disclosure prohibitions that permit a Transmission Provider to communicate with its Marketing or Energy Affiliate, including: (1) Information relating to specific transactions (transaction specific exemption);  31 and (2) crucial operating information (crucial operating information exemption). 32

109. In Order No. 2004-A, the Commission added additional regulatory text in § 358.4(a)(5) to provide that “A Transmission Provider may share transmission information * * * with its senior officers and directors provided that they do not (1) participate in directing, organizing or executing transmission system operations or marketing functions; or (2) act as a conduit to share such information with a Marketing or Energy Affiliate.” The Commission also revised § 358.5(b)(7) to provide that “A Transmission Provider may share information * * * with employees permitted to be shared under §§ 358.4(a)(4), (5) and (6) provided that such employees do not act as a conduit to share such information with any Marketing or Energy Affiliates.”

110. On rehearing, Entergy argues that these revisions may reinstate an “automatic imputation rule, 33 because shared employees receiving the information will themselves be employees of Marketing or Energy Affiliates. Entergy seeks clarification that the Commission means what it said and the regulatory revisions in §§ 358.4(a)(5) and 358.4(b)(7) result in a No Conduit Rule without the overlay of the automatic imputation rule.

111. The Commission clarifies that the additional regulatory text added in §§ 358.4(a)(5) and 358.5(b)(7) was not intended to impose the automatic imputation rule on the No Conduit Rule. As provided in § 358.5(b)(7), neither a Transmission Provider nor an employee of a Transmission Provider is permitted to use anyone as a conduit for sharing information covered by the prohibitions of § 358.5(b)(1) and (2) with a Marketing or Energy Affiliate. As the Commission stated in Order No. 2004-A, notwithstanding the prohibitions of §§ 358.5(b)(1) and (2), the Commission intends to allow a Transmission Provider to share information with employees that permissibly may be shared so that they can engage in certain functions, e.g. , corporate governance, risk management, or certain “support-type” services. The additional regulatory text was intended to reflect that the No Conduit Rule also will apply to such shared employees.

112. Order No. 2004 permitted a Transmission Provider to share crucial operating information with its Energy Affiliates to maintain the reliability of the transmission system. In Order No. 2004-A, the Commission clarified that “crucial” operating information is that information necessary to operate and maintain the transmission system on a day-to-day basis; it does not include transmission or marketing information that would give a Transmission Provider's Marketing or Energy Affiliate undue preference over a Transmission Provider's nonaffiliated customers in the energy marketplace. The Commission revised the regulatory text at § 358.5(b)(8) eliminating the term “crucial” and providing that a Transmission Provider is permitted to share information necessary to maintain the operations of the transmission system with its Energy Affiliates.

113. Shell Offshore requests the Commission to clarify the relationship between the “crucial operating information exemption in § 358.5(b) and the “No Conduit Rule.” Specifically Shell Offshore requests the Commission to clarify that, in the “crucial operating information exemption,” the “No Conduit Rule” applies only to the employees of the Transmission Provider and not to the employees of an Energy Affiliate. Shell Offshore argues that applying the “No Conduit Rule” to the crucial operating information exemption is unnecessary and unworkable because the information that is to be shared is the information necessary to operate and maintain the transmission system on a day-to-day basis and it does not include transmission or marketing information that would give a Transmission Provider's Marketing or Energy Affiliate undue preference over a Transmission Provider's non-affiliated customers in the Energy marketplace. Shell Offshore argues that, since the crucial operating information will not give the Energy Affiliate an undue preference, there is no reason to make the communication of this information subject to the No Conduit Rule.

114. The Commission's clarification of operating information makes clear that information necessary to operate a transmission system on a day-to-day basis may be shared with an Energy Affiliate. However, Energy Affiliate Employees who receive such transmission information are, by definition, employees engaged in the physical operations of the Energy Affiliate. These operational employees may not share with other Energy Affiliate employees (serve as a conduit of) the transmission information the operational employees receive.

115. INGAA and Duke Energy request the Commission to clarify that the sharing of operational information under § 358.5(b)(8) will not violate the functional separation requirement codified in § 358.4. They are concerned that § 358.4, without referencing § 358.5(b)(8), contains an exception that applies only “in emergency circumstances affecting system reliability.” Therefore, they seek clarification that the functional separation requirement of § 358.4 does not limit the sharing of operational information permissible under § 358.5(b)(8).

116. The Commission clarifies that sharing of information necessary to maintain the operations of the transmission system under § 358.5(b)(8) does not compromise the independent functioning required in § 358.4.

117. In the Final Rule, the Commission codified a “transaction specific exemption” in § 358.5(b)(5). Under the exemption, Transmission Providers do not have to contemporaneously disclose information covered by § 358.5(b)(1) if the communication between the Transmission Provider and its Marketing or Energy Affiliates relates solely to the Marketing or Energy Affiliate's specific request for transmission service.

118. Order No. 2004-A required that when a Transmission Provider and an Energy Affiliate participate in scoping meetings or discussions about capacity expansion or new development (scoping meetings), the Transmission Provider must: (1) Post an advance notice to the public on its OASIS or Internet website of its intent to conduct a meeting with its Energy Affiliate; (2) transcribe the meeting in its entirety; and (3) retain the transcript of the scoping meeting for three years and make it available to the Commission upon request. 34 Order No. 2004-A stated, further, that a Transmission Provider cannot provide advance information to a Marketing or Energy Affiliate regarding a general expansion project because that would not be transaction-specific and such information would give the Marketing or Energy Affiliate an undue competitive advantage.

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, Joseph T. Kelliher, and Suedeen G. Kelly.

1. On February 13, 2004, the Commission issued a “Notice Soliciting Public Comment” (the Notice) on its procedures for dealing with critical energy infrastructure. 69 FR 8636 (Feb. 25, 2004). The Commission's CEII procedures were established by Order Nos. 630 and 630-A. See Critical Energy Infrastructure Information, Order No. 630, 68 FR 9857 (Mar. 3, 2003), FERC Stats. & Regs. ¶ 31,140 (2003); order on reh'g, Order No. 630-A, 68 FR 46456 (Aug. 6, 2003), FERC Stats. & Regs. ¶ 31,147 (2003). In Order Nos. 630-A and 643, 1 the Commission committed to solicit public comment after six months in order to identify any potential problems with the Commission's regulations regarding CEII. The Notice provided an opportunity for those with experience under Order Nos. 630, 630-A, and 643 to provide feedback on the CEII process. The Commission received comments on Order Nos. 630 and 630-A from the following five entities: the American Public Power Association and Transmission Access Policy Study Group (APPA/TAPS), the Hydropower Reform Coalition (HRC), the National Hydropower Association (NHA), Southern California Edison Company (SCE), and the United States Department of Interior (DOI). No comments were received regarding Order No. 643. In light of those comments and the Commission's own experience, this order amends 18 CFR 388.113 and clarifies some other points regarding CEII.

2. The Commission began its efforts with respect to CEII shortly after the attacks of September 11, 2001. See Statement of Policy on Treatment of Previously Public Documents, 66 FR 52917 (Oct. 18, 2001), 97 FERC ¶ 61,130 (2001). The Commission's initial step was to remove from its public files and Internet page documents such as oversized maps that were likely to contain detailed specifications of facilities licensed or certified by the Commission, directing the public to request such information pursuant to the Freedom of Information Act (FOIA) process detailed in 5 U.S.C. 552 and in the Commission's regulations at 18 CFR 388.108. In September 2002, the Commission issued a notice of proposed rulemaking regarding CEII, which proposed an expanded definition of CEII to include detailed information about proposed facilities as well as those already licensed or certificated by the Commission. Notice of Rulemaking and Revised Statement of Policy, 67 FR 57,994 (Sept. 13, 2002); FERC Stats. & Regs. ¶ 32,564 (2002). The Commission issued its final rule on CEII on February 21, 2003, defining CEII to include information about proposed facilities, and to exclude information that simply identified the location of the infrastructure. Order No. 630, 68 FR 9857, FERC Stats. & Regs. ¶ 31,140. After receiving a request for rehearing on Order No. 630, the Commission issued Order No. 630-A on July 23, 2003, denying the request for rehearing, but amending the rule in several respects. Order No. 630-A, 68 FR 46456, FERC Stats. & Regs. ¶ 31,147. Specifically, the order on rehearing made several minor procedural changes and clarifications, added a reference in the regulation regarding the filing of non-Internet public (NIP) information, a term first described in Order No. 630, and added the aforementioned commitment to review the effectiveness of the new process after six months. The Notice issued on February 13, 2004, facilitated the review contemplated in Order No. 630-A. This order addresses the comments received in response to the Notice.

3. The comments received fall primarily into the following two broad categories: Concerns about inconsistencies and over-designation of material as CEII, and concerns regarding the CEII clearance/approval process. The HRC and NHA both indicate that there is a need for additional guidance and clarity regarding which materials qualify for CEII and NIP protection. HRC at p. 2; NHA at pp. 1-3. The HRC states that submitters are over-designating information as CEII, and claims that “the breadth of information submitted as CEII has led to an unnecessary withholding of information that does not meet the regulatory definition.” HRC at pp. 2-3. The HRC notes that permitting some filers to over-designate information as CEII is unfair both to those who claim CEII status prudently and those who are unable to access information that should be publicly available. The HRC encourages the Commission to assume responsibility for reviewing information as it is submitted to determine whether it qualifies as CEII, and classify it accordingly. HRC at p. 2. As now explained, although such an approach might add consistency, the Commission does not believe such an approach is necessary or practical.

4. Even before CEII existed, the Commission's rule at 18 CFR 388.112 permitted filers to designate information for non-public treatment. Such documents received non-public treatment by default until the Commission or a member of the public (through the filing of a FOIA request) questioned whether or not the information deserved non-public treatment. The Commission never found it necessary to review claims for non-public treatment prior to affording documents such status in order to save a requester the time and expense of filing a FOIA request for the information. Indeed, the burden on the Commission associated with previewing each such filing would be excessive.

5. Similarly, the Commission presently does not see a need to review claims for CEII treatment before anyone has indicated an interest in the document by filing a CEII request. CEII requests usually present less burden and greater chance of success than FOIA requests. There is no fee associated with a request for CEII. In addition, CEII requests are granted more often than FOIA requests, giving requesters access to information that would not be available to them under the FOIA. Nevertheless, although it is not practical for Commission staff to review all material filed as CEII, staff will continue to take steps to have the status of information promptly changed if they notice information has erroneously been filed as CEII. Those steps include notice and an opportunity for the submitter to defend the CEII designation, and notice to the submitter prior to denying CEII status to the document. For documents designated as CEII by the Commission, CEII status can be changed even more quickly, without notice or an opportunity for comment. The Commission encourages members of the public to bring such matters to the attention of its staff, who are committed to responding timely. 2

6. In addition, the Commission believes improving instructions to filers and Commission staff regarding which information qualifies for treatment as CEII is an effective way to combat the problem of inconsistency in claims for CEII treatment. Therefore, the Commission will be providing additional direction to filers on this subject, and will begin this effort in the area of hydropower information because that appears to be the area of the most uncertainty. Any guidance developed will be disseminated to the appropriate entities through the relevant industry associations, namely the National Hydropower Association, the Edison Electric Institute, and the Interstate Natural Gas Association of America by the effective date of this rule. In addition, as suggested by the NHA, the Commission will designate certain staff members in each program area who will be available to answer specific questions filers may have regarding appropriate designation of certain information. This contact information will be made available on the Commission's Web site within the same timeframe.

7. The HRC also questions whether the Commission's definition of CEII is too broad. The Commission defines CEII as “information about proposed or existing critical infrastructure that (i) Relates to the production, generation, transportation, transmission, or distribution of energy; (ii) Could be useful to a person in planning an attack of critical infrastructure; (iii) Is exempt from mandatory disclosure under the [FOIA]; and (iv) Does not simply give the location of the critical infrastructure.” 18 CFR 388.113(c)(1). The HRC is concerned that parts two and four of the definition are too broad. HRC at p. 5. As an initial matter, the Commission notes that its definition of CEII is limited to information that is exempt from disclosure under the FOIA, and the remaining elements of the definition only serve to create a subset of FOIA-exempt information that may be released to requesters who evidence a need for such information. While the Commission agrees that part two of the definition is fairly subjective, the requirement that the information fall within a FOIA exemption serves to limit its applicability appropriately. As discussed above, the Commission will provide additional guidance that will help define elements two and four of the definition.

8. The HRC also raises the issue of the Commission's reliance on FOIA Exemption 7 to protect CEII, stating “FERC's current interpretation of FOIA's exemptions is disturbingly broad particularly with respect to information compiled for law enforcement purposes.” HRC at p. 3. The HRC notes that Exemption 7 has traditionally been used to protect information relating to criminal investigations, and states that FERC's use of Exemption 7 to protect CEII “is neither legally defensible nor good public policy.” HRC at p. 4. The Commission disagrees. While it is true that Exemption 7 has most often been applied in the context of criminal investigations, it is not limited to that context. Courts have found that both the Federal Communication Commission's authority to revoke or deny licenses and the Federal Trade Commission's authority over advertising practices were law enforcement activities. See Kay v. FCC, 867 F. Supp. 11, 16-18 (D.DC 1994); Ehringhaus v. FTC, 525 F. Supp. 21, 22-23 (D.DC 1980). More recently, courts have found that the law enforcement threshold was met with respect to Bureau of Reclamation dam inundation maps used to develop emergency actions plans. See Living Rivers, Inc. v. United States Bureau of Reclamation, 272 F. Supp. 2d 1313, 1316 (D. Utah 2003). This is very similar to information protected by the Commission in the hydropower area. The Commission continues to believe that such information may appropriately be protected under Exemption 7(F).

9. The HRC indicates particular concern regarding project boundary maps. In Order No. 630, the Commission specified that “maps of projects (including location of project works with respect to water bodies, permanent monuments, or other structures that can be noted on the map and recognized in the field) such as those found in Exhibit G” are considered to be CEII. 68 FR at 9862, FERC Stats. & Regs. ¶ 31, 140 at p 32. In light of the concerns raised by the HRC regarding project boundary maps, the Commission has revisited this issue, and determined that such information should not be treated as CEII. The Commission hereby directs that in the future such maps generally should not be treated as CEII or submitted with requests for CEII treatment, but should instead be submitted as NIP information in accordance with 18 CFR 388.112 and instructions from the Office of the Secretary.

10. The commenters raise several issues regarding the filing and processing of CEII requests. The HRC contends that it is unnecessarily burdensome to require individual members of an organization to file separate requests and non-disclosure agreements (NDAs). See HRC at pp. 7-8. The Commission disagrees. When it first adopted the CEII request rules, the Commission chose not to clear entire entities, deciding instead to clear each individual requesting access. As the Commission noted in Order No. 630, “the more people who have access to information, the greater likelihood that it may find its way into the wrong hands.” Order No. 630, 68 FR at p. 9865, FERC Stats. & Regs. ¶ 31,140 at p 48. The Commission believes that the current approach is necessary to effectively limit the number of people getting access to CEII. Moreover, the burden associated with filing a CEII request is minimal. For the ease of requesters, the Commission has posted a form on its Web site that requesters may use to file a request, which simplifies the request process. See http://www.ferc.gov/help/how-to/file-ceii.asp. The average request takes approximately five minutes to complete. To read and sign a non-disclosure agreement requires about the same amount of time. Under the circumstances, the Commission believes that the current policy of requiring each requester to file separately continues to be the best way to control access to CEII, and does not pose an undue burden on requesters.

11. While noting that for the most part their members have not had problems gaining access to CEII, the HRC suggests that the Commission consider automatically allowing all parties in a proceeding access to the same information in the proceeding, including CEII. HRC at p. 8. The Commission is reluctant to automatically grant parties access to CEII because it may cause people to intervene solely to receive CEII. Under the Commission's rules, “[i]f no answer in opposition to a timely motion to intervene is filed within 15 days after the motion to intervene is filed, the movant becomes a party at the end of the 15 day period.” 18 CFR 385.214(c)(1). Therefore, many motions to intervene are granted with no evaluation of the motion. The Commission is not comfortable granting CEII access without an affirmative analysis of the requester and his or her need for the information, so it will not automatically grant interveners access to CEII. Alternatively, the HRC urges the Commission to adopt a lower threshold for parties to a proceeding where others in the proceeding have access to CEII. In effect, this already happens. Under the Commission's regulations, someone has a right to participate in a Commission proceeding if such right is granted by law, if they have or represent an interest which may be directly affected by the proceeding, or if their participation is in the public interest. 18 CFR 388.214(b)(2). Therefore, if a CEII requester puts forth the same information required in a motion to intervene, that same information would most likely suffice to show that he is a legitimate requester with a need for the information requested, making it very likely his request for CEII would be granted.

12. While the HRC is concerned that the Commission's rules are too burdensome on requesters, SCE is concerned that the Commission's threshold for granting requests for CEII is too low. SCE urges the Commission to “provide stricter limitations on the use of the [CEII] and require a greater showing of legitimate need for the CEII requested in order to ensure its confidentiality is maintained.” SCE at p. 2. SCE believes that absent a showing of a valid need and legitimate use of the information, little protection is afforded by the requester's willingness to sign a non-disclosure agreement. Id. The Commission has found that CEII such as Form Nos. 715 and 567 are heavily requested by consultants who use the information to advise clients, often not with respect to a particular docketed Commission proceeding. The Commission believes that it is not always necessary for requesters to identify a particular Commission matter or even a particular client in order to qualify as a legitimate requester, especially where the Commission has been able to verify that the individual or firm provides legitimate consulting services. These consultants often provide a valuable service by giving market participants information necessary to make business decisions regarding expansion of the infrastructure, ultimately making it less vulnerable to attack. The Commission is unwilling to restrict access to information necessary to make such critical decisions.

13. The HRC also voices concern with the notice and comment process applicable to requests for information that has been submitted to the Commission with a request for CEII treatment, stating that “FERC has not outlined a compelling reason to provide licensees with the opportunity [to] comment on the release of CEII to a requestor.” HRC at p. 6. The notice and comment process existed previous to September 11, 2001, with respect to information that was submitted to the Commission with a request for non-public treatment. The prior version of 18 CFR 388.112(d) stated that “[w]hen a FOIA requester seeks a document for which privilege is claimed, the Commission official who will decide whether to make the document public will notify the person who submitted the document and give the person an opportunity (at least five days) in which to comment in writing on the request.” This provision has its foundations in Executive Order No. 12600, which applies specifically to confidential commercial information traditionally protected by FOIA Exemption 4. For more than fifteen years, the Commission has extended the procedural safeguards found in E.O. 12600 to any information submitted with a request for privileged treatment, and more recently in Order No. 630, the Commission extended those safeguards to information submitted with a request that it be treated as CEII. The executive order aside, the Commission believes there are benefits to affording the submitter of the information an opportunity to comment on the request. First, this gives the submitter of the information an opportunity to explain in more detail which exemption applies to protect the information and the potential harm that could result from disclosure of the information. Second, in many instances the submitter is familiar with the requester, and can provide information useful to the Commission in verifying the identity of the requester, providing a better foundation for the CEII Coordinator's decision. Third, if notice and comment were only afforded where the submitter claimed that the information was confidential commercial information, it would give companies incentives to make such claims where they might otherwise not be made.

14. The HRC also claims that providing notice and an opportunity for submitters to comment on release “could undermine a part[y's] negotiating position in a settlement proceeding.” HRC at p. 6. The HRC goes on to state that “[t]he CEII coordinator should be vested with the authority to determine when information qualifies as CEII and whether a requestor has demonstrated a need for the information.” Id. The HRC appears to misunderstand the purpose of providing notice and an opportunity to comment. The submitter does not make the decision regarding whether the information is CEII or whether to release the information to the requester; the submitter's comments only inform the CEII Coordinator's decision. There have been numerous instances where the CEII Coordinator has released CEII despite the submitter's opposition to such a release. The Commission continues to find that the benefits of maintaining the notice and comment process outweighs the inconvenience to the requesters and concludes that there is little danger of the process undermining settlement proceedings.

15. Although generally finding that the Commission responds “almost immediately” to CEII requests, the HRC has indicated concern with the time it takes to process CEII requests, especially in matters with quick turnaround times, specifically referencing the Commission's integrated licensing process (ILP). HRC at p. 7. The Commission agrees that HRC has raised a legitimate concern given that the ILP has defined deadlines for all participants, including the Commission, throughout the process. However, the majority of the documents filed as part of the licensing process typically are not CEII, so the problem will not be widespread. Given the Commission's contemporaneous decision to no longer consider Exhibit G project boundary maps as CEII, the most likely information to be filed in the ILP as CEII is Exhibit F (details of project facilities), 3 which will be part of the draft license application, if prepared, and the final license application filed with the Commission. The comment deadlines for these two steps are 90 days and 120 days respectively. Given these deadlines, requesters should have little trouble getting timely access to the information. In other instances with shorter timeframes, the Commission will strive to respond as quickly as possible. Requesters should highlight short deadlines so staff can expedite the request if possible. Requesters also have the option of seeking the information directly from the applicant, and the Commission will encourage applicants to negotiate with requesters to provide CEII directly to them wherever possible. In fact, the Commission already encourages such cooperation.

16. The DOI has asked the Commission to loosen some of the requirements on federal agency requesters. Specifically, the DOI urges that “[f]ederal agencies should be able to identify themselves one time in each proceeding, and be granted complete access to the docket from then on.” DOI at p. 2. The Commission has reconsidered the position of federal agency requesters and agrees that once an agency has been granted access to CEII in a particular docket, it is entitled to receive subsequent CEII in that docket. However, the Commission will not assume an affirmative duty to transmit such information absent a subsequent request from the agency. Such subsequent request may be as informal as a phone call or e-mail to a staff contact requesting additional CEII in the docket. The burden must remain on the requesting agency to voice such requests; otherwise the burden on Commission staff to keep track of such ongoing requests would be too great.

17. The NHA has requested clarification of the owner/operator request process, and has suggested that the Commission designate a specific person for owner/operators to contact to obtain CEII on their own projects. NHA at 3. Currently, 18 CFR 388.113(d)(1) provides that “[a]n owner/operator of a facility, including employees and officers of the owner/operator, may obtain CEII relating to its own facility directly from Commission staff without going through the procedures outlined in paragraph (d)(3) of this section.” In most instances, the owner/operator representative has a contact on Commission staff and the CEII request is sent directly to that staff person. In cases where an owner/operator does not have a relationship with a staff person from the Office of Energy Projects, the request may be sent to the General and Administrative Law Section of the Commission's Office of the General Counsel, directed to the attention of Carol Johnson ( carol.johnson@ferc.gov ). The telephone number for General and Administrative Law is 202-502-6457 and the facsimile number is 202-208-0056.

18. The NHA has also requested that the Commission alter its policy that agents of an owner/operator may not file CEII requests. The current regulation requires that agents or other non-employee representatives of owner/operators obtain CEII directly from the owner/operator. In several instances this has resulted in an unwieldy process. The Commission has reconsidered its approach with respect to agents of owner/operators and has decided to permit the agents to have the same access as the owner/operator as long as they present written authorization from the owner/operator for such access. Therefore, the Commission is amending § 388.113(d)(1) to include agents of owner/operators, deleting § 388.113(d)(2), and re-designating § 388.113(d)(3) as 388.113(d)(2).

19. SCE requests that the Commission require that consultants agree to return or destroy CEII when the proceeding is finished, or within two years of receipt, arguing that Form No. 715 data does not necessarily become stale. SCE at pp. 2-3. SCE has advocated this approach in several of its responses to Form No. 715 notice and comment letters. The Commission has considered the advantages and disadvantages of placing time limits on a recipient's use of CEII. The advantage is that it limits the amount of time such information is vulnerable to disclosure. A primary disadvantage of such an approach is that it would require monitoring and follow up, which would be quite a large administrative task when one considers the volume of CEII requests, which are averaging over 200 requests per year thus far. Another problem is that some of the recipients use the CEII to develop some sort of product or database. Once the time limit expires, they would not only need to return the original information, they would have to dismantle the product or database that utilized the information. That could be an expensive proposition, and discourage recipients from undertaking the analysis in the first place. These analyses are often performed to assist market participants in making critical decisions about where to invest in new infrastructure. The Commission is reluctant to take steps that could discourage such analyses. Finally, the Commission does believe that the sensitivity of much of the information will diminish over time. For these reasons, the Commission declines to routinely place time limits on a recipient's access to CEII, but would consider doing so in a unique case where a compelling need could be shown.

20. The APPA/TAPS cautions the Commission not to presume too much given the absence of complaints to date, noting that there have not been many controversial rate requests and no significant merger applications filed since the CEII rules took effect. APPA/TAPS at p. 2. The APPA/TAPS encourages the Commission to re-evaluate the effectiveness of the rules again in another year. Id. at p. 3. The HRC also urges the Commission to continue to evaluate the CEII rules “using measures of success in addition to evaluating comments and input from the public.” HRC at p. 3. The Commission will continue to monitor and review the success of the CEII program. It will continue to be alert to situations where a party's ability to effectively participate in a proceeding may be impacted by the rules. In addition, the Commission will re-examine the effectiveness of the rules again within one year. That evaluation will take into account the potential threats and what level of protection is required given the current world situation.

21. The Office of Management and Budget's (OMB's) regulations require that OMB approve certain information collection requirements imposed by agency rule. 5 CFR 1320.12 (2004). This final rule does not impose any additional information collection requirements. Therefore, the information collection regulations do not apply to this final rule.

22. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment. 4 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusions are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended. 18 CFR 380.4(a)(2)(ii). This rule is procedural in nature and therefore falls under this exception; consequently, no environmental consideration is necessary.

23. The Regulatory Flexibility Act of 1980 (RFA)  5 generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities. The Commission is not required to make such analyses if a rule would not have such an effect. The Commission certifies that this proposed rule, if finalized, would not have such an impact on small entities.

24. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through FERC's Home Page ( http://www.ferc.gov ) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.

25. From FERC's Home Page on the Internet, this information is available in the Commission's document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

26. User assistance is available for eLibrary and the FERC's Web site during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at FERCOnlineSupport@FERC.gov ), or the Public Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at public.referenceroom@ferc.gov ).

27. These regulations are effective September 9, 2004. The provisions of 5 U.S.C. 801 regarding Congressional review of Final Rules do not apply to this Final Rule, because the rule concerns agency procedure and practice and will not substantially affect the rights of non-agency parties.

Pfizer, Inc., 235 East 42d St., New York, NY 10017, filed a supplement to NADA 141-095 for DECTOMAX (doramectin) Pour-On Solution for Cattle. The supplemental application provides for an increased period of protection from reinfection with three species of internal parasites following topical administration of doramectin solution on cattle. Specifically, the period of persistent effectiveness is increased from 21 days to 28 days for Cooperia oncophora , from 28 days to 35 days for C. punctata , and from 21 days to 28 days for Dictyocaulus viviparus . The supplemental NADA is approved as of June 30, 2004, and the regulations in 21 CFR 524.770 are amended to reflect the approval and a current format. The basis of approval is discussed in the freedom of information summary.

In accordance with the freedom of information provisions of 21 CFR part 20 and 21 CFR 514.11(e)(2)(ii), a summary of safety and effectiveness data and information submitted to support approval of this application may be seen in the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday.

Under section 512(c)(2)(F)(iii) of the Federal Food, Drug, and Cosmetic Act (21 U.S.C. 360b(c)(2)(F)(iii)), this approval qualifies for 3 years of marketing exclusivity beginning June 30, 2004. Exclusivity applies only to the extension of the persistent effectiveness claims for the three species of parasites listed previously.

The agency has carefully considered the potential environmental impact of this action and has concluded that the action will not have a significant impact on the human environment and that an environmental impact statement is not required. FDA's finding of no significant impact and the evidence supporting that finding, contained in an environmental assessment, may be seen in the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.

This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.

(a) Specifications . Each milliliter (mL) of solution contains 5 milligrams (mg) doramectin.

(b) Sponsor . See No. 000069 in § 510.600(c) of this chapter.

(c) Related tolerances. See § 556.225 of this chapter.

(d) Special considerations . See § 500.25 of this chapter.

(e) Conditions of use in cattle —(1) Amount . Administer topically as a single dose 0.5 mg (1 mL) per kilogram (1 mL per 22 pounds) body weight.

(2) Indications for use . For treatment and control of gastrointestinal roundworms: Ostertagia ostertagi (adults and fourth-stage larvae), O. ostertagi (inhibited fourth-stage larvae), O. lyrata (adults), Haemonchus placei (adults and fourth-stage larvae), Trichostrongylus axei (adults and fourth-stage larvae), T. colubriformis (adults and fourth-stage larvae), Cooperia oncophora (adults and fourth-stage larvae), C. punctata (adults and fourth-stage larvae), C. pectinata (adults), C. surnabada (adults), Bunostomum phlebotomum (adults), Oesophagostomum radiatum (adults and fourth-stage larvae), Trichuris spp. (adults); lungworms: Dictyocaulus viviparus (adults and fourth-stage larvae); eyeworms: Thelazia gulosa (adults), T. skrjabini (adults); grubs: Hypoderma bovis and H. lineatum ; sucking lice: Linognathus vituli , Haematopinus eurysternus , and Solenopotes capillatus ; biting lice: Damalinia bovis; mange mites: Chorioptes bovis and Sarcoptes scabiei ; horn flies: Haematobia irritans ; and to control infections and to protect from reinfection with C. oncophora , D. viviparus , O. ostertagi , and O. radiatum for 28 days; and with C. punctata , and H. placei for 35 days after treatment.

(3) Limitations . Do not slaughter cattle within 45 days of latest treatment. Not for use in female dairy cattle 20 months of age or older. Do not use in calves to be processed for veal.

These regulations amend 26 CFR part 1. On July 2, 2003, a temporary regulation (TD 9067) relating to transfers of compensatory options was published in the Federal Register (68 FR 39453). A notice of proposed rulemaking (REG-116914-03) was published in the Federal Register for the same day (68 FR 39498). No public hearing was requested or held. No written or electronic comments responding to the notice of proposed rulemaking were received. The proposed regulations are adopted without change by this Treasury decision, and the corresponding temporary regulations are removed.

It has been determined that these regulations are not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations, and because these regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Pursuant to section 7805(f) of the Code, these regulations were submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business.

The principal author of these final regulations is Stephen Tackney of the Office of Division Counsel/Associate Chief Counsel (Tax Exempt and Government Entities). However, other personnel from the IRS and Treasury Department participated in their development.

This document contains amendments to the Excise Tax Procedural Regulations (26 CFR part 40) and the Facilities and Services Excise Tax Regulations (26 CFR part 49). Section 4251 of the Internal Revenue Code (Code) imposes an excise tax on amounts paid for certain communications services. Sections 4261(a) and (b) impose excise taxes on amounts paid for taxable transportation of persons by air. Section 4261(e)(3) provides that any amount paid to an air carrier or related party for the right to provide mileage awards for (or other reductions in the cost of) any transportation of persons by air is treated for purposes of section 4261(a) as an amount paid for taxable transportation and is therefore subject to tax. Section 4261(c) imposes an excise tax on any amount paid for the air transportation of persons that begins or ends in the United States. Section 4271 imposes an excise tax on amounts paid for taxable transportation of property by air. These taxes collectively are referred to as collected excise taxes.

For each of the collected excise taxes, the person liable for the tax is the person making the payment on which tax is imposed (the taxpayer). Under section 4291, the person receiving the payment on which tax is imposed (the collector) generally must collect the tax from the person making the payment and pay it over to the government.

If the taxpayer refuses to pay the tax the collector is required, under § 49.4291-1, to report this refusal to the IRS. The IRS will then assert the tax against the taxpayer. Current regulations do not specify the time within which the collector must report this refusal to the IRS.

Collectors are responsible for filing returns with respect to the collected excise taxes and for making deposits of tax as required by section 6302. Section 40.6302(c)-3 provides an alternative method for computing the amount of deposits of collected excise taxes. Under the alternative method, collectors may compute the amount of tax to be deposited on the basis of amounts considered as collected instead of on the basis of actual collections of tax. A person may use the alternative method with respect to a tax only if the person separately accounts for the tax. The separate account must reflect for each month all items of tax that are included in amounts billed or tickets sold to customers during the month and items of adjustment (including bad debts and errors) relating to the tax for prior months within the period of limitations for credits or refunds. When a collector using the alternative method determines that a taxpayer has refused to pay the tax, the collector adjusts the separate account to reflect that the tax was not collected. Current regulations do not specify the time for adjusting the separate account to reflect that refusal.

The temporary regulations provide that the collector must report the refusal to pay the tax to the IRS by the due date of the return on which the tax would have been reported but for the refusal to pay. In addition, the temporary regulations provide that, for a person using the alternative method, the separate account cannot be adjusted to reflect a refusal to pay tax for the month unless such refusal has been reported.

It has been determined that this Treasury decision is not a significant regulatory action as defined in Executive Order 12866. Therefore, a regulatory assessment is not required. It also has been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. chapter 5) does not apply to these regulations. For applicability of the Regulatory Flexibility Act, please refer to the cross-referenced notice of proposed rulemaking published elsewhere in this issue of the Federal Register . Pursuant to section 7805(f) of the Code, these temporary regulations will be submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business.

The principal author of these regulations is Patrick S. Kirwan, Office of Associate Chief Counsel (Passthroughs and Special Industries). However, other personnel from the IRS and Treasury Department participated in their development.

Effective on July 11, 2003, the bridge owner, the New Jersey Department of Transportation, was officially permitted to operate the Route 70 Bridge across Manasquan River with new regulations. The new operating regulations listed at 33 CFR § 117.727 allows the draw of the bridge to open on signal on the hour, except that from 4 p.m. to 7 p.m. Monday through Friday, except Federal holidays; and from 11 p.m. to 7 a.m., every day the draw need not be open.

Based on comments received on the new operating regulations of the bridge and in an effort to facilitate vessel and vehicular traffic while providing for the reasonable needs of navigation, the District Commander has offered a test period to reexamine the rush hour closure periods during the forthcoming recreational boating season. The new proposal will test a new rush hour period from 5 p.m. to 7 p.m. Monday through Friday, except Federal holidays, as opposed to the current 4 p.m. to 7 p.m. regulatory hours. Therefore, the last drawbridge opening for vessels before the rush hour will occur at 4 p.m. and first opening following the rush hour will be at 7 p.m.

Under this 90-day temporary deviation, effective from August 2, 2004 through October 31, 2004, the Route 70 Bridge across Manasquan River shall open on signal on the hour, except that from 5 p.m. to 7 p.m., Monday through Friday, except Federal holidays; and from 11 p.m. to 7 a.m., every day the draw need not be opened.

This deviation from the operating regulations is authorized under 33 CFR 117.43.

The Metropolitan Avenue Bridge has a vertical clearance in the closed position of 10 feet at mean high water and 15 feet at mean low water. The existing drawbridge operation regulations are listed at 33 CFR 117.801(e).

The owner of the bridge, New York City Department of Transportation (NYCDOT), requested a temporary deviation from the drawbridge operation regulations to facilitate rehabilitation repairs at the bridge. The bridge must remain in the closed position to perform these repairs.

Under this temporary deviation the NYCDOT Metropolitan Avenue Bridge may remain in the closed position from August 16 to August 21, and August 23 to August 28, 2004.

This deviation from the operating regulations is authorized under 33 CFR 117.35, and will be performed with all due speed in order to return the bridge to normal operation as soon as possible.

On September 4, 2002 and July 25, 2003, the South Carolina Department of Health and Environmental Control submitted revisions to the South Carolina State Implementation Plan. These revisions pertain to source testing requirements for all affected source owners or operators and source testers. The purpose of these revisions is to restore accuracy and completeness of the regulations incorporated by reference into the SIP and to clarify language specifying authorization for proposing alternate test methods.

a. The title of Regulation 61-62.1 is being changed to “Definitions and General Requirements” to identify that the regulation contains general provisions.

b. Section IV—Source Tests, is being added to Regulation 61-62.1. Regulation 61-62.5, Standard No. 1, Section VII—Source Test Requirements and Standard No. 4, Section XIII—Source Test Requirements are being incorporated into Regulation 61-62.1, Section IV—Source Tests. Regulation 61-62.5, Standard No. 1, Section VII and Standard No. 4, Section XIII are being reserved for future use. Other amendments to Regulation 61-62.1 specify requirements for site-specific test plans including: a detailed discussion of the test objectives, accessibility and representativeness of sampling locations, process descriptions, in-house testing protocol, all sampling and analytical procedures, internal quality assurance/quality control, data reduction and reporting procedures, and safety considerations.

c. Amendments were made to Regulation 61-62.1, Section II—Permit Requirements and Regulation 61-62.5, Standard No. 1, Section VI—Periodic Testing to specify that the responsible official for ensuring the performance of source tests is an owner or operator of stationary sources and to provide a requirement for sources to comply with the new source test section, 61-62.1 Section IV—Source Tests.

d. Typographical corrections and clarifications were made to Regulation 61-62.5 for formatting consistency.

e. Regulation 61-62.1 Definitions and General Requirements, Section IV—Source Tests is being amended to clarify the language concerning alternate methods of source testing. These revisions address the comments received during the comment period.

f. The words “Section I” were removed from Section II—Permit Requirements for formatting consistency with Regulation 61-62.5, Standard No. 7.

EPA is approving the aforementioned changes to the State of South Carolina SIP because they are consistent with the CAA and EPA policy. The EPA is publishing this rule without prior proposal because the Agency views this as a noncontroversial submittal and anticipates no adverse comments. However, in the proposed rules section of this Federal Register publication, EPA is publishing a separate document that will serve as the proposal to approve the SIP revision should adverse comments be filed. This rule will be effective October 12, 2004, without further notice unless the Agency receives adverse comments by September 9, 2004.

If the EPA receives such comments, then EPA will publish a document withdrawing the final rule and informing the public that the rule will not take effect. All public comments received will then be addressed in a subsequent final rule based on the proposed rule. The EPA will not institute a second comment period. Parties interested in commenting should do so at this time. If no such comments are received, the public is advised that this rule will be effective on October 12, 2004, and no further action will be taken on the proposed rule. Please note that if we receive adverse comment on an amendment, paragraph, or section of this rule and if that provision may be severed from the remainder of the rule, we may adopt as final those provisions of the rule that are not the subject of an adverse comment.

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is not a “significant regulatory action” and therefore is not subject to review by the Office of Management and Budget. For this reason, this action is also not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001). This action merely approves state law as meeting Federal requirements and imposes no additional requirements beyond those imposed by state law. Accordingly, the Administrator certifies that this rule will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ). Because this rule approves pre-existing requirements under state law and does not impose any additional enforceable duty beyond that required by state law, it does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4).

This rule also does not have tribal implications because it will not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action also does not have Federalism implications because it does not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999). This action merely approves a state rule implementing a Federal standard, and does not alter the relationship or the distribution of power and responsibilities established in the Clean Air Act. This rule also is not subject to Executive Order 13045 “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because it is not economically significant.

In reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. In this context, in the absence of a prior existing requirement for the State to use voluntary consensus standards (VCS), EPA has no authority to disapprove a SIP submission for failure to use VCS. It would thus be inconsistent with applicable law for EPA, when it reviews a SIP submission, to use VCS in place of a SIP submission that otherwise satisfies the provisions of the Clean Air Act. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ).

The Congressional Review Act, 5 U.S.C. 801 et seq. , as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register . A major rule cannot take effect until 60 days after it is published in the Federal Register . This action is not a “major rule” as defined by 5 U.S.C. 804(2).

Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by October 12, 2004. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this rule for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)

EPA Region IX is publishing this Direct Final Notice of Deletion from the NPL for the San Fernando Valley Basin Area 3, Verdugo Study Area Superfund Site. EPA identifies sites that appear to present a significant risk to public health or the environment and maintains the NPL as the list of those sites. As described in § 300.425(e)(3) of the NCP, sites deleted from the NPL remain eligible for remedial actions if conditions at a deleted site or new information warrant such action.

Section II of this document explains the criteria for deleting sites from the NPL. Section III discusses procedures that EPA is using for this action. Section IV discusses the San Fernando Valley Basin Area 3, Verdugo Study Area Superfund Site and demonstrates how it meets the deletion criteria. Section V discusses EPA's action to delete the Site from the NPL unless adverse comments are received during the public comment period.

Section 300.425(e) of the NCP provides that releases may be deleted from the NPL where no further response is appropriate. In making a determination to delete a release from the NPL, EPA must determine, in consultation with the State, that one of the following criteria have been met:

(1) Responsible parties or other parties have implemented all appropriate response actions required;

(2) All appropriate Fund-financed (Hazardous Substance Superfund Response Trust Fund) response under CERCLA has been implemented, and no further response action by responsible parties is appropriate; or

(3) The remedial investigation has shown that the release poses no significant threat to public health or the environment and, therefore, taking of remedial measures is not appropriate.

As a No Action decision was made for this Site, a Five-Year Review is not required under CERCLA section 121(c). However, EPA may decide to conduct a discretionary review to confirm that the No Action decision remains appropriate, in the future. Whenever there is a significant release from a site deleted from the NPL, the deleted site may be restored to the NPL without application of the hazard ranking system.

Deletion of a site from the NPL does not itself create, alter, or revoke any individual's rights or obligations. Deletion of a site from the NPL does not in any way alter EPA's right to take enforcement actions, as appropriate. The NPL is designed primarily for informational purposes and to assist EPA management. Section 300.425(e)(3) of the NCP states that the deletion of a site from the NPL does not preclude eligibility for future response actions, should new information or conditions warrant such actions.

The following procedures were followed for deletion of this Site:

(1) The EPA consulted with State of California, Department of Toxic Substances Control (DTSC) on the deletion of this Site from the NPL, prior to developing the Direct Final Notice of Deletion. EPA also provided notices to the California Regional Water Quality Control Board (RWQCB), and Department of Health Services (DHS);

(2) The State of California, DTSC and RWQCB have concurred with deletion of the Site from the NPL;

(3) Concurrently with the publication of this Direct Final Notice of Deletion, a Notice of Intent to Delete is being published today in the Proposed Rules section of the Federal Register and in a major local newspaper of general circulation near the Site. The newspaper notice announces the 30-day public comment period for the Notice of Intent to Delete the Site from the NPL. The Notice of Intent to Delete is also being distributed to appropriate Federal, State, and local government officials and other interested parties; and

(4) The EPA placed copies of documents supporting the deletion in the Deletion Docket and the Site Information Repositories identified above.

The following information provides EPA's basis for deleting the Site from the NPL:

The Verdugo Study Area comprises approximately 2,000 of the 4,400 acre Verdugo Basin, which is situated in the eastern portion of the San Fernando Valley Basin (SFVB), Los Angeles, California.

The Verdugo Study Area includes the groundwater in and around several water supply well fields in the Verdugo Basin. The Verdugo Basin is bounded on the northeast by the San Gabriel Mountains, on the west by the Verdugo Mountains, and on the southeast by the San Rafael Hills. The Verdugo Basin is generally considered a small tributary of the larger San Fernando Valley groundwater basin. Land use in the Verdugo Basin is primarily residential along the floor of the valley, and open space in the surrounding mountains, with limited commercial and agricultural activity. No significant industrial development is present and the Site does not appear to have any primary sources of groundwater contamination.

In 1986, at the request of the State of California (State), EPA placed four areas within the SFVB on the National Priorities List (NPL) as individual Superfund sites, due to the presence of volatile organic compounds (VOCs) in groundwater at concentrations exceeding State and Federal drinking water standards. The four areas are: North Hollywood (Area 1), containing the North Hollywood Operable Unit (OU) and the Burbank OU; Crystal Springs (Area 2), containing the Glendale North and South OUs; Verdugo Study Area (Area 3); and Pollock (Area 4).

Groundwater is used as a potable supply by two purveyors in the Verdugo Study Area, the City of Glendale and the Crescenta Valley Water District (CVWD). The City of Glendale operates the Glorietta well field in the southern portion of the Site and the CVWD operates the Glenwood and Mills well fields in the north-central part of the Site. Perchloroethene (PCE) in groundwater is the primary contaminant of concern (COC) for the Verdugo Study Area. Historically, the PCE plume in the Verdugo Study Area extended from the Glenwood well field in the north to the Glorietta well field in the south, and appears to flow in the direction of groundwater. The geometry of the Verdugo Basin is such that it funnels flow from the broader northern area to the more narrow southern area. The maximum historic concentration of PCE from sampling efforts in 1982 was 52 parts per billion (ppb) in the northern portion of the Site, but by 2002 the maximum level was below the maximum contaminant level (MCL) at 2.5 ppb PCE in the southern end of the Site. Based on consistently decreasing levels of contamination over time to below MCLs and risks falling within the EPA risk range, EPA selected the no action remedy for this site in a Record of Decision, signed on February 24, 2004.

In 1981, prior to the Site being listed on the NPL, the Los Angeles Department of Water and Power (LADWP) began a 2-year study to assess groundwater contamination in the SFVB, including wells located in the Glenwood, Mills and Glorietta well fields in the Verdugo Study Area. More than 600 water supply wells were sampled in the SFVB as part of this program. Additional work included a review of existing hydrogeologic data and industrial site surveys. Results of this work are presented in the Groundwater Quality Management Plan for the San Fernando Valley Basin , and indicate that 45 percent of LADWP supply wells in the eastern SFVB contained trichloroethene (TCE) in excess of the federal MCL and/or PCE in excess of the State action level (LADWP, 1983) of 4 ppb. The State adopted a 5 ppb MCL for PCE in May 1989. However, in the Verdugo Study Area, no TCE above the MCL was detected. PCE was the most prevalent organic contaminant at the Site. The historic high of 52 ppb PCE at the Site was detected during this study, in Glenwood well field production well CVCWD-8.

Pursuant to California Assembly Bill 1803 (AB 1803), wells within the SFVB were sampled in 1983 for VOCs, semivolatile organic compounds (SVOCs), and pesticides/herbicides. Results of the 1983 sampling again revealed concentrations of VOCs above MCLs in several SFVB well fields, with TCE and PCE the two most common contaminants. Again, PCE was the main contaminant detected in the Verdugo Study Area, and was detected in excess of its state action levels in several water supply production wells, although the levels were below the 52 ppb detected in 1982.

After listing the four San Fernando Valley Basin sites on the NPL in 1986, EPA entered into a cooperative agreement to have the LADWP conduct a Remedial Investigation (RI) for the SFVB sites. In 1989, LADWP completed a soil gas sampling and analysis program within the SFVB, designed to better define the limits of shallow groundwater contamination. In the Verdugo Study Area, 73 soil gas samples were obtained and analyzed. Based upon results of soil gas sampling and available data from existing production wells, seven vertical profile borings in the Verdugo Study Area were converted into shallow monitoring wells in 1990.

A baseline risk assessment was conducted in conjunction with the SFVB RI in 1991. This baseline risk assessment was completed on a regional scale and did not specifically focus on the Verdugo Study Area. The risk assessment addressed compounds that exceeded MCLs in the groundwater of the entire eastern portion of the SFVB. Results indicated that the total cancer risk in the eastern SFVB was greater than EPA's acceptable range for ingestion and inhalation. However, in the Verdugo Study Area, the levels of contaminants were significantly lower than the concentration levels used to calculate risk for the entire SFVB. The primary carcinogenic risk drivers for the SFVB were 1,1-DCE, carbon tetrachloride, TCE, PCE, 1,2-DCE and arsenic; of these only PCE was present in the Verdugo Study Area. In October 2003, a screening level human and ecological risk assessment for the Verdugo Study Area indicated risks for the Site within the acceptable risk range.

To focus specifically on the Verdugo Study Area, EPA completed a hydrogeologic site assessment in 1993 ( Site Assessment and Monitoring Plan for the Verdugo Basin, Los Angeles County, California , April 17, 1993). This document assisted in evaluating the nature and extent of groundwater contamination in the basin and provided recommendations for ongoing monitoring of groundwater contamination.

Since the completion of the RI in 1992 up through 2002, EPA continued to monitor groundwater quality by sampling monitoring wells in the Verdugo Study Area four times a year as part of the SFVB basinwide monitoring program. Due to the low levels of PCE and low risk, no Feasibility Study was prepared for the Verdugo Study Area. Groundwater sampling results for this Site from the 1980's through 2002 are summarized in the “Final Summary of Groundwater Quality, San Fernando Valley Superfund Site, Area 3 (Verdugo Basin),” dated May 20, 2003, prepared by CH2M Hill for EPA.

On February 24, 2004, consistent with the Remedy Delegation Report of March 8, 1985, EPA Region IX approved a Record of Decision (ROD) for this Site. The selected remedy was No Action.

The results from groundwater monitoring conducted from the early 1980's through December 2002 indicate that the low levels of VOC contamination at the Site are within EPA's acceptable risk range and meet State and Federal MCLs. No activities using removal authority were conducted at this site.

Site-specific screening-level human health and ecological risk assessments were conducted to support EPA's proposal for no remedial action for the Verdugo Study Area (CH2M HILL, October 2003). Potential risks to human health associated with exposure to chemicals of potential concern in groundwater were found to be within EPA's acceptable risk range. There were no ecological risks found for the compounds present, as no completed exposure pathways exist for eco-receptors.

As no remedial action is required at this Site, a Five-Year Review is not required under CERCLA section 121(c). However, EPA may decide to conduct a discretionary review to confirm that the No Action decision remains appropriate.

Public participation activities including a public meeting at the Verdugo Woodland Elementary School on November 18, 2003 have been satisfied as required in CERCLA section 113(k), 42 U.S.C. 9613(k), and CERCLA section 117, 42 U.S.C. 9617. Documents in the Deletion Docket which EPA relied on for recommendation of the deletion from the NPL are available to the public in the information repositories.

The EPA, with concurrence of the State of California, has determined that based on the Remedial Investigation, the release poses no significant threat to public health or the environment, and, therefore, taking of remedial measures is not appropriate. Therefore, EPA is deleting the Site from the NPL.

RSPA/OPS has responsibility for ensuring safety and environmental protection against risks posed by the Nation's approximately two million miles of gas and hazardous liquid pipelines. RSPA/OPS shares responsibility for inspecting and overseeing the Nation's pipelines with state pipeline safety offices.

On July 24, 1987, the fishing vessel Sea Chief struck and ruptured an 8-inch submerged natural gas liquids pipeline in the Gulf of Mexico. The escaping gas ignited and exploded, killing two crew members. A similar accident occurred on October 3, 1989, when the fishing vessel Northumberland struck and ruptured a 16-inch submerged gas pipeline, killing 11 crew members.

The National Transportation Safety Board (NTSB) investigated the Northumberland accident and prepared a report, Fire on Board the F/V Northumberland and Rupture of a Natural Gas Transmission Pipeline in the Gulf of Mexico Near Sabine Pass, TX (October 3, 1989; NTIS Report Number PB90-916502), which found that the probable cause of the accident was the failure of the pipeline operator to maintain the pipeline at the burial depth to which it was initially installed.

NTSB also found that the failure of RSPA/OPS to require pipeline operators to inspect and maintain submerged pipelines in a protected condition contributed to the accident. The NTSB subsequently issued Safety Recommendation P-90-29, which directed RSPA/OPS to “develop and implement with the assistance of the Mineral Management Service (MMS), the United States Coast Guard (USCG), and the United States Army Corp of Engineers (USACE), effective methods and requirements to bury, protect, inspect the burial depth of and maintain all submerged pipelines in areas subject to damage by surface vessels and their operations.”

In November 1990, Congress addressed hazards of underwater pipelines through amendments to the Hazardous Liquid Pipeline Safety Act of 1979 and the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 101-599). These amendments, in part, required the operators of offshore pipeline facilities in the Gulf of Mexico and its inlets to conduct an underwater depth-of-burial inspection of the pipeline facility and to report any exposed portion or any portion of the pipeline facility which posed a hazard to navigation to the Secretary of Transportation.

The 1990 amendments also required the Secretary of Transportation to establish a mandatory, systematic, and, where appropriate, periodic inspection program of all offshore pipeline facilities and any other pipeline facility crossing under, over, or through navigable waters (as defined by the Secretary) if the Secretary decides that the location of the facility in those navigable waters could pose a hazard to navigation or public safety.

In response to the NTSB recommendation and the Congressional mandates, RSPA/OPS formed a multi-agency task force on offshore pipelines to study the issue. The task force consisted of representatives from RSPA/OPS, USCG, MMS, the Department of Commerce, the National Oceanic and Atmospheric Administration/National Oceans Service, the USACE, the Louisiana Office of Conservation, and the Texas Railroad Commission.

The task force reviewed information, views, and concerns provided by the government and the marine and pipeline industries. The assessment focused on the extent and adequacy of Federal regulations, the technology for determining pipeline location and cover, the availability of maps and charts depicting the location of pipelines, and possible government initiatives to enhance safety.

In November 1990, the task force issued a report, Joint Task Force Report on Offshore Pipelines . The report concluded that exposed pipelines pose a potential risk to navigation safety, especially for mariners operating in shallow, near-shore waters. The task force also concluded that underwater inspections for depth-of-burial of those pipelines were not being performed despite a requirement to place pipelines below the sea floor in shallow water.

To reduce the likelihood of further casualties, the report recommended that operators inspect these pipelines at regular intervals and re-bury exposed pipelines. A copy of the report is available in the docket for this rulemaking.

On December 5, 1991, RSPA/OPS published regulations requiring an operator to conduct inspections of its underwater pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water (56 FR 63764). The regulations required that these inspections be completed before November 16, 1992, and that the results be submitted to RSPA/OPS.

The results of these inspections were reported to RSPA/OPS and have been used to inform this rulemaking. The regulations also established a course of action for the operator to follow if, as a result of the inspection or upon notification by any person, the operator discovers that a pipeline is exposed or a hazard to navigation.

In 1994, to gain further information on the risks posed by underwater pipelines, RSPA/OPS, in conjunction with other Federal agencies, requested that the Marine Board of the National Research Council (NRC) conduct an interdisciplinary review and assessment of the many technical, regulatory, and jurisdictional issues that affect the safety of the marine pipelines in the United States' offshore waters. The Marine Board's interdisciplinary Committee on the Safety of Marine Pipelines reviewed the causes of past pipeline failures, the potential for future failures, and the means of preventing or mitigating these failures. The NRC issued a report, Improving the Safety of Marine Pipelines (1994). This report is available online at: http://books.nap.edu/books/0309050472/html/ . The report can also be ordered by mail at National Academies Press, 500 Fifth Street, NW., Lockbox 285, Washington, DC 20055. A copy of this report is also available for review in the docket for this rulemaking.

The NRC determined that the marine pipeline network does not present an extraordinary threat to human life. Pipeline accidents involving deaths or injuries are rare. The most widespread risks posed by pipelines are due to oil pollution—mainly from pipelines damaged by vessels and their gear. The NRC concluded that the risks generally could be managed with currently available technology and without major new regulations if enforcement of some current regulations is improved.

In June 1997, a comprehensive study of the pipeline surveys in the Gulf of Mexico required by §§ 192.612 and 195.413 was completed by the Texas Transportation Institute (TTI). TTI also collected information on the available technology to conduct underwater depth-of-burial inspections and made recommendations for risk analysis, inspection intervals, and establishment of a definition of underwater natural bottom. A copy of the report, Analysis of Pipeline Burial Surveys in the Gulf of Mexico , is available in the docket for this rulemaking.

In addition to this final rule, many of the issues identified in these reports, in particular risks of pipelines in navigable waters, have been addressed in four other final rules: December 2000—a rule that requires integrity management programs for large liquid pipelines (65 FR 75377); January 2002—a rule that requires integrity management programs for smaller liquid pipelines (67 FR 2136); August 2002—a rule that defines “High Consequence Areas” (HCA) for gas transmission pipelines (67 FR 50824); and January 2003—a rule that revises the HCA definition and requires integrity management programs for gas transmission pipelines in HCAs (69 FR 69778).

On December 12, 2003, RSPA/OPS issued a Notice of Proposed Rulemaking (NPRM) with request for comment (68 FR 69368). The comment period closed on March 10, 2004. Copies of the NPRM, the Draft Final Regulatory Evaluation, the Regulatory Flexibility Certification, and the comments are available in the docket for this rulemaking.

RSPA/OPS proposed to require operators of hazardous liquid and natural gas pipelines to prepare and follow a procedure to conduct periodic underwater inspections of their pipelines offshore or crossing under commercially navigable waterways in waters less than 15 feet deep to ensure that the pipeline is not exposed or a hazard to navigation.

The procedure would be used by the operator to assess the risk of an underwater pipeline becoming exposed or a hazard to navigation by taking into account the particular dynamics of the water and bottom, including the probability of flotation, scour, erosion, and the impacts of major storms. The operator would also establish a timetable for depth-of-burial inspection of shallow underwater pipelines based on the identified risks. The NPRM provided, as an example, the risk analysis procedure developed by TTI in their report.

RSPA/OPS received 22 comments to the NPRM: one from a private individual, one from a marine pipeline consultant, one from a fisheries company, one from a State utilities board, four from trade organizations, and fourteen from pipeline companies.

1. Several commenters supported the proposed rule. One commenter stated that every 38 minutes a football sized parcel of Louisiana's wetlands turns to water and that regulations that clearly require procedures for periodic inspections of underwater pipelines is an important part of preventing pipeline damage. Another commenter noted that the chaos caused when pipelines are struck and destroyed not only hurts humans, but also causes catastrophe in the ocean by injuring fish, marine mammals, and the quality of the water.

Another commenter stated that the NPRM was timely. The commenter identified nine incidents involving collisions of vessels and underwater pipelines and stated that the Coast Guard “Notice to Mariners” frequently identify locations of exposed pipelines that have been discovered and marked with warning buoys.

However, many commenters raised questions and concerns about the proposed rule, in particular the inclusion of waters other than the Gulf of Mexico and its inlets. Several commenters did not believe the NPRM adequately justified expanding the pipeline survey requirements from the Gulf of Mexico to all inland waterways, noting that the NPRM did not provide evidence of accidents or incidents in shallow inland commercially navigable waters. Another commenter recommended that pipeline operating environments such as Long Beach harbor be excluded from this rule.

Several commenters suggested that this issue merited more public discussion to provide an opportunity to develop a technical basis for including crossings of navigable waters in the rulemaking. Another commenter stated that the analysis omitted the impact on up to 1,400 gas distribution operators.

RSPA/OPS believes that this rule is necessary. It is expected to result in increased protection from the Northumberland type incidents. However, RSPA/OPS has determined that the underwater periodic inspection provision will be limited to the Gulf of Mexico and its inlets. RSPA/OPS has not been presented with sufficient evidence that the rule should include other offshore and inland waters. RSPA/OPS believes that hazards to navigation in these areas is already being adequately managed by application of the regulations in part 192 and part 195 and the regulations of other agencies.

Therefore, RSPA/OPS concludes that offshore waters outside the Gulf of Mexico and its inlets and inland waters have not been shown to pose a hazard to navigation or public safety that warrant periodic underwater inspections.

2. Another operator stated that 90% of all damage is caused by anchors and occurs most often in shallow bays and inlets. The commenter suggests that more education is needed on the part of the marine vessel industry on how to avoid areas that pose a higher than normal risk. Another commenter stated that prevention of damage to pipeline facilities must be a cooperative effort between pipeline and vessel operators.

RSPA/OPS agrees and has supported efforts to develop international signage designed to warn vessel operators of pipeline hazards. In addition, RSPA/OPS works closely with other Federal and State agencies, such as USCG, MMS, USACE, and the Environmental Protection Agency (EPA) to address public safety concerns. However, RSPA/OPS' authority to implement rulemaking does not extend to the marine vessel industry.

3. Another commenter believed that there is not sufficient data to prove that natural gas pipelines account for a significant amount of pollution. The commenter stated that some distinction needs to be made between damage to hazardous liquid pipelines and damage to gas pipelines.

RSPA/OPS disagrees. The 13 fatalities noted in the NPRM were the result of vessel interaction with natural gas pipelines. The study by the NRC recommended that natural gas and hazardous liquid pipelines be regulated identically under the periodic depth-of-burial inspection regulation because the higher risk to persons or property posed by natural gas pipeline facilities is balanced by the higher risk to the environment posed by hazardous liquid pipelines.

4. Another commenter believed that a mandatory “one-call” system, as is presently required for onshore pipelines, needs to be developed for marine pipelines.

RSPA/OPS supports the concept of “one-call” and has forwarded this recommendation to the Common Ground Alliance (CGA), a nonprofit organization dedicated to damage prevention efforts. The CGA addresses the many issues involved in protecting the nation's underground infrastructure from outside force damage.

6. A commenter stated that the cost-benefit analysis provided with the NPRM does not account for the cost of remediation, which could be significant.

RSPA/OPS disagrees. The cost of remediation should not be included in the cost-benefit analysis for this rule because an operator is required to re-bury the pipeline under current regulations when it becomes aware that the pipeline is exposed or a hazard to navigation.

RSPA/OPS requested comments on the respective merits of a performance-based or a prescriptive requirement. A performance-based requirement would require an operator to use risk-based analyses to determine the periodic underwater inspection intervals for each of their pipelines and to conduct the appropriate periodic underwater inspections. A prescriptive requirement would mandate a specific periodic underwater inspection interval.

Nine commenters supported a performance-based approach. Another commenter stated that the acceptance of integrity management principles by RSPA/OPS is a practical method of ensuring pipeline safety and that performance-based regulations should be used whenever possible. Another commenter stated that the different soil and weather conditions require individual evaluations and determinations of adequate inspection intervals. Another commenter urged that predictive land loss models be used because some coastal areas require more frequent inspection than others and that performance-based language would allow operators the flexibility to address the myriad of situations encountered with underwater buried pipelines in a practical and effective manner.

Three commenters supported some combination of approaches. A commenter suggested a trigger mechanism to require an inspection following a major storm and marine event. The commenters believed that regulatory language that is entirely performance-based, without benchmarks for compliance, could lead to inconsistency in implementation and enforcement.

Two commenters supported a prescriptive approach for the inspection of liquid pipelines. Two commenters sought clarification that the recommendations in the Joint Task Force report, the NRC report, and the TTI report were discretionary guidelines for establishing risks and underwater periodic inspection intervals.

One commenter recommended that inspection intervals longer than five years should be established on a case-by-case basis and be based on knowledge and experience gained during the ongoing inspections. Another commenter supported a mandated interval of five years with provision to extend this interval for sound technical reasons. Another commenter supported deferring to MMS directives as the trigger mechanism for more frequent inspections in the Gulf of Mexico and its inlets. Another commenter stated that the value of a prescriptive approach is that it would establish unambiguous requirements for inspection intervals and protocols.

RSPA/OPS agrees with most of the commenters regarding use of a performance-based approach. RSPS/OPS is implementing a performance-based approach because it offers the best overall protection without imposing overly burdensome requirements that may not reflect the operating environment of the pipeline. RSPA/OPS confirms that adoption of the risk analysis systems provided in the NPRM and further articulated in the TTI report is discretionary. RSPA/OPS provided the examples in order to demonstrate the levels of complexity for the proposed performance-based requirement.

Several commenters noted that the use of the term “sea bed” in the definition of “hazard to navigation” is inappropriate. They suggested that RSPA/OPS use the term that was defined in the proposed rule, “underwater natural bottom,” in place of the term “sea bed.”

Another commenter opposed defining a “navigational hazard” as a pipeline that is buried less than 24 inches below the seabed in water less than 15 feet deep. The commenter stated that it was not apparent from the NPRM that there exists credible scientific or empirical evidence to support 24 inches.

RSPA/OPS agrees and has incorporated the phrase “underwater natural bottom” (as determined by recognized and generally accepted practices) in place of the term “seabed” in the affected sections. RSPA/OPS also agrees that the threshold for reburial should remain at 12 inches and is retaining the threshold of 12 inches in the definition of “hazard to navigation.” RSPA/OPS believes that 12 inches is an appropriate threshold because there has not been a Sea Chief or Northumberland type accident since the inspection and reburial regulation issued by RSPA/OPS in 1991.

Several commenters questioned the definition of commercially navigable waterways. Some commenters believed that using the Bureau of Transportation Statistics (BTS) database of commercially navigable waterways and non-commercially navigable waters helps provide consistency and certainty to the regulation, but others believed that the BTS database should not be the definitive source for defining commercially navigable waters.

RSPA/OPS agrees that the description of commercially navigable water in the NPRM is confusing. In addition, RSPA/OPS did not receive comments that pipelines crossing these waters currently pose a threat to navigation that is not already being addressed by the recent integrity management rules for high consequence areas and other regulations.

RSPA/OPS is limiting the requirement to waters less than 15 feet deep in the Gulf of Mexico and its inlets. Therefore it is not necessary to define commercially navigable waterways in this rule.

Several commenters requested confirmation that the existing regulations requiring operators to notify the National Response Center upon becoming aware that their pipeline is exposed or a hazard to navigation remain in effect.

RSPA/OPS confirms that the existing regulations at §§ 192.612(b)(1) and 195.413(b)(1) remain in effect. These regulations require an operator to promptly, but not later than 24 hours after the discovery, notify the National Response Center upon becoming aware that their pipeline is exposed or a hazard to navigation.

One commenter encouraged a specific reference to a USCG-approved marker for identifying pipeline hazards to navigation, particularly as it relates to night time navigation. Another commenter supported the current regulations that require marking of exposed pipelines pending their reburial.

RSPA/OPS believes that the current regulations sufficiently address the marking of exposed underwater pipelines. They require an operator to promptly, but not later than 7 days after the discovery, mark the location of the pipeline in accordance with 33 CFR part 64 (the USCG regulations for identifying hazards to navigation).

Many commenters believed that the final regulation should allow for operators to use sound and proven engineering alternatives, such as articulated concrete mats, riprap stone, and pre-manufactured concrete blocks, that provide a level of protection that meets or exceeds the protection derived from reburial. One commenter suggested that the proposed rule should clarify that the reburial only applies if the pipeline is a hazard to navigation, as defined in §§ 192.3 and 195.2. Several commenters requested that § 195.413(b)(3) be amended to allow operators the opportunity to petition for an extension of the 6 month requirement for re-establishing protective cover of the exposed pipeline. Another commenter stated that the application of the existing reburial requirements to offshore pipelines is inconsistent. The initial construction requirements differentiate burial for offshore pipelines in less than 12 feet of water and those in at least 12 feet of water. For initial construction, pipelines in at least 12 feet of water are to be placed below the natural bottom. However, under § 192.612(b)(3), pipelines between 12 and 15 feet of water will require reburial to a greater depth, 36 inches for soil (18 inches for rock). These pipelines that were in compliance at initial construction located below the natural bottom will now have to be re-buried to 36 inches.

RSPA/OPS agrees with the commenters that concrete mats or other engineered alternatives to reburial can provide for a measure of safety equal to or greater than reburial, particularly in areas of high erosion or soft silty bottoms. RSPA/OPS has modified this final rule to allow for a performance-based alternative to reburial.

Three commenters expressed support for RSPA/OPS’ clarification that these proposed requirements would not apply to abandoned pipelines. They agreed that abandoned pipelines do not pose a hazard to navigation, and therefore should not be included in this rule.

RSPA/OPS concurs with these commenters and has not included abandoned pipelines in this rule.

Several commenters supported RSPA/OPS’ efforts to clarify that there are two types of exposed pipelines—those underwater and those that are on land. The commenters suggested that the definition of “exposed underwater pipeline” be clarified to “an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom.”

RSPA/OPS agrees and has amended the language in the final rule.

Several operators supported RSPA/OPS’ proposed amendment to the definition of “Gulf of Mexico” to clarify that the Gulf of Mexico includes waters beyond 15 feet deep. Another commenter sought clarification on the application of the revised rule. The commenter believed that the proposed language of § 192.612(a) implied that the entire length of an offshore pipeline is subject to the inspection and reburial requirements, regardless of water depth. In contrast, another operator encouraged RSPA/OPS to retain the current definition of Gulf of Mexico and its inlets because revising the definition would cause confusion with current permits and agreements.

RSPA/OPS appreciates the support for modifying the definition of the Gulf of Mexico and its inlets to reflect that Gulf of Mexico includes waters beyond 15 feet deep. RSPA/OPS confirms that the proposed change was not intended to have a material affect on the scope of pipelines in the Gulf of Mexico affected by this rule. However, to avoid unintentional impacts on any existing contracts, RSPA/OPS is not changing the definition of Gulf of Mexico in this final rule. RSPA/OPS has clarified that certain requirements only apply to waters less than 15 feet deep by amending the affected §§ 192.612(a), 195.246(b), 195.413, 195.248(a), and 195.248(b).

One commenter believed that the use of the term “surface” in the new definition of “underwater natural bottom” was confusing. The commenter stated that surface is usually interpreted to be the top, especially when dealing with water bodies. Another commenter recommended that RSPA/OPS revise the term “natural bottom” as used in § 192.327(e) to read “underwater natural bottom.” Several commenters questioned RSPA/OPS’ proposal to use a 50 kHz fathometer signal to determine the underwater bottom, stating that a 50 kHz fathometer may not work properly in 15 feet or less of water. The commenters were generally supportive of the use of a frequency or some sound engineering method to determine the underwater natural bottom, but believed that the choice should be performance-based.

RSPA/OPS agrees. This final rule amends §§ 192.327(e), 192.612(b)(3), 195.246(b), 195.248(a), and 195.413(b)(3) to clarify that the natural bottom or seabed is the underwater natural bottom (as determined by recognized and generally accepted practices).

In addition, during the initial Gulf of Mexico underwater inspections, many operators reported confusion in establishing the point of the underwater natural bottom. In order to resolve this concern, TTI conducted an analysis of pipeline burial in the Gulf of Mexico. The study recommended that the underwater natural bottom be defined as the surface which reflects a fathometer signal. The study further recommended the use of a 50 kHz signal as most appropriate for the very soft, silty bottoms in the Gulf of Mexico and for the water depths of 15 feet or less.

However, RSPA/OPS agrees that allowing for the use of recognized and generally accepted practices would provide the operators with greater flexibility without compromising safety and has amended this final rule accordingly.

The Technical Hazardous Liquid Pipeline Safety Standards Committee is a Federal advisory committee established under Section 204 of the Hazardous Liquid Pipeline Safety Act of 1974 (HLPSA) (49 App. U.S.C. 2003). The Technical Pipeline Safety Standards Committee is a Federal advisory committee established under Section 4 of the Natural Gas Pipeline Safety Act of 1968 (NGPSA). These committees advise DOT on the feasibility, reasonableness, and practicability of standards imposed under HLPSA and NGPSA.

The committees members convened on June 30, 2004, for a telephonic public meeting to discuss the NPRM, the public comments, and RSPA/OPS’ evaluation of the comments, and to vote on the proposal. The advisory committees voted unanimously in favor of the motion that the NPRM, “Pipeline Safety Underwater Periodic Inspections” (68 FR 69368), which published on December 12, 2003, and the draft final regulatory evaluations are technically feasible, reasonable, and cost-effective if the following changes are made: (1) Provisions for alternative protective measures, other than burial, including engineered protection; (2) a process to ensure that RSPA/OPS is notified of delays in the issuance of environmental permits, and (3) inspection procedures to address environmental risks.

The committees also recommended that RSPA/OPS conduct further studies to collect additional data on the risks of exposed pipelines and possible hazards to navigation in offshore waters other than the Gulf of Mexico and its inlets.

The transcript of these advisory committee meetings is available in the docket for this rulemaking.

RSPA/OPS incorporated the advisory committee recommendations in the final rule to allow operators to employ engineered alternatives to burial that meet or exceed the level of protection provided by burial. In addition, RSPA/OPS has incorporated a provision in the final rule to require an operator to notify RSPA/OPS if it cannot obtain required state or Federal permits in time to comply with the regulation.

RSPA/OPS has provided examples of several environmental risk assessment procedures which were developed in conjunction with this rule. These procedures are described in detail in the National Research Council Report Improving the Safety of Marine Pipelines (1994) and in the Texas Transportation Institute Report Analysis of Pipeline Burial Surveys in the Gulf of Mexico. These reports are available in the docket for this rulemaking.

RSPA/OPS will consider issuing a notice to request further public comment on the risks of exposed pipelines and possible hazards to navigation in offshore waters other than the Gulf of Mexico and its inlets.

A copy of the Paperwork Reduction Analysis for this proposal has been put in the public docket for this rule. The following is a summary of the highlights of this analysis.

Approximately 125 pipeline operators are potentially subject to this new requirement. It will take a pipeline operator approximately 500 hours to develop and implement a program to determine the need for periodic inspection. The total industry time to develop this program is 62,500 hours.

Comments were invited on: (a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques.

Several commenters expressed concern about the added costs to prepare and follow a procedure to identify pipelines that are at risk of being exposed underwater pipelines or hazards to navigation and to conduct appropriate periodic underwater inspections in areas other than the Gulf of Mexico and its inlets. Because the scope of the final rule is limited to the Gulf of Mexico and its inlets, the costs of applying this rule to other offshore water and inland waters do not need to be addressed.

Some commenters questioned whether RSPA/OPS was proposing some change to the current requirements for reporting to the USCG's National Response Center. Under current regulations, if an operator discovers that a pipeline is exposed it must take actions that include reporting the location to the National Response Center. In this final rule, RSPA/OPS is not changing this requirement.

A final regulatory evaluation for this rule has been prepared and placed in the public docket. This rule is a response to Congressional requirements that pipelines posing a hazard to navigation or public safety be periodically inspected to notify the operator of the exposure or hazard. The Congressional requirements responded to two accidents in the late 1980s in which fishing vessels collided with underwater natural gas pipelines in the Gulf of Mexico, resulting in multiple fatalities.

Approximately 125 companies operate underwater pipelines in the shallow waters of the Gulf of Mexico and its inlets. Under this rule, each of these companies will be required to prepare and follow a procedure to identify pipelines in waters less than 15 feet deep that are at risk of being an exposed underwater pipeline or a hazard to navigation and to conduct appropriate periodic underwater inspections.

A survey conducted by RSPA/OPS in 1992 determined that less than two percent of the affected underwater pipeline were exposed or a hazard to navigation. RSPA/OPS believes that at most 10% of the affected pipelines may need to be reinspected periodically. RSPA/OPS estimates that the initial cost of this proposal is $6.25 million with annual reinspection costs of approximately $200,000 per year. More details of the costs and benefits of this rule can be found in the public docket.

Several commenters questioned the need for extending inspection requirements outside of the Gulf of Mexico and its inlets. RSPA/OPS agrees with these comments and has limited the scope of the final rule to the Gulf of Mexico and its inlets.

Most commenters agreed with RSPA/OPS' proposal that the rule should be performance-based rather than prescriptive. RSPA/OPS is allowing operators some flexibility in complying with this rule by adopting a performance-based approach. The varied risks faced by underwater pipelines require each operator to determine the hazards posed by each of its pipelines and to develop appropriate responses to the risks. This flexibility is expected to lead to lower costs of compliance.

One commenter was concerned with the impacts on gas distribution operators who operate in inland navigable waterways. The final is limited to the Gulf of Mexico and its inlets and is not expected to have any measurable impact on gas distribution pipeline operators.

Some commenters stated that RSPA/OPS underestimated the costs of this rule by not including remediation costs. However, an operator is currently required to take action if they discover that a pipeline is exposed. Therefore, remediation is not an additional cost imposed by this rule.

Several commenters were concerned that the inclusion of pipelines in navigable waterways in the proposed rule would add significant costs without added benefits. As discussed above, distribution pipeline operators had particular concerns. The great majority of small pipeline operators in the United States are distribution operators. By limiting this final rule to pipelines in the Gulf and its inlets RSPA/OPS has eliminated most, if not all, small operators from the impact of this regulation. Based on the facts available about the anticipated impact of this rulemaking, I certify, pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605), that this action will not have a significant economic impact on a substantial number of small entities.

A preliminary draft Environmental Assessment (EA) was prepared and is available in the docket. No comments on the EA were received from the public. The inspection and reburial of the pipelines should not have a significant impact on the environment. Previous inspections of underwater pipelines in the Gulf of Mexico found less than two percent of pipelines required reburial. RSPA/OPS anticipates that very few pipelines will require reburial as a result of this rule. Therefore, this rule will not have a significant impact on the human environment. A Final EA has been placed in the docket.

RSPA/OPS analyzed this action in accordance with the principles and criteria contained in Executive Order 12612 (52 FR 41685).

RSPA/OPS has determined that the action does not have substantial direct effects on the States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, this rule does not have sufficient federalism implications to warrant preparation of a Federalism Assessment.

Section 118 of the MMPA requires NMFS to place all U.S. commercial fisheries into one of three categories based on the level of incidental serious injury and mortality of marine mammals occurring in each fishery (16 U.S.C. 1387 (c)(1)). The categorization of a fishery in the LOF determines whether participants in that fishery may be required to comply with certain provisions of the MMPA, such as registration, observer coverage, and take reduction plan requirements. NMFS must reexamine the LOF annually, considering new information in the Stock Assessment Reports and other relevant sources and publish in the Federal Register any necessary changes to the LOF after notice and opportunity for public comment (16 U.S.C. 1387 (c)(1)(C)).

The definitions for the fishery classification criteria can be found in the implementing regulations for section 118 of the MMPA (50 CFR 229.2). The criteria are also summarized here.

The fishery classification criteria consist of a two-tiered, stock-specific approach that first addresses the total impact of all fisheries on each marine mammal stock, and then addresses the impact of individual fisheries on each stock. This approach is based on consideration of the rate, in numbers of animals per year, of incidental mortalities and serious injuries of marine mammals due to commercial fishing operations relative to the potential biological removal (PBR) level for each marine mammal stock. The MMPA (16 U.S.C. 1362 (20)) defines the PBR level as the maximum number of animals, not including natural mortalities, that may be removed from a marine mammal stock while allowing that stock to reach or maintain its optimum sustainable population. This definition can also be found in the implementing regulations for section 118 at 50 CFR 229.2.

Tier 1: If the total annual mortality and serious injury of a marine mammal stock, across all fisheries, is less than or equal to 10 percent of the PBR level of the stock, all fisheries interacting with the stock would be placed in Category III. Otherwise, these fisheries are subject to the next tier (Tier 2) of analysis to determine their classification.

Tier 2, Category I: Annual mortality and serious injury of a stock in a given fishery is greater than or equal to 50 percent of the PBR level.

Tier 2, Category II: Annual mortality and serious injury of a stock in a given fishery is greater than 1 percent and less than 50 percent of the PBR level.

Tier 2, Category III: Annual mortality and serious injury of a stock in a given fishery is less than or equal to 1 percent of the PBR level.

While Tier 1 considers the cumulative fishery mortality and serious injury for a particular stock, Tier 2 considers fishery-specific mortality and serious injury for a particular stock. Additional details regarding how the categories were determined are provided in the preamble to the final rule implementing section 118 of the MMPA (60 FR 45086, August 30, 1995).

Since fisheries are categorized on a per-stock basis, a fishery may qualify as one Category for one marine mammal stock and another Category for a different marine mammal stock. A fishery is typically categorized on the LOF at its highest level of classification ( e.g. , a fishery qualifying for Category III for one marine mammal stock and for Category II for another marine mammal stock will be listed under Category II).

In the absence of reliable information indicating the frequency of incidental mortality and serious injury of marine mammals by a commercial fishery, NMFS will determine whether the incidental serious injury or mortality qualifies for Category II by evaluating other factors such as fishing techniques, gear used, methods used to deter marine mammals, target species, seasons and areas fished, qualitative data from logbooks or fisher reports, stranding data, and the species and distribution of marine mammals in the area, or at the discretion of the Assistant Administrator for Fisheries (50 CFR 229.2).

This final rule includes two tables that list all U.S. commercial fisheries by LOF Category. Table 1 lists all of the fisheries in the Pacific Ocean (including Alaska). Table 2 lists all of the fisheries in the Atlantic Ocean, Gulf of Mexico, and Caribbean.

Owners of vessels or gear engaging in a Category I or II fishery are required under the MMPA (16 U.S.C. 1387(c)(2)), as described in 50 CFR 229.4, to register with NMFS and obtain a marine mammal authorization from NMFS in order to lawfully incidentally take a marine mammal in a commercial fishery. Owners of vessels or gear engaged in a Category III fishery are not required to register with NMFS or obtain a marine mammal authorization.

Fishers must register with the Marine Mammal Authorization Program (MMAP) by contacting the relevant NMFS Regional Office (see ADDRESSES ) unless they participate in a fishery that has an integrated registration program (described below). Upon receipt of a completed registration, NMFS will issue vessel or gear owners physical evidence of a current and valid registration that must be displayed or in the possession of the master of each vessel while fishing in accordance with section 118 of the MMPA (16 U.S.C. 1387(c)(3)(A)).

For some fisheries, NMFS has integrated the MMPA registration process with existing State and Federal fishery license, registration, or permit systems and related programs. Participants in these fisheries are automatically registered under the MMPA and are not required to submit registration or renewal materials or pay the $25 registration fee. Following is a list of integrated fisheries and a summary of the integration process for each Region. Fishers who operate in an integrated fishery and have not received registration materials should contact their NMFS Regional Office (see ADDRESSES ).

The following fisheries have integrated registration programs under the MMPA:

1. All Alaska Category II fisheries;

2. All Washington and Oregon Category II fisheries;

3. Northeast Regional fisheries for which a State or Federal permit is required.

Individuals fishing in fisheries for which no state or Federal permit is required must register with NMFS by contacting the Northeast Regional Office (see ADDRESSES ); and

4. All North Carolina, South Carolina, Georgia, and Florida Category I and II fisheries for which a State permit is required.

Regional Offices, except for the Northeast Region, annually send renewal packets to previously registered participants in Category I or II fisheries. However, it is the responsibility of the fisher to ensure that registration or renewal forms are completed and submitted to NMFS at least 30 days in advance of fishing. Individuals who have not received a renewal packet by January 1 or are registering for the first time should request a registration form from the appropriate Regional Office (see ADDRESSES ).

In accordance with the MMPA (16 U.S.C. 1387(e)) and 50 CFR 229.6, any vessel owner or operator, or fisher (in the case of non-vessel fisheries), participating in a Category I, II, or III fishery must report to NMFS all incidental injuries and mortalities of marine mammals that occur during commercial fishing operations. “Injury” is defined in 50 CFR 229.2 as a wound or other physical harm. In addition, any animal that ingests fishing gear or any animal that is released with fishing gear entangling, trailing, or perforating any part of the body is considered injured, regardless of the presence of any wound or other evidence of injury, and must be reported. Instructions on how to submit reports can be found in 50 CFR 229.6.

Fishers participating in a Category I or II fishery are required to accommodate an observer aboard vessel(s) upon request. Observer requirements can be found in 50 CFR 229.7.

Fishers participating in a Category I or II fishery are required to comply with any applicable take reduction plans.

NMFS reviewed the marine mammal incidental serious injury and mortality information presented in the Stock Assessment Reports (SARs) for all observed fisheries to determine whether changes in fishery classification were warranted. NMFS SARs are based on the best scientific information available, including information on the level of serious injury and mortality of marine mammals that occurs incidental to commercial fisheries and the PBR levels of marine mammal stocks. NMFS also reviewed other sources of new, relevant information, including marine mammal stranding data, observer program data, fisher self-reports, and other information that is not included in the SARs. Additionally, NMFS took into account information presented at a workshop from June 2-3, 2004, to review data used in the proposed categorization of the Hawaii longline fishery.

The information contained in the SARs is reviewed by regional scientific review groups (SRGs) representing Alaska, the Pacific (including Hawaii), and the U.S. Atlantic, Gulf of Mexico, and the Caribbean. The SRGs were created by the MMPA to review the science that goes into the SARs, and to advise NMFS on population status and trends, stock structure, uncertainties in the science, research needs, and other issues.

The LOF for 2004 was based, among other things, on information provided in the final SARs for 1996 (63 FR 60, January 2, 1998), the final SARs for 2001 (67 FR 10671, March 8, 2002), the final SARs for 2002 (68 FR 17920, April 14, 2003), and the draft SARs for 2003 (68 FR 51561, August 27, 2003).

NMFS received 10 comment letters on the proposed 2004 LOF (69 FR 19365, April 13, 2004) from environmental, commercial fishing, and Federal and State interests. Issues outside the scope of the LOF are not responded to in this final rule. Any comments received after the public comment period closed on June 14, 2004, are not responded to in this final rule.

Comment 1: One commenter disapproved of the fishery classification criteria used for the LOF, but did not offer an alternative suggestion for the criteria.

Response: The current fishery classification system is based on a two-tiered, stock-specific approach that first addresses the total impacts of all fisheries on each marine mammal stock and then addresses the impacts of individual fisheries on each stock (60 FR 31666, June 16, 1995). Tier 1 considers the additive fishery mortality and serious injury for a particular stock, while Tier 2 considers fishery-specific mortality for a particular stock. This approach is based on the rate, in numbers of animals per year, of serious injuries and mortalities due to commercial fishing relative to a stock's PBR level. Under the Tier 1 analysis, if the total annual mortality and serious injury across all fisheries that interact with a stock is less than or equal to 10 percent of the PBR level of such a stock, then all fisheries interacting with this stock would be placed in Category III. Otherwise, these fisheries are subject to the next tier to determine their classification. Under the Tier 2 analysis, those fisheries in which annual mortality and serious injury of a stock in a given fishery is greater than or equal to 50 percent of the stock's PBR level are placed in Category I, while those fisheries in which annual mortality and serious injury is greater than 1 percent and less than 50 percent of the stock's PBR level are placed in Category II. Individual fisheries in which annual mortality and serious injury is less than or equal to 1 percent of the PBR level would be placed in Category III. The threshold between Tier 1 and Tier 2 was set at 10 percent of the PBR level based on recommendations that arose from a PBR Workshop held in La Jolla, California in June 1994. The Workshop Report indicated if the total annual incidental serious injury and mortality level for a particular stock did not exceed 10 percent of the PBR level, the amount of time necessary for that population to achieve the optimum sustainable population level would only increase by 10 percent. Thus, 10 percent of the PBR level for a particular stock was equated to “biological insignificance.” This approach ensures that fisheries are categorized based on their impacts on stocks and allows NMFS to focus resources on those fisheries that have a significant impact on marine mammals.

This approach is based on the fact that the MMPA established both a short-term and a long-term goal with respect to take reduction plans for reducing marine mammal mortality and serious injury incidental to commercial fishing operations. MMPA section 118(f)(2) provides: “The immediate goal of a take reduction plan for a strategic stock shall be to reduce, within 6 months of its implementation, the incidental mortality or serious injury of marine mammals incidentally taken in the course of commercial fishing operations to levels less than the potential biological removal established for that stock under section 117. The long-term goal of the plan shall be to reduce, within 5 years of its implementation, the incidental mortality or serious injury of marine mammals incidentally taken in the course of commercial fishing operations to insignificant levels approaching a zero mortality and serious injury rate, taking into account the economics of the fishery, the availability of existing technology, and existing State or regional fishery management plans.” NMFS established the tier-based fishery classification system with each goal in mind and to ensure that fisheries progressively move toward the long-term goal of the MMPA.

Comment 2: One commenter called into question NMFS' execution of the LOF, particularly that all fisheries should be listed as Category I.

Response: Section 118 of the MMPA (16 U.S.C. 1387(c)(1)) and the regulations implementing that section (50 CFR part 229) specify how NMFS executes the annual LOF. NMFS reexamines commercial fisheries each year to determine whether changes are needed. Proposed and final LOFs must categorize each commercial fishery based on the definitions of Category I, II, and III fisheries (50 CFR 229.2), list the marine mammals that have been incidentally injured or killed by commercial fishing operations, and estimate the number of vessels or persons involved in each commercial fishery. See Response to Comment 1.

Comment 3: One commenter stated that all high seas fisheries conducted by U.S. flagged vessels should be listed on the LOF. In particular, the commenter suggested adding the U.S. Patagonian toothfish longline fishery and the U.S. trawl fishery for krill as Category II fisheries until further information is available. The commenter noted several other fisheries, including the Cobb Seamount, Pacific pelagic squid jig, and South Pacific tuna purse seine, that should be analyzed for interactions with marine mammals and appropriately classified on the LOF.

Response: NMFS must publish any proposed changes to the LOF in the Federal Register to allow for notice and opportunity for public comment. Therefore, NMFS cannot add these new fisheries to the 2004 final LOF because it is beyond the scope of what was included in the proposed 2004 LOF. NMFS will consider this comment and whether the LOF applies to high seas fisheries during development of future proposed LOFs.

Comment 4: One commenter stated that gillnet fisheries in Alaska may require more observer coverage than current fishery classifications allow.

Response: NMFS works annually through the National Observer Program to obtain resources necessary to monitor Alaska gillnet fisheries. Funds are limited; therefore NMFS rotates observer coverage among gillnet fisheries based on statutory priorities (16 U.S.C. 1387(d)) and specific time cycles. The Alaska gillnet fisheries on the LOF (nearshore salmon drift and set gillnet fisheries) are managed by the State of Alaska's Department of Fish and Game. These fisheries were originally placed into Category II as unobserved fisheries. The Category II designation was made for these fisheries, where little or no information on marine mammal takes for the specific fisheries was available, because gillnet fisheries worldwide have been demonstrated as having the capability of causing significant numbers of mortalities and serious injuries to marine mammals. The only Alaska gillnet fisheries currently in Category III are those fisheries that have been observed and subsequent analyses of observer data indicate these fisheries meet the threshold for a Category III designation. The remainder of the unobserved Alaska gillnet fisheries continue to remain in Category II until such time that they can be observed and data are obtained that indicate a change in fishery classification is warranted. Several Alaska gillnet fisheries that have been observed remain in Category II due to analyses of observer data that indicate a Category II threshold has been met for each of those fisheries.

Comment 5: NMFS received several comments supporting the delineation of Alaska fisheries. One commenter stated that NMFS should reclassify fisheries appropriately after analyses on the new fisheries are completed. Another commenter was concerned that subdividing Alaska fisheries creates the appearance of fewer impacts on marine mammals, when a larger fishery as previously delineated may have met the threshold for classification as a Category I or II fishery.

Response: NMFS plans to complete the analyses on all Alaska fisheries and appropriately propose reclassification of those fisheries that meet the criteria for Category I and II fisheries in the 2005 proposed LOF. The analysis for fishery classification is designed to take into effect the cumulative impacts of multiple fisheries on marine mammal stocks. NMFS continues to work toward supporting increased observer coverage in all Category I and II fisheries across the country, including fisheries in Alaska, to improve the accuracy of marine mammal bycatch estimates.

The Alaska fisheries delineated in the 2004 proposed LOF as individual fisheries were separated to more accurately reflect the actual management and operational practices of those fisheries and to keep better track of marine mammal serious injuries and mortalities occurring in different sectors of the fishery. This is being implemented as a two-step process, the delineation of the fisheries in 2004 followed by analyses to reclassify the fisheries as appropriate in the 2005 proposed LOF. The analyses will be performed according to the existing protocol used to categorize fisheries. Documented mortalities and serious injuries used in previous analyses to categorize the fisheries will be assigned to one of the newly delineated fisheries. Any additional documented serious injuries or mortalities will likewise be assigned to the appropriate fishery. These changes will also be made in the SARs for each of the relevant marine mammal stocks. These changes will provide a more accurate understanding of the interactions between marine mammals and various Alaska fisheries. Prior to these changes, large groups of diverse fisheries were artificially lumped together based only on gear type over vast geographic areas of the Bering Sea and the Gulf of Alaska.

Comment 6: One commenter suggested that NMFS update relevant SARs with the new Alaska fishery delineations, determine which trawl and pot fisheries interact with the central and western North Pacific stocks of humpback whales, and recategorize the fisheries accordingly.

Response: Delineating the Alaska trawl and pot fisheries by area and target species will allow NMFS to better evaluate interactions between the central and western North Pacific humpback whale stocks and specific fisheries. NMFS will analyze relevant data and propose fishery classifications accordingly. See Response to Comment 5.

Comment 7: One commenter suggested separating out the yellowfin sole fishery from the Bering Sea and Aleutian Islands (BSAI) flatfish trawl fishery because the fishery has its own total allowable catch (TAC) and prohibited species catch (PSC). The commenter also noted that some vessels that target yellowfin sole do not target other flatfish species. Additionally, the yellowfin sole fishery operates in the relatively shallow waters along the sand bottom shelf areas of the central and northern portions of the Bering Sea where interactions with marine mammals seems unlikely.

Response: The BSAI flatfish trawl fishery was designated as a single fishery in the proposed 2004 LOF based on information indicating an overlap in the prosecution of the flatfish trawl fisheries of the BSAI. As noted in the public comment, the yellowfin sole fishery has its own TAC and PSC quotas, as do other flatfish fisheries, and some separation exists in time and areas of prosecution of these fisheries. However, while the yellowfin sole fishery can be prosecuted at times with few interactions with marine mammals, significant overlap of the fishery occurs particularly with the rock sole, flathead sole, and Alaska plaice fisheries, with vessels catching these other species together with yellowfin sole in the same trip and haul. The overlap of these fisheries prevents listing the yellowfin sole fishery separately in the LOF.

Comment 8: One commenter stated that the reclassification of the CA/OR thresher shark/swordfish drift gillnet fishery (≥14 in. mesh) from Category I to Category II was premature and should be reversed. The commenter noted that the fishery still interacts with a wide range of stocks and the annual take of sperm whales is 47.8 percent of the stock's PBR level, just under the threshold for inclusion in Category I.

Response: The CA/OR thresher shark/swordfish drift gillnet fishery (≥14 in. mesh) was moved from Category I to Category II in the 2003 final LOF (68 FR 41725, July 15, 2003). This change in fishery classification was based on observer data from 1997-2001 that indicated the take of marine mammals incidental to this fishery was less than 50 percent of the PBR level for those stocks that interact with the fishery. One observed take of a sperm whale occurred in this fishery in 1998, but no takes have been observed in the most recent 5 years of data from 1999-2003. Therefore, NMFS does not believe a change in fishery classification is warranted at this time. In an effort to reduce marine mammal serious injury and mortality, the owners and operators of CA/OR drift gillnet vessels operating in this fishery have been complying with the requirements of the Pacific Offshore Cetacean Take Reduction Plan, including carrying observers, using acoustic deterrents (pingers) on the nets, and complying with other gear modification requirements. Observers will continue to monitor this fishery, and if sperm whales are observed taken, NMFS will reevaluate this fishery.

Comment 9: Several commenters requested NMFS to extend the public comment period on the proposed 2004 LOF to accommodate a workshop on false killer whale population abundance and fishery interactions in the central Pacific Ocean (Workshop).

Response: NMFS agreed and the public comment period was extended from May 13, 2004, to June 14, 2004 (69 FR 26539, May 13, 2004), to accommodate the Workshop, which was held June 2-3, 2004 in Honolulu, Hawaii, and public comment resulting from the Workshop. The purpose of the Workshop was to discuss MMPA fishery classification requirements, specifically concerning the abundance and fishery interactions for false killer whales ( Pseudorca crassidens ) within the U.S. Exclusive Economic Zone (EEZ) around the Hawaiian Islands. The workshop also covered background information and procedures used to categorize the Hawaii longline fishery in the LOF. For a summary of the Workshop, please contact the Pacific Islands Regional Office (see ADDRESSES ).

Comment 10: One commenter requested that NMFS reopen the comment period on the 2004 proposed LOF once the results of the Workshop on the Hawaii longline fishery and false killer whales were made available for public review.

Response: NMFS convened the Workshop to review available information and the process to reclassify the Hawaii longline fishery based on that information. NMFS staff, scientific experts, fishery representatives, and other interested members of the public participated in this Workshop. NMFS considered all information presented and discussed at the Workshop and public comment resulting from the Workshop in the decision to reclassify this fishery. See Response to Comment 9.

Comment 11: NMFS received several comments supporting the proposed elevation of the Hawaii longline fishery from Category III to Category I.

Response: NMFS has reclassified and elevated the fishery from Category III to Category I in the 2004 LOF.

Comment 12: One commenter recommended elevating the Hawaii longline fishery from Category III to Category II, instead of Category I, based on uncertainties surrounding the population abundance and mortality data. The commenter maintains that the NMFS 2002 survey on cetacean abundance in Hawaiian waters is flawed for two reasons. First, it was conducted between August and November when false killer whales are generally less abundant in Hawaiian waters. Second, the survey covered the entire EEZ while false killer whales are known to occur around islands rather than in the open ocean.

Response: At the June 2004 Workshop, relevant information was presented indicating that there was no evidence of seasonality in abundance of false killer whales in waters surrounding Hawaii (Baird, Workshop presentation; Kobayashi, Workshop presentation). In addition, limited data that are available from year-round surveys may actually suggest lower encounter rates during the late spring/early summer than during November-December. The commenter cited a reference (Stacey et al , 1994) to indicate evidence of seasonality in false killer whale abundance. However, that study discussed seasonality in false killer whales in temperate waters around Japan and off the coast of the former Soviet Union, not in tropical waters surrounding the Hawaiian Islands. The marine ecosystems surrounding Japan and the Hawaiian Islands are very different and, therefore, NMFS does not believe that the information in this reference is relevant to false killer whales in Hawaiian waters.

Based on the data, NMFS concludes false killer whales are not more common around the Hawaiian Islands than in the open ocean. Relevant data indicate false killer whale occurrences on the open sea, and published literature indicates that “False killer whales are found most often offshore, although there are occasional records from inshore waters * * *” (Stacey and Baird, 1991). Furthermore, nearshore sightings data from studies conducted around the main Hawaiian Islands since 1993 (Baird, Workshop presentation; Mobley 2003) have demonstrated that sightings are not frequent around the main Hawaiian Islands. Particularly, during the two most recent spring aerial surveys, conducted in 2000 and 2003, no false killer whales were seen around the Hawaiian Islands. The NMFS 2002 survey was conducted in the area where the Hawaii longline fishery operates around the Hawaiian Islands and was compared to the mortality and serious injury of false killer whales in the same area for purposes of classifying the fishery.

Comment 13: One commenter disagreed with NMFS' abundance estimates of the Hawaiian stock of false killer whales for the following reasons. The commenter noted, first, that NMFS’ data indicate that the Hawaiian stock of false killer whales exhibit seasonal abundance, possibly peaking coincident to yellowfin tuna peak abundance. Second, the commenter maintained there is information indicating false killer whale distribution varies not only by season, but possibly over years, which may be linked to El Nino effects on prey species. Third, the commenter criticized NMFS’ extrapolation of one sighting during the 2002 shipboard survey to a group of 10 individuals. The commenter noted that it is well-accepted that false killer whales are a highly social species found in group sizes averaging from 20 to 50 individuals. Fourth, the commenter disapproved of NMFS’ diving correction factor, stating that it does not reflect false killer whale behavior.

Response: NMFS disagrees with this comment. The abundance estimates are based on established scientific methods and were reviewed and accepted by the Pacific Scientific Review Group. The issues raised by the commenter are not indicative of deficiencies in the abundance estimates. First, neither the cited NMFS data (Walsh and Kobayashi, Draft Report, May 21, 2004), nor the data presented by independent scientists (Baird, Mobley) at the June workshop, provide any evidence for seasonality in the abundance of false killer whales around Hawaii. The NMFS draft report states “False killer whales (Figure A3c) were the most frequently sighted species, present in every EEZ except Jarvis, with no apparent seasonality ” [emphasis added]. Second, NMFS agrees that interannual variability in false killer whale distribution may occur, and that additional years of data will improve the precision of the abundance estimate. However, the marine mammal stock assessment process under the MMPA was specifically designed to allow for levels of uncertainty in abundance similar to those observed for Hawaiian false killer whales. Third, the references cited by the commenter do not indicate substantially greater mean group sizes for false killer whales in tropical waters, such as those surrounding Hawaii. In the eastern tropical Pacific, Stacey and Baird (1991) report a mean group size of 18.1 false killer whales, contrasting with a mean group size of 55 in temperate waters off Japan (Stacey et al. , 1994). Extensive NMFS survey data for tropical Pacific waters yielded an average group size of 11.4 false killer whales (Wade and Gerrodette, 1993). Thus, published estimates for tropical waters are similar to the group size of 10 false killer whales observed during the 2002 survey. Finally, the dive correction factor used in the estimation of abundance (Barlow, 2003) reflects a combination of false killer whale diving behavior and the search behavior of the observer team aboard NMFS research vessels during marine mammal surveys. Observations of false killer whales from longline vessels are fundamentally different in nature, and the proportion of animals missed is expected to differ. See also Response to Comment 12.

Comment 14: Two commenters noted that false killer whale abundance around Hawaii may actually be overestimated, not underestimated, as stated in the proposed 2004 LOF. Several reasons were given: (1) The relative proportion of false killer whales to all delphinids is similar between the Hawaiian EEZ and the ETP; (2) false killer whales in Hawaiian waters do not appear to dive for particularly long periods ; (3) two independent research projects found false killer whales to be uncommon around Hawaii; and (4) the abundance estimate may be biased because it is based on a correction factor developed for a suite of similar-sized delphinids, which often occur in groups smaller than false killer whale groups and are, therefore, more difficult to observe.

Response: NMFS agrees that it is possible that the abundance estimate for the Hawaiian stock of false killer whales may be overestimated. NMFS recognizes that the correction factor used for animals missed on the trackline during a survey could possibly be overestimated if false killer whales are more active and visible around Hawaii than false killer whales and similar-sized cetaceans in the ETP, which is where the correction factor was developed. These potential sources of minor upward bias in the false killer whale abundance estimates do not affect the classification of the Hawaii-based longline fishery, because there would be no change in the classification of the fishery or the designation of the Hawaiian stock of false killer whales as a strategic stock if potential sources of upward bias were identified and removed. The total annual mortality and serious injury of the Hawaiian stock of false killer whales would still exceed the PBR level. Therefore, the available abundance estimates are considered reliable for purposes of the classification of the fishery as Category I.

Comment 15: One commenter noted that a revised aerial survey abundance estimate that includes data from 2000 and 2003 would be lower than that presented in Mobley (2000).

Response: If aerial survey data from 2000 and 2003 (Mobley) were revised and combined with the results of the offshore surveys (Barlow 2003), the abundance estimate would be equal to or less than the estimate presented in Barlow (2003). If an updated abundance estimate including the 2000 and 2003 aerial survey results were available, the Hawaiian stock of false killer whales would remain a strategic stock, and the Hawaii-based longline fishery would remain a category I fishery. See also the Response to Comment 14.

Comment 16: One commenter recommended that NMFS undertake a new population survey that accounts for the known seasonality of false killer whale abundance in the Hawaiian Islands EEZ before publishing the 2005 LOF.

Response: There is no known seasonality of false killer whales in the Hawaiian Islands EEZ. Neither NMFS observer data (Walsh and Kobayashi, Draft Report, May 21, 2004), nor data presented by independent scientists (Baird, Mobley) at the June 2004 workshop, provide any evidence for seasonality in the abundance of false killer whales around Hawaii.

Comment 17: One commenter noted that NMFS has defined the false killer whale stock in the Hawaiian EEZ as a strategic stock, based on genetic evidence suggesting false killer whales between the central North Pacific (Hawaii) are separate, reproductively isolated populations from false killer whales in the ETP. However, the commenter notes the degree of separation between these false killer whales is not known, and the geographic boundaries for the populations cannot yet be identified. False killer whales have been taken by the Hawaii longline fishery in an area ranging from north of the Hawaiian EEZ to the equator. Are all of these false killer whales from the same population or from separate isolated populations? If from the same population, then the designation of a strategic stock in the Hawaii EEZ would be questionable.

Response: The Hawaiian stock of false killer whales is considered a strategic stock under the MMPA because fishery-related mortality and serious injury exceeds the PBR level for this stock (see 16 U.S.C. 1362(19)).

Genetic analysis of samples from false killer whales in the North Pacific Ocean indicates population structure, but geographic boundaries of the various populations cannot yet be identified. However, the evidence for reproductive isolation and strong genetic differentiation of individuals sampled around Hawaii from individuals sampled in the ETP is solid. Furthermore, NMFS” current mortality and serious injury estimates are based only on takes within the U.S. EEZ and compared to PBR levels derived from abundance estimates for waters within the U.S. EEZ. In addition, even if the actual boundaries of the Hawaiian stock of false killer whales extended beyond the EEZ, the strategic status of the stock would not be changed. NMFS” guidelines for preparing marine mammal stock assessment reports contain specific instructions for calculating PBR of trans-boundary stocks. (The guidelines are available in electronic form at http://nmml.afsc.noaa.gov/library/gammsrep/gammsrep.htm. ) In cases such as false killer whales in the Hawaiian EEZ, where the stock could extend into international waters, the PBR would be based on the abundance of animals within the EEZ. This guideline was established to prevent underestimating the effects of mortality and serious injury incidental to U.S. fisheries in international waters where unknown levels of additional human-caused mortality and serious injury ( e.g. , incidental to foreign fisheries in the same waters) may also be affecting the stock. NMFS does, however, plan to try to obtain additional genetic samples from a broader geographic range to help define stock boundaries.

Comment 18: One commenter stated that estimated mortality of false killer whales in the Hawaii longline fishery may be underestimated for several reasons, including: (1) some hooked and thus seriously injured whales may break free of the gear before reaching the boat, (2) some false killer whales from the Hawaiian stock may be taken outside the U.S. EEZ; (3) false killer whales observed taken in Palmyra's EEZ may be part of the Hawaiian stock; and (4) several observed interactions with unidentified cetaceans are likely to have been false killer whales. If the number of unidentified cetaceans seriously injured or killed in the Hawaii longline fishery was pro-rated in proportion to the known mortality and serious injury of the potential species involved, the estimated takes of false killer whales within the Hawaiian EEZ would increase.

Response: Mortality of false killer whales in the Hawaii longline fishery may be underestimated. NMFS intends to obtain additional data to clarify the stock structure and genetic differentiation of animals found in waters surrounding Palmyra Island versus those in the Hawaiian EEZ and in international waters of the tropical Pacific . See Response to Comment 17.

Comment 19: One commenter noted that NMFS incorrectly states, “Since 1998, only one false killer whale has been observed killed in the Hawaiian EEZ” (69 FR 19368, May 13, 2004). The commenter stated that serious injury and mortality estimates should not have been based on this interaction because it is over five years old.

Response: The proposed 2004 LOF does contain an error; since 1998, only one false killer whale has been observed seriously injured in the Hawaiian EEZ. The individual was released with a hook in the mouth and trailing line. Based on NMFS” serious injury guidelines, any cetacean released with trailing gear is considered seriously injured. By definition, a serious injury is one that will likely result in mortality (50 CFR 229.2). Furthermore, section 118 of the MMPA treats mortality and serious injury equally.

NMFS mortality estimates are based on information presented in the most recent SAR. Based on NMFS” guidelines for preparing SARs, serious injury and mortality rates are generally based on the most recent 5-year averages of data available when the SAR is drafted ( e.g. , 1997-2001 for the 2003 SARs).

Comment 19a: One commenter stated re-opening the area closed to swordfish fishing will likely increase takes of false killer whales by the Hawaii longline fishery.

Response: Comment noted.

Comment 20: Two commenters expressed concerns regarding NMFS protocols for assessing serious injuries of false killer whales and requested NMFS to revisit its serious injury guidelines or develop a more refined assessment method. In particular, one commenter requested NMFS to convene a workshop to specifically address serious injury guidelines for false killer whales, since the commenter does not believe an individual hooked in the mouth is likely to die.

Response: NMFS convened a workshop of experts in marine mammal biology, marine mammal medicine, and fishing technologies in April 1997. The results of this workshop included guidelines for differentiating serious and non-serious injuries of marine mammals incidental to commercial fishing operations, which were published as a NOAA Technical Memorandum (NMFS-OPR-13 1998), and have been used to determine severity of injuries to false killer whales and other cetaceans in the Hawaii longline fishery. The publication process included scientific peer review. These guidelines represent a compilation of the best scientific information available at the time and have not been updated since 1997. Additional data, particularly on large whales, have been collected since the workshop was convened. When these additional data have been compiled and analyzed, NMFS will update the guidelines as needed.

Comment 21: One commenter urged NMFS to increase observer coverage to more accurately estimate serious injury and mortality of marine mammals incidental to the Hawaii longline fishery.

Response: There is 100-percent observer coverage in the shallow-set component and 20-percent observer coverage in the deep-set component of the Hawaii longline fishery beginning in 2004, as mandated by an Endangered Species Act section 7 biological opinion on sea turtle interactions with the fishery, and these observers are trained to collect information on interactions with all protected species. Given the relatively long history of the deep-set component and our understanding of fishing practices, catch, and interactions with protected species, 20 percent is a sufficient level of coverage in the deep-set component of the fishery.

Comment 22: One commenter stated that, under the National Environmental Policy Act (NEPA), NMFS should not rely on the Environmental Assessment (EA) prepared for regulations to implement section 118 of the MMPA (1995 EA) for the 2004 LOF.

Response: The 1995 EA concluded that implementation of these regulations would not have a significant impact on the human environment. This final rule would not make any significant change in the management of reclassified fisheries, and therefore, this final rule is not expected to change the analysis or conclusion of the 1995 EA. If NMFS takes a management action, for example, through the development of a TRP, NMFS will first prepare the appropriate environmental analysis as required under NEPA specific to that action.

Comment 23: One commenter stated that NMFS did not comply with the Regulatory Flexibility Act (RFA) in preparing the 2004 LOF.

Response: NMFS complied with the RFA. The Chief Counsel for Regulation of the Commerce Department certified to the Chief Counsel for Advocacy of the Small Business Administration that the rule would not have a significant economic impact on a substantial number of small entities. (See 5 U.S.C. 605 and the Classification section of the proposed rule, 69 FR 19365, April 13, 2004.) As a result, no initial or final regulatory flexibility analysis was required. For convenience, the factual basis leading to the certification is repeated below.

Comment 24: Several commenters recommended elevating the Gulf of Mexico blue crab trap/pot fishery from Category III to Category II due to interactions with bottlenose dolphins. One commenter also recommended that NMFS institute an observer program in this fishery to obtain more reliable information.

Response: As stated in the 2004 proposed LOF (69 FR 19365, 19370, April 13, 2004), NMFS believes it is necessary to investigate stock structure of bottlenose dolphins in the Gulf of Mexico and intends to reevaluate this fishery as relevant information becomes available. The vast majority of NMFS resources for bottlenose dolphin research is being expended in the Atlantic Ocean to satisfy the needs of the Atlantic Bottlenose Dolphin Take Reduction Team (TRT). As the needs of this existing TRT are met, NMFS plans to shift resources to the Gulf of Mexico to better define bottlenose dolphin stock structure and interactions with fisheries in this area. However, NMFS does not have adequate information at this time to change the classification of this fishery.

Comment 25: One commenter recommended NMFS reclassify the Gulf of Mexico menhaden purse seine fishery as a Category I fishery and direct more observer effort to determining the level of fishery interactions with bottlenose dolphins.

Response: NMFS believes it is necessary to investigate the stock structure of bottlenose dolphins in the Gulf of Mexico and monitor interactions between bottlenose dolphins and the Gulf of Mexico menhaden purse seine fishery and Gulf of Mexico gillnet fishery. NMFS intends to reevaluate this fishery as relevant information becomes available. However, NMFS does not have adequate information at this time to change the classification of this fishery. See Response to Comment 24. See also the 2003 LOF, for the response to a similar comment (68 FR 41725, 41730; July 15, 2003).

Comment 26: One commenter recommended NMFS reclassify the Gulf of Mexico gillnet fishery as a Category I fishery given that bottlenose dolphin population structure in the Gulf of Mexico is composed of numerous stocks with low PBR levels.

Response: See Response to Comment 25.

Comment 27: One commenter strongly urged NMFS to promptly respond to, and necropsy, strandings in the southeast U.S. to assess patterns and levels of marine mammal interactions with the Gulf of Mexico blue crab trap/pot fishery.

Response: The marine mammal stranding network has established protocols in place for responding to and investigating stranding events. The Level A data form that responders are required to use has a specific field to note any evidence of a fishery interaction. In the event that a fishery interaction is suspected, the network and the appropriate NMFS Regional Office and/or Science Center have protocols in place to investigate further and identify the fishery.

Comment 28: One commenter noted the expansion of open ocean aquaculture operations may warrant further consideration related to the LOF. The commenter stated that a proposal to expand aquaculture operations to old oil platforms in the Gulf of Mexico may cause interactions with bottlenose dolphins if the operation uses high intensity acoustic harassment devices. The commenter noted that the finfish or shellfish aquaculture fisheries currently listed on the LOF would not include this new operation.

Response: NMFS is aware of the expansion of aquaculture and growing concerns with aquaculture operations particularly as they relate to harassment of marine mammals. On January 12-13, 1999, NMFS held a marine aquaculture workshop to evaluate the potential effects of aquaculture operations on marine mammals and sea turtles. NMFS is considering additional workshops to further evaluate these operations for cases involving serious injuries and mortalities of marine mammals. NMFS believes the fishery classification criteria sufficiently address fishery-related interactions with aquaculture operations. NMFS is not aware of any proposals for the use of oil platforms as aquaculture facilities. The current marine aquaculture fisheries listed on the LOF, “Finfish aquaculture” and “Shellfish aquaculture,” apply to all aquaculture operations conducted in the Atlantic Ocean, Gulf of Mexico, and Caribbean.

The following summarizes changes to the LOF in 2004 in fishery classification, fisheries listed on the LOF, the number of participants in a particular fishery, and the species and/or stocks that are incidentally killed or seriously injured in a particular fishery. The LOF for 2004 is identical to the LOF for 2003 with the following exceptions.

The “Hawaii Swordfish, Tuna, Billfish, Mahi Mahi, Wahoo, Oceanic Sharks Longline/Set Line Fishery” is elevated from Category III to Category I.

The following fisheries are added to the LOF as Category III fisheries:

“AK Bering Sea and Aleutian Islands Atka Mackerel Trawl Fishery,” “AK Bering Sea and Aleutian Islands Flatfish Trawl Fishery,” “AK Bering Sea and Aleutian Islands Pacific Cod Trawl Fishery,” “AK Bering Sea and Aleutian Islands Pollock Trawl Fishery”, “AK Gulf of Alaska Flatfish Trawl Fishery,” “AK Gulf of Alaska Pacific Cod Trawl Fishery,” “AK Gulf of Alaska Pollock Trawl Fishery,” “AK Gulf of Alaska Rockfish Trawl Fishery,” “AK Aleutian Islands Sablefish Pot Fishery,” “AK Bering Sea Sablefish Pot Fishery,” “AK Bering Sea and Aleutian Islands Pacific Cod Pot Fishery,” “AK Gulf of Alaska Pacific Cod Pot Fishery,” “AK Southeast Alaska Shrimp Pot Fishery,” “AK Southeast Alaska Crab Pot Fishery,” “AK Gulf of Alaska Crab Pot Fishery,” “AK Bering Sea and Aleutian Islands Crab Pot Fishery,” “AK Bering Sea and Aleutian Islands Greenland Turbot Longline Fishery,” “AK Bering Sea and Aleutian Islands Pacific Cod Longline Fishery,” “AK Bering Sea and Aleutian Islands Rockfish Longline,” “AK Bering Sea and Aleutian Islands Sablefish Longline Fishery,” “AK Gulf of Alaska Sablefish Longline Fishery,” “AK Gulf of Alaska Pacific Cod Longline Fishery,” “AK Gulf of Alaska Flatfish Longline Fishery,” and “AK Gulf of Alaska Rockfish Longline.”

The following fisheries are removed from the 2004 LOF: The “AK Bering Sea and Gulf of Alaska Finfish Pot Fishery,” “AK Crustacean Pot Fishery,” “AK Bering Sea and Aleutian Islands Groundfish Longline/Set Line Fishery (federally regulated waters, including miscellaneous finfish and sablefish),” “AK Gulf of Alaska Groundfish Longline/Set Line Fishery (federally regulated waters, including miscellaneous finfish and sablefish),” “AK Bering Sea and Aleutian Islands Groundfish Trawl Fishery,” and “AK Gulf of Alaska Groundfish Trawl Fishery.”

The estimated number of participants in the “OR Swordfish Floating Longline Fishery” is updated to 1.

The estimated number of participants in the “WA Puget Sound Region Salmon Drift Gillnet Fishery” is updated to 210 based on 2003 permit data.

The following two tables list U.S. commercial fisheries according to their assigned categories under section 118 of the MMPA. The estimated number of vessels/participants is expressed in terms of the number of active participants in the fishery, when possible. If this information is not available, the estimated number of vessels or persons licensed for a particular fishery is provided. If no recent information is available on the number of participants in a fishery, the number from the most recent LOF is used.

The tables also list the marine mammal species or stocks incidentally killed or injured in each fishery based on observer data, logbook data, stranding reports, and fisher reports. This list includes all species or stocks known to experience serious injury or mortality in a given fishery, but also includes species or stocks for which there are anecdotal or historical, but not necessarily current, records of interaction. Additionally, species identified by logbook entries may not be verified. Not all species or stocks identified are the reason for a fishery's placement in a given category. There are a few fisheries that are in Category II that have no recently documented interactions with marine mammals. Justifications for placement of these fisheries are by analogy to other gear types that are known to cause mortality or serious injury of marine mammals, as discussed in the final LOF for 1996 (60 FR 67063, December 28, 1995), and according to factors listed in the definition of “Category II fishery” in 50 CFR 229.2.

Table 1 lists commercial fisheries in the Pacific Ocean (including Alaska); Table 2 lists commercial fisheries in the Atlantic Ocean, Gulf of Mexico, and Caribbean.

The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration that this rule will not have a significant economic impact on a substantial number of small entities. The factual basis for the certification appears elsewhere in the preamble to this rule and is not repeated here. As a result, no regulatory flexibility analysis was prepared. One comment was received regarding compliance with the RFA (Comment 23) and is responded to above. That comment did not cause a change in the certification previously made.

This final rule contains collection-of-information requirements subject to the Paperwork Reduction Act. The collection of information for the registration of fishers under the MMPA has been approved by the Office of Management and Budget (OMB) under OMB control number 0648-0293 (0.25 hours per report for new registrants and 0.15 hours per report for renewals). The requirement for reporting marine mammal injuries or moralities has been approved by OMB under OMB control number 0648-0292 (0.15 hours per report). These estimates include the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding these reporting burden estimates or any other aspect of the collection of information, including suggestions for reducing burden, to NMFS and OMB (see ADDRESSES ).

Notwithstanding any other provision of law, no person is required to respond to nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a currently valid OMB control number.

This final rule has been determined to be not significant for the purposes of Executive Order 12866.

An environmental assessment (EA) was prepared under the National Environmental Policy Act (NEPA) for regulations to implement section 118 of the MMPA (1995 EA). The 1995 EA concluded that implementation of those regulations would not have a significant impact on the human environment. This final rule would not make any significant change in the management of reclassified fisheries, and therefore, this final rule is not expected to change the analysis or conclusion of the 1995 EA. If NMFS takes a management action, for example, through the development of a Take Reduction Plan (TRP), NMFS will first prepare an environmental document as required under NEPA specific to that action.

This final rule will not affect species listed as threatened or endangered under the Endangered Species Act (ESA) or their associated critical habitat. The impacts of numerous fisheries have been analyzed in various biological opinions, and this final rule will not affect the conclusions of those opinions. The classification of fisheries on the LOF is not considered to be a management action that would adversely affect threatened or endangered species. If NMFS takes a management action, for example, through the development of a TRP, NMFS would conduct consultation under section 7 of the ESA for that action.

This final rule will have no adverse impacts on marine mammals and may have a positive impact on marine mammals by improving knowledge of marine mammals and the fisheries interacting with marine mammals through information collected from observer programs or take reduction teams.

This final rule will not affect the land or water uses or natural resources of the coastal zone, as specified under section 307 of the Coastal Zone Management Act.