The FAA invites comments on this proposed rule. You may submit whatever written data, views, or arguments you choose. You need to include the rule's docket number and submit your comments to the address specified under the caption ADDRESSES . We will consider all comments received on or before the closing date. We may amend this proposed rule in light of comments received. Factual information that supports your ideas and suggestions is extremely helpful in evaluating the effectiveness of this proposed AD action and determining whether we need to take additional rulemaking action.

The FAA specifically invites comments on the overall regulatory, economic, environmental, and energy aspects of this proposed rule that might suggest a need to modify the rule. You may view all comments we receive before and after the closing date of the rule in the Rules Docket. We will file a report in the Rules Docket that summarizes each contact we have with the public that concerns the substantive parts of this proposed AD.

If you want FAA to acknowledge the receipt of your mailed comments, you must include a self-addressed, stamped postcard. On the postcard, write “Comments to Docket No. 2000-CE-17-AD.” We will date stamp and mail the postcard back to you.

The Civil Aviation Authority (CAA), which is the airworthiness authority for the United Kingdom, recently notified FAA that an unsafe condition may exist on all Shorts Models SC-7 Series 2 and SC-7 Series 3 airplanes. The CAA reports that the Model SC-7 airframe has undergone structural evaluations that have resulted in the establishment of an airplane service life limit.

Modifications, inspections, and replacements of certain life limited items have been identified to further extend the life of the aircraft.

The life limits, if not complied with, could result in failure of the primary structural components and possibly result in structural failure during flight.

Shorts has issued the following service information:

Service information specifies procedures to be followed to allow life limits to be extended. They include:

The CAA classified this service bulletin as mandatory and issued British AD Number 019-09-81, not dated, in order to ensure the continued airworthiness of these airplanes in the United Kingdom.

These airplane models are manufactured in the United Kingdom and are type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, the CAA has kept FAA informed of the situation described above.

The FAA has examined the findings of the CAA; reviewed all available information, including the service information referenced above; and determined that:

This proposed AD would require you to incorporate the actions in the previously-referenced service bulletins.

We estimate that this proposed AD affects 22 airplanes in the U.S. registry.

The impact of this proposed AD would be not being able to operate the airplane past the established service life limit. The following paragraphs present cost if you choose to extend the life limit.

We estimate the following costs to accomplish the proposed aircraft life extension prescribed in Shorts Service Bulletin No. 51-51 on 19 aircraft:

We estimate the following to accomplish the proposed aircraft life extension prescribed in Shorts Service Bulletin No. 51-52 for the 6 aircraft serial numbers 1845, 1847, 1883, 1889, 1943, and 1960:

Three of these 6 airplanes will also incorporate Shorts Service Bulletin No. 51-51 and are part of the 19 airplanes subset of the total set of 22 airplanes in the U.S. registry.

The compliance time of this proposed AD is upon accumulating the applicable life limit or within the next 90 days after the effective date of this AD, whichever occurs later.

Why Is the Compliance Time of This Proposed AD Presented in Flights, Hours TIS and Calendar Time?

The unsafe condition on these airplanes is a result of the combination of the number of times the airplane is operated and how the airplane is operated (for example, weight carried). Airplane operation varies among operators. For example, one operator may operate the airplane 100 flights or 50 hours TIS in 3 months and carrying low weights while it may take another operator 12 months or more to accumulate 100 flights or 50 hours TIS while carrying heavy weights. For this reason, we have determined that the compliance time of this proposed AD should be specified in flights, hours time-in-service (TIS), and calendar time in order to assure this condition is not allowed to go uncorrected over time.

The regulations proposed herein would 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 proposed rule would not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this proposed 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) if promulgated, 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 copy of the draft regulatory evaluation prepared for this action has been placed in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption ADDRESSES .

Accordingly, under the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:

The FAA invites comments on this proposed rule. You may submit whatever written data, views, or arguments you choose. You need to include the rule's docket number and submit your comments to the address specified under the caption ADDRESSES . We will consider all comments received on or before the closing date. We may amend this proposed rule in light of comments received. Factual information that supports your ideas and suggestions is extremely helpful in evaluating the effectiveness of this proposed AD action and determining whether we need to take additional rulemaking action.

The FAA specifically invites comments on the overall regulatory, economic, environmental, and energy aspects of this proposed rule that might suggest a need to modify the rule. You may view all comments we receive before and after the closing date of the rule in the Rules Docket. We will file a report in the Rules Docket that summarizes each contact we have with the public that concerns the substantive parts of this proposed AD.

If you want FAA to acknowledge the receipt of your comments, you must include a self-addressed, stamped postcard. On the postcard, write “Comments to Docket No. 2002-CE-46-AD.” We will date stamp and mail the postcard back to you.

The Ente Nazionale per l' Aviazione Civile (ENAC), which is the airworthiness authority for Italy, recently notified FAA that an unsafe condition may exist on all PIAGGIO Model P-180 airplanes. The ENAC reports an incident of a ground fire on the left-hand engine nacelle of one of the affected airplanes. Investigation revealed that the fire was caused by a cracked crossfeed valve that had leaked fuel.

Further analysis led the ENAC to determine that the part number (P/N) EM484-3 valve was part of a manufacturing batch of nonconforming valves. This batch incorporates serial numbers 148 through 302 of these P/N EM484-3 valves. These valves can be utilized as either firewall shutoff or crossfeed valves.

If these valves are not removed from service, they could develop cracks and leak fuel. This could result in an engine fire.

PIAGGIO Aero Industries has issued:

The ENAC classified these service bulletins as mandatory and issued Italian RAI-AD 2002-442, dated February 21, 2002, in order to ensure the continued airworthiness of these airplanes in Italy.

This airplane model is manufactured in Italy and is type certificated for operation in the United States under the provisions of section 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement.

Pursuant to this bilateral airworthiness agreement, the ENAC has kept FAA informed of the situation described above.

The FAA has examined the findings of the ENAC; reviewed all available information, including the service information referenced above; and determined that:

This proposed AD would require you inspect and determine whether any firewall shutoff or crossfeed valve with a serial number in a certain range is installed and would require you to replace any valve that has a serial number within this range. The proposed AD would allow the pilot to check the logbook and would not require additional action if the check showed that one of these valves was definitely not installed.

The inspection compliance time of this AD is “within the next 30 days after the effective date of the AD.”

The compliance of this AD is presented in calendar time instead of hours TIS because the affected shutoff and crossfeed valves are unsafe as a result of a quality control problem. The problem has the same chance of existing on an airplane with 50 hours TIS as it would for an airplane with 1,000 hours TIS. Therefore, we believe that a compliance time of 30 days will:

We estimate that this proposed AD affects 22 airplanes in the U.S. registry.

We estimate the following costs to accomplish the proposed inspection:

We estimate the following costs to accomplish the proposed replacement/modification:

The regulations proposed herein would 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 proposed rule would not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this proposed 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) if promulgated, 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 copy of the draft regulatory evaluation prepared for this action has been placed in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption ADDRESSES .

Accordingly, under the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:

Federal Register document 02-21576 published on Friday, August 23, 2002 (67 FR 54599) proposed to establish Class E2 and Class E4 airspace and to modify Class E5 airspace at Ainsworth, NE. It has been determined that Class E4 airspace is only applicable when in conjunction with Class D airspace. There is no Class D airspace at Ainsworth, NE. The proposed Class E2 airspace must be redefined to include the proposed Class E4 airspace. The only change from the original Notice of Proposed Rulemaking is the title of the airspace involved.

Accordingly, pursuant to the authority delegated to me, the proposed Class E4 airspace is rescinded and the Class E2 airspace at Ainsworth, NE, as published in the Federal Register Friday, August 23, 2002 (67 FR 54599), (FR Doc. 02-21576), is corrected as follows:

Section 1a(5) of the Commodity Exchange Act (Act) defines the term “commodity pool operator” to mean—

We are proposing new Regulation G. 1

We also are proposing amendments to Item 10 of Regulation S-K, 2 Item 10 of Regulation S-B, 3 and Securities Exchange Act of 1934 4 Forms 8-K  5 and 20-F. 6

On July 30, 2002, President Bush signed into law the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley Act”). 7 Among its many goals, the Sarbanes-Oxley Act seeks to enhance the financial disclosures of public companies. As part of this effort to enhance disclosure to investors, Congress and the President recognized the immediate need to address issues relating to public companies' use of so-called “ pro forma financial information.”

Like Congress, the Commission also has been concerned with the use of “pro forma financial information.” In 1973, the Commission issued Accounting Series Release No. 142, warning of possible investor confusion from the use of financial measures outside of GAAP:

More recently, in December 2001, we issued cautionary advice regarding the use of “pro forma financial information” in earnings releases:

Additionally, earlier this year, we brought an enforcement action against Trump Hotels & Casino Resorts, Inc., where we found the use of pro forma financial information to be materially misleading. 10

Like the Commission, Congress also was specifically concerned with pro forma results that are prepared or derived on a basis other than GAAP when it included Section 401(b) in the Sarbanes-Oxley Act. Because the Commission's rules and regulations address the use of “pro forma financial information” in other contexts, particularly in Regulation S-X, 11 and use that term differently from its use in the Sarbanes-Oxley Act, 12 we are adopting the term “non-GAAP financial measures” to identify the types of information targeted by Section 401(b) of the Sarbanes-Oxley Act. The Sarbanes-Oxley Act sought to eliminate the manipulative or misleading use of non-GAAP financial measures and, at the same time, enhance the comparability associated with the use of that information. As the Senate Committee on Banking, Housing, and Urban Affairs noted in their Committee Report:

Accordingly, Section 401(b) of the Sarbanes-Oxley Act directs the Commission to adopt rules requiring that any public disclosure or release of non-GAAP financial measures by a company filing reports under Section 13(a)  14 or 15(d)  15 of the Exchange Act be presented in a manner that:

• Does not contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the non-GAAP financial measure, in light of the circumstances under which it is presented, not misleading; and

• Reconciles the non-GAAP financial measure presented with the financial condition and results of operations of the registrant under GAAP.

As used in this release, a “non-GAAP financial measure” is a numerical measure of an issuer's historical or future financial performance, financial position or cash flows that:

• Excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the statement of income, balance sheet or statement of cash flows (or equivalent statements) of the issuer; or

• Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure so calculated and presented.

In their efforts to enhance financial disclosure, Congress and the President recognized the importance of timely information to investors and our markets. Section 409 of the Sarbanes-Oxley Act added to the Exchange Act new Section 13(l), which obligates public companies to “disclose to the public on a rapid and current basis such additional information concerning material changes in the financial condition or operations of the issuer, in plain English, which may include trend and qualitative information and graphic presentations, as the Commission determines, by rule, is necessary or useful for the protection of investors and in the public interest.” 16 Before the adoption of the Sarbanes-Oxley Act, we had taken important steps in this regard by proposing accelerated deadlines by which companies would be required to disclose significantly expanded categories of material information. 17 Comments regarding our proposed accelerated deadlines for periodic reports of registrants, while not fully supporting that proposal, recognized the need for more current information. 18 In fact, the comments of the American Bar Association's Subcommittee on Disclosure and Continuous Reporting of the Committee on Federal Regulation of Securities, Section of Business Law, proposed alternatively that we require companies to file their earnings reports on Form 8-K. The ABA Subcommittee expressed the view that such a requirement:

• Would enhance the attention and level of care companies bring to those disclosures because companies would be aware that the disclosures will become part of the formal reporting system; and

• Would bring those disclosures into the formal disclosure system where they would be available electronically on a widespread basis. 19

Today, to implement the Sarbanes-Oxley Act's directives regarding the use of non-GAAP financial measures and further the statutory objective of increased real-time issuer disclosures, we are proposing new Regulation G, amendments to Item 10 of Regulation S-K, amendments to Item 10 of Regulation S-B and amendments to Exchange Act Forms 8-K and 20-F.

We intend the proposed rules and amendments to implement the requirements of the Sarbanes-Oxley Act, improve the transparency and quality of disclosure of non-GAAP financial measures and related information and enhance the current reporting of earnings information. We are taking a two-part approach to the disclosure of non-GAAP financial measures. First, we are proposing new Regulation G, which would apply whenever a company publicly discloses or releases material information that includes a non-GAAP financial measure. While Section 401(b) of the Sarbanes-Oxley Act refers to any communication of “ pro forma financial information,” we believe that proposing to make Regulation G applicable to public disclosures of material information containing or accompanied by non-GAAP financial measures delineates appropriately the scope of the rules required by Section 401(b). This regulation would impose specific requirements in connection with the public communication of non-GAAP financial measures and, without affecting the existing antifraud regime, would prohibit material misstatements or omissions that would make the presentation of the material non-GAAP financial measure, under the circumstances in which it is made, misleading. Regulation G provides a limited exception for foreign private issuers based on what we believe to be an appropriate territorial approach. This limited exception applies the principles of territoriality based on where the disclosure is initially made and is similar to that provided by Rule 135e  20 under the Securities Act of 1933 21 for offshore press and related activities.

Second, pursuant to the Sarbanes-Oxley Act and our existing authority under the Securities Act and Exchange Act, we are proposing to amend Item 10 of Regulation S-K and Item 10 of Regulation S-B to address specifically the use of non-GAAP financial measures in filings with the Commission. 22 These proposed amendments would apply to the same categories of non-GAAP financial measures as are covered by proposed Regulation G, but contain somewhat more detailed requirements than proposed Regulation G. 23

In addition to these proposals, in order to bring earnings information within our current reporting system, we are proposing an amendment to Form 8-K that would require the filing with the Commission of releases or announcements disclosing material non-public financial information about completed annual or quarterly fiscal periods. Our proposal would not require the issuance of earnings releases or similar announcements. However, such releases and announcements would trigger the new proposed filing requirement. The proposed filing requirement would apply regardless of whether the release or announcement included disclosure of a non-GAAP financial measure. Public disclosure of financial information for a completed fiscal period in a presentation that is made orally, telephonically, by webcast, broadcast or similar means would not be required to be filed, if the presentation:

• Occurs within 48 hours of a related release or announcement that is filed under proposed Item 1.04 of Form 8-K; and

• Is accessible to the public.

Proposed Regulation G would apply to any entity that is required to file reports pursuant to Sections 13(a) or 15(d) of the Exchange Act, other than a registered investment company. 24 Regulation G would apply whenever such a registrant, or a person acting on its behalf, discloses or releases publicly any material information that includes a non-GAAP financial measure. Regulation G would require the registrant to provide the following information as part of the disclosure or release of the non-GAAP financial measure:

• A presentation of the most comparable financial measure calculated and presented in accordance with GAAP;  25 and

• A reconciliation (by schedule or other clearly understandable method), which shall be quantitative for historic measures and quantitative, to the extent available without unreasonable efforts, for prospective measures, of the differences between the non-GAAP financial measure presented and the comparable financial measure or measures calculated and presented in accordance with GAAP.

If a non-GAAP financial measure is released orally, telephonically, in a webcast or broadcast or by similar means, proposed Regulation G would permit a registrant to provide the required accompanying information by posting it on the registrant's website. The registrant would be required to disclose the location and availability of the required accompanying information during its presentation.

With regard to the quantitative reconciliation of non-GAAP financial measures that are forward-looking, a schedule or other presentation detailing the differences between the forward-looking non-GAAP financial measure and the appropriate forward-looking GAAP financial measure would be required. If the GAAP financial measure is not accessible on a forward-looking basis, the registrant must disclose that fact, explain why it is not accessible on a forward-looking basis and provide any reconciling information that is available without an unreasonable effort. Furthermore, the registrant must identify any information that is unavailable and disclose its probable significance.

Proposed Regulation G also provides that a non-GAAP financial measure, taken together with the accompanying information, may not misstate a material fact or omit to state a material fact necessary to make the presentation of the non-GAAP financial measure not misleading, in light of the circumstances under which it is presented. 26

For purposes of Regulation G, a non-GAAP financial measure would be a numerical measure of a registrant's historical or future financial performance, financial position or cash flows that:

• Excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the statement of income, balance sheet or statement of cash flows (or equivalent statements) of the issuer; or

• Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure so calculated and presented.

In this regard, “GAAP” refers to generally accepted accounting principles in the United States, except that in the case of foreign private issuers whose primary financial statements are prepared in accordance with other generally accepted accounting principles, references to GAAP also include the principles under which those primary financial statements are prepared. We do not intend today's proposals to capture measures of operating performance or financial measures that fall outside the scope of the definition set forth above.

Non-GAAP financial measures would not include:

• Operating and other statistical measures (such as unit sales, numbers of employees, numbers of subscribers, or numbers of advertisers); and

• Ratios or measures that are calculated using only:

• Financial measures calculated in accordance with GAAP; and

• Operating measures or other measures that are not non-GAAP financial measures.

Non-GAAP financial measures would not include financial information that does not have the effect of providing numerical measures that are different from the comparable GAAP measure. Examples of measures to which Regulation G would not apply would include the following:

• Disclosure of amounts of expected indebtedness, including contracted and anticipated amounts;

• Disclosures or amounts of repayments that have been planned or decided upon but not yet made;

• Disclosures of estimated revenues or expenses of a new product line, so long as such amounts were estimated as GAAP figures; and

• Measures of profit or loss and total assets for each segment required to be disclosed in accordance with GAAP. 27

We do intend that the definition of non-GAAP financial measure capture all measures that have the effect of depicting either:

• A measure of performance that is different from that presented in the financial statements, such as income or loss before taxes, or net income or loss as calculated in accordance with GAAP; or

• A measure of liquidity that is different from cash flow or cash flow from operations computed in accordance with GAAP.

An example of a non-GAAP financial measure would be a measure of operating income that excludes one or more expense or revenue items that are identified as “non-recurring.” Another example would be EBITDA (earnings before interest, taxes, depreciation and amortization), which could be calculated using elements derived from GAAP financial presentations but, in any event, is not presented in accordance with GAAP. Examples of ratios and measures that would not be non-GAAP financial measures would include sales per square foot (assuming that the sales figure was calculated in accordance with GAAP) or same store sales (again assuming the sales figures for the stores were calculated in accordance with GAAP). An example of a ratio that would be a non-GAAP financial measure would be a measure of operating margin where either the revenue component or the operating income component of the calculation, or both, were not calculated in accordance with GAAP.

The proposed regulation would apply to registrants that are foreign private issuers, 28 subject to a limited exception. Specifically, Regulation G would not apply to public disclosure of a non-GAAP financial measure by or on behalf of a registrant that is a foreign private issuer if the following conditions were satisfied:

• The securities of the issuer are listed or quoted on a securities exchange or inter-dealer quotation system outside the United States;

• The non-GAAP financial measure and the most comparable GAAP financial measure are not calculated and presented in accordance with generally accepted accounting principles in the United States; and

• The disclosure is made by or on behalf of the registrant outside the United States, or is included in a written communication that is released by or on behalf of the registrant only outside the United States.

We believe that these conditions, by focusing on whether the financial measure relates to U.S. GAAP and on the territorial principle of where the disclosure is made by or on behalf of the foreign private issuer, appropriately balance the interests of U.S. investors, including those interests as provided by the Sarbanes-Oxley Act, with the interests of foreign private issuers in communicating in their home markets. The Commission has not historically applied specific disclosure requirements to communications by foreign private issuers other than in their annual reports on Form 20-F. We believe that it is appropriate to take the Sarbanes-Oxley Act as a direction to apply Regulation G to foreign private issuers, subject to the exception we have proposed.

In addition, we believe that the worldwide availability of information properly disclosed outside the United States and the interests of U.S. investors in information communicated by or on behalf of the issuer outside the United States dictate that the exception for foreign private issuers should continue to apply where:

• Foreign or U.S. journalists or other third parties have access to the information, so long as the information is disclosed or released by or on behalf of the registrant only outside the United States;

• Following its release or disclosure, the information appears on one or more web sites maintained by the registrant, so long as the web sites, taken together, are not available exclusively to, or targeted at, persons located in the United States; and/or

• Following the disclosure or release of the information outside the United States, the information is included in a submission to the Commission made under cover of a Form 6-K. 29

Indeed, regulators worldwide have been addressing this issue within their own jurisdictions. In May 2002, the Technical Committee of the International Organization of Securities Commissions (IOSCO) published a Cautionary Statement Regarding Non-GAAP Results Measures that urged issuers, investors and other users of financial information to use care when presenting and interpreting such information. 30 This IOSCO Cautionary Statement notes the universal concerns that regulators have about the potential misuse of non-GAAP earnings measures and provides examples of statements of cautionary advice regarding the appropriate use of non-GAAP information that have been issued in various countries.

Proposed Regulation G would be a disclosure provision applicable to entities that are required to file reports under Section 13(a) or Section 15(d) of the Exchange Act, other than registered investment companies. 31 Proposed Rule 102 of Regulation G  32 expressly provides that nothing in Regulation G shall affect any person's liability under Exchange Act Section 10(b) 33 or Rule 10b-5 thereunder. 34 Proposed Rule 102 also states that a person's compliance or non-compliance with the requirements of Regulation G would not affect that person's liability under Section 10(b) or Rule 10b-5. The facts and circumstances surrounding a violation of Regulation G, however, may give rise to a Rule 10b-5 violation if all the elements for such a violation are present. In this regard, we reminded companies in December 2001 that, under certain circumstances, non-GAAP financial measures could mislead investors if they obscure the company's GAAP results. 35 We continue to be of the view that some disclosures of non-GAAP financial measures could give rise to actions under Rule 10b-5. 36

Section 3(b) of the Sarbanes-Oxley Act provides that a violation of that Act or the Commission's rules thereunder shall be treated for all purposes as a violation of the Exchange Act. Therefore, if an issuer, or any person acting on its behalf, fails to comply with Regulation G, the issuer and/or the person acting on its behalf could be subject to a Commission enforcement action alleging violations of Regulation G. Additionally, if the facts and circumstances warrant, we could bring an action under both Regulation G and Rule 10b-5.

• As proposed, Regulation G would apply only to companies that are required to file reports pursuant to Section 13(a) or 15(d) of the Exchange Act. Should we expand the scope of the regulation to apply to all companies that publicly disclose non-GAAP financial measures, excluding registered investment companies?

• As an alternative to requiring reconciliation to the most directly comparable financial measure calculated and presented in accordance with GAAP, should we require reconciliation to specific GAAP financial measures in all cases, such as net income and cash flow from operating activities? If yes, to which GAAP financial measures should we require reconciliation?

• Should the presentation of certain non-GAAP financial measures require the presentation of a reconciled (full or summary) consolidated balance sheet, income statement and cash flow statement? If so, which non-GAAP financial measure(s) should trigger this requirement?

• Should the requirement of a quantitative reconciliation include an exception for prospective measures where the necessary information cannot be obtained without unreasonable effort?

• Should we limit the definition of non-GAAP financial measures to historical financial measures?

• Does the proposed definition of “non-GAAP financial measure” capture non-GAAP information where enhanced disclosure is appropriate? Does the proposed definition capture the pro forma financial information that the Sarbanes-Oxley Act targets? Should Regulation G apply to disclosures of material information including any financial measure calculated and presented otherwise than in accordance with GAAP? Is the proposed definition otherwise too narrow or too broad? If so, how should it be changed?

• Should we exclude non-GAAP financial measures communicated orally from the proposed regulation? Would such an exclusion be consistent with the terms of the Sarbanes-Oxley Act?

• Is there a danger that investors would consider the reconciliation to have been audited or reviewed by the issuer's independent auditors? Should Regulation G require companies to disclose whether the reconciliation has been reviewed or audited by their independent accountants in order to avoid investor confusion?

• In this release, we propose to require companies that include non-GAAP financial measures in filings to also include a discussion of the purposes for which the company's management uses the non-GAAP financial measure and why management believes the presentation of the non-GAAP financial measure provides useful information to investors. 37 Should we require that information in all communications that are subject to Regulation G? If so, why? If not, why not?

• Should we allow registrants greater latitude to satisfy the requirements of proposed Regulation G by posting the non-GAAP financial measure's components and the comparative GAAP financial measure on their website or in their Commission filings?

• As proposed below, and consistent with staff practice, the Commission generally has more detailed disclosure requirements where non-GAAP financial measures are included in Commission filings. Should we require these additional disclosure requirements in all cases, even in documents not filed with the Commission?

• Should we prohibit the presentation, whether or not included in filings with the Commission, of certain non-GAAP financial measures (for example, certain per-share measures or liquidity measures that exclude cash items)? If so, which measures?

• Will proposed Regulation G limit the use of non-GAAP financial measures? Please explain.

• Is the limited exception from Regulation G for foreign private issuers appropriate in furtherance of the purposes of the Sarbanes-Oxley Act? Should the exception be broader or more limited? If so, how?

• Does the limited exception from Regulation G for foreign private issuers deprive U.S. investors of material information? Alternatively, would eliminating the limited exception for foreign private issuers deprive U.S. investors of non-GAAP financial measures? Furthermore, would eliminating the limited exception from Regulation G for foreign private issuers result in foreign private issuers de-registering and exiting the U.S. capital markets?

• Proposed Regulation G would apply to disclosures of non-GAAP financial measures that represent projections or forecasts of results of business combination transactions (“post-transaction measures”) and that are filed with the Commission as information pursuant to the communications rules applicable to business combination transactions, 38 as well as non-GAAP financial measures of each registrant that are used to calculate post-transaction measures. Should there be an exception from certain requirements of Regulation G for post-transaction measures or other measures filed as information under the business combination rules? Should such measures be treated differently under Regulation G? If so, how? Business combination communications often include brief statements regarding the potential benefits to be achieved by the business combination ( e.g. , synergies, valuations, dividend amounts, etc.). Either instead of or in addition to the requirements of proposed Regulation G, should the rules specifically require the disclosure of any assumptions or bases underlying these measures?

• Should Regulation G be enforceable by the Commission only or also by private plaintiffs? Should language be included in Regulation G that makes explicit the manner in which it is to be enforced?

• Will proposed Regulation G meet the goals of Section 401(b) of the Sarbanes-Oxley Act? Does proposed Regulation G meet those goals in the most appropriate manner? Is there a way to achieve those goals that is less burdensome than that in proposed Regulation G? If so, what is it?

We are proposing to amend Item 10 of Regulation S-K and Item 10 of Regulation S-B to add a statement concerning the use of non-GAAP financial measures in filings made with the Commission. 39 In addition, we are proposing to amend Exchange Act Form 20-F to incorporate Item 10 of Regulation S-K (as proposed to be amended). The proposed amendments to Item 10 of Regulation S-K and Item 10 of Regulation S-B would make clear that registrants using non-GAAP financial measures in filings with the Commission would have to provide:

• A presentation, with equal or greater prominence, of the most directly comparable financial measure calculated and presented in accordance with GAAP;

• A quantitative reconciliation (by schedule or other clearly understandable method) of the differences between the non-GAAP financial measure disclosed with the most directly comparable measure or measures calculated and presented in accordance with GAAP;

• A statement disclosing the purposes for which the registrant's management uses the non-GAAP financial measure presented; and

• A statement describing the reasons why the registrant's management believes such non-GAAP financial measures provide useful information to investors.

In addition to these mandated disclosure requirements, we propose to amend Item 10 of Regulation S-K and Item 10 of Regulation S-B to prohibit the following:

• Presenting a non-GAAP financial measure in a manner that would give it greater authority or prominence than the comparable GAAP financial measure or measures;

• Excluding charges or liabilities that required, or will require, cash settlement, or would have required cash settlement absent an ability to settle in another manner, from non-GAAP liquidity measures;

• Adjusting a non-GAAP performance measure to eliminate or smooth items identified as non-recurring, infrequent or unusual, when the nature of the charge or gain is such that it is reasonably likely to recur;

• Presenting non-GAAP financial measures on the face of the registrant's financial statements prepared in accordance with GAAP or in the accompanying notes;

• Presenting non-GAAP financial measures on the face of any pro forma financial information required to be disclosed by Article 11 of Regulation S-X;

• Using titles or descriptions of non-GAAP financial measures that are the same as, or confusingly similar to, titles or descriptions used for GAAP financial measures; and

• Presenting a non-GAAP per-share measure.

The requirement of Regulation G that the presentation of a non-GAAP financial measure, taken together with the information accompanying the measure and any other accompanying discussion, not contain a material misstatement or material omission necessary in order to make the presentation not misleading, in light of the circumstances in which the presentation is made, would also apply to disclosures in documents filed with the Commission.

The requirements for filed information are proposed to be more extensive and detailed than those of proposed Regulation G. The additional requirements would be generally consistent with the staff's historical practice in situations where it has reviewed filings containing non-GAAP financial measures. In addition, the requirements for a GAAP presentation and for a reconciliation would be slightly more stringent than those set forth under Regulation G. In particular, in filings with the Commission, the presentation of the comparable GAAP financial measure must have equal or greater prominence, and there would not be an “unreasonable effort” exception for forward-looking information to the requirement for a quantitative reconciliation between the non-GAAP financial measure and the comparable GAAP financial measure. Additionally, any non-GAAP financial measure presented must be accompanied by statements disclosing the purposes for which the registrant's management uses the non-GAAP financial measure and why the registrant believes the non-GAAP financial measure would be useful to investors. This requirement is designed to ensure that companies are using non-GAAP financial measures that provide information that is important in analyzing and understanding the registrant. We believe that these more stringent requirements are appropriate for filings with the Commission.

The requirements that a statement regarding the purposes for which management uses the non-GAAP financial measure and the utility of the non-GAAP financial measure to investors could be satisfied by including the statements in the most recent annual report filed with the Commission (or a more recent filing) and by updating those statements, as necessary, no later than the time of the filing. 40

The definition of “non-GAAP financial measure” would be the same for purposes of these proposals as for Regulation G. Unlike under Regulation G, however, there is no limited exception for foreign private issuers and, therefore, the proposed requirements would apply to filings on Form 20-F. However, a non-GAAP financial measure that would otherwise be prohibited would be permitted in a Form 20-F filing of a foreign private issuer if the measure was expressly permitted under the generally accepted accounting principles used in the issuer's primary financial statements and was included in the issuer's annual report or financial statements used in its home country jurisdiction or market.

We are not proposing to subject filers on Form 40-F under the Multi-Jurisdictional Disclosure System (MJDS) to the proposed requirements because, under the philosophy of MJDS, which is currently applicable to certain Canadian issuers, the Canadian disclosure form requirements dictate required disclosure in filings with the Commission. Public disclosures in the United States by these issuers, including filings with the Commission on Form 40-F, would be subject to proposed Regulation G.

• Are the proposed additional disclosures required in filings necessary in light of proposed Regulation G?

• Consistent with current staff policy, our proposal would prohibit the use of non-GAAP per-share measures. Is such a prohibition necessary, or would it suffice to reconcile both the numerator and denominator of the non-GAAP per-share measure with comparable GAAP measures, respectively?

• Should the non-GAAP financial measures be presented in a separate section of a Commission filing?

• Should the requirements for filings and those required in Regulation G be different? For example, should the requirement that the GAAP measure in a filing be presented with equal or greater prominence be included in Regulation G or not included in Item 10 of Regulation S-K and Item 10 of Regulation S-B?

• Should the requirement that a quantitative reconciliation of prospective measures be included in the filing have an exception similar to that proposed in Regulation G where the necessary information cannot be obtained without unreasonable effort?

• Are there additional disclosures that should be required in filings? If so, what disclosure items would be beneficial to investors?

• Consistent with current staff policy, our proposals would prohibit specified types of disclosures. Is such a prohibition necessary and appropriate?

• Should the proposed requirements apply to foreign private issuers' reports on Form 20-F?

• Should the proposed requirements apply to filings by Canadian issuers under the MJDS on Form 40-F?

• As with Regulation G, in the case of business combinations, the proposed requirements would apply to “post-transaction measures” filed as information under the communication rules applicable to business combination transactions. 41 Is an exception from certain of the requirements for post-transaction measures or other measures filed as information under the business combination rules appropriate? Should such measures be treated differently? If so, how? Either instead of or in addition to the requirements of proposed Regulation G, should the rules specifically require the disclosure of assumptions or bases underlying announcements of potential benefits to be achieved by the business combination ( e.g. , synergies, valuations, dividend amounts, etc.)?

• If a company presents a non-GAAP measurement for a previous completed fiscal period, should it be required to present that same non-GAAP measurement in future filings where the previous period is compared to a recent completed fiscal period? For example, if a company presents a non-GAAP financial measurement that for the first fiscal quarter of 2002, should it be required to present the same non-GAAP measurement for the first fiscal quarter of 2003?

We propose to amend Form 8-K to add new Item 1.04 “Disclosure of Results of Operations and Financial Condition.” 42 New Item 1.04 would require registrants to file a Form 8-K within two business days of any public announcement or release disclosing material non-public information regarding a registrant's results of operations or financial condition for an annual or quarterly fiscal period that has ended.

Today, these types of announcements and releases are subject to Regulation FD. 43 Unlike disclosure made to satisfy Regulation FD, however, historical information filed under proposed Item 1.04 of Form 8-K always would be considered filed with the Commission for liability purposes. 44 Further, a Form 8-K filed pursuant to Item 1.04 would satisfy an issuer's obligation under Regulation FD only if the Form 8-K were filed within the time frame required by Regulation FD. Regulation FD could, of course, be satisfied by public disclosure other than through the filing of a Form 8-K meeting Regulation FD's requirements; in that case, a Form 8-K filed pursuant to Item 1.04 would be required to be filed within the two-business day timeframe.

Proposed Item 1.04 would require the registrant to identify briefly the announcement or release and file the announcement or release as an exhibit to the Form 8-K. Further, the requirements of proposed Item 10(e) of Regulation S-K or Item 10(h) of Regulation S-B would apply to a Form 8-K filed under proposed Item 1.04.

If non-public information is disclosed orally, telephonically, by webcast, broadcast, or similar means, Item 1.04 would not require the registrant to file a Form 8-K if:

• The disclosure initially occurs within 48 hours of a written release or announcement filed on Form 8-K pursuant to Item 1.04;

• The presentation is accessible to the public by dial-in conference call, webcast or similar technology;

• The financial and statistical information contained in the presentation is provided on the registrant's Web site, together with any information that would be required under proposed Regulation G; and

• The presentation was announced by a widely disseminated press release that included instructions as to when and how to access the presentation and the location on the registrant's Web site where the information would be available.

As noted above, our proposal would not require any registrant to issue an earnings release or similar announcement. However, if a registrant issues such a release or announcement containing material non-public information regarding the registrant's results of operations or financial condition for an annual or quarterly fiscal period that has ended, it would trigger the new proposed filing requirement.

The filing requirement under proposed Item 1.04 of Form 8-K would be triggered by the disclosure of material non-public information regarding a completed fiscal year or quarter. Repetition of previously publicly disclosed information or release of the same information in a different form, for example in an interim or annual report to shareholders, would not trigger the proposed Item 1.04 requirement. This result would not change if the repeated information were accompanied by information that was not material, whether or not already public. However, release of additional or updated material non-public information regarding the registrant's results of operation or financial condition for a completed fiscal year or quarter would trigger an additional Item 1.04 filing requirement. Issuers that make earnings announcements or other disclosures of material non-public information regarding a completed fiscal year or quarter in an interim or annual report to shareholders would be permitted to specify which portion of the report contains the information required to be filed under Item 1.04. In addition, the requirement to file under Item 1.04 of Form 8-K would not apply to issuers that make these announcements and disclosures only in their quarterly reports filed with the Commission on Form 10-Q  45 (or 10-QSB  46 ) or their annual reports filed with the Commission on Form 10-K  47 (or 10-KSB  48 ).

Proposed Item 1.04 of Form 8-K would apply only to publicly disclosed or released material non-public information concerning an annual or quarterly fiscal period that has ended. While such disclosure may also include forward-looking information, it is the material information about the completed fiscal period that triggers proposed Item 1.04. Accordingly, proposed Item 1.04 would not apply to public disclosure of earnings estimates for future or ongoing fiscal periods, unless those estimates are included in the public announcement or release of material non-public information regarding an annual or quarterly fiscal period that has ended. 49 In such a case, specifically identified forward-looking information could be furnished under Item 6.01  50 rather than filed under proposed Item 1.04. Information furnished under Item 6.01 should be included in the same Form 8-K that contains the historical material information filed pursuant to Item 1.04.

Information furnished under Item 6.01 would not be subject to Section 18  51 of the Exchange Act, nor would it be incorporated by reference into a registration statement, proxy statement or other report. The registrant would be required to identify the specific forward-looking statements it did not want to be considered filed. 52

• Is proposed Item 1.04 necessary given Regulation FD and proposed Regulation G?

• Should the Commission define “public disclosure” for purposes of proposed Item 1.04?

• Proposed Item 1.04 would apply only to disclosures regarding completed annual or quarterly fiscal periods. Should we expand the scope of proposed Item 1.04 to require the filing of all material updates to estimates for current or future fiscal periods?

• Will proposed Item 1.04 have the effect of decreasing the extent to which public companies make public announcements or releases of material non-public information regarding completed fiscal periods? If so, what are the specific factors that would result in that decrease? Why would those factors result in that decrease?

• Is the posting of the complementary information on a Web site sufficient disclosure or should a filing be required for this information as well?

• Regulation G requires that any information provided on a Web site be available at the time the original public communication is made. Is it necessary for Item 1.04 to contain the same timing requirement?

• Should we require forward-looking information to be considered filed for purposes of Section 18 of the Exchange Act? Should forward-looking information, where appropriate, be incorporated by reference into a registration statement, proxy statement or other report?

• Should the disclosure requirements of Item 10 of Regulation S-K and Item 10 of Regulation S-B apply to complementary information not filed with the Commission?

• Would the application of Item 1.04 only to disclosures regarding completed annual or quarterly periods cause public companies to increase their disclosure of intra-period information, rather than disclosure regarding completed periods, in an effort to avoid the requirements of Item 1.04?

We request and encourage any interested person to submit comments regarding:

• The proposed rule and amendments that are the subject of this release;

• Additional or different changes; or

• Other matters that may have an effect on the proposals contained in this release.

We request comment from the point of view of registrants, investors and other market participants. With regard to any comments, we note that such comments are of great assistance to our rulemaking initiative if accompanied by supporting data and analysis of the issues addressed in those comments.

Proposed Regulation G and related amendments to Regulations S-K, Form 8-K and Form 20-F contain “collections of information” requirements within the meaning of the Paperwork Reduction Act of 1995 (“PRA”), 53 and the Commission has submitted the proposals to the Office of Management and Budget (“OMB”) for review in accordance with 44 U.S.C. 3507(d) and 5 CFR 1320.11. The titles for the information collections are: Regulation G, Regulation S-K, Regulation S-B, Form 8-K and Form 20-F.

The Commission is proposing Regulation G pursuant to Section 401 of the Sarbanes-Oxley Act. Proposed Regulation G would require registrants when publicly disclosing material information that include non-GAAP financial measures to provide a reconciliation to comparable GAAP figures. Regulation G is intended to implement the requirements of the Sarbanes-Oxley Act. Specifically, Regulation G is intended to provide investors with balanced financial disclosure when non-GAAP financial measures are presented. Regulation G defines a non-GAAP financial measure as a numerical measure of an issuer's historical or future financial performance, financial position or cash flow that:

• Excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the statement of income, balance sheet or statement of cash flows (or equivalent statements) of the issuer; or

• Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure calculated and presented in accordance with GAAP.

Accordingly, by definition, a non-GAAP financial measure that triggers the application of Regulation G would have been derived from a GAAP measure. For example, generally, EBITDA is net income before interest, taxes, depreciation and amortization. In order for a company to present EBITDA it must already know the amount of net income. We expect the cost of obtaining the additional disclosure required by Regulation G to be minimal. Moreover, much of the disclosure mandated by Regulation G, such as the most directly comparable GAAP measure, is already required to be provided pursuant to other forms and regulations, such as Form 10-K, Form 10-Q and Regulation S-X. Therefore, most of the costs associated with collecting such information are already included in the burden hours associated with those forms and regulations. Thus, we have estimated for purposes of the PRA that it will take .5 burden hour for compliance with Regulation G. We anticipate that on average a company will have to comply with Regulation G roughly six times a year. Since there are approximately 14,000 public companies that would be subject to Regulation G we have estimated that there will be 84,000 disclosures made in accordance with Regulation G for a total of 42,000 burden hours. We would expect that an in house junior accountant would prepare the actual reconciliation.

Regulations S-K (OMB Control No. 3235-0071) and S-B (OMB Control No. 3235-0417) prescribe disclosure requirements that registrants must follow when filing registration statements, reports and schedule with the Commission. Our amendments to Item 10 of Regulation S-K and S-B incorporate the requirements of Regulation G and codify existing staff interpretations. Because the collection of information regarding the reconciliation is already being accounted for in Regulation G, we do not believe adding the same requirement to Item 10 of Regulation S-K and Item 10 of Regulation S-B incurs an additional collection of information within the meaning of the PRA. To account for the proposed reconciliation in both Regulation G and Item 10 or Regulation S-K and Item 10 of Regulation S-B would result in double counting. Additionally, companies already, usually and customarily, disclose the purposes for which the registrant's management uses the non-GAAP financial measure and why it believes that its presentation of the non-GAAP financial measure provides useful information to investors. Accordingly, we do not believe that our amendments to Item 10 of Regulation S-K and Item 10 of Regulation S-B contain a new “collection of information” or alter the existing burden of these collections of information within the meaning of the PRA.

Form 8-K (OMB Control No. 3235-0060) prescribes information, such as material events or corporate changes that a registrant must disclose. Proposed Item 1.04 of Form 8-K would require a company that publicly discloses material information regarding its actual or expected quarterly or annual results of operations or financial condition for a completed fiscal period to file the text of the public disclosure and any accompanying analysis. Proposed Item 1.04 of Form 8-K would not require companies to actually issue an earnings announcement or release but only require that it be filed if they choose to issue an earnings announcement or release. Proposed Item 1.04 would bring earnings announcements and releases into the formal disclosure system where they would be available to investors on a widespread basis.

Proposed Item 1.04 of Form 8-K would impose the obligation to file a public company's earnings release. We estimate for purposes of the PRA that the burden associated with actually filing the Form 8-K to be minimal. We believe that proposed Item 1.04 of Form 8-K would require approximately .5 of a burden hour. We estimate that approximately 14,000 public companies would make an average of four filings per year. We believe the total burden hours associated with proposed Item 1.04 would be 28,000 hours. We would expect that companies would use in house personal to file the Form 8-K.

We have amended Form 20-F (OMB Control Number 3235-0288) to incorporate our amendment to Item 10 of Regulation S-K. While proposed Regulation G provides a limited exception for foreign private issuers, this exception would not apply to their Form 20-F filing or any disclosure of non-GAAP financial measures made in the United States. Accordingly, we do not believe our amendment to Form 20-F would result in an additional collection of information as any burden is already accounted for in Regulation G.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. Compliance with the disclosure requirements is mandatory. There is no mandatory retention period for the information disclosed, and responses to the disclosure requirements will not be kept confidential.

We request comment in order to: (a) Evaluate whether the proposed collection of information and amendments to existing collections of information are necessary for the proper performance of the functions of the Commission, including whether the information will have practical utility; (b) evaluate the accuracy of our estimate of the burden of the proposed collection of information and amendments to existing collection of information; (c) determine whether there are ways to enhance the quality, utility and clarity of the information to be collected; and (d) evaluate whether there are ways to minimize the burden of the proposed collection of information and amendments of existing collections of information on those who respond, including through the use of automated collection techniques or other forms of information technology. 54

Persons who desire to submit comments on the proposed collections of information requirements should direct their comments to the OMB, Attention: Desk Officer for the Securities and Exchange Commission, Office of Information and Regulatory Affairs, Washington, DC 20503, and send a copy of the comments to Jonathan G. Katz, Secretary, Securities and Exchange Commission, 450 Fifth Street NW., Washington, DC 20549-0609, with reference to File No. S7-XX-02. Requests for materials submitted to the OMB by us with regard to this collection of information should be in writing, refer to File No. S7-XX-02 and be submitted to the Securities and Exchange Commission, Records Management, Office of Filings and Information Services, 450 Fifth Street NW., Washington, DC 20549. Because the OMB is required to make a decision concerning the collections of information between 30 and 60 days after publication, your comments are best assured of having their full effect if the OMB receives them within 30 days of publication.

The Sarbanes-Oxley Act seeks to enhance the financial disclosure of public companies. In furtherance of this goal, the Sarbanes-Oxley Act has required the Commission, among other things, to adopt rules requiring that if a company publicly discloses non-GAAP financial measures or includes them in a Commission filing, the company must reconcile those non-GAAP financial measurements to a company's financial condition and results of operations under GAAP. Moreover, Sarbanes-Oxley requires that any public disclosure of non-GAAP financial measures not contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the non-GAAP financial measure, in light of circumstances under which it is presented not misleading. Additionally, the Sarbanes-Oxley Act seeks to have companies that report under Sections 13(a) and 15(d) of the Exchange Act disclose to the public on a rapid and current basis such additional information concerning material changes in its financial condition or operations.

Proposed Regulation G, amendments to Item 10 of Regulation S-K, Item 10 of Regulation S-B and Form 20-F, upon adoption, would fulfill the statutory directive under Section 401(b) of the Sarbanes-Oxley Act. We recognize that any implementation of the Sarbanes-Oxley Act would likely result in costs as well as benefits and have an effect on the economy. We are sensitive to the costs and benefits of our proposals. We discuss these costs and benefits below as well as the costs and benefits associated with our amendments to Form 8-K.

The proposed rules and amendments are intended to ensure that investors and others are not misled by the use of non-GAAP financial measures. Additionally, the proposed amendments to Form 8-K are intended to create a central depository where investors and other market participants can look to find the latest earning announcements and releases by public companies and provide enhanced attention to those announcements and releases. Furthermore, as the ABA noted in their comment letter regarding the Commission's recent proposal on accelerated reporting periods, the filing of the earnings reports would enhance the attention and level of care companies bring to those disclosures because they will become part of the formal reporting system and provide widespread access to investors. Therefore, we would expect the accuracy and reliability of a company's earnings report to be enhanced.

Regulation G and amendments to Item 10 of Regulations S-K and S-B require that any non-GAAP financial measure presented be reconciled with its most comparable financial measure prepared in accordance with GAAP. We anticipate that this reconciliation will help investors and market professionals to better evaluate the non-GAAP financial measures presented. It is possible that the reconciliation will provide the securities markets with additional information to more accurately evaluate companies' securities and in turn result in a more accurate pricing of securities. We, however, do not currently have sufficient information to quantify these or other benefits that Regulation G and our amendments to Item 10 of Regulation S-K, Regulation S-B, and Form 8-K and Form 20-F would provide. We therefore request your comments, including supporting data, on the benefits of these proposals.

As discussed in the PRA section, we believe that the costs associated with the proposed Regulation G and amendments will be minimal. With regard to Regulation G, the costs associated with the requirement to reconcile the non-GAAP financial measure, should be minimal since by definition the non-GAAP financial measure would have been derived from a GAAP financial measure. Accordingly, in most cases, the registrant already will have available the comparable GAAP financial measure. Moreover, in cases where the GAAP financial measure is not available, any costs associated with obtaining the GAAP financial measure would reduce future costs associated with filing other forms, such as the Form 10-Q and Form 10-K where the GAAP measure must be presented.

We have estimated that public companies would have to comply with Regulation G six times a year. There are roughly 14,000 public companies. Using our estimates from the PRA section, we would expect that it would take a junior accountant roughly .5 hours to complete the required reconciliation and ensure there are no material misstatements. Accordingly, we have estimated that the total burden hours needed to comply with Regulation G would be 42,000 hours. Using cost data from the Securities Industry Association's Report on Management & Professional Earnings in the Securities Industry 2001 (SIA Report)  55 and adding an additional 35% for costs associated with overhead, we find that, on average, a junior accountant would earn $26 an hour. We believe the salary of a junior accountant is appropriate for our estimates since in most cases we would expect the most directly comparable GAAP measure to be available. Therefore, we have estimated the total costs associated with complying with Regulation G to be $1,092,000.

Our amendments to Item 10 of Regulation S-K and Item 10 of Regulation S-B incorporate the requirements of Regulation G. Because the costs associated with providing a reconciliation are already being accounted for in Regulation G, we do not believe adding the same requirement to Item 10 of Regulation S-K and Item 10 of Regulation S-B incurs any additional cost to the registrant. To account for the required reconciliation in both Regulation G and Item 10 or Regulation S-K and Item 10 of Regulation S-B would result in double counting. Additionally, because companies currently disclose the purposes for which the registrant's management uses the non-GAAP financial measure and why it believes that presentation of the non-GAAP financial measure provides useful information to investors, this aspect of the proposed rule would not increase costs already being borne by registrants. Accordingly, we do not believe our amendments to Item 10 of Regulation S-K and Item 10 of Regulation S-B would result in any additional costs not already included in Regulation G or current filing requirements.

Our amendment to Form 8-K, would result in the additional cost of actually filing the earnings release or earnings announcement. There is no requirement to actually make an earnings announcement or release. The only requirement is to file such announcement or release if it is publicly disclosed. We have not included in our estimates any additional legal review costs associated with the filing of earnings releases or announcements, since we do not anticipate any additional significant review would be needed. In this regard, we note that many issuers already file their earnings releases and those releases whether filed or not are subject to Rule 10b-5.

We believe that personnel in finance, investor relations or corporate communications departments would most likely file the earnings announcements or releases since most earnings announcements are disseminated via press release. We have estimated that the actual time required to file an earnings announcement or release on Form 8-K to be .5 hour. In estimating this time burden we note that most press releases are fairly short in length, making the actual process of filing easier. We also note that the software necessary to file a Form 8-K is available free of charge from the Commission. We have estimated that public companies would be required to comply with Item 1.04 of Form 8-K roughly four times a year. Assuming 14,000 public companies and a total burden of .5 hour for the filing, we estimate that companies will spend 28,000 hours complying with our proposed Form 8-K amendment. Again using the SIA Report, and adding an additional 35% for costs associated with overhead, we find that a Corporate Communications Manager, on average, earns $56.00 an hour. Accordingly, we have estimated the total salary cost associated with our amendments to Form 8-K to be $1,568,000.

Finally, our proposed amendments to Form 20-F would incorporate Item 10 of Regulation S-K. While proposed Regulation G provides a limited exception for foreign private issuers, this exception would not apply to their Form 20-F filing or any disclosure of non-GAAP financial measures made in the United States. Accordingly, the costs associated with our amendment to Form 20-F are already accounted for in our cost estimates for Regulation G.

We request your comments, including any supporting data, on our estimates of the costs of the proposals and any alternative options that may reduce the costs or enhance the benefits of our proposal.

• We have assumed that non-GAAP measures are derived and calculated from the GAAP measures. Accordingly, we do not believe there would be significant costs associated with the proposed reconciliation. Is our assumption that the comparable GAAP measure would be available at the time the non-GAAP measure is presented correct? If not, please discuss the nature and type of costs that may be incurred as a result of the reconciliation requirement.

• We believe the costs associated with the proposed filing requirement of Item 1.04 Form 8-K to be mainly administrative in nature. Are there other additional costs that may be incurred as a result of the proposed filing requirement of Form 8-K? If yes, please discuss the types and expected dollar amounts of such costs.

Section 23(a)(2) 56 of the Exchange Act requires us when adopting rules under the Exchange Act, to consider the impact that any new rule would have on competition. In addition, Section 23(a)(2) prohibits us from adopting any rule that would impose a burden on competition not necessary or appropriate in furtherance of the purpose of the Exchange Act. Proposed Regulation G and our proposed amendments to Item 10 of Regulation S-K, Item 10 of Regulation S-B, Form 20-F and Form 8-K would apply only to companies subject to the reporting requirements of Sections 13(a) and 15(d) of the Exchange Act, other than registered investment companies. Given that the estimated costs associated with our proposals are small we do not expect that competitors not subject to our proposals would gain any competitive advantage over those subject to the proposals. We, however, request comment on whether our proposals, if adopted, would impose a burden on competition. Commenters are requested to provide empirical data and other factual support for their views if possible.

In addition, Section 2(b)  57 of the Securities Act and Section 3(f)  58 of the Exchange Act require us, when engaging in rulemaking where we are required to consider or determine whether an action is necessary or appropriate in the public interest, to consider, in addition to the protection of investors, whether the action will promote efficiency, competition and capital formation. Proposed Regulation G and our proposed amendments to Item 10 of Regulation S-K, Item 10 of Regulation S-B and Form 20-F are proposed pursuant to the Sarbanes-Oxley Act. As noted above the costs associated with these proposals and our proposed amendment to Form 8-K are expected to be minimal. Accordingly we do not believe that there will be any significant effects on competition or capital formation. We do believe, however, that there may be some benefits with regard to investor protection and efficiency of the market. The additional information provided has the potential to limit any misunderstanding with regard to the value of certain non-GAAP measures. Accordingly, this may allow the market to more rapidly and accurately price securities. If this occurs there would be a benefit to capital formation.

We request comment on whether proposed Regulation G and our proposed amendments, if adopted would promote efficiency, competition, and capital formation. Commenters are requested to provide empirical data and other factual support for their views if possible.

The Commission hereby certifies pursuant to 5 U.S.C. § 605(b), that proposed Regulation G, amendments to Item 10 of Regulation S-K, Item 10 of Regulation S-B, Form 20-F and Form 8-K, contained in this release, if adopted, would not have a significant economic impact on a substantial number of small entities. The certification is based on the following analysis.

The proposals would affect companies that are small entities. Rule 0-10(a)  59 defines a company, other than an investment company, to be a “small business” or “small organization” for purposes of the Regulatory Flexibility Act if it had total assets of $10 million or less on the last day of its most recent fiscal year. We estimate that there were approximately 2,500 public companies, other than investment companies, that may be considered small entities.

Proposed Regulation G would require registrants when publicly disclosing material information that includes a non-GAAP financial measure to provide a quantified reconciliation to the most directly comparable GAAP financial measure. Regulation G is intended to implement the requirements of the Sarbanes-Oxley Act. Specifically, Regulation G is intended to provide investors with balanced financial disclosure when non-GAAP financial measures are presented. Regulation G defines a non-GAAP financial measure as a numerical measure of an issuer's historical or future financial performance, financial position or cash flow that:

• Excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the statement of income, balance sheet or statement of cash flows (or equivalent statements) of the issuer; or

• Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure calculated and presented in accordance with GAAP.

Accordingly, by definition, a non-GAAP financial measure that triggers the application of Regulation G would have been derived from a GAAP financial measure. Therefore, we expect the cost of obtaining the additional disclosure required by Regulation G to be minimal. Moreover, much of the disclosure mandated by Regulation G, such as the most directly comparable GAAP measure, is already required to be provided pursuant to other forms and regulations, such as Form 10-KSB, Form 10-QSB and Regulation S-X. We have estimated for purpose of the PRA that it will take .5 hour for small businesses to comply with Regulation G. We anticipate that on average a company will have to comply with Regulation G six times year. We would expect that an in house junior accountant would prepare the actual reconciliation.

Using cost data from the Securities Industry Association's Report on Management & Professional Earnings in the Securities Industry 2001 (“SIA”) and adding an additional 35% for costs associated with overhead, we find that, on average, a junior accountant would earn $26 an hour. We believe the salary of a junior accountant is appropriate for our estimates since in most cases we would expect the most directly comparable GAAP financial measure to be available. Therefore, we have estimated the total salary costs associated with complying with Regulation G to be $78 per small business 60 .

Our amendments to Item 10 of Regulation S-K and Item 10 of Regulation S-B incorporate the requirements of Regulation G and codify certain staff interpretations. Because the costs associated with providing a reconciliation are already being accounted for in Regulation G, we do not believe adding the same requirement to Item 10 of Regulation S-K and Item 10 of Regulation S-B incurs any additional costs to small businesses. To account for the required reconciliation in both Regulation G and Item 10 or Regulation S-K and Item 10 of Regulation S-B would result in double counting. Additionally, because the staff companies currently disclose the purposes for which the registrant's management uses the non-GAAP financial measure and why it believes that presentation of the non-GAAP financial measure provides useful information to investors, this disclosure would not impose new costs on small businesses. Accordingly, we do not believe our amendments to Item 10 Regulation S-K and Regulation S-B result in any additional costs not already included in Regulation G or current filing requirements.

Our amendment to Form 8-K, would require the filing of earnings releases or earnings announcement. There is no requirement to actually make an earnings announcement or release. We have not included in our estimates any additional legal review costs associated with the filing of earnings releases or announcements, since we do not anticipate any additional significant review would be needed. In this regard, we note that many issuers already file their earnings releases and those releases whether filed or not are subject to Rule 10b-5.

We believe that personnel in finance, investor relations or corporate communications departments would most likely file the earnings announcement or release since most earnings announcements and releases are disseminated via press release. We have estimated that the actual time required to file an earnings announcement or release on Form 8-K to be .5 hours. In estimating this time burden we note that most press releases are fairly short in length, making the actual process of filing easier. We also note that the software necessary to file a Form 8-K is available free of charge from the Commission.

We have estimated that small businesses would be required to comply with Item 1.04 of Form 8-K roughly four times a year. Again using the SIA Report and adding an additional 35% for costs associated with overhead, a Corporate Communications Manager, on average, earns $56.00 an hour. Accordingly, we have estimated the total costs to a small business associated with our amendments to Form 8-K to be $112. 61

Additionally, our proposed amendments to Form 20-F would incorporate Item 10 of Regulation S-K. Because only foreign private issuers file Form 20-F we do not include the impact on them in our analysis.

Finally, to further examine the possible impact of the proposals on small businesses, we sampled publicly available information about 75 small businesses. We searched the Dow Jones Press Release Wire, for the period January 1, 2001 to July 1, 2002 to review any earnings announcements or earnings releases by the 75 small businesses. We found that 30 small businesses had no earnings announcements or releases available over the period and the other 45 companies reported only GAAP earnings. Accordingly, the cost impact would be significantly less if the small business does not use non-GAAP financial measures since there would be no reconciliation required. Additionally, if the small business does not issue earnings releases or announcements there would be no filing requirement on Form 8-K.

In sum, the proposals are expected to result in minimal additional costs to all subject companies, large or small. Accordingly, we believe the proposals should not have a significant economic impact on a substantial number of small entities.

We encourage written comments regarding this certification. We solicit comment as to whether the proposed changes could have an effect that we have not considered. We request that commenters describe the nature of any impact on small entities and provide empirical data to support the extent of the impact.

For purposes of the Small Business Regulatory Enforcement Fairness Act of 1996, a rule is “major” if it has resulted, or is likely to result in:

• An annual effect on the economy of $100 million or more;

• A major increase in costs or prices for consumers or individual industries; or

• Significant adverse effects on competition, investment or innovation.

We request comment with regard to our analysis. Commenters should provide empirical data on (a) the annual effect on the economy; (b) any increase in costs or prices for consumers or individual industries; and (c) any effect on competition, investment or innovation.

The proposed new Regulation G, new Item 1.04 to Form 8-K and the amendments to Item 6.01 of Form 8-K, Item 10 of Regulation S-K, Item 10 of Regulation S-B and Form 20-F are being proposed pursuant to Sections 2(b), 6, 7, 8, 19(a), and 28 of the Securities Act of 1933 as amended, Sections 3, 4, 10, 12, 13, 15, 23 and 36 of the Securities Exchange Act of 1934, as amended and Sections 3(a), 401 and 409 of the Sarbanes-Oxley Act.

In accordance with the foregoing, the Securities and Exchange Commission proposes to amend Title 17, chapter II of the Code of Federal Regulations as follows:

For additional information see the direct final rule which is published in the Rules Section of this Federal Register.

The use of “we,” “us,” or “our” in this document refers to EPA.

We are proposing to find that the Washington area has failed to attain the one-hour ozone NAAQS by the November 15, 1999, attainment deadline prescribed under the CAA for serious ozone nonattainment areas. EPA's authority to make this finding is discussed under section 181(b)(2) of the CAA. Section 181(b)(2) explains the process for determining whether an area has attained the one-hour ozone standard and reclassification of the area if necessary. If we issue a final finding of failure to attain, the Washington area will be reclassified by operation of law from serious nonattainment to severe nonattainment.

Since the CAA's inception in 1970, EPA has set NAAQS for six common pollutants: carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and sulfur dioxide. For most of these common air pollutants, there are two types of pollution limits referred to as the primary and secondary standards. 1 The primary standard is based on health effects; the secondary standard is based on environmental effects such as damage to property, plants, and visibility. The CAA requires these standards to be set at levels that protect public health and welfare with an adequate margin of safety. These standards present state and local governments with the air quality levels they must meet to achieve clean air. Also, these standards allow the American people to assess whether the air quality in their communities is healthful.

The NAAQS for ozone is currently expressed in two forms which are referred to as the one-hour and eight-hour standards. Table 1 summarizes the ozone standards.

The 1-hour ozone standard of 0.12 parts per million (ppm) has existed since 1979. On July 18, 1997, EPA adopted the 8-hour ozone standard, which was intended to replace the one-hour standard in areas that were attaining the one-hour standard, (62 FR 38856). 2 The one-hour ozone standard continues to apply to all areas, notwithstanding promulgation of the 8-hour standard (40 CFR 50.9(b)). Both standards are codified at 40 CFR part 50. This document addresses the classification of the Washington area relative to only the one-hour ozone standard.

The Washington area consists of the District of Columbia (the District), a Northern Virginia portion (Arlington, Fairfax, Loudoun, Prince William and Stafford Counties and the cities of Alexandria, Falls Church, Fairfax, Manassas, and Manassas Park), and Calvert, Charles, Frederick, Montgomery, and Prince George's Counties in Maryland.

Under section 107(d)(1)(C) of the CAA, each ozone area designated nonattainment for the one-hour standard prior to enactment of the 1990 CAA amendments, such as the Washington area, was designated nonattainment by operation of law upon enactment of the amendments. Under section 181(a) of the Act, each ozone area designated nonattainment under section 107(d) was also classified by operation of law as “marginal,” “moderate,” “serious,” “severe,” or “extreme,” depending on the severity of the area's air quality problem. The design value for an area, which characterizes the severity of the air quality problem, is represented by the highest design value at any individual ozone monitoring site ( i.e. , the highest of the fourth highest one-hour daily maximum monitored ozone levels in a given three-year period with complete monitoring data). Table 2 provides the design value ranges for each nonattainment classification. Ozone nonattainment areas with design values between 0.160 and 0.180 ppm, such as the Washington area (which had a design value of 0.165 ppm in 1989), were classified as serious. These nonattainment designations and classifications were codified in 40 CFR part 81 (see 56 FR 56694, November 6, 1991).

In addition, states containing areas that were classified as serious nonattainment were required to submit SIP revisions to provide for certain controls, to show progress toward attainment, and to provide for attainment as expeditiously as practicable, but not later than November 15, 1999. Serious area SIP requirements are found primarily in section 182(c) of the CAA.

Regarding reclassification for failure to attain, section 181(b)(2)(A) of the Act provides that: Within six months following the applicable attainment date (including any extension thereof) for an ozone nonattainment area, the Administrator shall determine, based on the area's design value (as of the attainment date) whether the area attained the standard by that date. Except for any Severe or Extreme area, any area that the Administrator finds have not attained the standard by that date shall be reclassified by operation of law in accordance with table 1 of subsection (a) to the higher of—

(i) The next higher classification for the area, or

(ii) The classification applicable to the area's design value as determined at the time of the notice required under subparagraph (B).

No area shall be reclassified as Extreme under clause (ii).

Furthermore, section 181(b)(2)(B) of the Act provides that:

The 1-hour ozone NAAQS is 0.12 ppm not to be exceeded on average more than one day per year over any three year period. 40 CFR 50.9 and Appendix H. Under our policies, we determine if an area has attained the one-hour standard by calculating, at each monitor, the average number of days over the standard per year during the preceding three year period. 4 See 40 CFR part 50, Appendix H.

If an area has at least one monitor recording four or more exceedances during a 3-year period, then the average number of exceedance days per year exceeds one, and the area has not attained the standard.

Conversely, if an area has all monitors with an average number of exceedance days per year less than or equal to one, only then has the area attained the standard.

For this proposal, we have based our determination of whether the Washington nonattainment area attained the 1-hour ozone standard by November 15, 1999, on both the area's design value and the average number of exceedance days per year during the 1997 to 1999 period.

The effect of a reclassification to severe on the Washington nonattainment area is to set a new attainment deadline for the area of November 15, 2005, and to require the State to submit a SIP revision that meets the CAA's requirements for severe ozone nonattainment areas. See CAA sections 181(a) and 182(i). Under section 182(i), we may set the submittal deadlines for these new planning requirements.

Table 3 lists the average number of days when ambient ozone concentrations exceeded the one-hour ozone standard at each monitoring site in the Washington area for the period 1997-1999. The ozone design value for each monitor is also listed for the same period. A complete listing of the ozone exceedances for each monitoring site, as well as EPA's calculations of the design values, can be found in the docket file for this action. The data in Table 3 show that, for 1997-1999, many monitoring sites in the Washington area averaged more than one exceedance day per year. Therefore, pursuant to section 181(b)(2)(B) of the CAA, we propose to find that the Washington area did not attain the one-hour standard by the November 15, 1999, deadline.

Several monitors recorded more than two or more exceedances in 1999. These included the McMillan Reservoir monitor in the District, the Southern Maryland, and Greenbelt monitors in Maryland and the Arlington County monitor in Virginia.

For some time, EPA has recognized that pollutant transport can impair an area's ability to meet air quality standards by the date prescribed in the Act. In March 1995 a collaborative, Federal-state process to assess the ozone transport problem began. Through a two-year effort known as the Ozone Transport Assessment Group (OTAG), EPA worked in partnership with the 37 easternmost states and the District of Columbia, industry representatives, academia, and environmental groups to develop recommended strategies to address transport of ozone and ozone-forming pollutants across state boundaries.

On November 7, 1997, EPA acted on OTAG's recommendations and issued a proposal (the proposed oxides of nitrogen (NO X ) SIP call, 62 FR 60318) requiring 22 states and the District of Columbia to submit state plans addressing the regional transport of ozone. These SIP revisions will decrease the transport of ozone across state boundaries in the eastern half of the United States by reducing emissions of NO X (a precursor to ozone formation). EPA took final action on the NO X SIP call on October 27, 1998 (63 FR 57356). EPA expects the final NO X SIP call will assist many areas in attaining the 1-hour ozone standard.

On July 16, 1998, in consideration of these factors and the realization that many areas were unable to meet the CAA-mandated attainment dates due to transport, EPA's then Acting Assistant Administrator, Richard Wilson, EPA issued an attainment date extension policy. 5 Under this policy, the attainment date for an area may be extended provided that the following criteria are met: (1) The area is identified as a downwind area affected by transport from either an upwind area in the same state with a later attainment date, or an upwind area in another state that significantly contributes to downwind nonattainment (by “affected by transport,” EPA means an area whose air quality is affected by transport from an upwind area to a degree that affects the area's ability to attain); (2) an approvable attainment demonstration is submitted along with any necessary, adopted local measures and with an attainment date that shows that the area will attain the 1-hour standard no later than the date that the reductions are expected from upwind areas under the final NO X SIP call and/or the statutory attainment date for upwind nonattainment areas, i.e. , assuming the boundary conditions reflect those upwind reductions; (3) the area has adopted all applicable local measures required under the area's current classification and any additional measures necessary to demonstrate attainment, assuming the reductions occur as required in the upwind areas; and (4) the area provides it will implement all adopted measures as expeditiously as practicable but no later than the date by which the upwind reductions needed for attainment will be achieved (64 FR 14441, March 25, 1999).

EPA contemplated that when it acted to approve such an area's attainment demonstration and attainment date extension, it would, as necessary, extend that area's attainment date to a date appropriate for that area in light of the schedule for achieving the necessary upwind reductions. As a result, the area would no longer be subject to reclassification or “bump-up” for failure to attain by its original attainment date under section 181(b)(2).

The State of Maryland, the Commonwealth of Virginia and the District of Columbia each submitted a request for such an extension of the attainment date for the Washington nonattainment area. In a January 3, 2001 (66 FR 586), final rule, EPA approved these requests along with attainment demonstration SIP revisions. The Sierra Club and its local chapters filed a petition for review in the United States Courts of Appeals for the appropriate circuits. 6 The petitions were consolidated in the United States Courts of Appeals for the District of Columbia Circuit.

On July 2, 2002, the United States Courts of Appeals for the District of Columbia Circuit (the Court) issued its ruling that vacated our January 3, 2001, final rule. With respect to the attainment date extension, the Court found that the plain language of Clean Air Act “sets a deadline without an exception for setbacks owing to ozone transport.” The Court said that the EPA was without authority to extend the Washington, DC area's attainment deadline unless it also ordered the area to be reclassified as a “severe” area.

Because we can no longer grant the Washington area an attainment date extension using the July 16, 1998, policy, we must determine whether the Washington area will be reclassified by operation of law to severe if we issue a final action finding that the area failed to attain.

The air quality in the Washington area has improved significantly since the area was designated nonattainment following enactment of the 1990 CAA amendments, when the area's (1987-1989) ozone design value was 0.165 ppm. The most recent ( i.e. , 1999-2001) area-wide ozone data shows a continuing downward trend in the numbers of violations and ozone design values. The area now has only three monitors violating the standard, and of these, the maximum number of violations is 2.0 at the Greenbelt monitor in Maryland. The current design value is 0.130 ppm. The 1987-1989, 1997-1999 and 1999-2001 data are summarized in Table 4.

EPA has approved, and the District, Maryland and Virginia have implemented, VOC emission reductions as part of the State's 15 Percent Rate-of-Progress Plan, and VOC and NO X emission reductions as part of the Post-1996 Rate-of-Progress Plan. The area has already opted into the Federal reformulated gasoline program. For an extensive summary of these plans and the measures currently in place or scheduled for future implementation refer to the preambles of our December 16, 1999 (64 FR at 70471-70474), and January 3, 2001 (66 FR at 589-590), Federal Register publications. In addition, since the January 3, 2001, final rule, the District and Virginia have adopted rules to implement the NO X SIP call with implementation in 2003 and 2004, respectively. Virginia submitted its rule on June 25, 2002. 7 See 67 FR 48032, July 23, 2002. We approved the District's rule on November 1, 2001, (66 FR 55099).

As stated previously, section 181(b)(2)(A) of the Act requires that, when an area is reclassified for failure to attain, its reclassification must be the higher of the next higher classification or the classification applicable to the area's ozone design value at the time the notice of reclassification is published in the Federal Register . However, no area can be reclassified as extreme based upon its design value. The official design value of the Washington area based on quality-assured ozone monitoring data from 1997-1999 is 0.132 ppm. The classification corresponding to this value is “marginal” nonattainment. By contrast, the next higher classification for the Washington area is “severe” nonattainment. Because “severe” is a higher nonattainment classification than “marginal,” under the statutory scheme, the area would be reclassified to severe nonattainment. Refer to Table 3 above.

In April 1998, the District, Maryland and Virginia each submitted modeling and a weight of evidence demonstration setting local overall emissions budgets when combined with boundary conditions consistent with the NO X SIP call to demonstrate attainment of the 1-hour ozone NAAQS. While the air quality modeling analysis considered projected local emissions levels that were expected to occur by 1999, the calendar year itself is not an input to the air quality model. The air quality model responds only to the meteorology (temperature, wind patterns, etc.) of the selected episode, the ozone and precursor levels at the boundaries of the grid of the area being modeled and the overall change in local emissions levels in the local area. During February 2000, the States submitted SIP revisions that demonstrated that the local overall emissions budgets set by the air quality modeling demonstration could be achieved in 2005 with a combination of Federally promulgated national measures and local measures in the approved SIPs. (For a discussion of these measures and their status as of January 3, 2001, see 66 FR at 589-590, January 3, 2001.)

If reclassified, the Washington area would need to attain the one-hour ozone NAAQS as expeditiously as practicable, but no later than November 15, 2005. The District, Maryland and Virginia would also need to submit SIP revisions addressing all the severe area requirements for the one-hour standard specified in sections 182(a) through 182(d) of the Act. The SIP requirements for severe ozone nonattainment areas include, but are not limited to, the following:

(1) Attainment demonstration for 2005 and rate-of-progress demonstrations for 2002 and 2005 including adequate on-road mobile emissions budgets for transportation conformity purposes.

(2) A 25 ton-per-year major stationary source threshold for volatile organic compounds and nitrogen oxides.

(3) More stringent new source review requirements.

(4) Enforceable transportation control strategies and measures to offset projected growth in vehicle miles traveled or number of vehicle trips as necessary to demonstrate attainment and to achieve periodic emissions reduction requirements.

(5) Contingency measures.

The ozone reclassification in and of itself would not immediately affect the applicable motor vehicle emissions budgets in the Washington area. Currently the only applicable motor vehicle emission budgets for the District, Maryland and Virginia are those for VOC and NO X in the approved rate-of-progress plan for 1999 and two sets of outyear budgets established for 2015 and for 2020. 8 Until such time as rate-of-progress and/or 2005 attainment year ozone budgets have been determined to be adequate or are approved, these 1999 budgets apply until 2015, at which point the outyear budgets apply for 2015 and all future years. See 65 FR 40167, July 3, 2000.

Our January 3, 2001, final rule approved motor vehicle emissions budgets for 2005 which were contained within the February 2000 submittals, but the Court's July 2, 2002, decision has vacated our approval action. We had found these budgets to be adequate on June 8, 2000, (65 FR 36439), but have always interpreted the transportation conformity rule such that a final rulemaking action approving a control strategy or maintenance plan SIP renders any prior adequacy determination made for budgets related to that particular control strategy or maintenance plan SIP of no further force or effect. Instead, the final rulemaking governs which budgets apply for conformity purposes. We also interpret our transportation conformity rule to mean that once an approval is vacated the prior adequacy determination is not resurrected. We made the prior adequacy determination based upon the record before us at that time. At the very least, we are now confronted with the fact of the Court's vacatur of the January 3, 2001, final rule and thus must consider whether or not the Court's ruling precludes a determination of adequacy of the calendar year 2005 motor vehicle emissions budgets in the February 2000 SIP submissions.

We initiated a new adequacy process with respect to the budgets for 2005 that were contained in the February 2000 plan. On September 9, 2002, we completed the public notice and comment portion of the process to determine the adequacy process. EPA received adverse comments on the adequacy of these budgets, and is currently considering appropriate action in response to those comments. Further information on any findings of adequacy can be found at http://www.epa.gov/otaq/transp/conform/adequacy.htm.

Once new severe area budgets are submitted and have been determined adequate, these post-1999 rate-of-progress budgets would set emission caps for any post-1999 milestone years (2002 and 2005), and the new attainment year budgets would apply to the 2005 attainment year and all years beyond the attainment year up to the point when an outyear budget has been established.

The 2005 motor vehicle emissions budgets contained in the February 2000 submittal are not based upon the most recent mobile source emission factors model, MOBILE6. The February 2000 attainment plan SIP submissions relied upon reductions from EPA's Tier 2 Federal motor vehicle control program standards and Sulfur in gasoline rule (the Tier 2/Sulfur program) to in effect demonstrate that the reduction in local emissions between 1990 and 2005 would be greater than or equal to the reduction in local overall emissions assumed in the air quality modeling demonstration. We have always stated that the benefits of the Tier 2 program cannot be accurately estimated until MOBILE6 is released. Before the official release of the MOBILE6 emission factor model, we required States that adopted benefits of the Tier 2/Sulfur program into their attainment demonstrations (and certain other SIP revisions) to submit an enforceable commitment to revise the motor vehicles emissions budgets within either one or two years of the release of the MOBILE6 model. For further detail on our rationale regarding this commitment see 64 FR 70460, December 16, 1999, and 65 FR 46383, July 28, 2000. The District, Maryland and Virginia submitted an enforceable commitment to revise the motor vehicles emissions budgets within one-year of the release of the MOBILE6 model. Because the MOBILE6 model was released on January 29, 2002, (67 FR 4254) the commitment required submittal of revised budgets by January 29, 2003. We believe that approval of this commitment only has context within the framework of an approval of the attainment demonstration under the conditions we laid out in our January 3, 2001, final rule and in the proposed actions leading up to that final action. We have interpreted the Court of Appeals's July 2, 2002, ruling as vacating the approval of this commitment.

We expect that any subsequent motor vehicle emissions budgets submitted to fulfill the severe area requirements including that of the attainment demonstration will be prepared using the MOBILE6 emissions factor model and pursuant to applicable guidance and policy such as that found in the January 18, 2002, joint memorandum from John S. Seitz and Margo Tsirigotis Oge entitled “Policy Guidance for the Use of MOBILE6 in SIP Development and Transportation Conformity” (January 18 MOBILE6 policy). Thus, although the obligation to submit MOBILE6 budgets by January 29, 2003, has been vacated, the severe area SIP when submitted must contain budgets based on MOBILE6 modeling.

In our guidance documents, the EPA has interpreted the section 182(c)(2) reasonable further progress requirement as mandating volatile organic compounds (VOC) or nitrogen oxides (NO X ) reductions of 3 percent per year, averaged over a 3-year period, for serious and above ozone nonattainment areas that were designated and classified under the 1-hour ozone NAAQS. The EPA refers to these reductions as the rate-of-progress requirement.

The January 18, 2002, MOBILE6 policy guidance indicates that among other things, the motor vehicle emissions budgets in the post-1999 rate-of-progress plans will have to developed using MOBILE6. In this policy we said:

The post-1999 rate-of-progress requirement flows from section 182(c)(2)(B) which requires serious and above areas to achieve a 3 percent per year reduction in baseline VOC emissions (or some combination of VOC and NO X reduction from baseline emissions pursuant to section 182(c)(2)(C)) averaged over each consecutive three-year period after November 15, 1996, until the attainment date. 10 Baseline emissions are the total amount of actual VOC or NO X emissions from all anthropogenic sources in the area during the calendar year 1990, excluding emissions that would be eliminated under certain Federal programs and Clean Air Act mandates: phase 2 of the Federal gasoline Reid vapor pressure regulations (Phase 2 RVP) promulgated on June 5, 1990 (see 55 FR 23666); the Federal motor vehicle control program in place as of January 1, 1990 (1990 FMVCP); and certain changes and corrections to motor vehicle inspection and maintenance (I/M) programs and corrections and reasonably available control technology (RACT) that were required under section 182(a)(2). 11 We have issued guidance that provides detailed information on for implementing the rate-of-progress provisions of section 182. 12 Basically our guidance requires the calculation of a target level of emissions for each rate-of-progress milestone year. The target level for any rate-of-progress milestone year is the 1990 baseline emissions decreased by the amount of baseline emissions that would be reduced by the 1990 FMVCP and the Phase 2 RVP program by that year and reduced by the amount of the mandated minimum reductions (15 percent VOC by 1996, and an additional nine (9) percent VOC, or VOC and NO X by 1999, * * *). Under our guidance the first rate-of-progress milestone year target levels, for example, the 15 percent VOC reduction by 1996 requirement, starts with the 1990 base year emissions and then subtracts the effects of the 1990 FMVCP and Phase 2 RVP through 1996 and also subtracts the required 15 percent VOC reduction. The 1999 VOC target level starts with the 1996 target level and subtracts the effects between 1996 and 1999 of the 1990 FMVCP and Phase 2 RVP and subtracts the required 9 percent post-1996 reduction. For each target level, our guidance requires the preparation of a 1990 base year inventory “adjusted” to the milestone year (the “1990 adjusted base year inventory”) to account for the effects of the 1990 FMVCP and Phase 2 RVP by the milestone year. The adjusted inventory uses 1990 motor vehicle activity levels but emission factors computed by MOBILE6 for the applicable milestone year. For example, preparation of a rate-of-progress plan for 1999 with NO X substitution requires a 1990 base year inventory for both VOC and NO X , a 1990 base year VOC inventory adjusted to 1996 and 1990 base year VOC and NO X inventories inventory adjusted to 1999. Preparation of a rate-of-progress plan for 1999 with NO X substitution requires a 1990 base year inventory for both VOC and NO X plus the following seven “adjusted” inventories: 1996 VOC; 1999 VOC and NO X ; 2002 VOC and NO X and 2005 VOC and NO X .

One consequence of the need to use MOBILE6 emission factors in the post-1999 rate-of-progress plan is that the area must recompute the 1990 baseline emissions using the MOBILE6 emissions factor model to update the 1990 on-road mobile sources portion of the 1990 base year emission inventory. The area must also calculate post-1999 rate-of-progress target levels by re-iterating the target levels for rate-of-progress requirements for the 1996 and 1999 milestone years.

In addition to vehicle emissions budgets for any applicable milestone year, the post-1999 rate-of-progress requirement will also require the development of a revision to the 1990 base year emissions inventories and development of up to seven 1990 adjusted inventories (VOC for 1996, VOC and NO X for 1999, VOC and NO X for 2002, plus VOC and NO X for 2005).

If the Washington area is reclassified to severe, the new attainment deadline under section 181(b)(2) would be as expeditious as practicable, but no later than the date applicable to the new classification, i.e. , November 15, 2005.

The District, Maryland and Virginia would be required to submit a SIP that adopts all the severe area requirements. Under section 181(a)(1) of the Act, the new attainment deadline for serious areas reclassified to severe under section 181(b)(2) would be as expeditious as practicable, but no later than the date applicable to the new classification, i.e. , November 15, 2005. When we issue any final finding of failure to attain that reclassifies the Washington area, we must also address the schedule by which the District, Maryland and Virginia will be required to submit a SIP revision meeting the severe area requirements. Pursuant to section 182(i), EPA can adjust any applicable deadline (other than the attainment date) as appropriate for any area reclassified under section 181(b) of the CAA. We propose to have the District, Maryland and Virginia submit this SIP by the earlier of the following dates: within one year of the effective date of a final action on the proposed finding of failure to attain and any consequent reclassification or March 1, 2004. If any of the Washington area States fail to submit a complete severe area SIP that addresses the new severe area requirements by the deadline set in a final rule reclassifying this area, we will start a sanctions clock pursuant to CAA section 179(a)(1) for failure to submit a required SIP revision.

EPA believes that this proposed rule provides ample advance notice to the affected jurisdictions that the severe area requirements may become applicable to the Washington area. However, the issuance of the MOBILE6 emission factor model will require the area to recompute the 1990 base year emissions and restate pre-1999 rate-of-progress targets using MOBILE6. This will require significantly more inventory preparation than would have occurred had the MOBILE5 model remained in force and the area could have used the MOBILE5-based 1990 base year emissions inventories and target levels through 1999. A March 1, 2004, submittal deadline will require the jurisdictions to have adopted additional emission control regulations that can allow sources a minimally reasonable time to comply before the start of the 2005 ozone season and, for measures needed solely to meet rate-of-progress requirements, slightly longer to comply before the rate-of-progress deadline of November 15, 2005. This schedule is for all the severe area SIP requirements. We solicit comments on this proposed schedule.

Section 182(c)(2)(B) requires serious and above areas achieve a 3 percent per year reduction in baseline VOC emissions (or some combination of VOC and NO X reductions from baseline emissions pursuant to section 182(c)(2)(C)) averaged over each consecutive three-year period after November 15, 1996, until the attainment date. Therefore, a serious area must achieve a 9 percent reduction between November 15, 1996, and November 15, 1999; a severe area with an attainment date of November 15, 2005, additionally has to achieve an additional 9 percent reduction by November 15, 2002, and a further 9 percent reduction by November 15, 2005.

Under the schedule for submittal of all severe area requirements that is proposed in the preceding section of this document under the heading “B. When are the Required SIP Revisions Due,” the rate-of-progress plan for the 2002 milestone year will be due well after the November 15, 2002, milestone date for the first of the post-1999 9 percent reduction requirements.

If sufficient actual reductions occurring by the November 15, 2002, milestone date do not now exist, then Maryland, Virginia or the District can only get reductions after the milestone deadline because, at this point, the States do not have the ability to require additional reductions for a period that has already passed. We believe the passing of the deadline does not relieve Maryland, Virginia or the District from the requirement to achieve the 9 percent reduction in emissions, but rather the 9 percent reduction needs to be achieved as expeditiously as practicable after November 15, 2002.

The approved SIPs for the area contain measures that either were not used in the demonstration of rate-of-progress by 1999 or that generate additional benefits after November 15, 1999, over and above what was credited to the rate-of-progress plan for 1999. Such measures include the National Low Emission Vehicle program in the entire area and, in the District and Maryland portions of the Washington area, beyond RACT reduction requirements on large sources of NO X . The area also opted-into the Federal reformulated gasoline (RFG) program. The second phase of the RFG program, which went into effect on January 1, 2000, also produces reductions creditable towards the 2002 rate-of-progress requirement.

As discussed elsewhere in this document in the section titled “What is the Relationship Between MOBILE6 and the Post-1999 Rate-of-Progress,” the CAA specifies the emissions “baseline” from which each emission reduction milestone is calculated. Section 182(c)(2)(B) states that the reductions must be achieved “from the baseline emissions described in subsection (b)(1)(B).” This baseline value is termed the 1990 adjusted base year inventory. Section 182(b)(1)(B) defines baseline emissions (for purposes of calculating each milestone VOC/NO X emission reduction) as “the total amount of actual VOC or NO X emissions from all anthropogenic sources in the area during the calendar year of enactment” (emphasis added) and excludes from the baseline the emissions that would be eliminated by certain specified Federal programs and ceratin changes to state I/M and RACT rules. 13 The 1990 adjusted base year inventory must be recalculated relative to each milestone and attainment date because the emission reductions associated with the FMVCP increase each year due to fleet turnover. 14

Therefore, EPA concludes that the area has already implemented measures creditable towards the 2002 rate-of-progress milestone. However, we are not able to conclude that the area has sufficient measures to achieve the required 9 percent reduction by November 15, 2002, in the absence of a full blown rate-of-progress plan for the 2002 milestone year that documents the calculations of the 2002 target levels of emissions, documents how the SIP accounts for expected growth in emissions related activities and contains the requisite demonstration that sufficient creditable reductions have or were projected to occur by November 15, 2002. We have insufficient data concerning what the levels of reductions will be in the area by 2002, what the proper 1990 adjusted base year inventory for 2002 will be or how much emissions growth will occur in the period November 15, 1999, through November 15, 2002. Nor do we have sufficient information to allow us to determine what date will be as expeditiously as practicable after November 15, 2002, for this first post-1999 9 percent rate-of-progress requirement.

EPA proposes that the 2002 rate-of-progress requirement be that the District, Maryland and Virginia submit a rate-of-progress plan that demonstrates that the SIP has sufficient measures to make the required percent reduction by November 15, 2002, or by a date as expeditiously as practicable thereafter. 15 Such SIP revisions will have to demonstrate that any date after November 15, 2002, by which the first post-1999 9 percent rate-of-progress reduction is achieved is that which is as expeditiously as practicable.

EPA is not proposing any change to the date by which the second 9 percent increment of post-1999 rate-of-progress must be achieved. If the currently adopted and approved SIP measures and the current suite of Federal measures will not achieve the required rate-of-progress reductions, we believe the area has sufficient time to adopt and implement measures to achieve the required reductions by November 15, 2005.

The contingency measures plan must identify specific measures to be undertaken if the area fails to meet any applicable milestone, failure to make rate-of-progress or failure to attain the NAAQS. With respect to the November 15, 2002, milestone, EPA believes that the contingency plan will need to account for any adjustment to the milestone date.

Upon reclassification the major stationary source threshold will be lowered from 50 tons per year (TPY) to 25 TPY. Consequently, the District's, Maryland's and Virginia's Title V operating permits program regulations need to cover sources that will become subject to the lower major stationary source threshold. EPA has reviewed the relevant permit program regulations for the Washington area states. This review indicates that the three program regulations will apply the requisite 25 TPY major stationary source threshold to the Washington area if this area is reclassified to severe. No changes to the State's' Title V permit program regulations will be required as a result of a reclassification of the Washington area to severe nonattainment.

After any reclassification to severe, additional sources will become subject to the Title V permitting requirements due to the change in the major stationary source threshold from 50 TPY to 25 TPY. Any newly major stationary sources must submit a timely Title V permit application. “A timely application for a source applying for a part 70 permit for the first time is one that is submitted within 12 months after the source becomes subject to the permit program or on or before such earlier date as the permitting authority may establish.” See 40 CFR 70.5(a)(1). The 12 month (or earlier date set by the applicable permitting authority) time period to submit a timely application will commence on the effective date of any reclassification action.

Commencing with “State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990” (57 FR 13498, April 16, 1992), EPA has issued numerous policy and guidance memoranda and guidance documents related to the attainment demonstration, rate-of-progress and other requirements related to the severe area classification. These documents are too numerous to list here.

Several have already been cited elsewhere in this document.

Several of the documents identified in prior Federal Register publications related to the Washington area, for example, those listed at 64 FR at 70469, December 16, 1999, no longer are applicable in this instance because they have dealt with quantifying the benefits of our Tier 2 regulations prior to the release of MOBILE6 and have become unnecessary since the release of the MOBILE6 model and the January 18 MOBILE6 policy. 16 The final mid-course review guidance has been released whereas prior Federal Register publications referenced a draft. 17 And the Memorandum, “Extension of Attainment Dates for Downwind Transport Areas,” issued July 16, 1998, was declared unlawful by the United States Courts of Appeals for the District of Columbia.

EPA is soliciting public comments on the issues discussed in this document or on other relevant matters. These comments will be considered before taking final action. Interested parties may participate in the Federal rulemaking procedure by submitting written comments to the EPA Regional office listed in the ADDRESSES section of this document.

EPA is proposing to find that the Metropolitan Washington, D.C. serious ozone nonattainment area has failed to attain the one-hour ozone NAAQS by November 15, 1999, the date set forth in the Clean Air Act (CAA or Act) for serious nonattainment areas. If EPA takes final action to issue this proposed finding of failure to attain, the area would be reclassified as a severe ozone nonattainment area by operation of law. EPA is proposing to require the District of Columbia, the State of Maryland and the Commonwealth of Virginia to submit revisions to its State Implementation Plan (SIP) that adopt the severe area requirements within one year of the effective date of a final action on the attainment determination and any consequent reclassification but not later than March 1, 2004, whichever is sooner. Finally, EPA is proposing to adjust the dates by which the area must achieve a nine (9) percent reduction in ozone precursor emissions to meet the 2002 rate-of-progress requirement and contingency measure requirement as this relates to the 2002 rate-of-progress requirement.

Under Executive Order 12866 (58 FR 51735, October 4, 1993), EPA is required to determine whether regulatory actions are significant and therefore should be subject to Office of Management and Budget (OMB) review, economic analysis, and the requirements of the Executive Order. The Executive Order defines a “significant regulatory action” as one that is likely to result in a rule that may meet at least one of the four criteria identified in section 3(f), including, under paragraph (1), that the rule may “have an annual effect on the economy of $100 million or more or adversely affect, in a material way, the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local or tribal governments or communities.”

The Agency has determined that the proposed finding of nonattainment would result in none of the effects identified in section 3(f) of the Executive Order. Under section 181(b)(2) of the CAA, determinations of nonattainment are based upon air quality considerations and the resulting reclassifications must occur by operation of law. They do not, in and of themselves, impose any new requirements on any sectors of the economy. In addition, because the statutory requirements are clearly defined with respect to the differently classified areas, and because those requirements are automatically triggered by classifications that, in turn, are triggered by air quality values, determinations of nonattainment and reclassification cannot be said to impose a materially adverse impact on state, local, or tribal governments or communities.

For this reason, the proposed finding of nonattainment and reclassification 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).

Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to any rule that: (1) Is determined to be economically significant as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency. This proposed action is not subject to Executive Order 13045 because this is not an economically significant regulatory action as defined by Executive Order 12866.

Executive Order 13132, entitled Federalism (64 FR 43255, August 10, 1999) requires EPA to develop an accountable process to ensure “meaningful and timely input by state and local officials in the development of regulatory policies that have Federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that 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.” Under Executive Order 13132, EPA may not issue a regulation that has Federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal Government provides the funds necessary to pay the direct compliance costs incurred by state and local governments, or EPA consults with state and local officials early in the process of developing the proposed regulation. EPA also may not issue a regulation that has Federalism implications and that preempts state law unless the Agency consults with state and local officials early in the process of developing the proposed regulation. This determination of nonattainment and the resulting reclassification of a nonattainment area by operation of law will 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), because this action does not, in and of itself, impose any new requirements on any sectors of the economy, and does not alter the relationship or the distribution of power and responsibilities established in the CAA. Thus, the requirements of section 6 of the Executive Order do not apply to these actions.

This proposed 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).

The Regulatory Flexibility Act (RFA) generally requires an agency to conduct a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.

Determinations of nonattainment and the resulting reclassification of nonattainment areas by operation of law under section 181(b)(2) of the CAA do not in and of themselves create any new requirements. Instead, this rulemaking only makes a factual determination, and does not directly regulate any entities. See 62 FR 60001, 60007-60008, and 60010 (November 6, 1997) for additional analysis of the RFA implications of attainment determinations. Therefore, pursuant to 5 U.S.C. 605(b), I certify that this proposed action does not have a significant impact on a substantial number of small entities within the meaning of those terms for RFA purposes.

Under section 202 of the Unfunded Mandates Reform Act of 1995 (UMRA), signed into law on March 22, 1995, EPA must prepare a budgetary impact statement to accompany any proposed or final rule that includes a Federal mandate that may result in estimated annual costs to state, local, or tribal governments in the aggregate, or to the private sector, of $100 million or more. Under section 205, EPA must select the most cost-effective and least burdensome alternative that achieves the objectives of the rule and is consistent with statutory requirements. Section 203 requires EPA to establish a plan for informing and advising any small governments that may be significantly or uniquely impacted by the rule.

EPA believes, as discussed previously in this document, that the finding of nonattainment is a factual determination based upon air quality considerations and that the resulting reclassification of the area must occur by operation of law. Thus, EPA believes that the proposed finding does not constitute a Federal mandate, as defined in section 101 of the UMRA, because it does not impose an enforceable duty on any entity.

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, section 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e.g. , materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.

This proposed action does not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards.

This proposed action to reclassify the Washington, DC area as a severe ozone nonattainment area and to adjust applicable deadlines does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ).

All written comments should identify the docket and notice numbers stated in the heading of this notice. Anyone who wants confirmation of mailed comments must include a self-addressed stamped postcard. To file written comments electronically, after logging on to http://dms.dot.gov, click on “ES Submit.” You can also read comments and other material in the docket at http://dms.dot.gov. General information about our pipeline safety program is available at http://ops.dot.gov.

NAPSR is a non-profit association of officials from State agencies that participate with RSPA in the Federal pipeline safety regulatory program. Each year NAPSR holds regional meetings to discuss safety and administrative issues, culminating in resolutions for program improvement.

In 1990 we asked NAPSR to review the gas pipeline safety standards in 49 CFR part 192. The purpose of the review was to identify standards that NAPSR considered insufficient for safety or not clear enough to enforce. NAPSR compiled the results of its review in a report titled “Report on Recommendations For Revision of 49 CFR part 192,” dated November 20, 1992. The report, a copy of which is in the docket of the present proceeding, recommends changes to 40 sections in part 192.

By the time NAPSR completed its report, we had published a notice of proposed rulemaking to change many part 192 standards that we considered unclear or overly burdensome (Docket PS-124; 57 FR 39572; Aug. 31, 1992). Because a few of NAPSR's recommendations related to standards we had proposed to change, we published the report for comment in the PS-124 proceeding (58 FR 59431; Nov. 9, 1993). The PS-124 Final Rule (61 FR 28770; June 6, 1996) included four of NAPSR's recommended rule changes, and we scheduled the remaining recommendations for future consideration. Later, at a meeting on corrosion problems held in San Antonio, Texas on April 28, 1999, we opened NAPSR's recommendations on corrosion control to further public discussion (Docket RSPA-97-2762; 64 FR 16885; April 7, 1999).

In PS-124 we received 79 comments on NAPSR's recommendations, primarily from pipeline trade associations, pipeline operators, and State pipeline safety agencies. Industry commenters generally opposed most of NAPSR's recommendations on grounds that standards would be changed not for safety reasons or clarity but to make compliance auditing easier. In contrast, the State agencies generally supported NAPSR's recommendations. NAPSR denied it was merely trying to simplify the auditing process, and said its experience provided a unique perspective on which standards are ineffective or inappropriate.

Because industry and State views were so divergent, in October 1997, the American Gas Association (AGA), the American Public Gas Association (APGA), and NAPSR formed SIRRC to iron out their differences over the recommendations. SIRRC agreed on all but eight of the recommendations scheduled for future consideration. A copy of SIRRC's report titled “Summary Report,” dated April 26, 1999, is in the docket of the present proceeding.

We have completed our review of NAPSR's 1992 recommendations as updated by SIRRC's 1999 Summary Report. The review also covered a NAPSR resolution on the definition of “service line.” Although this resolution was not in NAPSR's 1992 report, SIRRC dealt with the resolution in it's Summary Report.

The purpose of the review was to decide which, if any, of NAPSR's recommendations warrant inclusion in a notice of proposed rulemaking. If SIRRC agreed to modify a recommendation, our review focused on that modification. If SIRRC did not reach agreement, we focused on NAPSR's recommendation in light of SIRRC's discussion. Our responses to the recommendations are discussed in the next section of the preamble.

This section summarizes NAPSR's recommendations and SIRRC's consideration of those recommendations. It also states our responses to the recommendations. For ease of reference, we have numbered the recommendations according to their sequence in SIRRC's Summary Report. The following table categorizes the recommendations according to the rulemaking status indicated by our responses:

Recommendation. To help distinguish mains from transmission lines, revise the definition of “main” and the first paragraph of the definition of “transmission line” to read:

• “Main” means a pipeline installed in a community to convey gas to individual service lines or to other mains.

• “Transmission line” means a pipeline, or a series of pipelines, other than a gathering line, that: (a) Transports gas from a gathering line, storage field or another transmission line to a storage field or to one or more distribution systems or other load centers.

SIRRC. The committee reached consensus to modify the recommendation as follows:

• “Main” means a segment of pipeline in a distribution system installed to transport gas to individual service lines or other mains.

• In the present definition of “transmission line,” change “distribution center” to “distribution system” to eliminate the only use of this undefined term in Part 192.

Response: Part 192 defines “distribution line” but not “distribution system.” So substituting “distribution system” for “distribution line” in the present “main” definition and for “distribution center” in the present “transmission line” definition would not necessarily add clarity to either definition. Also, by referring to “mains,” SIRRC's definition of “main” loops back on itself. Therefore, we are not proposing to adopt the SIRRC's suggestion.

Recommendation. Adopt the following new and amended definitions to bring Part 192 in line with acceptable arrangements of service lines:

• “Customer meter” means the meter that measures the transfer of gas from an operator to a consumer.

• “Service line” means a distribution line that transports gas from a common source of supply to an individual customer, two adjacent or adjoining residential or small commercial customers, or to an aboveground meter header supplying up to ten residential or small commercial customer meters. A service line terminates at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.

• “Service regulator” means the device on a service line which controls the pressure of gas delivered from a high pressure distribution system to the level at which it is provided to the customer. A service regulator may serve one customer meter, or up to ten customer meters grouped on an aboveground meter header.

SIRRC. The committee suggested modification of the definitions as follows:

• “Customer meter” means the meter that measures the transfer of gas from an operator to a consumer.

• “Service line” means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line terminates at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.

• “Service regulator” means the device on a service line which controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer, or multiple customers through a meter header or manifold.

Response. Although § 192.3 already defines the term “customer meter,” the definition of this term is included in the definition of “service line.” SIRRC's suggestion would merely move the “customer meter” definition to an alphabetical position in § 192.3. Since “customer meter” is used in part 192 in places other than the “service line” definition, we agree that an alphabetical position is preferable. So we are proposing to amend § 192.3 as SIRRC suggested.

Under the part 192 definitions of “service line” and “main,” if an operator runs a single line from main to supply gas to two customers, the single line is itself a main because it is a common source of supply for more than one service line. 1 Typically such single-line installations serve two or more adjacent single-family residences through branch lines connected to the single line. They also serve apartment buildings and shopping centers through meter manifolds, or meter headers.

Because these single lines are more like service lines than mains—their size is small, their pressure is low, and they are located on private property rather than under a public street or alley—many State pipeline safety agencies have granted waivers for the lines, permitting operators to treat them as service lines. Consequently, under most State waivers, the single lines may be designed, installed, operated, and maintained as service lines. They do not have to meet any part 192 standard that applies strictly to mains. For example, § 192.327(b) requires a minimum burial depth for mains (24 in) that is greater than the depth § 192.361 requires for service lines (12 or 18 in). Single-line installations serving adjacent customers may also increase safety by minimizing connections to mains. These connections are susceptible to leaks and damage accidentally caused by street excavation activities.

Since SIRRC's suggested definition of “service line” is consistent with State waivers we considered appropriate, we are proposing to amend § 192.3 by revising the definition of “service line” as SIRRC suggested. Note, however, that the proposed definition uses the general term “meter manifold” instead of “meter header or manifold.” If adopted as final, the proposed definition would eliminate the need for similar waivers in the future.

We are also proposing to adopt SIRRC's suggested definition of “service regulator.” SIRRC's definition is consistent with state waivers that distinguish regulators connected to customer meter manifolds from regulating stations that must be inspected under § 192.739.

We are particularly interested in receiving comments on how the term “small commercial customers” might be stated differently or defined to minimize potential confusion in identifying the customers involved. Would it be appropriate to consider a “small commercial customer” as a business that receives volumes of gas similar to the volumes that a residential customer receives?

Recommendation. Delete § 192.55(a)(2)(ii), which provides requirements for the use of new steel pipe manufactured before November 12, 1970.

SIRRC. The committee suggested that § 192.55(a)(2)(ii) should not be deleted.

Response. Although NAPSR initially thought § 192.55(a)(2)(ii) was obsolete, several PS-124 commenters said the section should remain because operators have stockpiles of steel pipe manufactured before 1970. The SIRRC Summary Report indicates operators continue to stock such pipe. We concur with SIRRC that § 192.55(a)(2)(ii) should not be removed.

Recommendation. Delete § 192.65(b), which provides requirements for the use of certain steel pipe transported by railroad before November 12, 1970.

SIRRC. The committee agreed that § 192.65(b) should not be deleted.

Response. Although NAPSR initially thought § 192.55(b) was obsolete, several PS-124 commenters said they had stockpiled pipe manufactured before 1970. In addition, the SIRRC Summary Report indicates that operators still have this pipe and that it may have been transported by railroad. We concur with the SIRRC's suggestion.

Recommendation. Delete the second sentence of § 192.123(b)(2)(i), which allows plastic pipe manufactured before May 18, 1978, and strength rated at 73 °F to be used at temperatures up to 100 °F.

SIRRC. The committee agreed that the second sentence of § 192.123(b)(2)(i) should be deleted.

Response. NAPSR thought the second sentence of § 192.123(b)(2)(i) was obsolete. However, the PS-124 comments indicated that several utilities had inventories of plastic pipe manufactured before May 18, 1978, that they intended to use as replacement pipe. In contrast, the SIRRC Summary Report states that the committee members were unaware of any pre-1978 plastic pipe in operators' stocks. Moreover, the committee members had reservations about using plastic pipe of that vintage.

Assuming the SIRRC Summary Report generally reflects the present status of operators' stocks of plastic pipe, we are proposing to delete the second sentence of § 192.123(b)(2)(i) as obsolete. If this proposal were adopted as final, any stockpiled pre-1978 thermoplastic pipe whose long-term hydrostatic strength was determined at 73 °F could not be used above that temperature. We are particularly interested in hearing from industry commenters whether they still have any stockpiles of this pipe that they plan to use at temperatures above 73 °F.

Recommendation. In § 192.197(a), change “under 60 psig” to “60 psig or less.”

SIRRC. The committee agreed that § 192.197(a) should be changed as NAPSR recommended.

Response. Section 192.197(a) provides that in distribution systems operated “under 60 psig (414 kPa) gage,” if service regulators meet certain criteria, no other pressure limiting devices are required. However, § 192.197(b) states that if those criteria are not met in systems operating at “60 psig (414 kPa) gage, or less,” additional pressure control is required. Thus there is a 1 psi discrepancy between these two sections. We agree with SIRRC that § 192.197(a) should be in sync with § 192.197(b), particularly since § 192.197(c) applies to systems in which the operating pressure “exceeds 60 psig (414 kPa) gage.” Therefore, we are proposing to change § 192.197(a) as NAPSR recommended.

Recommendation. In § 192.203(b)(2), change “takeoff line” to “instrument, control, and sampling line” to clarify the lines on which a shutoff valve must be installed.

SIRRC. The committee agreed the recommended change to § 192.203(b)(2) is not needed.

Response. In Docket PS-124, we modified § 192.203(b)(2) by excepting takeoff lines that can be isolated from sources of pressure by other valving. The SIRRC Summary Report indicates this exception resolved NAPSR's concern about § 192.203(b)(2). Therefore, we are adopting the SIRRC consensus that the recommended rulemaking action is not needed.

Recommendation. Change § 192.225(a) to require qualification of welding procedures according to “American Petroleum Institute (API), American Society of Mechanical Engineers (ASME), or other standards.”

SIRRC. The committee agreed the recommended change is needed. However, it suggested the term “other standards” should be changed to “other accepted pipeline welding standards.”

Response. We proposed to adopt the core of NAPSR's recommendation in the proceeding called “Periodic Updates to Pipeline Safety Regulations (1999)” (56 FR 15290; Mar. 22, 2000). We proposed to amend § 192.225(a)to require operators to qualify welding procedures under either Section 5 of API 1104, “Welding of Pipelines and Related Facilities,” or Section IX of the ASME Boiler and Pressure Vessel Code. However, our proposal did not include allowing the use of “other accepted pipeline welding standards,” as SIRRC suggested, because we are not aware of any other generally accepted pipeline welding standards.

Recommendation. Change § 192.241(a) to require that visual inspection of welding be conducted “by an inspector qualified by appropriate training and experience.”

SIRRC. The committee agreed the recommended change is needed. However, it suggested the term “inspector” should be changed to “person.”

Response. In the proceeding called “Periodic Updates to Pipeline Safety Regulations (1999)” (56 FR 15290; Mar. 22, 2000), we proposed to amend § 192.241(a) as NAPSR recommended. Although we overlooked SIRRC's suggestion to use “person” instead of “inspector,” we will consider the suggestion in developing the final rule.

Recommendation. In § 192.285, revise paragraph(c) to require that persons who join plastic pipe requalify annually to make joints. Also, revise paragraph (d) to require that operators maintain certain records for use in monitoring personnel qualifications.

SIRRC. The committee did not agree that NAPSR's recommended rule changes were needed. However, the committee did agree that in § 192.285(d) the term “his” should be replaced by a term that is not gender-specific.

Response. NAPSR was concerned that while most newly installed distribution lines are made of plastic pipe, the qualification requirements for persons who join plastic pipe are less stringent than the qualification requirements for persons who weld steel pipe. NAPSR felt the plastic pipe joining and welder qualification requirements should be comparable because the consequences of failure of a plastic pipe joint may be just as severe as the consequences of failure of a welded joint.

We do not believe NAPSR's reasoning is sufficient to justify stronger plastic pipe joining requirements. The skill needed for joining plastic pipe is so much simpler than the skill needed for welding steel pipe that the welding requirements cannot reasonably serve as a basis for establishing more stringent plastic pipe joining requirements. Therefore, we are not proposing to adopt NAPSR's recommended rule changes.

It is worth noting, though, that after SIRRC completed it's report, we published new qualification of personnel rules in Subpart N of Part 192. The competency evaluations required by these rules should enhance the qualifications of persons who make plastic pipe joints.

Section 192.285(d) now uses the term “his.” As SIRRC suggested, we are proposing to change this term to “the operator's.”

Recommendation. Remove the requirement from § 192.311 that a “patching saddle” must be used to repair harmful damage to new plastic pipelines if the damaged pipe is not removed.

SIRRC. The committee agreed the recommended change is needed.

Response. We concur with NAPSR that the meaning of “patching saddle” is unclear, although we have stated the term implies a plastic saddle adhered to pipe. Still, there are various means available to effect safe repairs, and we do not think it's necessary to limit the method of repair. Section 192.703(b) would forbid the use of any method that would result in an unsafe condition. So we are proposing to amend § 192.311 as NAPSR recommended.

Recommendation. To prevent underground plastic pipe from being damaged by electrically charged tracer wire and to maintain wire integrity, require separation between pipe and wire, where practical, and require that tracer wire be protected against corrosion.

SIRRC. The committee agreed to accept NAPSR's recommendation. It also agreed that § 192.321, which applies to mains and transmission lines, and § 192.361, which applies to service lines, should be changed as follows:

• Revise § 192.321(e) to read as follows:

(e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire shall not be wrapped around the pipe and contact with the pipe shall be minimized. Tracer wire or other metallic elements installed for pipe locating purposes shall be resistant to corrosion damage, either by use of coated copper wire or by other means.

• Establish § 192.361(g) to match proposed § 192.321(e).

Response. Although there have been only a few instances where highly charged tracer wire damaged buried plastic pipe, we believe separating wire from pipe wherever practical is a reasonable safeguard. It is also reasonable that tracer wire or other metallic means of pipe locating be resistant to corrosion. Therefore, we are proposing to adopt SIRRC's consensus by revising § 192.321(e) and adding § 192.361(g) as set forth below in the proposed amendments section of this notice.

We recognize that continuous separation may not be ensured when wire and pipe are installed together in the same hole made by trenchless technology. In fact, in such cases the wire is often randomly taped to the pipe to control separation during installation. The proposed requirement to minimize contact with the pipe should not deter this common installation practice.

Note that part 192 does not now require that underground plastic service lines have a means for locating the lines. However, operators commonly use tracer wire for this purpose as they do under existing § 192.321(e) for locating underground plastic mains and transmission lines.

Recommendation. Amend § 192.353(a) to emphasize that vehicular damage is a type of damage from which meters and service regulators must be protected.

SIRRC. Although the committee members agreed that the existing rule implicitly requires protection from vehicular damage, they did not agree on the need to emphasize this type of damage. Industry members thought emphasizing vehicular damage would cause more disputes with government inspectors over what level of protection is needed.

Response. In enforcing § 192.353(a), our position has been that the provision that meters and service regulators must be protected from “corrosion and other damage” requires reasonable protection from vehicular damage where warranted. SIRRC's Summary Report supports this position. Furthermore, AGA's “Guide for Gas Transmission and Distribution Piping Systems,” which advises operators on compliance with Part 192, recognizes this requirement. It states with regard to § 192.353(a) that if the potential for vehicular damage is evident, the meter or service regulator should be protected or an alternate location selected.

NAPSR reported that its members had found meter sets that were damaged by vehicles or were at serious risk of such damage. When this information is considered in light of the industry's apparent understanding of the present rule, it indicates some operators may have been lax in providing needed protection. Emphasizing vehicular damage in the present rule should at least cause operators to pay more attention to the problem and perhaps reduce the risk of damage. So we are proposing to adopt NAPSR's recommendation by amending § 192.353(a) to emphasize vehicular damage.

Although § 192.353(a) affects design and does not apply to pipelines constructed before it went into effect, protection from vehicular damage is also a safety concern on earlier constructed pipelines. These pipelines, however, are subject to the general maintenance standard of § 192.703(b), which requires operators to correct any pipeline that becomes unsafe. If the safety of a meter set is jeopardized by vehicular traffic, the operator would have to take action under § 192.703(b) to correct the problem.

Recommendation. Amend §§ 192.457(b) and § 192.465(e) to clarify the meaning of “electrical survey” and what circumstances make an electrical survey “impractical.” Also, require operators to consider all relevant information when using an alternative to an electrical survey.

SIRRC. The committee concluded that electrical surveys are seldom used on distribution systems, so there is no advantage to requiring electrical surveys as a preferred corrosion inspection method on distribution systems. SIRRC further concluded that if electrical surveys are not used, all available information should be used to determine if active corrosion exists. The committee agreed that the second sentence of § 192.457(b), as it relates to distribution lines, and § 192.465(e) should be changed to read as follows:

• § 192.457(b):

The operator shall determine the areas of active corrosion by electrical survey or by analysis and review of the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment. For the purpose of this section, an electrical survey is a series of closely spaced pipe-to-soil readings over a pipeline which are subsequently analyzed to identify any locations where a corrosive current is leaving the pipe.

• § 192.465(e):

(i) For transmission pipelines, after the initial evaluation required by paragraphs (b) and (c) of § 192.455 and paragraph (b) of § 192.457, each operator shall, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator shall determine the areas of active corrosion by electrical survey, or where an electrical survey is impractical, by analysis and review of the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment.

(ii) For distribution pipelines, after the initial evaluation required by paragraphs (b) and (c) of § 192.455 and paragraph (b) of § 192.457, each operator shall, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator shall determine the areas of active corrosion by electrical survey or by analysis and review of the pipeline condition. Analysis and review shall include, but is not limited to, leak repair history, exposed pipe condition reports, and the pipeline environment.

(iii) For the purpose of this section, an electrical survey is a series of closely spaced pipe-to-soil readings over a pipeline which are subsequently analyzed to identify any locations where a corrosive current is leaving the pipe.

SIRRC also agreed that “pipeline environment” refers to whether soil resistivity is high or low, wet or dry, contains contaminants that may promote corrosion, or has any other known condition that might influence the probability of active corrosion.

Response. We recently revised the corrosion control regulations for hazardous liquid and carbon dioxide pipelines in 49 CFR part 195 (Docket RSPA-97-2762; 66 FR 66994; Dec. 27, 2001). In doing so, we relied on SIRRC's suggestion on monitoring unprotected gas transmission lines as a basis for revising the requirement to monitor unprotected pipe (see 49 CFR 195.573(b)). Because we believe SIRRC's approach is reasonable for both transmission and distribution lines, we are proposing to adopt the SIRRC suggestion on monitoring these lines by revising § 192.465(e) as set forth below in the proposed amendments section of this notice.

However, rather than change the second sentence of § 192.457(b) as SIRRC suggested, we are proposing to delete the second sentence because we think it's unnecessary. This sentence, which is repeated in § 192.465(e), is no longer needed in § 192.457(b) because the time for completing the initial evaluation of the need for corrosion control required by § 192.457(b) has expired. All subsequent evaluations are required by § 192.465(e). Also, we are proposing to move the definition of “active corrosion,” now in § 192.457(c), to § 192.465(e).

Recommendation. Amend § 192.459 to clarify that when an operator examines the exposed portion of a buried pipeline, the operator must determine the condition of the coating and keep a record of the condition under § 192.491.

SIRRC. The committee agreed that records of coating condition are important in evaluating the overall condition of a pipeline, and that this information helps meet the continuing surveillance and active corrosion rules. The committee suggested that § 192.459 be revised to read as follows:

Response. In light of NAPSR's recommendation and an earlier recommendation by the National Transportation Safety Board on inspecting exposed pipe, we revised § 192.459 to require that operators determine the extent of any corrosion that is found on the exposed portion of a pipeline (64 FR 56981, Oct. 22, 1999). At a minimum, the present rule requires that operators inspect exposed pipelines to see if the coating on coated pipe has deteriorated. In addition, § 192.491(c) requires a record of each inspection “in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist.” Thus we have essentially adopted the SIRRC consensus, because the combination of § 192.459 and § 192.491(c) adequately addresses the need to examine and record the condition of coating on exposed coated pipe.

Recommendation. Amend § 192.467(d) to require annual electrical tests on casings to determine if there is contact with the encased pipe. Also, require remedial action according to Recommendation No. 19 if contact is found.

SIRRC. The committee did not reach agreement on the need to conduct annual tests for shorted casings, although consensus was reached on remedial action as discussed below regarding Recommendation No. 19. Industry's position on annual testing was that separate tests on casings are unnecessary as long as the pipe potential is above −850Mv. NAPSR's position was that because a shorted casing shields encased pipe from protective current, the encased pipe can corrode regardless of the potential of pipe outside the casing.

Response. A large majority of PS-124 commenters opposed NAPSR's recommendation on the ground that no correlation had been found between shorted casings and corrosion of the encased pipe. One commenter alleged that the purpose of § 192.467(c), which requires isolation of gas pipe from casings, is to maintain protective current levels.

Also, several commenters addressed the shorted casing issue in response to our San Antonio meeting notice. Five persons said shorts should be cleared because using more protective current to offset the short could have adverse effects. Two other commenters said that clearing shorts can be costly if the line must be taken out of service or replaced, and that there is no consensus on the adequacy of other remedial measures. Another San Antonio commenter suggested the present electrical isolation requirement of § 192.467(c) is not needed since cathodic protection has to meet the part 192 criteria for adequacy. In this regard, AGA's Gas Piping Technology Committee (GPTC) has submitted a rulemaking petition to rescind the requirement to isolate gas pipe from metallic casings, arguing there are no safety benefit from clearing shorted casings.

Considering the conflicting opinions on the need to clear shorted casings to prevent pipe corrosion, we have decided not to propose to adopt NAPSR's recommendation for annual testing. Instead we will consider the recommendation in a separate rulemaking proceeding called “Pipeline Safety: Controlling Corrosion on Gas Pipelines” (RIN 2137-AD63). In that proceeding, we will examine the need to change part 192 to improve the industry's corrosion control practices in light of new technology and the new requirements for hazardous liquid and carbon dioxide pipelines in 49 CFR part 195.

Deferring the recommendation also will give us time to gather more information on the shorted casing issue. We are particularly interested in receiving comments from anyone who has empirical data on the relation of shorted casings to pipe corrosion.

Recommendation. Amend § 192.475(c) to express the permissible level of hydrogen sulfide in parts-per-million as well as grains.

SIRRC. The committee agreed no further rulemaking action is needed.

Response. The PS-124 Final Rule included NAPSR's recommended change to § 192.475(c).

Recommendation. Require all aboveground pipelines exposed to the atmosphere to meet the same atmospheric corrosion control and remedial requirements, no matter when the pipeline was installed.

SIRRC. The resolution of the committee was that all exposed aboveground pipe should be subject to the same atmospheric protection standards. The committee agreed that § 192.479 should be revised to read as follows, and explained that “active corrosion” does not include non-damaging corrosive films:

(a) Each aboveground pipeline or portion of a pipeline that is exposed to the atmosphere must be cleaned and either coated or jacketed with a material suitable for the prevention of atmospheric corrosion. An operator need not comply with this paragraph, if the operator can demonstrate by test, investigation, or experience in the area of application that active corrosion does not exist.

(b) If active corrosion is found on an aboveground pipeline or portion of pipeline, the operator shall—

(1) take prompt remedial action consistent with the severity of the corrosion to the extent required by the applicable paragraphs of §§ 192.485, 192.487, or 192.489; and

(2) clean and either coat or jacket the areas of atmospheric corrosion with a material suitable for the prevention of atmospheric corrosion.

Response. Section 192.479 prescribes atmospheric protection requirements according to the date of pipeline installation. Pipelines installed after July 31, 1971, must be entirely protected from atmospheric corrosion, except where the operator can demonstrate that a corrosive atmosphere does not exist. In contrast, pipelines installed before August 1, 1971, need only be protected where atmospheric corrosion has progressed to the point that remedial action is required under § 192.485, § 192.487, or § 192.489. Periodic monitoring to determine the need for remedial action is required by § 192.481.

As previously stated, we recently revised the corrosion control regulations in 49 CFR part 195 governing hazardous liquid and carbon dioxide pipelines. The old rule on protection from atmospheric corrosion (§ 195.416(i)) required full protection of all pipelines exposed to the atmosphere, regardless of the date of installation. Based on San Antonio comments that the old rule was overly burdensome, we revised the rule to allow operators to avoid coating pipelines they demonstrate will have either a light surface oxide (a non-damaging corrosion film) or atmospheric corrosion that will not affect safe operation before the next scheduled inspection (§ 195.581).

We believe § 195.581 is consistent with SIRRC's suggested change of § 192.479. Section 195.581 requires the same level of protection for old and new pipelines. Also the exceptions for a light surface oxide and corrosion that will not need remedial action before the next scheduled inspection are equivalent to SIRRC's exception of non-active corrosion. One of our goals in revising the Part 195 corrosion control regulations was to establish similar corrosion control requirements for gas and liquid pipelines wherever appropriate. Therefore, in keeping with this goal, we are proposing to use § 195.581 instead of SIRRC's suggestion as the basis for changing § 192.479. The existing standards for remedial action, §§ 192.485, 192.487, and 192.489, will provide a benchmark for any demonstrations that protection is not required before the next inspection.

NAPSR did not recommend any change to the periodic monitoring requirements of § 192.481. These requirements are comparable to the monitoring requirements for hazardous liquid and carbon dioxide pipelines under § 195.583. Both sections require monitoring for atmospheric corrosion at least every 3 years for onshore pipelines and every year for offshore pipelines. And both sections require remedial action if harmful atmospheric corrosion is found. However, § 195.583 specifies particular pipeline features, such as soil-to-air interfaces, that must be inspected, and specifies what remedial action to take. Although these differences are minor, we think the monitoring requirements for gas and hazardous liquid pipelines should be in accord. Therefore, we are proposing to amend § 192.481 to comport with § 195.583.

PS-124 commenters representing industry largely objected to NAPSR's recommendation to treat old and new pipelines alike. They feared they would have to fully protect all pre-August 1971 pipelines regardless of whether harmful corrosion was present. However, there is no basis for this concern under proposed § 192.479. Operators would not have to protect any pre-1971 pipeline or portion of pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will only be a light surface oxide or not affect safe operation before the next scheduled inspection. We believe this approach is consistent with the present rule.

Recommendation. Specify what operators must do to protect carrier pipe when a shorted casing cannot be cleared.

SIRRC. The committee agreed that § 192.483(d) should be established to read as follows:

(d) If it is determined that a casing is electrically shorted to a pipeline, the operator shall:

(1) Clear the short, if practical;

(2) Fill the casing with a corrosion inhibiting material;

(3) Monitor for leakage with leak detection equipment at least once each calendar year with intervals not exceeding 15 months; or

(4) Conduct an initial inspection with an internal inspection device capable of detecting external corrosion in a cased pipeline, and repeat at least every 5 years at intervals not exceeding 63 months.

Response. As stated above in response to Recommendation No. 16, there is conflicting information on the need to clear shorted casings. Therefore, we are not now proposing to adopt SIRRC's suggested options for dealing with shorted casings. Instead, as with Recommendation No. 16, we will consider this recommendation in a separate rulemaking proceeding called “Pipeline Safety: Controlling Corrosion on Gas Pipelines” (RIN 2137-AD63).

Recommendation. Amend § 192.483 to refer to appropriate consensus standards that are to be used in determining the remaining strength of corroded pipe.

SIRRC. The committee agreed that further rulemaking action is not needed.

Response. The Final Rule in Docket PS-124 covered NAPSR's recommendation in an amendment to § 192.485(c). Thus, we agree with SIRRC that further action is not needed.

Recommendation. Clarify that internal sealing of graphitized pipe is not a method of strengthening the pipe.

SIRRC. The committee agreed that the problem of graphitization should be addressed case-by-case rather than by changing § 192.489 as NAPSR recommended.

Response. New technology may result in liners that strengthen as well as seal pipe. Therefore, we agree with SIRRC that § 192.489(b) should not be changed as NAPSR recommended.

Recommendation. Amend §§ 192.505 and 192.507 to clarify that the test pressure must be high enough to substantiate the maximum allowable operating pressure (MAOP) under § 192.619(a)(2)(ii).

SIRRC. The committee did not reach an agreement on this recommendation. NAPSR members contended some operators have not substantiated MAOP because §§ 192.505 and 192.507 do not specify a minimum test pressure. On the other hand, industry members thought that because § 192.503(a)(1) already requires that pressure tests substantiate MAOP under § 192.619, there is no need to repeat the requirement in §§ 192.505 and 192.507.

Response. We addressed this issue once before. In 1988 we amended § 192.503(a)(1) specifically to indicate that § 192.619 prescribes the minimum test pressure needed to substantiate MAOP (53 FR 1635). We think this earlier action adequately clarified the minimum test pressures, and no further action is needed.

Recommendation. To establish consistent leak test pressures for mains and service lines, require that non-plastic service lines operated at less than 1 psig be tested to at least 10 psig. Also, require that each main and service line operated at 1 psig or more be tested to 90 psig or 1.5 times the intended operating pressure, whichever is higher.

SIRRC. The committee did not reach a consensus on this recommendation. Industry members were concerned that additional equipment would be needed to test above 90 psig, and that testing existing service lines at higher pressures (as when service is reinstated or connected to a new main) could cause failures. NAPSR countered that operators could use plastic pipe test equipment, and that a test failure indicates the line is unsafe.

Response. NAPSR felt the minimum leak test pressures prescribed by §§ 192.509(b) and 192.511(b) and (c) for mains and service lines should be the same because mains and service lines are operated together. NAPSR also felt the resulting safety factors should not diminish as operating pressures increase, as they do under the present rules. Many PS-124 commenters, including some operators, agreed with NAPSR. However, AGA and other operators said there is no need to leak test steel mains and service lines operating at less than 100 psig at 1.5 times operating pressure. These commenters argued that the purpose of leak tests is not to assure the pipeline is unlikely to fail at operating pressure, but to verify that the pipeline does not leak.

The regulatory history does not explain why minimum leak test pressures under §§ 192.509(b) and 192.511(b) and (c) are not consistent. Nevertheless, lack of consistency, by itself, does not justify additional or more stringent test requirements. A link between inconsistency and safety would be needed, and NAPSR did not establish such a link. Also, because only tests for leaks rather than pipeline integrity are at issue, we do not think safety factors are relevant to determining if the present leak test pressures are appropriate. Therefore, we are not proposing to adopt NAPSR's recommendation.

Recommendation. To aid compliance investigations, amend § 192.517 to require that operators keep records of leak tests done under § 192.509 for pipelines to operate below 100 psig, of leak tests done under § 192.511 for service lines, and of leak tests done under § 192.513 for plastic pipelines.

SIRRC. The committee disagreed about what information is needed in leak test records. Also, industry members were concerned that distribution operators would have to keep a very large volume of individual records of limited use.

Response. Section 192.517 requires operators to record certain information about pressure tests done under §§ 192.505 and 192.507 to qualify steel pipelines to operate at 100 psig or more. NAPSR recommended that we extend this requirement to other pipelines that are pressure tested for leaks. While a few PS-124 commenters supported the recommendation, most did not. Those who opposed the recommendation generally argued that since leak tests are not as significant as tests done under §§ 192.505 and 192.507, it is unnecessary to maintain the same information about both types of tests.

Without appropriate records, government inspection personnel have a difficult job of determining if required leak tests were indeed done. They may have to interview witnesses or draw inferences from related information. On the other hand, government's need for records must be weighed against the burden on operators to produce and maintain the records. By and large, PS-124 commenters and SIRRC industry members did not object to keeping records of leak tests. In fact, the SIRRC Summary Report states that keeping some type of leak test record is a common industry practice. It was the extent and volume of the records that SIRRC's industry members found objectionable.

In our view, NAPSR's recommended leak test records would be too burdensome, because the safety significance of leak tests is less than that of pressure tests done to establish the MAOP of pipelines operating above 100 psig. At the same time, it seems that industry's voluntary practices may satisfy the need for records to demonstrate compliance with leak test requirements. Therefore, while we are not proposing to adopt NAPSR's recommendation, we are proposing to amend § 192.517 to require that operators maintain a record of each test required by §§ 192.509, 192.511, and 192.513 for at least 5 years. This proposal should accommodate the industry's various voluntary recordkeeping practices, and allow time for government inspectors to view the records. The proposed rule would apply to leak tests done after the rule takes effect.

Recommendation. Clarify that § 192.557 does not allow MAOP to be increased without substantiation by pressure testing.

SIRRC. The committee did not reach a resolution on this recommendation. Industry members were concerned that NAPSR's recommended changes to § 192.557 would unintentionally prohibit the uprating of some pipelines that could be uprated under the present rule. However, the committee did agree that in § 192.553(d) the reference to “this part” should be changed to “§§ 192.619 and 192.621” to specify the sections that limit MAOP.

Response. We decided not to propose to adopt NAPSR's recommendation because we feel the requirement to base any increase in MAOP on a test pressure is clear under § 192.553(d). This section limits any increase in MAOP to the maximum allowed for new pipelines, which, under § 192.619(a)(2)(ii), must be based on a pressure test. However, we are proposing to adopt SIRRC's suggested change to clarify § 192.553(d).

Recommendation. Remove expired compliance deadlines from § 192.607.

SIRRC. The committee agreed the recommendation was no longer needed.

Response. The Final Rule in PS-124 repealed § 192.607.

Recommendation. Require that operators notify the public and known excavators about excavation damage prevention programs at least once a year.

SIRRC. The committee agreed to defer the recommendation to RSPA's damage prevention improvement team. (The work of that team has been assumed by the Dig Safely division of the Common Ground Alliance, a nonprofit organization that promotes best practices in damage prevention.)

Response. The present rule requires operators to notify the public and known excavators “as often as needed” to make them aware of the operator's program. This open-ended frequency permits operators to vary the timing and number of notices to recipients according to the results of their programs. Presumably fewer notices would be needed in an area where the incidence of excavation damage is low or dropping. Conversely, more would be needed if the incidence is high or increasing. Although NAPSR felt the rule should prescribe a minimum rate of notification, it did not explain why annual notification is appropriate in all situations. And we do not have data to support such an across-the-board rule change. Nevertheless, we think NAPSR's concern is mitigated by the authority of RSPA and state agencies under § 192.603(c) to require operators to modify their damage prevention procedures on a case-by-case basis as needed for safety. Meanwhile, we are working with the Common Ground Alliance to help operators improve their public education programs. If the need for rulemaking on notification frequency becomes apparent as a result of that effort, we will propose the necessary rule changes.

Recommendation. Amend § 192.615(a)(3)(i) to require that operators' procedures for handling emergencies provide for prompt and effective response to reports of gas odor inside or near buildings.

SIRRC. The committee did not reach consensus on the recommended change to § 192.615(a)(3)(i), because many operators consider gas-odor reports to be potential, but not actual, emergencies. Instead, the committee agreed that operating and maintenance manuals under § 192.605(b) are a better place for procedures on responding to gas-odor reports.

Response. We agree that not all reports of gas odor indicate that gas has actually been detected. Some reports may merely indicate that someone smells what is thought to be gas but which upon investigation cannot be confirmed as gas. If operators had to treat all reports of gas odor as emergencies, their ability to respond to true emergencies might decline. Thus we are not proposing to adopt NAPSR's recommendation.

Regardless of whether a gas odor report is an emergency, both PS-124 commenters and SIRRC recognized the need for prompt investigation of gas odor reports to determine if a hazardous situation exists. We believe that by and large operators respond promptly to gas odor reports and have procedures for doing so. Nevertheless, to insure that operators have adequate procedures for responding promptly to gas odor reports, we are proposing to adopt SIRRC's suggested alternative by establishing § 192.605(b)(11). Because some operators may prefer to apply their emergency procedures to all reports of gas odor, the proposed rule allows them to do so.

Recommendation. Require that operators sample gas to assure proper odorant concentration at least six times a year with an instrument capable of determining the percentage of gas in air.

SIRRC. The committee did not agree on the frequency of sampling. Industry members wanted to maintain the flexibility of the current rule, which allows operators to determine frequency based on need. NAPSR members wanted to add certainty to the rule by requiring a sampling frequency that is in keeping with common practice.

Nevertheless, the members did agree the rule should require use of an instrument, although they recognized that sampling for odorant concentration could not be done without an instrument. They also agreed the master meter exception should be relocated to minimize the potential for confusion over the acceptability of using “sniff” tests.

Response. The present rule requires operators to conduct periodic sampling to assure the proper concentration of odorant. However, operators of master meter systems (which exist mainly in mobile home parks and multifamily housing) do not have to conduct sampling if the operator verifies the system receives properly odorized gas and performs “sniff” tests to confirm the presence of odorant at the ends of the system.

NAPSR intended its recommendation to address two concerns. The first was that some operators, other than master meter operators, used “sniff” tests rather than instruments to determine odorant concentration. The second was that the required sampling frequency is vague. Regarding the first concern, both PS-124 commenters and SIRRC recognized that the present sampling requirement cannot be satisfied without using an appropriate test instrument. Indeed we believe use of an instrument is common industry practice, because a sniff test cannot accurately determine the concentration of odorant. Therefore, we are proposing to amend § 192.625(f) to state specifically that an instrument must be used to determine odorant concentration. In addition, we are not proposing to relocate the master meter exception, because we do not think its present location confuses the acceptable use of “sniff” tests.

As to NAPSR's second concern, we are certainly mindful of the importance of clarity in regulations. Yet we are uneasy about proposing a minimum sampling frequency that is not backed by consensus or a safety justification that supports the frequency. At the same time, we are persuaded by PS-124 commenters and SIRRC's industry members' view that sampling frequency is more appropriately determined on the basis of system conditions. A system might need sampling more often than six times a year in problem locations but less often at locations where odorant concentration consistently meets requirements. Also, under § 192.605(b)(1), each operator's operating and maintenance procedures must provide odorant sampling frequencies, and operators must be able to justify the frequencies. Finally, under § 192.603(c), government regulators are authorized to challenge any sampling frequencies they consider deficient on the basis of safety data. They may also require operators to amend their procedures after considering any relevant information the operator provides. We believe this review and amendment process serves as a check on any possible misuse of sampling flexibility. Therefore, we are not proposing to establish a minimum sampling frequency.

Recommendation. Amend § 192.723(b)(2) to allow leeway in meeting the leakage survey intervals.

SIRRC. The committee members agreed that NAPSR's recommendation was appropriate.

Response. In the proceeding called “Periodic Updates to Pipeline Safety Regulations (1999)” (56 FR 15290; Mar. 22, 2000), we proposed to amend § 192.723(b)(2) as NAPSR recommended.

Recommendation. Clarify the meaning of “correct pressure” in § 192.739(c) and “insufficient capacity” in § 192.743(c) by cross-referencing § 192.201, which limits the overpressure of pipelines protected by pressure relieving and limiting stations.

SIRRC. The committee agreed that both sections should cross-reference § 192.201. However, the committee revised NAPSR's recommended wording to clarify that the set point of overpressure protective devices may be above the downstream MAOP.

Response. We are proposing to change §§ 192.739(c) and 192.743(c) consistent with SIRRC's suggestions. The proposed changes would require that relief devices at existing pressure limiting and regulating stations meet the same standards for operation and relieving capacity as newly installed relief devices. The PS-124 comments and SIRRC's perspective indicate that industry practices are generally in accord with this approach to compliance with §§ 192.739(c) and 192.743(c). So we believe the proposed changes would clarify these regulations and not add significantly to the costs of compliance.

Recommendation. In view of the disadvantages of testing relief devices in place (cost, noise, and potential safety hazards from escaping gas), change § 192.743 to allow operators to use calculations to determine if relief devices are of sufficient capacity without first having to determine that testing the devices in place is not feasible.

SIRRC. The committee members agreed to accept NAPSR's recommendation.

Response. Under the present rule, operators may not use calculations to determine necessary relief capacity until they determine that testing existing relief devices in place is not feasible. In addition to SIRRC, most PS-124 commenters supported NAPSR's recommendation. For the reasons NAPSR advanced, we also believe the recommended change is appropriate. Therefore, we are proposing to change §§ 192.743(a) and (b) to remove the present preference for testing relief devices in place.

Recommendation. For each transmission line valve inspected under § 192.745, require that operators take immediate remedial action on any valve found to be inoperable, inaccessible, improperly supported, subject to external loads or unusual stresses, or inadequately protected from unauthorized operation, tampering, or damage.

SIRRC. The committee did not reach a resolution on this recommendation. Industry members questioned the need for the recommended changes.

Response. Section 192.745 requires annual inspection of transmission line valves that might be needed during an emergency. Because § 192.745 requires each inspection to include partial operation of the valve, there is no question operators must maintain these valves in an operable condition.

Section 192.745 does not regulate how soon a valve must be corrected if it is found inoperable. NAPSR recommended immediate remedial action. Most PS-124 industry commenters preferred to act “as soon as practical,” so they would not have to disrupt other essential services. But NAPSR did not think this phrase reflected the urgency of the situation.

In the absence of a specified time limit for remedial action, operators may take a reasonable time. Although a reasonable time may be satisfactory for some maintenance duties, we agree with NAPSR that emergency valves found inoperable need priority attention. Therefore, we are proposing to amend § 192.745 to require operators to take prompt remedial action if any valve is found inoperable. Requiring prompt action rather than immediate action should allow operators the latitude they sought in scheduling maintenance activities, yet assure a timely response.

Part 192 design and construction regulations already address most of NAPSR's other objectives. For instance, § 192.179(b), a design rule, requires that onshore transmission line block valves be readily accessible, protected from tampering and damage, and adequately supported. In addition, § 192.317, a construction rule, requires protection of transmission lines from external loads and unusual stresses. Moreover, if for any reason an emergency valve becomes unsafe, such as by damage or loss of support, § 192.703(b) would require remedial action. While § 192.703 does not establish a time limit for remedial action, we think a reasonable time is sufficient for any deficiency that does not make the valve inoperable. Therefore, we are not proposing to adopt NAPSR's recommendation to shorten the allowable response time to deficiencies that do not make an emergency valve inoperable.

Part 192 does not regulate the protection of transmission line valves from unauthorized operation. However, operators commonly provide valve security. And unauthorized operation of valves has not been a significant problem on transmission lines. Also, operators of large systems can detect unauthorized operation of valves through monitoring of system pressures. Following the events of September 11, 2001, we began working with operators and other federal agencies to consider the need to improve the security of critical pipeline facilities. Given these circumstances, we are not now proposing to regulate the unauthorized operation of transmission line valves.

Recommendation. Change § 192.747, which requires annual inspection and servicing of each valve that may be needed for safe operation of a distribution system, to apply only to valves that operators designate for use in an emergency. Also, require partial operation of each emergency valve, and immediate remedial action if the valve is found to be inoperable, inaccessible, improperly supported, subject to external loads or unusual stresses, or inadequately protected from unauthorized operation, tampering, or damage.

SIRRC. Although the committee did not reach consensus on this recommendation, it agreed that remediation could include designation of an alternate emergency valve. Industry members were particularly concerned that partial operation could cause some valves to close inadvertently, with potentially dangerous consequences, and could damage valves not designed for frequent operation.

Response. NAPSR's rationale for limiting the present rule to designated emergency valves was to make clear which valves are to be inspected. However, we think § 192.605(b)(1), which requires operators to have procedures for complying with § 192.747, adequately addresses NAPSR's concern. Operators' procedures should not only explain how to inspect and service valves, but also identify which valves are to be inspected and serviced. In addition, valves intended for safe operation of a distribution system may not be the same valves operators might designate for use in an emergency. So limiting the present rule to emergency valves for the sake of clarity could inadvertently narrow the rule.

Still we think that any valve that may be needed for safe operation of a distribution system should receive priority attention if it is found inoperable. Therefore, we are proposing to amend § 192.747 to require prompt remedial action if any such valve is found inoperable, unless the operator designates an alternate valve. For the reasons stated above in response to Recommendation No. 33, we are not proposing to adopt NAPSR's recommendation to require immediate remedial action on deficient valves that remain operable. Further, because of the possibility of adverse consequences to the valve or others, we are not proposing to require partial operation of valves.

The accessibility of distribution system valves has been a safety problem in some situations. For instance, if a valve essential to stop the flow of gas in an emergency is found to be paved over, the resulting delay in operating the valve can worsen the emergency. We think § 192.605(b)(1) addresses this problem. This rule requires distribution operators to have and follow procedures to carry out the safety valve maintenance requirements of § 192.747. And these procedures should identify which distribution system valves are subject to § 192.747. If an identified safety valve is paved over without notice between annual inspections, the operator should discover the problem no later than the next annual inspection. At that time the operator would have to either correct the problem in order to carry out the inspection or revise its procedures to designate an alternative safety valve.

Recommendation. Correct the conflict between § 192.621(a)(3), which allows a pressure as high as 25 psig in cast iron pipe with unreinforced bell and spigot joints, and § 192.753(a), which requires cast-iron bell and spigot joints subject to pressures of 25 psig or more to be sealed.

SIRRC. The committee members agreed the conflict should be corrected.

Response. We are proposing to change § 192.753 to remove the conflict.

RSPA does not consider this proposed rulemaking to be a significant regulatory action under Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, the Office of Management and Budget (OMB) has not received a copy of this rulemaking to review. RSPA also does not consider this proposed rulemaking to be significant under DOT regulatory policies and procedures (44 FR 11034: February 26, 1979).

We prepared a Draft Regulatory Evaluation of the proposed rules, and a copy is in the docket. This regulatory evaluation concludes that the proposed changes to existing rules may actually reduce operators' costs to comply with those rules because some proposals have compliance options. If you disagree with this conclusion, please provide information to the public docket described above.

The proposed rules are consistent with customary practices in the gas pipeline industry. Therefore, based on the facts available about the anticipated impacts of this proposed rulemaking, I certify, pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605), that this proposed rulemaking would not have a significant impact on a substantial number of small entities. If you have any information that this conclusion about the impact on small entities is not correct, please provide that information to the public docket described above.

The proposed rules have been analyzed in accordance with the principles and criteria contained in Executive Order 13084, “Consultation and Coordination with Indian Tribal Governments.” Because the proposed rules would not significantly or uniquely affect the communities of the Indian tribal governments and would not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13084 do not apply.

Proposed §§ 192.517(b) and 192.605(b)(11) contain minor additional information collection requirements. Operators would be required under § 192.517(b) to maintain for 5 years records of certain leak tests, and under § 192.605(b)(11) to have procedures for responding promptly to a report of gas odor inside or near a building. However, we believe most operators already maintain records of leak tests and have procedures for responding to reports of gas odor inside or near buildings. Also, we believe the burden of retaining these records is minimal. These records are largely computerized. Maintaining these records on a floppy disk or computer file represents very minimal costs. So, because the additional paperwork burdens of this proposed rule are likely to be minimal, we believe that submitting an analysis of the burdens to OMB under the Paperwork Reduction Act is unnecessary. If you disagree with this conclusion, please submit your comments to the public docket.

This proposed rulemaking would not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million or more to either State, local, or tribal governments, in the aggregate, or to the private sector, and would be the least burdensome alternative that achieves the objective of the rule.

We have analyzed the proposed rules for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq. ). Because the proposed rules parallel present requirements or practices, we have preliminarily determined that the proposed rules would not significantly affect the quality of the human environment. An environmental assessment document is available for review in the docket. A final determination on environmental impact will be made after the end of the comment period. If you disagree with our preliminary conclusion, please submit your comments to the docket as described above.

We do not want to impose new requirements that would mandate business process changes when the resources necessary to implement those requirements would otherwise be applied to “Y2K” or related computer problems. The proposed rules would not mandate business process changes or require modifications to computer systems. Because the proposed rules would not affect the ability of organizations to respond to those problems, we are not proposing to delay the effectiveness of the requirements.

The proposed rules have been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). The proposed rules do not propose any regulation that: (1) Has substantial direct effects on the States, the relationship between the National government and the States, or the distribution of power and responsibilities among the various levels of government; (2) imposes substantial direct compliance costs on State and local governments; or (3) preempts state law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.

For the reasons discussed in the preamble, RSPA proposes to amend 49 CFR part 192 as follows: