Comment Summary on Gas Transmission Annual Report

OMB Control # 2137-0522

One Rule Comments Specific to Gas Transmission Annual Report

Comments

Q1. INGAA, API, AOPL, and TPA commented that reporting mileage to three decimal places is more precise than is needed or justified. INGAA suggested miles be reported to the nearest tenth. The other commenters would report to the nearest mile.

A1. Response

PHMSA agrees that reporting of mileage to three decimal places is unnecessary. At the same time, PHMSA notes that there are some pipelines less than one mile in length and for which it would be unclear whether zero or one should be reported if reporting were by mile. PHMSA has revised the form to allow reporting to one decimal place and has indicated that rounding to the nearest mile is allowed.

The annual report describes the status of a pipeline at the end of the reporting year and/or events that occurred during that year. Gathering lines that become regulated during a year should be reported as part of infrastructure on that year’s annual report. Regulated events (e.g., incidents) that occur during the year and following the date on which the lines become regulated should also be reported.

Q2. Part A - Operator Information

NAPSR would add CO2 to the list of commodities given that transport of CO2 as a gas is likely to become more prevalent with forthcoming carbon sequestration projects. SWGas and Paiute suggested defining “assets,” as used in Part A.

INGAA and TPA recommended deleting the last boxes in question 8, “DOES THIS REPORT REPRESENT A CHANGE FROM LAST YEAR’S FINAL REPORTED NUMBERS FOR ONE OR MORE OF THE FOLLOWING PARTs:” They contended that virtually all operators will experience one or more of these changes and that the rare case where none of the boxes would be checked does not warrant the inconvenience for others to respond. SWGas and Paiute requested clarifying the scope of changes that would trigger a response in question 8. NiSource commented that operators who experience no changes should not have to complete the remainder of the form. NiSource reads the form to indicate that operators with changes must complete only those sections for which changes affect the reported data while operators who do not experience any changes must complete the entire form. TPA noted that spaces are needed for operator Headquarters’ state and zip code.

A2. Response

PHMSA recognizes that carbon sequestration projects are likely to result in transport of carbon dioxide in gaseous form. At present, however, PHMSA does not have jurisdiction to regulate transportation of carbon dioxide as a gas. Legislative change would be required to establish jurisdiction; therefore, PHMSA cannot accept NAPSR’s suggestion to add CO₂ as a gas to the list of commodities transported.

PHMSA accepts that the term “assets,” could be confusing and has replaced this term with “pipelines” and “pipeline facilities,” both of which are defined in the regulations.

PHMSA has revised Question 5 and the instructions to resolve confusion concerning how to report IM data. IM data is to be reported by individual OPID and not as part of a common program under one OPID, as discussed above. The revised question simply asks whether the pipelines and pipeline facilities under the OPID being reported are under an IM program. If not, the form indicates which parts (i.e., those collecting IM-related data) the operator need not complete.

PHMSA has revised question 8 in response to the comments on this portion of the form and to comments made about a similar question on the hazardous liquid pipeline annual report form. PHMSA has combined the blocks operators would use to report changes due to mergers and acquisitions, as suggested by API and AOPL, for the hazardous liquid form because these two terms can be confused and there is no reason to report the events separately. PHMSA has also revised question 8 to indicate that operators who have experienced no changes need not complete many sections of the form for which data would be identical to that reported in the prior year. (Note that this is not applicable to reporting for calendar year 2010 given that the data on this form will be reported for the first time during that year). PHMSA concludes this will reduce the reporting burden for operators who do not experience changes to their pipeline systems. Operators who experience changes due to any of the reasons listed in question 8 must complete the entire form.

PHMSA notes the confusion regarding the intent of question 8. In particular, INGAA and TPA claimed the question was unnecessary because virtually all operators would experience one of the listed changes during any given year. PHMSA advises that simply experiencing such a change does not lead to a “yes” answer to this question. Instead, “yes” indicates that the numbers reported on the prior year’s form have changed as a result of one of the listed events. PHMSA intends to use the responses to this question to understand why data that was reported changed for a given operator from year-to-year and to help prioritize its inspection activities. In addition, eliminating the need for operators who have not experienced changes that affect data reported previously to report the same data again will improve data quality by avoiding collection of inaccurate data due to data entry errors. For example, operators who experience a modification to their pipeline (one of the listed changes) but for whom that modification results in no change to the numbers reported on the prior year’s annual report would answer “no” to question 8 and would not be required to complete the bulk of the form (except for 2010). PHMSA has made editorial changes to the form to emphasize this.

PHMSA has made a number of other editorial corrections to the form, including adding space for operator headquarters’ state and zip code.

Q3. Part B – Transmission Pipeline HCA (High Consequence Area) Miles

INGAA suggested deleting the number of offshore miles because there are not enough miles of offshore transmission pipeline to make the data pertinent.

A3. Response

PHMSA will require reporting of offshore HCA miles. Although there may be few such miles, they do exist (e.g., an offshore platform that includes a transmission line and is occupied by 20 or more persons). Operators who have no offshore HCAs, which PHMSA recognizes will be most operators, may enter zero in this field.

Q4. Part C – Volume Transported in Transmission Pipelines Only in Million Standard Cubic Feet (mmscf)-Miles Per Year

AGA contended that it would be unreasonably burdensome to report volume transported. INGAA and Spectra maintained that because transported gas does not necessarily traverse an entire pipeline reporting volume-miles is impractical and PHMSA should use data already collected by FERC. Atmos, TPA, SWGas, and Paiute commented that this information does not appear relevant to pipeline safety and would be difficult to collect, particularly for bi-directional pipelines. GPTC and Nicor commented that this element is impractical for distribution pipeline systems in which only a small portion of pipeline is defined as transmission due to operating pressure. They noted that it is impractical to determine how much gas flowed through these limited portions of a pipeline system and questioned the safety need for the information. NiSource and NWN also claimed that it is unclear why PHMSA needs this information and that it may be proprietary or is already available from FERC. TPA suggested that, if we retain this section, we specify the reporting basis (e.g., standard temperature and pressure) because some states (e.g., Texas) require reporting of volumes under other pressure bases.

A4. Response

PHMSA recognizes that it is difficult to determine the amount of gas transported, in mmscf-miles, for pipelines with multiple locations at which gas can be collected and delivered. At the same time, an indication of the total volume of gas transported will be useful data for PHMSA’s analysis of pipeline safety performance. Such information can, for example, be used to normalize analyses of different events. PHMSA has revised this part to require reporting of the total volume of gas transported under the reporting OPID during the reporting year for operators who do not operate their transmission lines as part of a distribution pipeline system. PHMSA recognizes that this will not accurately represent the volume carried in only portions of interstate gas transmission systems, but PHMSA believes this strikes an appropriate balance between the burden to calculate mmscf-miles and the need for an overall measure of relative activity of different OPID transmission volumes. PHMSA will use this information with care.

PHMSA also recognizes that it would be particularly difficult for operators of distribution pipeline systems in which only a portion of the pipeline is classified as transmission to estimate the volume of gas carried by their transmission pipelines. PHMSA has revised this part to eliminate the need to report volume transported for operators who operate transmission pipelines as part of a distribution pipeline system. Volume information for these pipelines will be collected on the distribution pipeline system annual report, which PHMSA is currently revising.

PHMSA notes that the proposed instructions for this part included a definition of mmscf as million standard cubic feet and noted that standard conditions are “normally set at 60F and 14.7 psia.” PHMSA has deleted the word “normally” to make clearer that these are the conditions at which volume is to be reported. PHMSA has also revised the proposed instruction to reflect a pressure of 14.73 psia to be consistent with how FERC describes standard conditions.

Q5. Part F - Integrity Inspections Conducted and Actions Taken Based on Inspection

INGAA commented that PHMSA should make clear that only testing conducted as a result of IM requirements (i.e., HCA testing and overtesting) should be reported.

AGA contended that PHMSA has not justified collecting more detailed IM performance data. SWGas and Paiute claimed that PHMSA does not need additional data to judge the adequacy of IM. National Grid does not support reporting information beyond the number of immediate and scheduled repairs in HCAs, because additional data would cause confusion due to overlapping inspection techniques.

Atmos and TPA commented that reporting the number of assessments by tool type would overstate the mileage assessed compared with other assessment types given that operators typically run multiple tools over the same mileage as part of a complete assessment. AGA and NWN claimed that collecting repair data by assessment technique would be burdensome with no apparent safety benefit, and that information concerning assessments conducted by method has no apparent safety value. INGAA, GPTC, and NiSource recommended deleting questions concerning inspections by tool type, contending that separate collection is misleading, will lead to incorrect mileage totals, and is of marginal value. INGAA also would limit miles inspected and actions taken for hydrotests to HCA miles because that is the only area with consistent repair criteria.

Atmos and TPA also maintained that reporting the number of conditions identified for repair by various assessment techniques, particularly outside HCAs, will provide no useful information given that there are no common criteria for when repairs are required. AGA argued that repairs outside of HCA should not be reported because this data serves no safety benefit and PHMSA has not justified collecting this data. GPTC, NiSource, Nicor, NWN, Piedmont, and INGAA also supported this position.

AGA and NWN maintained it would be more useful to collect data on anomalies identified by assessment cycle (e.g., baseline, first re-assessment) rather than by tool.

National Grid noted that because “one year” and “scheduled” conditions are the same under § 192.933, both terms should not be used. GPTC and Nicor would clarify that the number of anomalies within HCAs (section 2c) should be the number repaired. AGA, GPTC, NWN, SWGas, Paiute, NiSource, and Nicor suggested that consistent and more-detailed definitions are needed for the terms leak, failure, incident, and rupture if consistent reporting is to be achieved. They further suggested PHMSA consider whether events of this type are to be reported based only on IM assessments or from all means by which they are identified. BG&E suggested that PHMSA conform terms to their use elsewhere and specifically use the terms “immediate,” “scheduled,” and “monitored,” as used in Subpart O of Part 192, to refer to anomalies of concern under IM requirements.

Sempra Energy Utilities (Sempra) recommended modifying this part to allow an operator to reference another OPID for IM data. This would accommodate situations in which IM activities are managed under a common program for multiple OPIDs. NWN also noted that IM programs are often run in common for multiple OPIDs making it difficult to break out the data for individual OPIDs.

GPTC noted that question 5b refers to in-line inspection (ILI) even though the subject of question 5 is non-ILI techniques. NiSource would delete Part F5, since it duplicates information collected elsewhere on the form.

A5. Response

PHMSA does not understand completely why INGAA believes that only testing conducted as a result of IM requirements should be included. If, as INGAA suggested “overtesting” (i.e., testing of non-HCA miles assessed as part of an IM inspection) were included, what would be excluded for these segments? While the regulations establish maximum reassessment intervals, they also require that operators base their reassessment intervals on the identified threats, data from the last assessment and data integration (§ 192.939). Assessments that are conducted at shorter intervals than the maximums specified in the regulations provide additional data that must be considered in data integration and thus come under the provisions of IM regulations (see the response to FAQ-70 on the gas integrity IM website, http://primis.phmsa.dot.gov/gasimp, for additional discussion). Therefore, all testing on pipelines with HCAs must be reported.

Assessments that are conducted on pipelines that do not contain any HCAs are a different matter. Such pipelines are not covered by the IM provisions of the regulations. Operators are not required to report data for portions of these pipelines that they may assess for other reasons. PHMSA will consider future regulatory changes to establish requirements for reporting assessments and repair actions on pipeline segments that do not include HCAs.

Although PHMSA recognizes that there are no criteria in the regulations for when anomalies outside of HCAs must be repaired, PHMSA is aware that operators repair many anomalies outside of HCAs. PHMSA considers it important to understand when such repairs are being made and any trends (e.g., are the number of repairs increasing over time). PHMSA recognizes that operators use different criteria for these repairs and that the data must therefore be used with care. This does not mean, however, that the data is not meaningful. Any data that is indicative of the condition of U.S. pipelines has value in PHMSA’s analyses and decision making. PHMSA disagrees with INGAA’s suggestion that repairs performed as a result of hydrotests should only be reported when they occur within HCA miles. Hydrotests identify defects, by causing leakage or a rupture, which must be repaired and, therefore, provide the most consistent “criteria” for repair of defects outside HCAs of any assessment method.

Similarly, collecting data by tool type and other assessment methods will be useful in informing PHMSA decision making and in improving PHMSA’s understanding of the relative effectiveness and extent of use of various assessment methods. PHMSA recognizes that adding the miles assessed by different assessment methods provides a result that appears to overstate the number of pipeline miles actually assessed. Adding miles does, however, provide a better indicator of the number of miles by assessment method. Again, PHMSA recognizes that the totals need to be used with caution. Still, it will be appropriate to use them for some purposes, while miles inspected using individual tools (also collected in this part) or total HCA miles (collected in Part B) will be more appropriate for other uses.

PHMSA agrees that it could be more useful to collect data on the number of repairs in each assessment cycle. The effectiveness of IM regulations would be demonstrated by a reduced number in subsequent reassessments. PHMSA considers, however, that it would be more difficult to collect and use this data. New HCAs on pipelines previously assessed make it unclear how to differentiate between baseline and reassessment, for example. Given that operators now collect data per integrity assessment method trends in this data over time will better reflect the relative effectiveness of IM.

PHMSA has been careful to use terms with meanings commonly understood within the pipeline industry. The terms “leak,” “failure,” and “incident” are defined in the instructions consistent with ASME/ANSI B31.8S and with current regulations. PHMSA recognizes that these terms are used in other situations and will try to ensure consistent use on other forms. Use of the term “scheduled” to identify some IM anomalies is also consistent with the regulations and is not redundant with “one-year conditions.” Section 192.933(c) requires that operators schedule some anomalies for remediation consistent with the scheduling provisions of ASME/ANSI B31.8S, while § 192.933(d)(2) identifies some specific anomalies as “one-year conditions.” PHMSA has revised the section references on the form (which both previously referred only to § 192.933) to make this distinction more clear.

PHMSA acknowledges that question 5 in Part F inaccurately referred to ILI inspections. This question is intended to address assessments by other techniques. PHMSA has corrected this error, which eliminates the duplication NiSource noted.

We addressed above in the section on “Creating a National Registry of Pipeline and LNG Operators” comments about reporting IM data by individual OPID vs. under a common program.

Q6.Part G – Miles of HCA Baseline Assessments Completed

INGAA suggested that this section be broken into separate sub-sections for each reassessment. Atmos and TPA reported that they did not see how reporting assessments by vintage was useful. Spectra noted that HCA miles complicate the treatment of vintage given that an assessment by ILI often inspects more than just HCA mileage. A new HCA within a piggable segment, for example, may undergo a baseline assessment at the same time that other HCAs within the segment are being reassessed.

A6. Response

At this time, PHMSA agrees that collecting data on assessment vintage (i.e., first, second, etc.) is not necessary. PHMSA may revisit the need for this information as part of future activities. PHMSA has revised this part to collect data on the number of baseline miles completed and the number of reassessment miles (regardless of vintage). PHMSA expects that there will be a reduction in the number of anomalies identified in reassessments vs. initial baseline assessments, and needs this data to validate that expectation.

Q7. Part H – Miles of Pipe by Nominal Pipe Size

INGAA noted that the proposed form does not allow reporting of odd pipe sizes. The form provides for reporting of even pipe sizes specified in modern standards, but INGAA noted that intermediate sizes may exist in older systems, particularly for grandfathered pipe. INGAA also noted that the largest pipe size included in the form is 36-inch diameter and pointed out that larger pipe is being used/planned for some gas transmission pipelines.

A7. Response

PHMSA acknowledges that odd pipe sizes may exist in some pipeline systems, including small diameter pipe (e.g., 5-inch diameter) and pipe installed in older pipeline systems before pipe sizing was standardized. PHMSA has modified the form and instructions to accommodate reporting of odd pipe sizes and to include sizes larger than 36-inch diameter.

Q8. Part J- Miles of Transmission Pipe by Specified Minimum Yield Strength

AGA, NWN, SWGas, and Paiute commented that reporting pipeline mileage by specified minimum yield strength (SMYS) would be unduly burdensome because records are incomplete, grandfathered pipe may not fit into standard categories, and information technology (IT) changes would be needed to track mileage by SMYS. These commenters see no safety benefit in doing so. Atmos and TPA would also delete this section although they recognized there could be some benefit in reporting for pipelines operating under special permits or at 80% SMYS where special regulatory attention may be needed. They suggested that targeted reporting for these pipelines should be established rather than imposing an unjustified burden on all pipeline operators. TPA claimed that some operators of gathering pipelines treat all of their lines as Type A rather than determining the percentage of SMYS at which they operate and that it would be unreasonable to require operators to make this determination solely for this reporting.

NiSource noted that no allowance is made for pipelines operating at an unknown percentage of SMYS even though the regulations allow operations without this determination. For example, § 192.739 provides for determining a pressure limit for pipeline operating at an unknown percentage of SMYS. NiSource also noted that plastic and iron pipe are excluded, even though some transmission pipe is constructed of these materials. NiSource also claimed that the information collected via Part J largely duplicates information from Part K, miles of pipe by class location.

INGAA suggested that we eliminate blacked-out cells (implying that no pipeline should exist in that category) and noted that there is no offshore transmission pipeline that exceeds 72 percent SMYS.

A8. Response

PHMSA considers this data to be important. The thresholds dividing the various categories in the table reflect regulatory requirements (e.g., change in design factors) and PHMSA needs to have an understanding of the inventory of pipe to which these requirements apply. PHMSA notes that INGAA, which represents transmission pipeline operators who would tend to have pipeline across the range of allowable percentages of SMYS, did not object to reporting this data. Rather, AGA and some of its member companies expressed concerns. These companies generally operate distribution pipeline systems. While many of their systems include some transmission pipeline, the amount is relatively less and most tend to operate in the lower percentage SMYS categories. Thus, the burden for completing this section will be less for these companies.

While the regulations establish design thresholds consistent with those in this part, existing pipelines do not always fit into these neat categories. Pipe that was installed prior to the time pipeline safety regulations were initially established (i.e., pre-1970) may operate at maximum allowable operating pressures (MAOP) based on historical operation prior to that date (so-called “grandfathered pipe”) and this pressure is in some cases in excess of 72 percent SMYS. Some pipe operates under special permits that allow different MAOP. Some pipe operates at MAOP greater than originally designed due to changes in class location and the allowance for pressure increase that is inherent in § 192.611. PHMSA is not persuaded by arguments that it is too hard for pipeline operators to acquire this data. Pipeline operators should acquire this data wherever possible because of its importance. Pipe operating at a higher percentage of SMYS has less safety margin. It is important that operators know where this pipe is and take this factor into account in the risk analyses required by IM regulations.

For these reasons, PHMSA has retained this part. PHMSA has made changes in response to the other comments concerning this part. PHMSA has eliminated blacked out cells. As discussed above, grandfathering, special permits, and other circumstances could result in pipe operating at various combinations of MAOP and class location and PHMSA agrees it is more appropriate to allow for data collection in all categories. Operators with no pipe in individual categories will simply enter zero. The revised form allows for pipe that operates at an unknown percentage of SMYS and for pipelines other than steel. PHMSA has also deleted the row corresponding to offshore transmission pipeline with MAOP greater than 72 percent SMYS.

The information collected in this part does not duplicate that in Part K. PHMSA agrees that the information in the two parts is related. Important information will be obtained through analyses that compare the information obtained in each of these parts. This will help PHMSA understand, for example, the amount of pipe that operates at MAOP higher than initial design due to the automatic-increase provisions in §192.611. It is necessary to collect the data in both parts to allow this kind of correlation to be made.

Part J applies to transmission pipeline. Operators of gathering lines need not complete Part J.

Q9. Part K - Miles of Pipe by Class Location

SWGas and Paiute commented that this section appears to replicate Part B insofar as it relates to miles in HCA. They claimed it could be confusing to report miles that are not in an HCA but which must be inspected anyway under the IM program.

SWGas recommended that we exempt distribution pipeline operators that also report on transmission pipeline they operate. Many distribution operators treat all of their pipeline as Class 3 or 4 and do not perform analyses to determine accurately the class location of their transmission pipeline. SWGas opposed requiring such analyses solely to meet this reporting requirement.

A9. Response

PHMSA agrees that reporting HCA miles in the IM program in this part duplicates Part B and has eliminated this section of Part K.

This part does not require that operators perform Class location studies if they do not do so for other purposes. Operators of distribution pipeline that treat all of their pipeline as Class 3 or 4 should report the mileage that they consider to be in each Class.

Q10.Part L1 - Leaks Eliminated/Repaired During Year and Failures/Incidents in HCA

Atmos, NWN, and TPA requested clarification as to whether leaks repaired in IM assessments and reported in Part F are also to be reported in this part.

Nicor and NWN suggested reorganizing the columns for failure, leak, and incident data in order of severity to provide clarity and help assure consistent reporting. AGA noted that the failure category was omitted for gathering pipelines.

NAPSR suggested adding a column for unregulated gathering lines, as they consider that data should be collected for all gathering lines.

A10. Response

Operators are to report all leaks both in HCAs and outside HCAs. Failures and incidents are to be reported for HCAs. This is an existing performance measure required by §192.945 (through reference to ASME/ANSI B31.8S) that has been reported on semi-annual performance measure reports.

PHMSA agrees that reordering the columns in order of relative severity could improve clarity and has made that change.

While PHMSA agrees with NAPSR that it would be beneficial to have data for unregulated gathering lines, such lines are by definition unregulated. PHMSA cannot impose a reporting requirement on these pipelines without a regulatory change. Such changes are beyond the scope of this rulemaking.

Q11. Part N - Certifying Signature

Atmos and TPA suggested that a separate signature block be used to certify IM information because the proposed form implies certification of the entire form, which is not required. INGAA noted that the references to the parts of the form containing IM information, and for which certification is required, were incorrect.

A11. Response

PHMSA has revised the form to make it clearer that executive certification applies only to IM information. PHMSA will also clarify this in the on-line electronic reporting system.

Q12. Instructions

Atmos and TPA commented that the instructions need to reflect electronic reporting and address the requirements for seeking alternate reporting methods.

TPA suggested that the instructions define interstate pipelines as those to subject to FERC jurisdiction “under the Natural Gas Act” rather than simply “subject to FERC jurisdiction,” noting that some intrastate pipelines are subject to limited FERC jurisdiction.

NAPSR suggested defining synthetic gas. NAPSR also suggested clarifying the instructions on counting repaired leaks. For example, if a section of pipe with leaks is replaced, does PHMSA consider that one repair or must the number of leaks within the section be reported?

SWGas and Paiute contended that the definition of operator in the instructions is inconsistent with the definition in the regulations in that it introduces the term “substantial control.”

INGAA suggested that the instructions for Part F, Question 4 should refer to “meeting repair criteria” rather than “exceeding.” INGAA also suggested that the instructions for Part G should mirror those for Part F.

SWGas and Paiute suggested that the instructions for Part J clarify reporting for pipe that is classified as transmission under the functional aspects of the regulatory definition even though it operates at less than 20% SMYS.

A12. Response

PHMSA has revised the instructions to address requirements for applying for alternate methods (i.e., non-electronic) of data submission and to use the statutory definition of interstate pipeline from 49 USC 60101. PHMSA has included a definition of synthetic gas that is consistent with the definition in the instructions for the new incident report form. PHMSA has also reviewed and revised all definitions to be consistent with regulations.

Counting leaks has always been problematic. As NAPSR pointed out, when a section of pipe is replaced due to leakage, an operator could count the repair as one repair or as the number of leaks in the replaced section. When replaced pipe is retired in place, it may not be possible to count the number of leaks. Operators have previously been required to report the number of leaks repaired as part of their annual reports. Operators should report the number of leaks repaired based on the best data they have available. For sections replaced, but retired in place, operators should consider leak survey information to determine, to the extent practical, the number of leaks in the replaced section.

PHMSA has made editorial changes concerning repair of anomalies “meeting” repair criteria. INGAA’s suggestion that the instructions for Part G mirror those for Part F was predicated on its recommended expansion of Part G so that the parts would be similar in content. As discussed above, this change is not necessary because we have simplified Part G to reflect only baseline and reassessment miles, regardless of vintage.

PHMSA does not understand the basis for confusion over whether Part J should apply to transmission pipelines operating at less than 20 percent SMYS. The proposed part explicitly included a section in the form for pipeline operating at less than or equal to 20 percent SMYS. Nevertheless, PHMSA has clarified in the instructions that Part J applies to all transmission pipeline.

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2137-0522

One Rule Comment-Responses

Specific to Gas Trans. Annual Report

PHMSA F-7100.2-1