U.S. DOT/PHMSA - Regulatory Evaluation

Page 1m. O f impomm -..-, „,, U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration ' ^ " " Regulatory Evaluation September 2007 Pipeline Safety: Protecting Unusually Sensitive Areas from Rural Onshore Hazardous Liquid Gathering Lines and Low-Stress Pipelines Docket No. PHSMA-2003-158f i - ^- 1- ! Regulatory Analysis For Final Rule I. INTRODUCTION Currently, rural onshore hazardous liquid gathering lines and rural onshore hazardous liquid low-stress pipelines are exempt from most of the Pipeline and Hazardous Materials Safety Administration's (PHMSA's) safety rules for transportation of hazardous liquids by pipeline. A spill from one of these could cause substantial harm to an unusually sensitive environmental area. 1.1 Rural Onshore Hazardous Liquid Gathering Lines PHMSA is applying limited operation and maintenance requirements, along with reporting requirements for accidents and safety related conditions, and requiring the use of line markers to certain currently unregulated rural onshore hazardous liquid gathering lines. Specifically, the gathering lines impacted by this regulatory change are those located in or within 1/4 mile of an unusually sensitive area (USA) as defined in 49 CFR § 195.6' that • Have a nominal diameter fi-om 6 5/8 to 8 5/8 inches, and • Operate at a stress level of more than 20% of SMYS during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, at a pressure of more than 125 psig. For these rural onshore hazardous liquid gathering lines, PHMSA is making the following changes to 49 CFR Part 195: ' A USA is defined in 49 CFR § 195.6 as "drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release."#

Page 2Including the gathering lines in a new definition of "regulated rural onshore gathering lines;" ^ Requiring operators of "regulated rural onshore gathering lines" to follow safety rules for design, construction, testing, and maximum operating pressure; Requiring operators of "regulated rural onshore gathering lines" to protect those pipelines from corrosion and excavation damage; Requiring operators of "regulated rural onshore gathering lines" to install and maintain line markers; Requiring operators of "regulated rural onshore gathering lines" to undertake public education programs; Requiring operators of "regulated rural onshore gathering lines" to demonstrate Operator Qualification (OQ) compliance; and Requiring operators of "regulated rural onshore gathering lines" to report accidents and safety-related conditions and to make annual reports. Develop a program to monitor and mitigate operating conditions that could lead to internal corrosion. 1.2 Rural Onshore Hazardous Liquid Low-Stress Pipelines PHMSA is extending the safety rules for the transportation of hazardous liquids by pipeline contained in 49 CFR Part 195 to certain rural onshore low-stress pipelines. Specifically, the low-stress pipelines impacted by this regulatory change are those located in or within 1/2 mile of a USA as defined in 49 CFR § 195.6 that • Have a nominal diameter of 8 5/8 inches or more, and • Operate at a stress level of 20% or less of SMYS during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, at a pressure of 125 psig or less. Additionally, PHMSA is requiring operators of all unregulated rural low-stress lines to file annual, accident, and safety-related condition reports. 1.3 Intent of PHMSA's Regulatory Changes The changes summarized above are to improve the safety of rural onshore hazardous liquid pipelines and to help protect USAs. Furthermore, they are intended to be responsive to the requirements relating to hazardous liquid pipelines included in the Pipeline Inspection, Protection, Enforcement, and Safety (PIPES) Act of 2006 (Pub. L. No. 109-468) and other laws. ^ Certain gathering lines are currently regulated. Those gathermg lines are sometimes collectively referred to as "regulated gathering lines" (see, for example, PHMSA's file on the Internet containing the 2004 annual reports for hazardous liquid pipelines at http://ops.dot.gov/stats/DT98.htm). This, however, is a term of art and is not currently defined in the Federal pipeline safety regulations pertaining to hazardous liquid pipelines.#

Page 31.4 Purpose of this Report In this report, the benefits and costs of the regulatory changes included in the final rule are examined. The report also includes other mandatory analyses, including the analysis required by the Regulatory Flexibility Act. 2. BACKGROUND 2.1 Hazardous Liquid Gathering Lines Hazardous liquid gathering lines are primarily pipelines transporting crude oil fi"om wells to downstream locations, such as refineries. These pipelines can be found in rural and non-rural areas as well as onshore and offshore. It is estimated by the Association of Oil Pipelines (AOPL) that between 30,000 and 40,000 miles of crude oil gathering lines are currently in operation in oil producing states.^ The Federal safety regulation found in 49 CFR Part 195 defines a "gathering line" as a pipeline with a nominal outside diameter of 8 5/8 inches or less that transports petroleum from a production facility. "Petroleum," as defined in Part 195, means crude oil, condensate, natural gasoline, natiaral gas liquids, and liquefied natural gas. A "rural area" is defined as a location outside the limits of any incorporated or unincorporated city, town, village, or any other designated residential or commercial area, such as a subdivision, a business or shopping center, or community development. Federal safety regulations covering the transportation of hazardous liquids by pipeline found at 49 CFR Part 195 apply to both offshore and onshore hazardous liquid gathering lines. Onshore gathering lines in rural areas, however, are currently exempt fi-om all Part 195 regulations, except those relating to inspection and burial in Gulf of Mexico inlets (i.e., 49 § CFR 195.1(b)(4)). It should be noted that, because of their higher operating pressures, PHMSA expects that major pipeline firms operate the rural onshore gathering lines impacted by the final rule. 2.2 Low-Stress Pipelines Low-stress pipelines are hazardous liquid pipelines operating at 20% or less of the specified minimum yield strength (SMYS) of the line pipe. Most pipelines moving large volumes of petroleum or petroleum product do so at high pressures (i.e., over 20% of SMYS). The economics of pipeline operation, and the physical characteristics and condition of a pipeline may result, however, in a pipeline operating at 20% or less of SMYS. For instance, the lifetimes of pipelines that are in poor condition may be extended by operation at lowered pressures. Furthermore, low-pressure operation may result fi-om market conditions or reduced volumes of pipeline throughput. Safety ^ See "How Many Pipelines are There?" at http://www.pipeline 101 .com/Overview/energv-pl.html. This estimate is for oil producing states. Consequently, it might not include mileage in Outer Continental Shelf (OCS) waters outside of state control.#

Page 4regulations for hazardous liquid pipelines, contained in 49 CFR Part 195, had not previously been applicable to pipelines operating at low-stress outside populated areas, except for those that cross navigable waterways (49 CFR § 195.1(b)(3)).'' On September 6, 2006, PHMSA published a Notice of Proposed Rulemaking (NPRM) proposing to apply limited, threat-focused pipeline safety requirement to larger-diameter rural onshore low-stress hazardous liquid pipelines within a defined buffer of USAs (71 FR 52504). USAs are non-populated areas requiring extra protection because of the presence of sole-source drinking water resources, endangered species, or other ecological resources that could be adversely affected by accidents or leaks occurring on hazardous liquid pipelines. The proposed requirements were limited to those that would address the most common threats to these rural low-stress pipelines. After PHMSA had issued the NPRM, the PIPES Act was signed into law on December 29,2006. Section 4 of the PIPES Act requires PHMSA to "issue regulations subjecting low-stress hazardous liquid pipelines to the same standards and regulations as other hazardous liquid pipelines" with some limited exceptions. The Act allows the new regulations to be phased in. In response to the PIPES Act requirement, on May 18,2007, PHMSA published a Supplemental Notice of Proposed Rulemaking (SNPRM) to apply all of Part 195 to the low-stress pipelines proposed for coverage in the NPRM, except that the buffer was extended fi-oml/4 mile to 1/2 mile (72 FR 28008). On October 31,1990, an Advance Notice of Proposed Rulemaking (ANPRM) entitled "Transportation of a Hazardous Liquid in Pipelines Operating at 20 Percent or Less of Specified Minimum Yield Strength" was published in the Federal Register. The ANPRM included a questionnaire designed to elicit information about the existence of pipelines operating at 20% of SMYS or less including their age, condition, length, and use, as well as their failure records fi-om 1986 through 1990. The questionnaire also requested information about whether the pipelines were currently being operated in compliance with Part 195, and, if not, what the one-time and continuing costs of bringing them into compliance would be. The responses by industry to the ANPRM questionnaire can be found in the docket. 3. STATEMENT OF THE PROBLEM 3.1 Gathering Lines With the Pipeline Safety Act of 1992 (Pub. L. 102-508), Congress granted the U.S. Department of Transportation (DOT) the authority to regulate a class of rural gathering lines called "regulated gathering lines." Congress left the definitions of "gathering lines" and "regulated gathering lines" to DOT to develop (see 49 U.S.C. 60101(b)(1)(A) and 49 U.S.C. 60101(b)(2)(A)). In the Accountable Pipeline Safety and Partnership Act (Pub. L. " * For a full discussion of the background concerning historical treatment of low-stress rural pipelines and the decision to apply safety regulations at this time, see the September 6, 2006, notice.#

Page 5104-304), Congress amended the requirement to define "regulated gathering lines" by adding the words "if appropriate." Congress also gave DOT the authority to collect information from gathering line operators related to deciding whether and to what extent to regulate rural gathering lines. Congress recognized that some rural gathering lines might pose risks warranting Federal safety regulation. As a consequence, it gave DOT authority to regulate a class of rural gathering lines called "regulated gathering lines" based on risk-related physical characteristics, such as diameter, pressure, location, and length of line. In its report on H.R. 1489, a bill that led to the Pipeline Safety Act of 1992, the House Committee on Energy and Commerce stated that: DOT should find out whether any gathering lines present a risk to people or the environment, and if so how large a risk and what measures should be taken to mitigate the risk.^ PHMSA believes that this instruction shows that Congress wanted DOT to limit "regulated gathering lines" to lines posing a significant risk and to limit regulation of those lines to suitable risk-reduction measures. Seeking more information specifically about rural gathering lines, DOT asked the public about whether these pipelines pose a risk warranting Federal safety regulation and, if so, what those regulations should be. Most commenters recognized the need for Federal safety regulation, and most felt that the regulations should address knovm risks of a significant scale. In association v^th its comments, the AOPL provided incident data showing that corrosion and excavation damage are the leading causes of spills on gathering lines overall (i.e., for both rural and non-rural gathering lines). It should also be noted that there is no reason to expect that rural gathering lines are any less vulnerable to corrosion, excavation damage, or other integrity threats than non-rural gathering lines. Consequently, PHMSA believes that it is reasonable to assume that AOPL's incident data are representative of the safety situation with respect to rural gathering lines. This belief is strengthened by the findings of a 1997 report by California's Office of the State Fire Marshal entitled, "An Assessment of Low-Pressure Crude Oil Pipelines and Gathering Lines," which found that the leading causes of pipeline incidents from 1993 to 1995 on rural gathering lines and other pipelines exempt from Part 195 were corrosion and excavation damage.^ As a consequence of Congress' safety concerns, comments received from stakeholders, and accident data, PHMSA believes that the potential for fiiture harm to people and the environment from rural gathering lines is clear. Furthermore, based on the foregoing, PHMSA believes that the present exemption of rural gathering lines from nearly all safety regulations in 49 CFR Part 195 is no longer appropriate. The final rule aims to H.R. Report No. 102-247, Part 1, 102"" Congress, T' Session, 23 (1991). 6 This report is available on the Internet at http://osfin.fire.ca.gov/lowpressrpt.html.#

Page 6fiilfill Congress' statutory mandate as it relates to rural onshore gathering lines by amending 49 CFR Part 195. 3.2 Low Stress Lines Beginning in 1991, Congress paid greater attention to the risks that hazardous liquid and natural gas pipelines pose to the environment. In the Pipeline Safety Act of 1992 (Pub. L. 102-508), Congress gave DOT greater authority to protect the environment from the risks that pipelines pose. Congress continued to emphasize the need to better protect the environment from pipeline risks in the Accountable Pipeline Safety and Partnership Act of 1996 (Pub. L. 104-304). With the PIPES Act of 2006, Congress went ftirther and instructed DOT to subject low-stress hazardous liquid pipelines to the same regulatory standards as other hazardous liquid pipelines regulated under Part 195. Recent accidents have demonstrated the need to regulate the safety of low-stress pipelines, particularly those near USAs. For instance, on March 2, 2006, a spill from HP's 34-inch unregulated low-stress pipeline in North Slope Borough, Alaska, released 5,000 barrels of crude oil, impacting the artic tundra and covering approximately 2 acres of permafrost. On March 23, 2006, a spill from BP's 36-inch low-stress pipeline in Toledo, Ohio, released 200 barrels of unleaded gasoline, some of which found its way into Shantee Creek, which flows to Lake Erie, On August 6, 2006, BP found corrosion and leaks in its unregulated low-stress pipeline in North Slope Borough, Alaska. The discovery of severe corrosion and the lesJcs caused BP to shut the pipeline down. Because of this, production from part of the massive Prudhoe Bay oilfield also had to be shutdovm. PHMSA sees no reason to expect unregulated low-stress pipelines to be less vulnerable to corrosion, excavation damage, and other integrity threats than higher pressure regulated lines. Low-stress pipelines may be even more vulnerable because they have not been subject to Federal safety regulation to ensure their continued integrity. Based on Congress' and PHMSA's safety concerns, public comments, and available accident data, PHMSA believes the potential for future harm to people and the environment from unregulated rural low-stress pipelines is clear. These pipelines have the same leading causes of accidents as the hazardous liquid pipelines that PHMSA regulates. Therefore, PHMSA believes it is no longer appropriate to exempt these lines from Part 195 coverage. This is sfrengthened by Congress's recent mandate. 4. RATIONALE FOR REGULATORY ASSESSMENT Executive Order (EO) 12866 directs Federal agencies to develop both preliminary and final regulatory analyses if their new or revised regulations are likely to be "significant regulatory actions" tihat may have an annual impact on the economy of $100 million. EO 12866 also requires a determination about whether a new or revised rule could adversely affect the economy or a section of the economy in terms of productivity, employment, the environment, public health, safety, or State, local or tribal governments. Under the#

Page 7regulatory philosophy and principles provided in sections 1(a) and (b) and section 6(a)(3)(C) of EO 12866, an economic analysis of the new or revised rule must be conducted. Furthermore, the Regulatory Flexibility Act of 1980, as amended, requires Federal agencies to conduct a separate analysis of the economic impact of new or revised rules on small entities, and the Unfimded Mandates Act also requires economic impact analysis. Under the above directives, PHMSA has performed an evaluation of the potential compliance costs of the regulatory change and feasible regulatory options and identified those benefits that can be expressed in monetary terms. To the extent possible, this is based on the available data and information from several sources including PHMSA's Incident Reporting Database and comments from stakeholders. PHMSA estimates the impact of implementing the regulatory changes would not be greater than $100 million annually, nor would the regulatory changes adversely affect the economy or a section of the economy in terms of productivity, employment, the environment, public health, safety, or State, local or tribal governments. PHMSA has also determined, as required by the Regulatory Flexibility Act, that the regulatory changes would not have a significant economic impact on a substantial number of small entities in the United States. Additionally, the regulatory changes would not impose annual expenditures of $120.7 million or more on State, local, or tribal governments or the private sector (and thus would not require an Unfunded Mandates Act analysis). 5. ALTERNATIVES CONSIDERED 5.1 Gathering Lines PHMSA considered several alternatives to assure the necessary protection from potential incidents on rural onshore gathering lines. These alternatives were: • No action. • Collect more information about the potential hazards of the rural onshore gathering lines before proposing any specific safety regulations; • Apply all Part 195 regulations to the rural onshore gathering lines; • Implement limited operation and maintenance regulations, along with implementing reporting regulations for accidents and safety-related conditions, to the rural onshore gathering lines; • Develop a completely new set of safety regulations for rural onshore gathering lines; and • Implement limited operation and maintenance regulations, along with implementing reporting regulations for accidents and safety-related conditions and requiring the use of line markers. In this alternative, include regulations for design, construction, and testing of new, relocated, replaced, or otherwise changed lines. The evaluations for the alternatives considered by PHMSA are presented below.#

Page 85.1.1 No Action Congress has mandated that action be taken concerning gathering lines. Not taking action would be unresponsive to the Congressional mandate. For that reason, this alternative is not considered any further in this analysis. 5.1.2 Collect more information about the potential hazards of the rural onshore lines before proposing any specific safety regulations This alternative received some support from industry, and Congress did grant DOT specific authority to collect more information about hazards before proposing any safety regulations. This alternative was rejected, however, because PHMSA feels that there is currently a demonstrated need for safety regulation. Also, based on PHMSA experience with hazardous liquid pipelines, collecting more information about the rural onshore gathering lines would be unlikely to change the current understanding concerning the potential risks these lines pose. For these reasons, collecting more information about the potential hazards of the rural onshore lines was evaluated no ftirther. 5.1.3 Apply all Part 195 regulations to the rural onshore lines This alternative would impose significant costs on the industry for little safety benefit. Also, the costs could have a significant effect on U.S. oil supplies by causing production to cease at marginal wells connected to the lines. For these reasons, applying the regulations from Part 195 to rural onshore lines was not evaluated ftirther. 5.1.4 Implement limited operation and maintenance rules, along with implementing reporting rules for accidents and safety-related conditions AOPL recommended the approach covered by this aUemative for gathering lines. With respect to gathering lines, the operation and maintenance rules to be implemented would be the public education rules in 49 CFR § 195.440, the excavation damage prevention rules in 49 CFR § 195.442, and the corrosion control rules in subpart H of Part 195. The reporting rules would be provisions of subpart B of Part 195 relating to accidents and safety-related conditions. The benefit of this ahemative would be that it would avoid excessive safety regulation by focusing on the leading threats to rural gathering lines - corrosion and excavation damage. Also, the information collected through application of the reporting rules would enable PHMSA to recognize safety problems and evaluate the effectiveness of adopting only limited safety rules. One disadvantage of this alternative is that it does not include the installation and maintenance of line markers, OQ program requirements, or drug and alcohol requirements. The use of line markers to warn excavators of the presence of hazardous liquid pipelines is a well-established safety practice within the hazardous liquid pipeline industry. Regarding OQ, Congress mandated that PHMSA establish regulations for OQ on pipelines. Congress also directed pipeline operators to develop and adopt a#

Page 9qualification program should DOT fail to prescribe standards and criteria. Finally, requirements on testing for the presence of prohibited drugs and alcohol apply to operators of a pipeline facility subject to Part 195. Because of the gaps noted by PHMSA, this alternative was not considered any ftirther. 5.1.5 Develop a completely new set of safety rules for the rural onshore gathering lines PHMSA rejected this alternative because there is no reason to believe that the Part 195 safety regulations now in effect for non-rural gathering lines would not be as effective if applied to rural gathering lines. PHMSA's experience indicates that Part 195 regulations can be expected to work well for rural gathering lines because the integrity threats involved are similar for all the lines. Consequently, the alternative of developing a new set of safety regulations applicable to the rural onshore gathering lines was not evaluated fiarther. 5.1.6 Implement limited operation and maintenance rules, along with implementing reporting rules for accidents and safety-related conditions and requiring the use of line markers Finally, PHMSA considered a modified version of the alternative discussed above in Section 5.1.4. The modified version of that alternative would add the line marker rules in 49 CFR § 195.410, the qualification requirements in subpart G for operator personnel, and drug testing and alcohol misuse prevention requirements in Part 199 to the other regulations. Line markers are a traditional way of alerting excavators to the presence of a hazardous liquid pipeline. Under 49 U.S.C. 60131, DOT must require pipeline operators to develop and adopt qualification programs complying with the standards DOT develops. Furthermore, any operator subject to 49 CFR Part 195 is required under 49 CFR Part 199 to test covered employees for the presence of prohibited drugs and alcohol. In addition, this modified alternative would require operators to establish a maximum operating pressure for each steel line according to 49 CFR § 195.406, and to design and construct new lines according to applicable Part 195 regulations. A maximum operating pressure with accompanying pressure control would guard against the danger of accidental overpressure. The design and construction regulations in 49 CFR Part 195 would ensure a minimum standard of integrity for all new, replaced, and relocated rural onshore gathering lines designated as "regulated rural onshore gathering lines" PHMSA proposed similar rules on markers, operating pressure, and design and construction for rural gas gathering lines in a final rule published March 15, 2006 (see 71 FR 13289). These additions to the approach suggested by AOPL should not be too burdensome, because similar safety requirements are included in (American Society of Mechanical Engineers) ASME B31.4, a consensus standard followed widely throughout the hazardous liquid pipeline industry. For the reasons outlined above, this alternative was selected for gathering lines.#

Page 105.2 Low-Stress Pipelines PHMSA considered three alternatives to assure the necessary protection from potential incidents on rural onshore low-stress pipelines. These alternatives were: • No action. • Complete the currently outstanding rulemaking relating to low-stress pipelines and then apply Part 195 to all rural onshore low-stress pipelines at the same time. • Apply Part 195 to rural onshore low-stress pipelines in two phases, with the initial phase covering those lines posing the greatest risk to the environment. Evaluations of these alternatives are presented below. 5.2.1 No Action Section 4 of the PIPES Act of 2006 requires Part 195 to apply to all low-stress pipelines, with certain limited exceptions. Not taking action would be unresponsive to the Congressional mandate. For that reason, this alternative is not considered any ftirther in this analysis. 5.2.2 time Complete the currently outstanding rulemaking relating to low-stress pipelines and then apply Part 195 to all rural onshore low-stress lines at the same As mentioned above, on September 6, 2006, PHMSA published an NPRM proposing extending limited threat-focused requirements to larger-diameter rural onshore low-stress hazardous liquid pipelines within a defined buffer of USAs. Those limited threat-focused requirements are less than "the same standards and regulations as [apply to] other hazardous liquid pipelines" required by the PIPES Act. Finalizing that proposal without change would impose some requirements on affected pipelines, only to be followed by additional regulations imposing ftirther requirements. PHMSA considers such sequential application of requirements to be inefficient and to pose an unnecessary additional burden on pipeline operators. Therefore, this alternative is not considered any ftirther in this analysis. 5.2.3 Apply Part 195 to the rural onshore low-stress pipelines in two phases, with the initial phase covering those lines posing the greatest risk to the environment The September 2006 NPRM proposed limited threat-focused requirements for certain rural onshore low-stress hazardous liquid pipelines within a defined buffer of USAs. The low-stress pipelines covered by the rule are those where additional safety regulation is most important - larger-diameter pipelines that can have adverse impacts on USAs. PHMSA believes the most appropriate and expeditious means of implementing the PIPES Act mandate is to act in phases. 10#

Page 11In phase 1, PHMSA undertook to modify the NPRM via a SNPRM to add to the requirements to be applied to the low-stress pipelines covered by the NPRM. Pipelines affected by the phase 1 rulemaking are those low-stress pipelines 8 5/8 inches and greater in diameter. PHMSA believes that most operators of these larger low-stress pipelines also operate pipeline at higher stresses or operate regulated low-stress pipe within populated areas. PHMSA thus has a regulatory relationship with those operators. In phase 2, PHMSA will initiate a separate rulemaking to apply Part 195 to all remaining unregulated rural low-stress pipelines. For the reasons mentioned above, this alternative was selected for low-stress pipelines. 6. ECONOMIC ANALYSIS The benefits and costs of the regulatory changes included in the final rule are addressed in this section of this report. The analysis of benefits and costs takes the following approach: (1) the mileage impacted by the regulatory changes is identified and estimated, (2) the potential benefits of the regulatory changes are examined, (3) the potential costs of the regulatory changes are examined, and (4) a discussion of the expected benefits versus the expected costs are presented. Unless otherwise specified, all dollar amounts in section 6 of this report are given in constant 2005 dollars.^ Because PHMSA has not regulated the pipelines covered by the final rule, PHMSA has only limited information about the pipelines, their location, operating characteristics, and safety performance. Consequently, a number of assumptions have been made in this economic analysis. 6.1 Impacted Mileage Both rural onshore gathering lines and rural onshore low-stress pipelines will be impacted by the regulatory changes included in the final rule. The impacted mileages for each of these two types of pipeline are estimated below. 6.1.1 Gathering Lines The rural onshore gathering line mileage that will be impacted by the regulatory changes is unknown and must be estimated. The impacted mileage would be operated as regulated rural onshore gathering lines. Such regulated rural onshore gathering lines ^ Where necessary, dollars are converted fi-om nominal values to real 2005 values using the Implicit Price Deflators for Gross Domestic Product. The source of these deflators is the annual data version of Table 1.1.9 Implicit Price Deflators for Gross Domestic Product, which is located on the Bureau of Economic Analysis website at http://www.bea.gov/bea/dn/nipaweb/SelectTable.asp?Selected=N. 11#

Page 12• Have a nominal diameter from 6 5/8 to 8 5/8 inches; • Operate at a stress level of more than 20 %of SMYS (specified minimum yield strength) during normal operation or, if the stress level is unknovm or the pipeline is not constructed using a steel pipe, at a pressure of more than 125 psig; and • Are within 1/4 mile of a USA as defined in 49 CFR § 195.6. Information about the mileage of gathering lines in the U.S. is somewhat sketchy. AOPL estimates that there are between 30,000 and 40,000 miles of crude oil gathering lines in this country. ^ This estimated mileage includes both onshore and offshore gathering lines as well as both rural and non-rural gathering lines. A mileage breakdovm between onshore and offshore lines and rural and non-rural gathering lines is not available. PHMSA does have information indicating that pipeline operators have 2,573 miles of crude oil gathering lines that are currently regulated under Part 195. Some of this mileage may be non-rural. Other mileage, however, may be rural mileage located in the inlets of the Gulf of Mexico and subject to 49 CFR § 195.413. It is also known that interstate common-carrier pipelines that are required to file Form 6 with the U.S. Federal Energy Regulatory Commission (FERC) operate approximately 15,000 miles of crude gathering lines.^ Common carrier pipelines are those that charge a fee for their service. There is a filing threshold for Form 6 that is based on pipeline operating revenues, and some common carrier pipelines may have revenues below that threshold and consequently may not be reporting their gathering system mileage to FERC.'° For the purposes of this analysis, the gathering line mileage that would be impacted by the regulatory changes included in the final rule was estimated as follows. As mentioned before, AOPL, an industry group representing pipeline operators, estimates that there are between 30,000 and 40,000 miles of gathering lines in the U.S." The midpoint of AOPL's range, 35,000 miles, is used as the point estimate for the total number of miles of gathering lines in the U.S. Also as mentioned before, DOT currently regulates the safety of approximately 2,600 miles of gathering lines.'^ Those lines, which include all non-rural gathering lines. * The Association of Oil Pipelines estimates that there are between 30,000 and 40,000 miles of gathering lines in the U.S. This includes the mileage of onshore and offshore crude gathering lines (see "How Many Pipelines are There?" at http://www.pipeline 101 .com/Overview/energv-pl.htmn. ' In Warren R. True and Jeannie Stell, "Special Report: Pipeline Economics," Oil & Gas Journal Data Book, 2005 Edition, PennWell Corp., Tulsa, OK, 2005, p. 80, it is reported that these pipelines operated 14,187 miles of gathering lines in 2003, while the pipelines operated 16,214 miles of gathering lines in 2002. '" True and Stell, p. 66. " AOPL's estimate is for oil producing states. It might not include mileage in waters of the OCS outside of state control. Consequently, the actual rural gathering line mileage might be higher than estimated here. '^ This includes all crude oil gathering lines subject to Part 195, including those on the OCS. 12#

Page 13offshore gathering lines, and some rural onshore gathering lines, will continue to be regulated, and furthermore, it is assumed that the regulatory changes included in the final rule will not impact them. Consequently, an estimated 32,400 (= 35,000 - 2,600) miles of rural gathering lines are currently unregulated. The 32,400 mile estimate includes both onshore and offshore mileage. PHMSA assumes that 50% of all rural gathering line mileage is onshore. Thus, an estimated 16,200 (= 0.5 X 32,400) miles of rural onshore gathering lines are currently unregulated. Furthermore, based on comments by AOPL,''' PHMSA assumes that no more than 20% of all onshore gathering line mileage that is currently unregulated meets the following conditions: (1) has a nominal diameter of 6 5/8 inches or greater and (2) operates at greater than 20% of SMYS (or alternatively at a pressure of 125 psig or greater). Thus, PHMSA expects that no more than 3,240 (= 0.2 x 16,200) miles of rural onshore gathering lines (1) have a nominal diameter of 6 5/8 inches or greater and (2) operate at greater than 20% of SMYS (or at a pressure of 125 psig or greater). Some the mileage will not be impacted because it already operates in compliance with Part 195, even though that is not currently required. No information is readily available for gathering lines, but information is available from the 1990 ANPRM questionnaire mentioned earlier on the percentage of low-stress pipelines operating in compliance with Part 195. Though this information is from 1990, it is still relevant, because the energy sector has been predominately stable for the periods of 1990 through 2003 with limited growth in infrastructure or changes in operation. Responses from this questionnaire indicated that approximately 16% of the low-stress mileage of the respondents was operated in compliance with Part 195, while approximately 84% were not.''' Given the situation in 1990 with low stress pipelines, PHMSA assumes that 16% of the rural onshore gathering lines currently operate in compliance with Part 195, while 84% do not. That means an estimated 2,722 (= 0.84 x 3,240) miles of rural onshore gathering lines do not operate in compliance with Part 195. To complete the estimation of the gathering line mileage impacted by the rule, information is needed on the proximity of gathering lines to USAs. According to information contained in the National Pipeline Mapping System, approximately 22% of all regulated hazardous liquid pipeline mileage is within 1/4 mile of a USA.'^ PHMSA assumes for the purposes of this analysis that 22% of the 2,722 miles of onshore gathering lines are within 1/4 mile of a USA. That is, PHMSA assumes that 599 (= 2,722 x 0.22) miles of onshore gathering lines are within 1/4 mile of a USA. " According to AOPL, "gathering lines generally operate...at lo w pressure...." Lines operating at greater than 20% of SMYS , as the NPR M notes, are not operating at lo w pressure. '^ For more detail on this, see p. 8 of "Economic Evaluarion of Regulating Certain Hazardous Liquid Pipelines Operating at 20% or Less of Specified Minimu m Yield Strength," July 21,1992, which can be foun d in Docket PS-117. '^ Communication fi-om Richard Hinton, PHMSA , June 19,2006. 13#

Page 14Since these lines operate at greater than 20% of SMYS, PHMSA assumes that major pipeline firms operate all of these lines. 6.1.2 Low-Stress Pipelines The rural onshore low-stress line mileage that will be affected by the regulatory changes is unknown and must be estimated. Some of the affected low-stress mileage would be brought under the safety regulations of Part 195 by the regulatory changes. That mileage consists of low-stress pipeline with the following characteristics: • Have a nominal diameter of 8 5/8 inches or more, • Operate at a stress level of 20% or less of SMYS during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, at a pressure of 125 psig or less and • Are in or within 1/2 mile of a USA as defined in 49 CFR § 195.6. Additionally, the operators of all unregulated low-stress pipelines would be required by the rule to file annual, accident, and safety-related condition reports with PHMSA for those pipelines. Low-Stress Mileage Brought Under Part 195 PHMSA assumes that approximately 200,000 miles of hazardous liquid pipeline are being used in the transport of petroleum and petroleum products in the U.S. '^ PHMSA regulates approximately 160,000 miles of that pipeline. ' The difference between these two numbers, 40,000 (= 200,000 - 160,000) miles, represents the total unregulated hazardous liquid pipeline mileage currently in operation. This unregulated mileage is made up primarily of low-stress pipelines and rural gathering lines. The Association of Oil Pipelines (AOPL), an industry group representing pipeline operators, estimates that there are between 30,000 and 40,000 miles of gathering lines in the U.S.'^ The midpoint of AOPL's range, 35,000 miles, is used as the point estimate for the total number of miles of gathering lines in the U.S. '^ DOT currently regulates the safety of approximately 2,600 miles of gathering lines.^^ Consequently, an estimated 32,400 (=35,000 - 2,600) miles of rural gathering lines are currently unregulated. Removing these from the 40,000-mile estimate of unregulated pipelines leaves 7,600 (=40,000 - 32,400) miles of pipeline as the estimate for unregulated low-stress lines. '* Richard A. Rabinow, "The Liquid Pipeline Industry in the United States: Where It's Been, Where It's Going," A report prepared for the Association of Oil Pipelines, April 2004, p. 4. " PHMSA, "Liquid Pipeline Operator Total National Mileage," located at http://ops.dot.gov/stats/lpo.htm. '* This includes the mileage of onshore and offshore crude gathering lines (see "How Many Pipelines are There?" at http://www.pipelinel01.comyOverview/energv-pl.htmn. " AOPL's estimate is for oil producing states. It might not include mileage in waters of the OCS outside of state control. Consequently, the actual rural gathering line mileage might be higher than estimated here. ^ ° This includes all crude oil gathering lines subject to Part 195, including those on the OCS. 14#

Page 15Only part of the 7,600 miles of pipeline will be impacted by the changes in the final rule. Some of low-stress pipelines will not be impacted because they are less than one mile long and consequently not covered by the changes. Respondents to the 1990 ANPRM questionnaire mentioned earlier in this report were asked about their low-stress interfacility pipelines (i.e., their low-stress lines that were less than one mile long). According to the responses, approximately 26% of the low-stress mileage of the respondents was interfacility pipeline mileage, while approximately 74% was not.^' Assuming that those percentages have not changed since 1990, an estimated 5,624 miles (= 0.74 X 7,600 miles) of low-stress pipeline are not interfacility pipelines with lengths of less than one mile. Additionally, some of the low-stress mileage will not be impacted because it already operates in compliance with Part 195, even though that is not currently required. Respondents to the 1990 ANPRM questionnaire were asked if their pipelines operated under Part 195. According to the responses, approximately 16% of the low-stress mileage of the respondents was operated in compliance with Part 195, while approximately 84% was not.^^ Assuming that those percentages have not changed since 1990, an estimated 4,724 (= 0.84 x 5,624) miles are not operated in compliance with Part 195. To complete the estimate of the low-stress mileage impacted by the regulatory changes in the final rule, information is needed on the proximity of low-stress pipelines to USAs. According to information from the National Pipeline Mapping System, approximately 27% of all regulated hazardous liquid pipeline mileage is within V z mile of a US A.^'' PHMSA assumes that 27% of the 4,724 miles of low-stress pipeline not currently operating in compliance with Part 195 is within 1/2 mile of a USA. That is, PHMSA assumes that 1,275 (= 4,724 x 0.27) miles of low-stress pipeline not currently operating under Part 195 is within 1/2 mile of a USA. The final rule will only bring those low-stress pipelines with a nominal diameter of 8 5/8 inches or more under Part 195. PHMSA estimates that 63% of all low-stress pipelines have a diameter of 8 5/8 inches or more. Thus, approximately 803 miles of low-stress pipeline will be affected by the final rule.^'* Low-Stress Mileage Required to File Annual, Accident, and Safety-Related Condition Reports Under the final rule, the operators of all currently unregulated low-stress pipelines will be required to file aimual, accident, and safety-related condition reports with PHMSA. That is, the operators of the 4,724 miles of currently unregulated rural onshore low-stress ^' PHMSA. ^ ^ For more detail on this, see p. 8 of "Economic Evaluation of Regulating Certain Hazardous Liquid Pipelines Operating at 20% or Less of Specified Minimum Yield Strength," July 21, 1992, which can be found m Docket RSPA-2003-15864. ^ Communication fi-om Amy Nelson, PHMSA, March 13, 2007. ^ ^ Preliminary results from the pre-test of an industry-wide survey of low-stress pipelines, Volpe Center for PHMSA, 2007. 15#

Page 16pipeline will have to file reports. So, in addition to the operators of the estimated 803 miles of unregulated low-stress pipeline that will be brought under Part 195 because of the regulatory changes, the operators of 3,921 (= 4,724 - 803) miles of unregulated low- stress pipeline that will not be brought under Part 195 safety requirements will also be required to file armual, accident, and safety-related condition reports with PHMSA.^^ Total Impacted Mileage for Low-Stress Pipelines Based on the forgoing, the final rule is expected to bring 803 miles of rural onshore low- stress lines under Part 195 safety requirements and an additional 3,921 miles of rural onshore under Part 195 reporting requirements for annual, accident, and safety-related condition reporting. 6.1.3 Impacted Mileage Summary The following table presents the estimates of the mileage impacted by the regulatory changes included in the final rule. TABLE 1. SUMMARY OF IMPACTED MILEAGE Category Mites Rural Gathering Lines Gathering line mileage impacted 599 Rural Low-Stress Pipelines Low-stress mileage brought under part 803 195 safety requirements Additional low-stress mileage for which 3,921 annual, accident, and safety-related condition reports must be filed 6.2 Benefits The benefits expected from the final rule are improved safety performance for the pipeline mileage brought under Part 195. That is, the final rule is expected to reduce the number of incidents and the incident consequences (including deaths, injuries, property damage, product loss, environmental damage, and environmental spill cleanup activities). This improved safety performance will result in greater public safety and confidence. The final rule is expected to generate benefits from both the impacted gathering lines and the impacted low-stress pipelines. ^ ^ For the purposes of this analysis, the operators of the unregulated low-stress pipeline that is currently operated in compliance with Part 19 5 are assumed to currently make all necessary reports. 16#

Page 176.2.1 Gathering Lines Because rural gathering lines are currently unregulated, PHMSA does not have any recent data showing the total number of incidents that have occurred on the lines. Until 1981, incident data were collected for rural gathering lines, but general improvements in pipeline safety that may have occurred over the years would make using that data in the estimation of the benefits of the final rule questionable. AOPL provided PHMSA with data on 583 gathering line spills collected from five of its member companies for the years 2001 through 2003. The origin of the data was the industry's Pipeline Performance Tracking System (PPTS), a voluntary data collection effort that began in 1999. Participants in PPTS report oil pipeline spills of 5 gallons or more on land and all spills in water, whether regulated by Part 195 or not. AOPL's data show 33% of the spills were 5 barrels or more. The data also show corrosion and excavation damage caused over 90% of the gathering line spills, pipe material and weld failures caused 2%, and other identified causes caused less than 1%. While of considerable interest, because it helps characterize the accident record of currently unregulated crude oil gathering lines, the AOPL data caimot be used for estimating the benefits of the final rule because, among other reasons, the gathering line mileage of the 5 operators is unknown. A total of 583 gathering line spills during a three- year period might represent a significant problem if each of the operators had only 1 mile of pipeline. On the other hand, it might be viewed as inconsequential if each of the operators had, say, and 5,830 miles of gathering lines. In April 1997, the California Office of the State Fire Marshal submitted a report to the California State Legislature entitled "An Assessment of Low Pressure Crude Oil Pipelines and Crude Oil Gathering Lines in Califomia,"^^ This report examined the incident data for all California crude oil pipelines not previously regulated by the state for the years 1993 through 1995. These had 494 miles of pipeline in 1993, and 496 miles of pipeline in 1994 and 1995. The California Fire Marshal's Office found that the pipelines had an incident rate over the period of 6.72 incidents per 1,000 miles per year. This covered all leaks of greater than 1 barrel (42 gallons). The pipelines had a total of 10 incidents (leaks) during the three-year study period. There were no injuries or fatalities attributable to the pipeline incidents. The pipelines, it should be noted, had a mean nominal diameter of 7.5 inches. The California Fire Marshal's Office noted in the same report that the incident rate for 1981 through 1990 for pipelines regulated by the California Fire Marshal's Office was 7.080 incidents per thousand miles per year. This figure included all leaks from the included pipelines. This figure is similar to the estimated incident rate for gathering lines in California. ^ * This report is available on the Internet at http://osfrn.fire.ca.gov/lowpressrpt.html. 17#

Page 18AOPL and the California Fire Marshal's report identified the primary causes of incidents on gathering lines as: (1) corrosion and (2) excavation/third party damage. Protecting against these threats would provide the greatest benefit for crude oil gathering lines. The final rule does just that. The benefits resulting from the final rule are expected to include reduced incident consequences. In particular, there is expected to be a reduction in property damage, lost product, environmental damage, and the costs of cleaning up after a spill (few deaths or injuries appear to occur as a result of crude oil incidents). The Federal safety rules are expected to reduce the number of incidents, as well as their severity. As indicated above, however, the incident data needed to estimate the reduction is not readily available. 6.2.2 Low-Stress Pipelines While PHMSA does not currently collect the data needed to estimate the reduction in the incident consequences attributable to the final rule, it is available for low-stress hazardous liquid pipelines from the responses to the 1990 ANPRM questionnaire. The respondents to the questionnaire provided information for the years 1986 through 1990^^ on incident costs for 1,564.6 miles of low-stress pipeline not currently in compliance with Part 195, as well as incident costs for 265.9 miles of low-stress pipeline reported by the respondents to be in compliance with Part 195. These costs include clean-up, loss of product, repair of the pipeline and restoration of the damaged environment. Table 2 presents information developed from the ANPRM survey for the accident cost per mile per year for low-stress pipelines not operating in compliance with Part 195 and for low-sfress pipelines operating in compliance with Part 195. ^ ^ For more detail on the incident data provided by respondents to the ANPRM questionnaire, see pp. 11-14 of "Economic Evaluation of Regulating Certain Hazardous Liquid Pipelines Operating at 20% or Less of Specified Minimum Yield Strength," July 21, 1992, which can be found in Docket PHMSA-2003-15864. 18#

Page 19TABLE 2. THE ACCIDENT COST PER MILE PER YEAR FOR ANPRM SURVEY PIPELINES (1991 dollars) Item Estlmiite IHpaines Not derating in CompUahee wiOi Part 195 Total mileage for pipelines not complying 1564.6 with Part 195 and providing requisite accident cost data in survey response Total accident cost per year Accident cost per mile per year ^BMifW-'Sm"J^BM^^efatingM^ with Part 19S Total mileage for pipelines complying with $5,776,000 $3,692 265.9 Part 195 and providing requisite accident cost data in survey response Total accident cost per year Accident cost per mile per year $28,000 $105 Source: "Economic Evaluation of Regulating Certain Hazardous Liquid Pipelines Operating at 20% or Less of Specified Minimum Yield Strength," July 21, 1992, which can be found in Docket RSPA-2003- 15864. Note: The pipelines fi-om the survey used in the calculation of the information given in the table were those that met all of the following conditions: (a) had a reported total mileage, rounded to the nearest 1/10* of a mile, that was greater than 0, (b) operated at 20% of SMYS or less or operated at a unspecified percentage of SMYS that was presumed to be less than or equal to 20%, (c) were reported to be operated in compliance with 49 CFR Part 195, (d) had a reported average annual accident cost of $0 or greater, and (e) were reported individually, as specified in the ANRPM, not as a block. Based on the information presented in Table 2, PHMSA estimates the expected incident cost per mile per year for low-stress pipelines not currently in compliance v^th Part 195 to be $4,969 (= $3,692 converted from 1991 dollars to 2005 dollars).^^ Also based on information presented in Table 2, PHMSA estimates that the expected incident cost per mile per year for low-sfress pipelines currently in compliance with Part 195 to be $141 (= $105 converted from 1991 dollars to 2005 dollars).^^ ^ * In calculating the expected incident cost for low-stress pipelines not in compliance with Part 195, PHMSA assumed that an incident of the size of the Arthur Kill pipeline incident, which occurred in January 1990 and was included in the incident for low-stress pipelines not in compliance, would only occur, on average, only once every ten years. This is based upon PHMSA's experience of large releases. Consequently, the reported mcident cost for the Arthur Kill incident was divided by 10 prior to being used to estimate the expected accident cost per mile per year. ^' The respondents to the ANPRM questionnaire used $1.5 million as the economic value of a human life and $450 thousand as the cost to society of an injury requiring hospitalization. The information needed to update these two numbers to the values currently used in PHMSA benefit-cost analyses is unavailable, so the numbers were not updated. 19#

Page 20From the foregoing, the benefits per mile, per year that are expected to result from the regulatory changes are the difference between the incident cost per mile per year for low- stress pipelines not operated in compliance with Part 195 and the incident cost per mile change, the final rule would be expected to result in benefits of approximately $3,876,884 (= $4,828 × 803) per year. As indicated in Table 3, the present value of these benefits over 20 years is estimated to be $58 million at a discount rate of 3% and $41 million at a discount rate of 7%. TABLE 3. ESTIMATED MONETARY BENEFITS RESULTING FROM THE IMPROVED SAFETY OF LOW-STRESS PIPELINES OVER TIME (All values given in thousands of dollars) Estimated Present value of the Present value of the benefits estimated benefits over estimated benefits over resulting from 20 years at a 20 years at a the improved 3% discount rate 7% discount rate safety of low- stress pipelines (per year) $3,877 $57,678 $41,072 6.2.3 Benefits Summary It is expected that the regulatory changes will reduce incident levels on the impacted pipelines and the severity of the consequences to the environment and other damage of the incidents that do occur. The rule also may produce benefits by preventing disruptions in fuel supply caused by pipeline failures. Any interruption in fuel supply impacts the U.S. economy by putting upward pressure on the prices paid by businesses and consumers, as recent incidents on Alaskan low-stress pipelines feeding major petroleum trunk lines have illustrated. Supply disruptions also have national security implications, because they increase dependence on foreign sources of oil. Because of a lack of data, quantitative monetary benefits relating to this expected reduction could not be estimated for the gathering lines impacted by the regulatory changes. What information PHMSA does have indicates that incidents on gathering lines result primarily from (1) corrosion and (2) excavation/third party damage. As a consequence, protecting against those threats would be expected to provide considerable benefit, and the final rule does just that. 20#

Page 21Data were available for the expected reduction in incidents and consequences on low sfress hazardous liquid lines that would result from bringing them under Federal safety regulation. It is expected that the rule will result in approximately $3.9 million per year in benefits for those lines, as shovm in Table 4. TABLE 4. ESTIMATED MONETARY BENEFITS OF THE FINAL RULE OVER TIME (All values given in thousands of dollars) improved Safety of Gatiiering Lines ^ e r Y e a r ) UNK Improved Safety of Low Stress Lines (Per Year) Present value over 20 years at 3% discount rate Present value over ^ years at 7% discount mte $3,877 $57,678 Note: UNK = Unknown. Information needed to estimate the value is unavailable. $41,072 As indicated in Table 4, the present value of the monetized benefits over 20 years is estimated to be $58 million at a discount rate of 3% and $41 million at a discoimt rate of 7%. 6.3 Compliance Cost Estimates The operators of the lines impacted by the regulatory changes included in the final rule are expected to incur costs attributable to those changes. Both the impacted gathering lines and the impacted low-stress pipelines are expected to incur costs attributable to the final rule. 6.3.1 Gathering Lines The operators of the gathering lines impacted by the final rule are expected to incur costs attributable to that rule. The following activities, which would be required under the rule for impacted gathering lines, are those most likely to give rise to new costs: • Determine whether the lines are within 1/4 mile of a USA; • Implement corrosion control for steel pipes, as well as continuously monitor that pipe to identify any changes that could necessitate cleaning the lines and accelerating the corrosion control program; • Install and maintain pipeline line markers; • Implement a damage prevention program; • Implement a public education program; • Establish a maximum operating pressure (MOP) for steel pipes; 21#

Page 22• Report accidents and safety-related conditions and make annual reports; • Meet design, construction, and testing requirements for steel gathering lines constructed, replaced, relocated, or otherwise changed; • Meet drug and alcohol testing requirements; • Demonstrate Operator Qualification (OQ) compliance; • Develop a program to monitor and mitigate operating conditions that could lead to internal corrosion. The costs associated with each of these are discussed below. Determining Proximity to a USA The operators of rural onshore gathering lines will need to determine what parts, if any, of their systems meet the definition of "regulated rural onshore gathering lines." To determine the parts of their lines that meet the new definitions of regulated rural onshore gathering lines, pipeline operators will be need to determine (1) the nominal diameter of their lines; (2) the SMYS (or, alternatively, the operating pressure) of their lines; and (3) whether the distance from their lines to the nearest unusually sensitive areas is 1/4 mile or less. Determining the nominal diameter and the SMYS (or, alternatively, the operating pressure) should in most cases be a straightforward and a relatively simple exercise, and the associated costs should be minimal. However, in determining whether the distance from the pipeline to the nearest USA is 1/4 mile or less, pipeline operators will incur more substantial costs. No information is available on the cost of making that determination, and consequently it must be estimated. To determine if segments of their lines are within 1/4 mile of a USA, pipeline operators would be able to consult the National Pipeline Mapping System (NPMS),^° which is identified in Section lA of Appendix C of Part 195 as a source for locating USAs. PHMSA expects that the impacted gathering lines are operated by major pipeline firms, and those firms will be familiar with this source. The Independent Pefroleum Association of America (IPAA), a national frade association representing independent oil and gas producers, has estimated that it would cost its members approximately $500 per mile (2003 dollars) to perform the initial population surveys needed to comply with Federal pipeline safety regulations relating to defining regulated onshore gas gathering lines. This includes surveillance and photographing the line from aircrafts, and field verification of the purpose and occupancy of some buildings. IPAA fiirther estimates that it would cost approximately $100 per mile (2003 dollars) for periodically recurring surveys to determine if changes in land use have resulted in new portions of the pipeline becoming regulated gas gathering lines. This work, it should be •" * The NPMS can be found at http://www.npms.rspa.dot.gov. 22#

Page 23noted, was for determining the proximity of the pipelines to high consequence areas. USAs are only one type of high consequence area. PHMSA assumes that determining whether a pipeline is within 1/4 mile of a USA would cost $105 per pipeline mile (= $100 per pipeline mile converted from 2003 dollars to 2005 dollars) to perform initially. The required determinations are expected to be easier than those required for gas gathering lines. Furthermore, PHMSA assumes that it would cost $105 per pipeline mile to perform any subsequent recurring periodic re- determinations. For the purposes of this analysis, PHMSA assumes that 599 miles of rural onshore gathering lines would need to be checked initially to determine its proximity to USAs. Furthermore, PHMSA assumes that, after the initial check, few, if any, periodic checks would need to be made. (PHMSA acknowledges that new or expanded USAs are occasionally identified, but feels that it is unlikely that such will impact the 599 miles of gathering lines.) Consequently, PHMSA expects the efforts of pipeline operators to determine the proximity of their impacted pipeline mileage to USAs to have a one-time cost of $63,000 (= 599 x $105). Implementing Corrosion Control Measures Under the final rule, impacted rural onshore gathering lines with steel pipes that will be required to meet the corrosion control regulations in subpart H. In addition, the operators of these gathering lines v^ll also be required to continuously monitor that pipe to identify any changes in operating conditions that could necessitate cleaning the lines and accelerating the corrosion confrol program. The operators of existing pipelines will have two years after the publication date of the final rule to bring their pipelines into compliance with those regulations. PHMSA expects that corrosion control is already being undertaken for a large portion of the mileage that would become regulated rural onshore gathering lines. Those pipelines are, by definition, the higher-pressure gathering lines. They are, thus, lines in which the operator has a significant economic investment, and a corresponding interest in asset protection. Protecting these lines from corrosion, a leading cause of pipeline failure, is an important economic consideration for operators. Implementing corrosion control processes and procedures when a pipeline is originally installed involves a relatively small incremental cost. This analysis assumes that the operators of 80% of all impacted gathering lines would already have implemented corrosion control for asset protection purposes and would not incur costs to install such protection as a result of this rule. Based on the foregoing, the total mileage on which new corrosion control measures must be implemented would be 120 miles (= 0.2 x 599). This estimate assumes, of course, that all of the pipeline mileage impacted by the rule is composed of steel pipe. Based on information from IPAA, the initial cost of corrosion control for gas gathering lines was estimated by PHMSA to be $14,615 per mile (2003 dollars), and the annual 23#

Page 24cost of corrosion control for gas gathering lines was estimated by PHMSA to be $382 per mile (2003 dollars). For this analysis, the initial cost of corrosion control for impacted gathering lines is estimated to be $15,022 per mile (= $14,615 per mile converted from 2003 dollars to 2005 dollars), and the annual cost of corrosion control for impacted lines is also estimated to be $393 per mile (= $382 per mile converted from 2003 dollars to 2005 dollars). The final rule would result in the implementation of new corrosion control measures on 120 miles of pipeline. The initial cost of the corrosion control measures would be approximately $1,803,000 (= 120 x $15,022). The recurring annual cost would be approximately $47,000 (= 120 x $393). All other pipeline that becomes regulated as a consequence of the final rule is already covered by corrosion control measures and, consequently, the final rule would result in no added costs to the operators of that pipeline. Installing and Maintaining Line Markers Line markers involve initial installation costs and annual maintenance costs. PHMSA estimates that the costs of installation and maintenance are approximately $50 per marker (2003 dollars). For regulated hazardous liquid pipelines, according to 49 CFR § 195.410, markers must be installed at each crossing of a public road and railroad and elsewhere along the buried line so that its location is accurately known. For gas gathering lines, IPAA has estimated that approximately 10 markers are needed per mile of pipeline. PHMSA believes that this number of line markers would also be appropriate for rural onshore gathering lines. Consequently, PHMSA estimates that the installation of line markers would cost the operators of gathering and lines $500 per mile (2003 dollars). Pipelines must be surveyed on an ongoing basis to verify the condition of the markers. A portion of the markers is likely to be damaged or faded and, consequently, to require replacement. For gas gathering lines, IPAA estimated that it costs $80 per mile (2003 dollars) each year to survey the condition of the line markers and that 10% of the markers (i.e., 1 per mile) must be replaced annually. PHMSA believes that this would also hold true for rural onshore gathering lines. Consequently, the maintenance of line markers would have an estimated annual cost of $134 per mile (= $80 + 0.1 x $500 converted from 2003 dollars to 2005 dollars). Installation of line makers would have an estimated cost of $514 per mile (= $500 converted from 2003 dollars to 2005 dollars). Damage by excavation is one of the two leading causes of pipeline accidents. Operators of gathering lines have an economic interest in marking their pipelines to protect them from excavation damage, and PHMSA presumes that many unregulated pipelines are marked. In fact, "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids" (ASME B31.4), an industry consensus standard followed widely throughout the hazardous liquid pipeline industry, calls for the installation and maintenance of line markers on pipelines. PHMSA believes that most pipeline markers used for this purpose 24#

Page 25would comply with the final rule, since the marking requirements in the regulations have become a common standard. PHMSA estimates that new line markers would be required for only 10% of the mileage that will become regulated under the rule, or 60 miles (= 0.1 X 599). The initial costs to install these markers are estimated to be $31,000 (= 60 x $514). The recurring costs to monitor and replace markers for this mileage would be $8,000 (= 60 X $134). Implementing Damage Prevention Programs Implementing a damage prevention program involves membership in a one-call program. Most states require all pipeline operators, including operators of lines not subject to Part 195, to belong to one-call programs. Operators participating in one-call programs must respond to calls reporting the intent of others to excavate near their pipelines by either screening the calls (i.e., determining that the proposed excavation is not sufficiently close to the pipeline to be of concern) or marking their lines. The costs of such a program depend on the number of calls or tickets that an operator experiences annually. For gas gathering lines, IPAA estimated that its members could expect 20 tickets per mile each year, at a cost of $1 per ticket (2003 dollars). IPAA estimated the cost to screen and locate pipeline at $10 per ticket (2003 dollars). (This cost is relatively low because screening can often be performed from available records without the need for a more costly site visit). IPAA therefore estimated that the total annual cost per mile for implementing a damage prevention program was $220 (2003 dollars). PHMSA assumes that the total aimual cost per mile for rural onshore gathering line damage prevention programs would be $226 (= $220 converted from 2003 dollars to 2005 dollars). PHMSA notes that this estimate may be high, since the IPAA estimate appears more appropriate for a populated area, rather than the rural areas in which the impacted gathering lines will be located. Only Colorado and Kansas have no requirement for participation in one-call programs. Furthermore, Oklahoma's requirements do not apply to all pipeline operators. The number of miles of pipelines in these three states that would be impacted by the final rule is unknown and must be estimated. AOPL notes that the majority of crude oil gathering lines are located in the states of Texas, Oklahoma, Louisiana, and Wyoming, "with small systems in a number of oil producing states."^' For the purposes of this analysis, PHMSA assumes that 25% of the 599 miles of pipeline that would be impacted by the final rule are located in Oklahoma, Colorado, and Kansas. That is, PHMSA assumes that 150 miles of rural onshore gathering lines would need to be brought into a one-call system. This would appear to be a fairly conservative assumption, since it is unlikely that such a high percentage of the impacted lines are located in the three states. PHMSA invites comments on this assumption. In total, PHMSA expects that the damage prevention program requirement would cost the operators of the gathering lines that would become regulated pipelines under the final rule approximately $34,000 (= 150 x $226) annually. ^' See "How Many Pipelines are There?" at http://www.pipelinel01.com/Overview/energv-pl.html. 25#

Page 26Implementing Public Education Programs In informal conversations regarding gas gathering lines, IPAA estimated that a public education program would cost each of its members $5,000 annually (2003 dollars). This would imply that the costs are the same regardless of how much mileage a company operates. PHMSA agrees that there are some fixed costs associated with such a program, but also considers that costs will vary with the number of miles involved. More mileage will lead to additional needs to identify and meet with local government officials, excavators, etc. PHMSA has no specific data concerning what the per-mile costs would be. As mentioned previously, PHMSA expects that major pipeline firms are operating the gathering lines impacted by the final rule. Those firms have or are in the process of establishing public education programs covering their currently regulated lines. Furthermore, an existing pipeline industry consensus standard, the American Petroleum Institute's standard 1162, "Public Awareness Programs for Pipeline Operators," provides guidance for the development, implementation, and evaluation of public awareness programs (i.e., of public education programs).''^ Based on the foregoing, it is reasonable to assume that the operators of all gathering lines impacted by the final rule are currently incurring the costs associated with public education programs. Additionally, currently existing public education programs may already cover at least some of the lines. Some additional costs may be incurred by the operators of the lines impacted by the final rule, and those costs will be associated with (1) the identification of entities in close proximity to the newly regulated segments and (2) the delivery of public information messages to those entities at appropriate time intervals. Based on information provided by IPAA and informal discussions with gas gathering line operators, PHMSA has previously estimated that public education programs would cost Type B gas gathering lines $168 per mile per year (2003 dollars). For this analysis, PHMSA estimates the cost of public education for rural onshore gathering lines to be $173 per mile per year (= $168 converted from 2003 dollars to 2005 dollars). The total cost of public education for the 599 miles of impacted lines that would become regulated under the final rule is therefore expected to be $104,000 (= $173 x 599) per year. PHMSA notes that this estimate may be high, since the IPAA bases its estimate upon what appears to be more appropriate for a populated area, rather than the rural areas in which the impacted gathering lines will be located. Establishing a Maximum Operating Pressure (MOP) Establishing MOP does not generally require any physical work along the pipeline. Instead, it involves a review of pipeline records to identify the pressures for which the pipeline was designed. For some pipelines, especially those that may have changed hands, this may require locating the appropriate records. For other pipelines, no new costs would be required, since information on the MOP would be readily available. For •' ^ A copy can be foimd at http://committees.api.org/pipeline/standards/docs/1162nonprintable.pdf. 26#

Page 27the purposes of this analysis, PHMSA assumes that the total costs of establishing the MOP would be minimal. Reporting Under the final rule, operators of rural onshore gathering lines would need to report any accidents that occurred on their impacted lines, as well as any safety-related conditions. Operators would also be required to file annual reports covering pipe inventory and leaks repaired. PHMSA expects the costs of the required reporting to be nominal. Furthermore, the majority of those costs would likely be incurred only when a reportable accident has occurred or a safety-related condition has been discovered. It should be noted that operators will often prepare reports when they have an accident or safety-related condition for their own purposes. Additionally, some reports on accidents may be required for other agencies of the Federal government, such as the U.S. Occupational Safety and Health Administration or the U.S. Environmental Protection Agency and by state and/or local agencies. Finally, reports on accidents may be required from pipeline operators for insurance purposes. As a consequence, PHMSA is confident that costs related to reporting accidents and safety-related conditions would be insignificant. With respect to aimual reports, PHMSA believes that the required information should be readily available to the operators. Good business practice would require that operators keep frack of their pipe inventory and leaks repaired. Furthermore, major pipeline firms are expected to be the operators of the impacted gathering lines, and they will already be submitting armual reports. Adding information to those reports for the impacted lines should be a trivial matter. Meeting Design, Construction, and Testing Requirements Steel lines constructed, replaced, relocated, or otherwise changed would need to be designed, installed, constructed, initially inspected and tested in accordance with the requirements of Part 195. Since the rural onshore gathering lines that would be impacted by the final rule are not currently regulated under Part 195, the costs associated with this requirement are unknown. Furthermore, the frequency with which they would be incurred is also unknown. That frequency would depend on the rates at which (1) new steel lines are constructed and (2) existing steel lines are replaced, relocated, or otherwise changed. These are also unknown. PHMSA notes that safety requirements addressing design, construction, and testing that similar to those in the final rule are included in ASME B31.4, a consensus standard followed widely throughout the hazardous liquid pipeline industry. Consequently, PHMSA expects the added costs resulting from the final rule to be minimal. For the purposes of this analysis, they are assumed to be $0. 27#

Page 28Meeting Drug and Alcohol Testing Requirements Rural onshore gathering lines impacted by the final rule would be subject not only to Part 195, but also to the drug and alcohol testing requirements found in 49 CFR Part 199. Part 199 requires that operators of pipelines subject to Part 195 test personnel for use of prohibited drugs and misuse of alcohol. Personnel subject to testing are those who perform a regulated operation, maintenance, or emergency-response function on a regulated pipeline. The costs of this would include: (1) the costs of developing a testing plan, (2) the costs of testing; (3) the costs of recordkeeping associated with the testing; and (4) the costs of reporting. Since PHSMA expects that major pipeline firms operate the pipelines that would become regulated as a consequence of the final rule, these costs would be minimal. A testing plan would already exist for the pipeline firm. The amount of additional testing needed as a consequence of the final rule is unknown. It is likely, however, that employees performing regulated fimctions are already being tested, either because the companies view such as good business practice or because the employees working on the currently unregulated gathering lines also perform the same fimctions on regulated pipelines. For the purposes of this analysis, PHMSA assumes that there are no initial costs attributable to meeting the drug and alcohol testing requirements, and that any recurring costs will be negligible. Demonstrating OQ Compliance The operators of the impacted gathering lines would need to demonstrate that they are in compliance with the OQ program requirements found in subpart G of 49 CFR Part 195. To do this, the operators of the line would need to detail the processes they use to determine the qualification of persons performing certain operations and maintenance tasks. OQ is basically an industry standard. The operators of the impacted gathering lines, all of which PHMSA expects to be major pipeline firms, will be thoroughly familiar with the OQ requirements. Furthermore, because major pipeline firms operate the lines, it is likely that OQ is already being used for personnel involved in the operations and maintenance of those lines. It also might be noted that Congress has recognized that compliance with OQ rules might not be suitable in all situations. As a consequence, it specifically allows DOT and State pipeline safety agencies to waive OQ requirements if not inconsistent with pipeline safety (49 U.S.C. 60131(e)(5) and (f)). Operators who can show compliance with OQ rules is excessive or otherwise inappropriate in particular situations may petition PHMSA or a State pipeline safety agency for a waiver of any of the rules (49 U.S.C. 60118(c) and (d)). The rural gathering lines of operators that successfiilly applied for a waiver would not be required to comply with the OQ rules. 28#

Page 29For the purposes of this analysis, PHMSA assumes that the cost of OQ compliance attributable to the final rule will be nominal. Developing a Monitoring Program The operators of the impacted rural gathering lines would need to develop and implement a program to monitor operating conditions, such as low volume throughput, where the movement of oil is too slow to keep impurities in the oil stream suspended, thus causing buildup in the pipeline leading to internal corrosion. Operators will then need to take mitigative measures, such as running cleaning pigs or using inhibitors in the oil stream. It is estimated that such a monitoring program will require 12 hours per operator. Thirty- five operators are expected to be affected by this rule, and assuming about $50 per hour of time each, the aggregate development costs are estimated at about $19,000 (12 hours x $50 per hour x 35 operators). The per mile cost to develop the program is thus about $158 ($19,000/120 miles). PHMSA estimates the recurring annual cost of the program (including measures to prevent and mitigate internal corrosion, such as cleaning the pipeline and using inhibitors) to be about $500 per mile. Based on the 120 miles of pipeline covered by the rule, recurring annual costs are about $60,000. Gathering Line Cost Summary Table 5 presents a summary of the gathering line costs attributable to the final rule. As indicated in the table, there would be a cost of approximately $2 million in the first year, the majority of which is due to the need to implement corrosion control. During the second through sixth years and from the 7" year on, there would be an annual cost of $253 thousand, the majority of which is due to the public education requirement. 29#

Page 30TABLE 5. ESTIMATED ADDITIONAL COST FOR ONSHORE RURAL GATHERING LINES DUE TO THE FINAL RULE Cost Component Unit Cost per Mile Additional Costs (In thousands of dollars) initial Recurring Years 2 T Years 7 and : Costs Costs through 6 on Proximity to a USA $105 $0 $63 $0 Corrosion Control $15,022 Line Markers $514 $393 $1,803 $47 $47 $134 $31 $8 $8 Damage Prevention $226* $226 $34* $104 $34 $34 Public Education $173* MOP NA $173 $104* $104 Negligible $0 $0 $0 Reporting NA Pipeline Design, $0 Negligible $0 $0 $0 $0 $0 $0 $0 Construction, and Testing Drug and Alcohol $0 Negligible $0 $0 Testing Operator Negligible Negligible $0 $0 Qualification Monitoring $158 $500 $79 $60 Program TOTAL NA = Not applicable $2,114 $253 $253 Notes: * = Recurring costs will be incurred in the initial year, as well as in all subsequent years. As indicated in Table 6, the present value of the costs for impacted gathering lines over 20 years is estimated to be approximately $5.6 million at a discount rate of 3% and approximately $4.4 million at a discount rate of 7%. These estimates assume the outlays shown at the bottom of Table 5. TABLE 6. TOTAL GATHERING LINE COMPLIANCE COSTS OVER TIME (All costs given in thousands of dollars) Present value over 20 •Present value over 20 3% discount rate years at years at 7% discount rate $5,571 $4,420 For ease of computation, all costs used to estimate the values in Table 4 are assumed to begin at the same time. In reality, however, operators would not be required to begin all of the requirements at the same time. 30#

Page 316.3.2 Low-Stress Pipelines Costs wdll be associated with bringing low-stress pipelines into compliance with Part 195, which has the following eight subparts: Subpart A - General Subpart B - Annual, Accident, and Safety-Related Condition Reporting Subpart C - Design Requirements Subpart D - Construction Subpart E - Pressure Testing Subpart F - Operation and Maintenance Subpart G - Qualification of Pipeline Personnel Subpart H - Corrosion Control In addition, the low-stress pipelines brought under Part 195 would also need to comply with 49 CFR Part 199, which deals with alcohol and drug testing. The expected costs associated with each of the subparts of Part 195 and with Part 199 will be discussed below. Following those discussions, the overall costs of compliance for low-stress pipelines will be developed. Subpart A - General Subpart A addresses the scope and applicability of Part 195, the definitions of terms used in the Part, and related administrative matters. The primary cost associated with this subpart is the cost of identifying pipeline with the following characteristics: • Nominal diameter of 8 5/8 inches or more; • Stress level of 20% of SMYS or less during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, pressure of 125 psig or less; and • Located in or within 1/2 mile of an unusually sensitive area as defined in 49 CFR § 195.6. Determining the nominal diameter and the SMYS (or, alternatively, the operating pressure) should usually be a straightforward and a relatively simple exercise, and the associated costs should be minimal. Determining whether the distance from the pipeline to the nearest USA is 1/2 mile or less will be more difficult, but those pipeline operators with affected lines will still incur only minimal costs. To determine if segments of their lines are within 1/2 mile of a USA, pipeline operators would be able to consult the National Pipeline Mapping System (NPMS),^'' which is identified in Section lA of Appendix C of Part 195 as a source for locating USAs. ^' The NPMS can be found at http://www.npms.rspa.dot.gov. 31#

Page 32PHMSA expects that the impacted rural onshore low-stress pipelines are operated by major pipeline firms and those firms will be familiar with this source. For the purposes of this analysis, PHMSA assumes that determining whether a pipeline is within 1/2 mile of a USA would cost $0 per pipeline mile to perform initially. Furthermore, PHMSA also assumes that it would cost $0 per pipeline mile to perform any subsequent recurring periodic re-determinations. Subpart B - Annual, Accident, and Safety-Related Condition Reporting Subpart B includes the requirements for operators to submit certain data to PHMSA annually, to report accidents occurring on their pipelines, and to report significant conditions that can affect safety. Under the final rule, the operators of all onshore rural low-sfress pipelines not currently regulated under Part 195 would need to file these reports. As previously stated in Section 6.1.2, this would impact the operators of 4,724 miles of onshore rural low-stress pipeline. PHMSA expects the costs of the required reporting to be nominal. Furthermore, most of those costs would likely be incurred only when a reportable accident has occurred or a safety-related condition has been discovered. It should be noted that operators will often prepare reports when they have an accident or safety-related condition for their ovra purposes. Additionally, some reports on accidents may be required for other agencies of the Federal government, such as the U.S. Occupational Safety and Health Administration or the U.S. Environmental Protection Agency and by state and/or local agencies. Finally, reports on accidents may be required from pipeline operators for insurance purposes. As a consequence, PHMSA is confident that costs related to reporting accidents and safety-related conditions would be insignificant. With respect to annual reports, PHMSA believes the required information should be readily available to the operators. Good business practice would require that operators keep frack of their pipe inventoty and leaks repaired. Furthermore, major pipeline firms are expected to be the operators of the 803 miles of low-stress pipelines impacted by all other parts of the final rule, and they already will be submitting annual reports. Adding information to those reports for the impacted lines should be a trivial matter. Some of the operators of the 3,921 miles of low-stress pipelines not impacted by the other parts of the rule will also be pipeline firms currently submitting annual reports to PHMSA. For them, adding information to their aimual reports also should be trivial. For the remainder of the operators, their systems should be so simple that preparing annual reports should not be a major undertaking, and the cost of preparing them should be nominal. 32#

Page 33Subpart C - Design Requirements, Subpart D - Construction, and Subpart E - Pressure Testing Subparts C, D, and E ensure a minimum standard of integrity for all new, replaced, and relocated pipelines. Any 8 5/8 inch diameter onshore rural low-stress steel pipelines within 1/2 mile of a USA that are constructed, replaced, relocated, or otherwise changed in the fiiture would need to be designed, installed, constructed, initially inspected and tested under Part 195. Since the onshore rural low-stress pipelines that would be impacted by the final rule are not currentiy regulated under Part 195, the magnitude of the costs associated with this requirement is unknown. Furthermore, the frequency with which they would be incurred is also unknown. That frequency would depend on the rates at which (1) new steel lines are constructed and (2) existing steel lines are replaced, relocated, or otherwise changed. These are also unknown. PHMSA notes that safety requirements addressing design, construction, and testing that are similar to those in the final rule are included in ASME B31.4, a consensus standard followed widely throughout the hazardous liquid pipeline industry. Consequently, PHMSA expects the added costs resulting from the final rule to be minimal. For this analysis, they are assumed to be $0. Subpart F - Operation and Maintenance Subpart F describes the requirements applicable to the operation and maintenance of pipelines. PHMSA notes that the operators of low-sfress pipelines currently subject to Part 195 do not appear to have experienced significant economic hardship in complying with Part 195. Operators have not requested waivers from compliance. Furthermore, based on the testimony operators gave during Congressional hearings in 2006, PHMSA assumes that most operators not currentiy subject to Part 195 use it or ASME B31.4, "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids," as guidelines for their daily operations and maintenance. The ASME code is the industry standard for liquid pipelines and is substantially similar to Part 195. Thus, PHMSA believes that requiring compliance with Part 195 will only slightly increase the operation and maintenance costs of the operators of rural onshore low-stress pipelines that would be brought under Part 195 by the SNPRM. The following operation and maintenance activities are those most likely to result in new costs for the impacted operators of rural onshore low-stress pipelines: • Maintain maps and records. Install and maintain pipeline line markers. Implement a damage prevention program. 33#

Page 34• Implement a public education program, • Establish an assessment integrity program, and • Establish a leak detection program. In the main, these activities are those that were included in the NPRM. The costs associated with each of these are discussed below. Maintaining Maps and Records Each operator subject to Part 195 must maintain (1) current maps and records relating to the characteristics of its pipeline systems, (2) the last 3 years of daily operating records, and (3) certain repair, inspection, and test records. PHMSA does not believe the requirements of subpart F relating to maps and records are burdensome. As good business practice, the operators of pipelines should be generating and keeping the required records already. Additionally, some of these records already may be generated and maintained for other regulators, for insurance purposes, or as part of the operator's general due diligence efforts. While the required records may already be being generated, some of them may not be currently kept as long as required by subpart F, however. The additional costs of keeping the records longer would be expected to be nominal. For the purposes of this analysis, PHMSA assumes that the added costs associated with maintaining the required maps and records would be nominal. Installing and Maintaining Line Markers Operators subject to Part 195 must install and maintain line markers over their buried pipeline. Those operators will incur both initial installation costs and annual maintenance costs for those line markers. PHMSA estimates the cost of installation to be approximately $50 per marker (2003 dollars). For regulated hazardous liquid pipelines, according to 49 CFR § 195.410, markers must be installed at each crossing of a public road and railroad and elsewhere along the buried line so that its location is accurately known. For gas gathering lines, the Independent Petroleum Association of America (IPAA) has estimated that approximately 10 markers are needed per mile of pipeline. PHMSA believes that this number of line markers also would be appropriate for rural onshore low- sfress pipelines. Consequently, installing line markers would cost the operators of low- sfress pipelines an estimated $514 per mile (= 10 x $50 converted from 2003 dollars to 2005 dollars). Pipelines must be surveyed regularly to verify the condition of the markers. A portion of the markers is likely to be damaged or faded and, consequently, to require replacement. For gas gathering lines, IPAA estimated that it costs $80 per mile (2003 dollars) each year to survey the condition of the line markers and that 10% of the markers (i.e., 1 per 34#

Page 35mile) must be replaced atmually. PHMSA believes that this would also hold true for rural onshore low-sfress pipelines. Consequently, maintaining line markers would have an estimated annual cost of $134 per mile (= $80 + 0.1 x $500 converted from 2003 dollars to 2005 dollars). Damage by excavation is one of the two leading causes of pipeline accidents. Operators of low-stress pipelines have an economic interest in marking their pipelines to protect them from excavation damage, and PHMSA presumes that many unregulated pipelines are marked. In fact, ASME B31.4, an industry consensus standard followed widely throughout the hazardous liquid pipeline industry, calls for the installation and maintenance of line markers on pipelines. PHMSA believes that most pipeline markers used for this purpose would comply with the final rule, since the marking requirements in the regulations have become a common standard. PHMSA estimates that new line markers would be required for only 10% of the mileage that will become regulated under the final rule, or 80 miles (=0.1 x 803). The initial costs to install these markers are estimated to be $41,120 (= 80 x $514). The recurring costs to monitor and replace markers for this mileage would be $10,720 (= 80 x $134). Implementing Damage Prevention Programs Under subpart F, each operator of buried pipeline must carry out a written program to prevent damage to that pipeline from excavation activities. Implementing a damage prevention program generally involves membership in a one-call program. Most States require all pipeline operators, including operators of lines not subject to Part 195, to belong to one-call programs. Operators participating in one-call programs must respond to calls reporting the intent of others to excavate near their pipelines by either screening the calls (i.e., determining the proposed excavation is not sufficiently close to the pipeline to be of concern) or marking their lines. The costs of such a program depend on the number of calls or tickets that an operator experiences annually. For gas gathering lines, IPAA estimated that its members could expect 20 tickets per mile each year, at a cost of $1 per ticket (2003 dollars). IPAA estimated the cost to screen and locate pipeline at $10 per ticket (2003 dollars). (This cost is relatively low because screening can often be performed from available records without the need for a more costly site visit), IPAA therefore estimated that the total annual cost per mile for implementing a damage prevention program was $220 (2003 dollars). PHMSA assumes that the total annual cost per mile for rural onshore low-stress line damage prevention programs would be $226 (= $220 converted from 2003 dollars to 2005 dollars). PHMSA notes that this estimate may be high, since the IPAA estimate appears more appropriate for a populated area, rather than the rural areas in which the low-sfress pipelines impacted by the SNPRM will be located. Only Colorado and Kansas have no requirement for participation in one-call programs. Furthermore, Oklahoma's requirements do not apply to all pipeline operators. The number of miles of pipelines in these three states that would be impacted by the final rule is unknown and must be estimated. For the purposes of this analysis, PHMSA assumes 35#

Page 36that 25% of the 803 miles of pipeline that would be impacted under the final rule are located in Oklahoma, Colorado, and Kansas. That is, PHMSA assumes that 201 miles of rural onshore low-stress pipelines would need to be brought into a one-call system because of the SNPRM. This is a fairly conservative assumption, since it is unlikely that such a high percentage of the impacted lines are located in the three states. It should be noted that there will be no expected costs associated with this requirement for any pipelines in states other than Oklahoma, Colorado, and Kansas, because of state- mandated participation in one-call or other types of damage prevention programs. In total, PHMSA expects the damage prevention program requirement would annually cost the operators of the low-sfress pipelines that would become regulated imder the regulatory changes included in the final rule approximately $45,426 (=201 x $226). Implementing Public Education Programs In informal conversations regarding gas gathering lines, IPAA estimated that a public education program would cost each of its members $5,000 annually (2003 dollars). This would imply that the costs are the same regardless of how much mileage a company operates. PHMSA agrees there are some fixed costs associated with such a program, but also considers that costs will vary with the number of miles involved. More mileage will lead to additional needs to identify and meet with local government officials, excavators, etc. PHMSA has no specific data on the per-mile costs. As mentioned previously, PHMSA expects that major pipeline firms operate the low- sfress lines covered by this rule. Those firms have public education programs covering their currently regulated lines. Furthermore, an existing pipeline industty consensus standard, the American Petroleum Institute's standard 1162, "Public Awareness Programs for Pipeline Operators," provides guidance for the development, implementation, and evaluation of public education programs.'^'* Based on the foregoing, it is reasonable to assume that the operators of all low-stress lines impacted by the final rule are currently incurring the costs associated with public education programs. Additionally, currently existing public education programs may already cover at least some of the lines. The requirement may result in some additional costs to operators of the affected lines and those costs will be associated with (1) identifying entities in close proximity to the newly regulated segments and (2) delivering public information messages to those entities at appropriate time intervals. Based on information provided by IPAA and informal discussions with gas gathering line operators, PHMSA has previously estimated that public education programs would cost Type B gas gathering lines $168 per mile per year (2003 dollars). For the purposes of this analysis, PHMSA estimates the cost of public education for rural onshore low-sfress lines to be $173 per mile per year (= $168 converted from 2003 dollars to 2005 dollars). The total cost of public education for the 803 miles of low-sfress lines that would be brought under Part 195 is therefore expected to be $138,919 (= $173 X 803) per year. PHMSA notes that this estimate may be high. ^ * A copy can be found at http://committees.api.Org/pipeline/standards/docs/l 162nonprintable.pdf. 36#

Page 37since the IPAA bases its estimate upon what appears to be more appropriate for a populated area, rather than the rural areas relevant to this rule. Establishing an Integrity Management Program Operators of rural onshore low-stress lines meeting the criteria described above would need to establish an integrity management program. PHMSA expects that major pipelines operate the lines covered by the final rule. Those pipelines already have integrity management programs that can be extended to cover the unregulated low-stress lines. Pipeline operators will need to begin assessing the integrity of segments of their low- stress lines, if they have not already done so. To do that, they will need to use in-line inspection tools, direct assessment, pressure testing, or some other appropriate technology. These assessments will need to be performed periodically. Table 7 presents estimates of the costs for hazardous liquid pipelines of the three primary methods used to assess pipeline integrity. Those methods are (1) in-line inspection; (2) hydrostatic testing; and (3) direct assessment. TABLE 7. PIPELINE INSPECTION COSTS PER MILE (1998 Dollars) Cost Category High Estimate Low Estimate In-Line Inspection Cost of preparing line $27,300 $6,800 Cost of in-line inspection $3,500 $2,000 Hydrostatic Testing Cost of preparing line $5,000 $1,250 Cost of hydrostatic testing $92,160 $27,650 Direct Assessment $0 $6,000 $2,000 Source: Appendix E, "Gas and Liquid Transmission Pipelines" by Neil Thompson, part of the Cost of Corrosion Study for FHWA (see http://www.corrosioncost.com/infrastructure/gasliquid/index.htm). PHMSA assumes that 50% of the mileage will be periodically evaluated using direct assessment, while 50% of the mileage will be periodically evaluated using in-line inspection. PHMSA assumes the cost of preparing a line for direct inspection to be $0. The cost per mile to perform direct assessment will be $4,649 (= $4,000 - the mid-point of the $2,000 to $6,000 range - converted from 1998 dollars to 2005 dollars). 37#

Page 38Furthermore, PHMSA assumes the cost per mile to prepare a line for in-line inspection to be $19,535 (= $17,050 - the mid-point of the $6,800 to $27,300 range - converted from 1998 to 2005 dollars). The cost per mile to perform in-line inspection will be $3,084 (= $2,750 - the mid-point of the $2,000 to $3,500 range - converted from 1998 to 2005 dollars). The cost to prepare a line for in-line inspection is incurred only once. PHMSA assumes that all affected low-stress pipeline mileage would be assessed, on average, once every 5 years (or, put another way, 1/s"h of the mileage would be assessed every year). That is, 161 (= 0.2 × 803) miles of low-stress pipeline would be assessed every year. Furthermore, PHMSA assumes the cost of preparing lines for integrity assessment to be incurred over the first five years. Finally, PHMSA assumes that the cost of performing in-line inspection or direct assessment would be incurred beginning in the first year. That is, in each of the first five years, 20 percent of the lines would be prepared and then in the same year some form of integrity assessment would be performed on those lines. Based on the foregoing, the annual cost of preparing lines for integrity assessment, which would be incurred only during the first five years after implementation of the final rule, would be $374,325 (= 161 miles x ($4,649 + $0) x 0.5). The annual cost of integrity assessment would be $1,820,910 (= 161 miles x ($19,535 + $3,084) × 0.5). The operators of pipelines would be allowed to notify PHMSA in certain circumstances where the operator decides to abandon a low-stress pipeline because of the economic burden associated with complying with the IM assessment requirements. If, after analysis by PHMSA in consultation with the U.S. Department of Energy, as appropriate, it is concluded that there would be an adverse energy or safety impact, PHMSA would work with the pipeline operator to grant a special permit that would allow continued operation of the line while also assuring safety through alternative requirements. Operators of the pipeline would be allowed to continue to do so while the analysis is conducted. While this would reduce the integrity management costs for the operators of the pipelines, it is expected that there will be only a nominal reduction in aggregate integrity management costs because of this. The operators of any marginal wells connected to the low-stress pipelines would be able to continue to produce and not be forced to shut down their wells or switch to another transportation mode. Summary of the Costs Associated with Subpart F Table 8 presents the estimated costs associated with subpart F. In total, subpart F is expected to cost operators approximately $2.4 million in the first year, $2.4 million in the second through fifth years, and $2.0 million every year thereafter. Most of these costs are expected to result from integrity management activities on low-stress pipelines, particularly integrity assessment. 38#

Page 39TABLE 8. ESTIMATED COSTS ASSOCIATED WITH SUBPART F Subpart F Unit Cost per Mile Additional Costs Requirement Tuitial (In thousands of dollars) Recurring Year 1 Costs Costs throughS SXears.6 and on Maps and Records $0 $0 $0 $0 Line Markers $514 $134 $41 $10 $10 Damage Prevention $226 $226 $45 $45 $45 Public Education $173 $173 $139 $139 $139 Integrity Varioust Varioustt $2,195 $2,195 $1,821 Management [TOTAL Notes: $2,420 | $2,014] I-S.49 or ps cons he sing is as en, 04 pract or no in ting inspecion. Subpart G - Qualification of Pipeline Personnel The operators of the affected low-stress lines would need to demonstrate that they are in compliance with the Operator Qualification (OQ) program requirements found in Part 195. To do this, the operators of the line would need to detail the processes they use to determine the qualification of persons performing certain operations and maintenance tasks. The operators of the impacted low-stress lines, all of which PHMSA expects to be major elise firmor pill be hors lain tries and are are mentated perime ipeline firms, 1 operators have implemented OQ programs, it is likely that OQ is already being used for personnel involved in the operations and maintenance of those lines. It also might be noted that Congress has recognized that compliance with OQ rules might not be suitable in all situations. As a consequence, it specifically allows DOT and State pipeline safety agencies to waive OQ requirements if not inconsistent with pipeline safety (49 U.S.C. 60131(e)(5) and (f)). Operators who can show compliance with OQ rules is excessive or otherwise inappropriate in particular situations may petition PHMSA or a State pipeline safety agency for a waiver of any of the rules (49 U.S.C. 60118(c) and (d). PHMSA assumes the cost of OQ compliance attributable to the final rule will be nominal. Subpart H - Corrosion Control This subpart includes requirements to prevent and mitigate corrosion damage of steel pipelines. Under the final rule, affected rural onshore low-stress lines with steel pipes will be required to meet the corrosion control regulations in subpart H. PHMSA expects 39#

Page 40that corrosion control is already being undertaken for a large portion of the 803 miles of onshore low-stress lines that will be brought into compliance with Part 195 by the final rule. PHMSA believes that major pipeline companies generally operate these low-sfress lines. Corrosion protection helps ensure that the pipelines are available to move product. For the purposes of this analysis, PHMSA assumes that operators of 90% of the 803 miles of low-sfress lines would already have implemented corrosion control measures and would not incur costs to install such protection because of this final rule. Based on the foregoing, the total mileage on which new corrosion control measures must be implemented would be 80 miles (= 0.1 x 803). This estimate assumes, of course, that all the pipeline mileage impacted by the final rule is composed of steel pipe. Based on information from IPAA, the initial cost of corrosion control for gas gathering lines was estimated by PHMSA to be $14,615 per mile (2003 dollars), and the armual cost of corrosion confrol for gas gathering lines was estimated by PHMSA to be $382 per mile (2003 dollars). For this analysis, the initial cost of corrosion control for and the 803 miles of low-stress lines is estimated to be $15,022 per mile (= $14,615 per mile converted from 2003 dollars to 2005 dollars), and the annual cost of corrosion confrol for the 803 miles of lines is also estimated to be $393 per mile (= $382 per mile converted from 2003 dollars to 2005 dollars). The final rule would result in implementing new corrosion control measures on 80 miles of pipeline. The initial cost of the corrosion confrol measures would be approximately $1,201,760 (= 80 X $15,022). The recurring annual cost would be approximately $31,440 (= 80 X $393). All other pipeline that becomes regulated under Part 195 because of the final rule is already covered by corrosion control measures and, consequently, the final rule would result in no added costs to the operators of that pipeline. Part 199 - Drug and Alcohol Testing The operators of the 803 miles of rural onshore low-stress lines brought under Part 195 by the final rule would be subject not only to Part 195, but also to the drug and alcohol testing requirements found in 49 CFR Part 199. Part 199 requires that operators of pipelines subject to Part 195 test personnel for use of prohibited drugs and misuse of alcohol. Persormel subject to testing are those who perform a regulated operation, maintenance, or emergency-response fimction on a regulated pipeline. The costs of this would include: (1) the costs of developing a testing plan, (2) the costs of testing; (3) the costs of recordkeeping associated with the testing; and (4) the costs of reporting. Since PHSMA expects that major pipeline firms operate the low-stress lines that would become regulated imder Part 195 as a consequence of the final rule, these costs would be minimal. A testing plan would already exist for the pipeline firm. So would any additional costs attributable to recordkeeping or reporting requirements. Any additional testing needed because of the final rule is unknown. It is likely, however, that employees performing regulated functions are already being tested, either because the companies view such as good business practice or because the employees working on the 40#

Page 41currently unregulated low-stress lines also perform the same fimctions on regulated pipelines. PHMSA assumes there are no initial costs attributable to meeting the drug and alcohol testing requirements, and that any recurring costs will be negligible. Low-Stress Pipeline Cost Summary Table 9 presents a summary of the costs expected to be attributable to the final rule. As indicated in the table, there would be a cost of approximately $4 million in the first year, most of which is due to the requirements of subpart F (particularly integrity management). During the second through fifth years, there would be an annual cost of approximately $2 million, the majority of which is again due to the requirements of subpart F (and particularly integrity management). Finally, beginning in the sixth year, there would be an annual cost of approximately $2 million. The largest portion of that cost would be attributable to subpart F (and particularly integrity management). 41#

Page 42TABLE 9. ESTIMATED ADDITIONAL COSTS FOR LOW-STRESS PIPELINES DUE TO THE FINAL RULE Cost Component Unit Cost per Mile Additional Costs Initial (In thousands of dollars) Recurring Year 1 Years 2 Years 6 and Costs Costs through 5 Part 195, Subpart A $0 $0 SO 50 50 - Annual, Accident art 195, Subpart E Nominal Nominal 50 50 and Safety-Related Condition Reporting Part 195, Subpart C $0 $0 $0 50 - Design Requirements, Subpart D- Construction, and Subpart E - Pressure Part 195, Subpart F Testing Various Various $2,420 $2,389 $2,014 - Operation and Maintenance Part 195, Subpart G Nominal Nominal 50 $O 50 - Qualification of Pipeline Personnel Part 195, Subpart H $15,022 $393 $1,202 $31 $31 - Corrosion Control Part 199 - Drug and $0 Negligible 50 50 Alcohol Testing TOTAL $3,622 $2,420 $2,064 As indicated in Table 10, the present value of the costs over 20 years is estimated to be $34 million at a discount rate of 3% and $24 million at a discount rate of 7%. These estimates assume the outlays shown at the bottom of Table 9. TABLE 10. TOTAL COMPLIANCE COSTS FOR LOW-STRESS PIPELINES OVER TIME (All costs given in thousands of dollars) Present value over 20 Present value over 20 years at years at 3% discount rate 7% discount rate $33,504 $24,449#

Page 43Fogicase of samputation, all costs used to estimate the values in Table 10 are assumed 10 6.3.3 Compliance Cost Summary Table 11 presents a summary of the costs for the final rule. As the table indicates, in Year 1, the final rule is expected to cost approximately $6 million, in Years 2 through 6, the rule is expected to cost approximately $3 million, and in Year 7 and later, the rule is expected to cost approximately $2 million. TABLE 11. TOTAL COMPLIANCE COSTS OVER TIME (All costs given in thousands of dollars) Type of Year 1 Years 2 - 6 Year 7 and Present Present Pipeline on value over value over 20 years at 3% 20 years at 7% discount rate discount rate For $2,114 $253 $253 $5,571 $4,420 gathering lines For low- $3,622 $2,420 $2,064 $33,504 $24,449 stress lines TOTAL $5,736 $2,673 S2,317 $39,075 $28,869 The estimated present value of the total costs for the final rule are expected to be approximately $39 million over 20 years assuming a 3% discount rate and $29 million over 20 years assuming a 7% discount rate. 6.4 Comparison of Benefits and Costs Table 12 summarizes the benefits and costs of the final rule. 43#

Page 44TABLE 12. SUMMARY OF BENEFITS AND COSTS OF THE FINAL RULE (All values in thousands of dollars) Type of Year 1 Years 2 - 6 Year 7 and Present Present Pipeline on value over value over 20 years at 20 years at 3% 7% discount discount rate rate Benefits For Unknown Unknown Unknown - - lines, gathering For low- $3,877 $3,877 $3,877 $57,678 $41,072 stress pipelines TOTAL $3,877 $3,877 $3,877 $57,678 S41,072 Costs For $2,114 $253 $253 $5,571 $4,420 gathering lines For low- $3,622 $2,420 52,064 $33,504 $24,449 stress lines TOTAL $5,736 $2,673 S2,317 $39,075 $28,869 The present value of the total benefits for the final rule is expected to be approximately $58 million over 20 years assuming a 3% discount rate and approximately $41 million over 20 years assuming a 7% discount rate. These benefits do not represent all the benefits, but only those that could be monetized. The present value of the total costs is expected to be approximately $39 million over 20 years assuming a 3% discount rate and $29 million over 20 years assuming a 7% discount rate. The final rule is expected to be cost beneficial, with net benefits of approximately $19 million at the 3% discount rate and $12 million at the 7% discount rate. The benefit-cost ratio is approximately 1.5 at both the 3% and 7% discount rates. SUMMARY AND CONCLUSIONS PHMSA is making certain currently unregulated rural onshore hazardous liquid gathering lines subject to limited operation and maintenance rules, along with reporting rules for accidents and safety-related conditions, and requiring the use of line markers. The gathering lines subject to this rule are those that 44#

Page 45• Have a nominal diameter from 6 5/8 to 8 5/8 inches, • Operate at a stress level of more than 20% of SMYS (specified minimum yield strength) during normal operation or, if the stress level is unknown or the pipeline is not constructed using a steel pipe, at a pressure of more than 125 psig; and • Are within 1/4 mile of a USA as defined in 49 CFR § 195.6. Furthermore, PMHSA is making certain currently unregulated rural onshore hazardous liquid low-stress pipelines subject to the safety regulations of 49 CFR Part 195. The low- sfress pipelines subject to this rule are those that • Have a nominal diameter of 8 5/8 inches or more, • Operate at a stress level of 20% or less of SMYS during normal operation or, if the sfress level is unknovm or the pipeline is not constructed using steel pipe, at a pressure of 125 psig or less and • Are in or within 1/2 mile of a USA as defined in 49 CFR § 195.6. These actions are expected to improve the safety performance of the pipelines, as well as public confidence in their safety. Overall, the benefits of the final rule are expected to be approximately $4 million annually. This includes only a portion of the total benefits, since benefits from improved safety of gathering lines could not be quantified. The present value of the benefits that could be quantified for a 20-year period using a 3% discount rate is approximately $58 million, while the present value for a 20-year period using a 7% discount rate is approximately $41 million. Overall, the costs of the final rule are expected to be approximately $6 million in the first year, $3 million in the second through the sixth years, and $2 million in all subsequent years. The present value of this cost over 20 years using a 3% discount rate is approximately $39 million, while its present value over 20 years using a 7% discount rate is approximately $29 million. Comparing the benefits and costs indicates the final rule is cost-beneficial. Net benefits (the excess of benefits over costs) for the final rule is approximately $19 million using a 3% discount rate and $12 million using a 7% discoimt rate. It should be noted that the operators of marginal wells connected to those low-sfress pipelines meeting the abandonment notification criteria of the rule should be able to continue to produce and not be forced to shut down their wells or switch to another fransportation mode due the economic burden placed on the low-stress pipelines serving those wells by the rule's IM assessment requirements. This is an additional benefit of the rule. 45#

Page 46Regulatory Flexibility Analysis The Regulatory Flexibility Act (5 U.S.C. 601 et seg.) requires an agency to review regulations to assess their impact on small entities unless the agency determines that a rule is not expected to have a significant impact on a substantial number of small entities. Need for the Final Rule: This final rule covers certain rural onshore hazardous liquid gathering lines and certain rural onshore low-stress hazardous liquid pipelines. With respect to gathering lines. Congress granted DOT the authority to regulate a class of rural gathering lines called "regulated gathering lines" with the Pipeline Safety Act of 1992 (Pub. L. 102-508). Congress left the definitions of "gathering lines" and "regulated gathering lines" to DOT to develop (see 49 U.S.C. 60101(b)(1)(A) and 49 U.S.C. 60101(b)(2)(A)). In the Accountable Pipeline Safety and Partnership Act (Pub. L. 104- 304), Congress amended the requirement to define "regulated gathering lines" by adding the words "if appropriate." Congress also gave DOT authority to collect information from gathering line operators related to deciding whether and to what extent to regulate rural gathering lines. With respect to low-sfress lines, Begirming in 1991, Congress paid greater attention to the risks that hazardous liquid and natural gas pipelines pose to the environment. In the Pipeline Safety Act of 1992 (Pub. L. 102-508), Congress gave DOT greater authority to protect the envirormient from risk that pipelines pose. Congress continued to emphasize the need to better protect the environment from the risks pipelines pose in the Accountable Pipeline Safety and Partnership Act of 1996 (Pub. L. 104-304). With the Pipeline Inspection, Protection, Enforcement, and Safety (PIPES) Act of 2006 (Pub. Law No. 109-468), Congress went further and instructed DOT to apply all Part 195 requirements to unregulated low-stress pipelines. It should be noted that, with respect to uru-egulated low-stress pipelines, PHMSA has decided to undertake the effort to apply all Part 195 requirements as a two-phase process. The decision was based on an analysis of its alternatives. The first phase, which is completed by this final rule, covers larger-diameter, higher-risk onshore rural low-stress pipelines. The second phase, which will be undertaken in a subsequent rulemaking, will cover the remaining unregulated onshore rural low-stress pipelines. As a consequence of the Congress' safety concern, as indicated by the foregoing, by comments received from various stakeholders, and by accident data suggesting that corrosion and excavation damage are the two greatest threats to rural onshore gathering and low stress lines, PHMSA believes that the potential for future harm to the environment from rural onshore gathering and low stress lines is clear. Furthermore, given Congressional mandates, including the PIPES Act, PHMSA believes that the present exemption of rural onshore gathering and low sfress lines from nearly all safety regulations in 49 CFR Part 195 is no longer appropriate. The final rule aims to amend 49 CFR Part 195 to begin to fiilfill Congress' statutory mandate. 46#

Page 47Description of Actions: PHMSA is making certain currently unregulated rural onshore hazardous liquid gathering lines subject to limited operation and maintenance rules, along with reporting rules for accidents and safety-related conditions, and requiring the use of line markers. Furthermore, PHMSA is bringing certain rural onshore low-stress pipelines under the safety regulation of 49 CFR Part 195. Identification of potentially affected small entities: This regulatory change would affect operators of larger-diameter, higher-risk rural onshore gathering and low-sfress lines. The number of operators affected by the regulatory change is unknown and must be estimated. Furthermore, the size of the operators impacted by the regulatory change is also unknown and, consequently, must also be estimated. PHMSA received no comment on these estimations from either industry or the public following issuance of the NPRM. The final rule applies to rural onshore gathering lines that • Have a nominal diameter from 6 5/8 to 8 5/8 inches, • Operate at a stress level of more than 20% of SMYS during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, at a pressure of more than 125 psig; and • Are within 1/4 mile of an unusually sensitive area as defined in 49 CFR § 195.6. It also applies to rural onshore low stress pipelines that • Have a nominal diameter of 8 5/8 inches or more, • Operate at a stress level of 20% of SMYS or less during normal operation or, if the stress level is unknown or the pipeline is not constructed using steel pipe, at a pressure of 125 psig or less, and • Are in or within 1/2 mile of an unusually sensitive area as defined in 49 CFR § 195.6. Gathering line operators belong primarily to the North American Industry Classification System (NAICS) 486110, Pipeline Transportation of Crude Oil. In accordance with size standards published by the Small Business Administration, a business with 1,500 or fewer employees is considered a small entity in this NAICS. ^ ^ Depending on the products being transported, low-stress pipeline operators belong to the NAICS 486110, Pipeline Transportation of Crude Oil, or NAICS 486910, Pipeline Transportation of Refined Petroleum Products. For both NAICS codes, a business with 1,500 or fewer employees is considered a small entity.^^ PHMSA expects that major petroleum pipeline companies operate the gathering lines operating at more than 20% of SMYS (or alternatively at 125 psig). According to ^ ^ http://www.sba.gov/size/sizetable.pdf ^ * Small Business Administration, Table of Small Business Size Standards Matched to North American Industry Classification System Codes, http://www.sba.gov/idc/groups/public/documents/sba homepage/serv sstd tablepdf.pdf. 47 ff"#

Page 48information in the Oil & Gas Journal Data Book, 2005 Edition, 35 major petroleum pipeline operators have crude oil gathering lines. In total, 33 of the operators were reported to have 14,187 miles of crude oil gathering lines (no information was available on the gathering line mileage of the 2 other operators). ^ ^ On average, the 33 operators each had 430 miles of crude oil gathering lines. For the purposes of this analysis, it is assumed that the 35 firms identified as major petroleum pipeline operators with crude oil gathering lines all have more than 1,500 employees. PHMSA expects that major petroleum pipeline companies operate the low-stress lines with a nominal diameter of 8 5/8 inches or greater, since those lines transport aviation fiiel and other refined products, as well as some crude oil. The exact number of operators with low-sfress lines is unknown. PHMSA expects the number of major pefroleum pipeline operators with low-sfress lines will be comparable to the number with crude oil gathering lines, however. According to information in the Oil & Gas Journal Data Book, 2005 Edition, 35 major petroleum pipeline operators have crude oil gathering lines. PHMSA assumes that between 30 and 40 firms operate low-stress hazardous liquid pipelines, and all have more than 1,500 employees. The final rule is not expected to affect any small operators of pipelines. It is unknown whether any small operators of marginal wells would be impacted by the rule. The final rule would not result in a significant adverse economic impact on any small entities. Related Federal rules and regulations: With respect to the safety of transporting hazardous liquids, there are no related rules or regulations issued by other department or agencies of the Federal Government. Alternate proposals for small businesses: The Regulatory Flexibility Act directs agencies to establish exceptions and differing compliance standards for small businesses, where it is possible to do so and still meet the objectives of applicable regulatory statutes. In the case of Congressionally mandated safety regulation of gathering lines and low-stress pipelines, it is not possible to establish exceptions or differing standards and still accomplish the objectives of Congress. Conclusion: This final rule does not apply to a substantial number of small entities. Furthermore, no small entities are expected to experience a significant adverse economic impact because of the final rule. '^ Warren R. True and Jeannie Stell, "Special Report: Pipeline Economics," Oil & Gas Journal Data Book, 2005 Edition, PennWell Corp., Tulsa, OK, 2005, pp. 78-80. 48 I P#