Original Notice.

     Preproposal statement of inquiry was filed as WSR 01-17-048.

     Title of Rule and Other Identifying Information: Chapter 480-93 WAC, Gas companies -- Safety.

     Hearing Location(s): Commission Hearing Room 206, 2nd Floor, Chandler Plaza Building, 1300 South Evergreen Park Drive S.W., Olympia, WA 98504-7250, on October 29, 2004, at 9:30 a.m.

     Date of Intended Adoption: October 27, 2004.

     Submit Written Comments to: Carole J. Washburn, Executive Secretary, P.O. Box 47250, Olympia, WA 98504-7250 or e-mail records@wutc.wa.gov, fax (360) 586-1150, by August 27, 2004. Please include Docket No. UG-011073 in your communication.

     Assistance for Persons with Disabilities: Contact Mary DeYoung, by Monday, October 25, 2004, TDD (360) 586-8203 or (360) 664-1133.

     Purpose of the Proposal and Its Anticipated Effects, Including Any Changes in Existing Rules: The proposed rules are intended to implement the requirements of Executive Order 97-02, requiring agencies to review significant rules for need; effectiveness and efficiency; clarity; intent and statutory authority; cost and fairness. The proposal repeals some of the existing rules that are no longer necessary, adds rules to clarify existing federal rules which the commission adopts by reference, and includes new rules that are more stringent than federal rules, such as adding "new construction" as an activity included as a covered task. The proposed rules include new rules for defining "timeframes" used throughout the chapter, and addressing protection of exposed plastic pipe.

     WAC 480-93-002, proposal deletes this rule and incorporates language in WAC 480-93-007.

     WAC 480-93-005, the proposed rule modifies the existing rule by eliminating definitions not pertinent to the commission's jurisdiction, clarifying terms used throughout the chapter, such as "operator," adding a definition for the term "business district," and adding a definition for the term "Master Meter," as is defined in 49 C.F.R. §191.3.

     WAC 480-93-007, a new proposed rule incorporating language from WAC 480-93-002.

     WAC 480-93-008, a new proposed rule that addresses applicability of the rules.

     WAC 480-93-009, a new proposed rule that provides for severability of rules.

     WAC 480-93-010, proposal deletes this rule and incorporates language in WAC 480-93-999.

     WAC 480-93-012, a new proposed rule that specifies timeframes identified in various rules.

     WAC 480-93-015, the proposed rule requires "sniff tests" be conducted at least once monthly and equipment used to perform the test be calibrated in accordance with manufacturer's recommendation. If there is no manufacturer's recommendation, equipment must be tested at least annually.

     WAC 480-93-017, rewritten for clarity.

     WAC 480-93-018, includes a requirement that pipeline companies update records within six months of completion of construction activity and make them available to company operation personnel.

     WAC 480-93-020, this rule is rewritten for clarity and incorporates the requirements of WAC 480-93-030.

     WAC 480-93-030, proposal deletes this rule and incorporates language in WAC 480-93-020.

     WAC 480-93-040, rewritten for clarity.

     WAC 480-93-080, the proposed rule changes the requalification requirement for Appendix C welders from one year to six months, and requires that welders carry identification cards. The rule also disallows Appendix C welders from welding high pressure, large diameter pipes.

     WAC 480-93-082, proposal deletes this rule.

     WAC 480-93-100, the proposed rule requires companies to identify emergency valves, install such valves in business districts, and near churches, schools, hospitals and emergency buildings, and maintain a written maintenance program detailing the valve selection process, when they will be inspected, and maintenance and operating procedures.

     WAC 480-93-110, the proposed rule requires companies to maintain detailed written cathodic protection (CP) procedures. In addition, the rule has been rewritten to clarify state and federal requirements, and adds remedial action timeframes. In addition, the proposed rule requires companies to have a written internal CP program that includes monitoring, and that CP tests be taken when steel pipe is exposed. The proposed [rule] also requires annual monitoring of pipelines that are less than ten feet in length and have been CP protected due to corrosion or leakage, rather than every ten years as required by federal rules.

     WAC 480-93-111, proposal deletes this rule and incorporates language in WAC 480-93-110.

     WAC 480-93-112, proposal deletes this rule and incorporates language in WAC 480-93-110.

     WAC 480-93-115, rewritten for clarity.

     WAC 480-93-120, proposal deletes this rule and incorporates language in WAC 480-93-124.

     WAC 480-93-124, the proposed rule requires companies to place markers at all railroad, road, irrigation, and drainage ditch crossings, river crossings, creeks, and at all fence lines where a pipeline crosses private property, or where a pipeline or pipeline facility is exposed. In addition the proposed rule requires companies to replace markers within forty-five days of discovery. Companies must also maintain records that identify class locations and where markers are required.

     WAC 480-93-130, proposal deletes rule.

     WAC 480-93-140, the proposed rule requires companies to follow the manufacturer's recommended installation and maintenance practices of service regulators to insure proper and safe operation. In addition, companies must verify the set points at the initial turn-on.

     WAC 480-93-150, proposal deletes rule.

     WAC 480-93-155, rewritten for clarity.

     WAC 480-93-160, rewritten for clarity.

     WAC 480-93-170, rewritten for clarity.

     WAC 480-93-175, rewritten for clarity.

     WAC 480-93-178, a new proposed rule that requires companies to monitor above-ground temporary installations of plastic pipe. In addition, a new requirement is proposed to keep pipe separated from other utilities when buried, requires a weak-link when pulling pipe so it isn't damaged, and has a maximum ultraviolet light exposure limit.

     WAC 480-93-180, rewritten for clarity.

     WAC 480-93-183, proposal deletes rule.

     WAC 480-93-184, proposal deletes rule.

     WAC 480-93-185, rewritten for clarity.

     WAC 480-93-186, the proposed rule requires companies to fix leaks and not regrade leaks numerous times. When a leak has been regraded and the same leak is later found at a more severe grade, the leak must be repaired.

     WAC 480-93-18601, rewritten for clarity.

     WAC 480-93-187, rewritten for clarity.

     WAC 480-93-188, the proposed rule specifies that companies must follow the manufacturer's recommendation for calibration, and if an instrument does not have a manufacturer's recommendation for calibration, then it must be calibrated once each month. In addition, section (3)(a) of the rule has been modified to require gas leak surveys in "business districts," as defined in WAC 480-93-005.

     WAC 480-93-190, proposal deletes rule and incorporates language in WAC 480-93-200.

     WAC 480-93-200, the proposed rule incorporates WAC 480-93-190. The rule is rewritten for clarity and consistency with federal regulations, requires drug and alcohol forms be submitted to the commission, changes the telephonic incident reporting requirement for more serious incidents from six to two hours and reporting for other reportable incidents from six to twenty-four hours. In addition, companies must submit daily reports of construction and repair activities.

     WAC 480-93-210, proposal deletes rule.

     WAC 480-93-220, proposal deletes rule.

     WAC 480-93-223, rewritten for clarity.

     WAC 480-93-230, rewritten for clarity.

     WAC 480-93-240, proposal makes no change to this rule.

     WAC 480-93-999, rewritten to incorporate accurate references. This rule reflects each regulation or standard the commission is adopting, the effective date of the regulation or standard, the place within the commission's rules the regulation or standard is referenced, and the availability in which the regulation is found. The commission adopts by reference the definition of the term "covered task" in 49 C.F.R. § 192.801(b), but adds "new construction" to the definition.

     Reasons Supporting Proposal: The proposed rules are necessary and reasonable to ensure the safety of gas pipeline operations and to promote safety for the citizens of Washington state from the hazards of gas pipeline operations. In addition, a review of the existing rules and the commission's experience in inspecting pipeline facilities in the state has shown a need for consistency in practices among companies, as well as clarity, and to define the meaning of terms used in federal and state rules. Some of the proposed rules apply more stringent requirements than existing federal rules to address concerns the commission has identified in its experience in inspecting pipeline facilities.

     Statutory Authority for Adoption: RCW 80.01.040, 80.04.160, and 80.28.210.

     Rule is not necessitated by federal law, federal or state court decision.

     Name of Proponent: Washington Utilities and Transportation Commission, governmental.

     Name of Agency Personnel Responsible for Drafting: Sondra Walsh, Senior Policy Strategist, 1300 South Evergreen Park Drive S.W., Olympia, WA 98504, (360) 664-1286; Implementation and Enforcement: Carole J. Washburn, Executive Secretary, 1300 South Evergreen Park Drive S.W., Olympia, WA 98504, (360) 664-1174.

     A small business economic impact statement has been prepared under chapter 19.85 RCW.

     Over the last three years, commission staff has held four stakeholder workshops with interested persons to discuss draft rule language, receive comments, and explore options. Staff has prepared three sets of draft rules and submitted them to stakeholders for comment. Staff believes that the draft rules are now sufficiently developed to recommend that the commission publish them as proposed rules, and proceed to the next phase of the rule making. When issuing a notice of proposed rules, agencies must provide a copy of the small business economic impact statement (SBEIS) prepared under chapter 19.85 RCW, or explain why an SBEIS was not prepared. RCW 34.05.320 (1)(k).

     2. SBEIS Requirements: The Regulatory Fairness Act, codified in chapter 19.85 RCW, provides that an agency must conduct an SBEIS "if the proposed rule will impose more than minor costs on businesses in an industry." RCW 19.85.030. An SBEIS is intended to assist agencies in evaluating any disproportionate impacts of the rule making on small businesses. A business is categorized as "small" under the Regulatory Fairness Act if the business employs fifty or fewer employees.

     Under RCW 19.85.040(1), agencies must determine whether there is a disproportionate impact on small businesses in the industry, and under RCW 19.85.030(2), consider means to minimize the costs imposed on small businesses. In determining whether there is a disproportionate impact on small businesses, agencies must compare the cost of compliance for small businesses with the cost of compliance for the 10% of businesses that are the largest businesses required to comply with the rule using either the cost per employee, the cost per hour of labor, or the cost per $100 of sales revenue, as a basis for comparing costs. See RCW 19.85.040(1).

     3. SBEIS Evaluation Procedure: Staff determined that it was necessary to prepare an SBEIS for gas safety rules in Docket No. UG-011073 as the proposed rules may impose more than minor costs on pipeline companies operating in Washington state. With the last set of draft rules, the commission mailed a notice to the fifteen natural gas companies under commission jurisdiction for pipeline safety, as well as other stakeholders, providing an opportunity to respond to an SBEIS questionnaire. This notice requested that the affected companies provide information concerning the cost impact of draft rules developed by commission staff for chapter 480-93 WAC, and to provide specific information for each draft rule that the company identifies as causing an impact. Staff received completed surveys in this docket from two natural gas companies and one direct sales company: Puget Sound Energy (PSE), Cascade Natural Gas (CNG), and Camas Mill (Georgia Pacific).

     None of the pipeline companies regulated by the commission, including the three companies that responded to the questionnaire, however, are small businesses: Staff has determined that none of the pipeline companies regulated by the commission for safety are categorized as "small" businesses as defined by the Regulatory Fairness Act. Large companies do not have great incentive to respond to the survey or to provide detailed information, because the commission is only required to mitigate the economic impacts of the proposed rules on small businesses. In addition, because the commission regulates pipeline companies for safety under chapter 480-93 WAC, and does not regulate the companies' rates, there are no requirements that pipeline companies submit any financial data to the commission.

     To conduct an SBEIS pursuant to the Regulatory Fairness Act, the commission must either determine the cost per employee, the cost per hour of labor or the cost per $100 of sales revenue. As discussed above, this information is not known or required to be submitted to the commission under chapter 480-93 WAC. The results of this survey, therefore, should be interpreted with an understanding that the study is based upon limited, and in some cases unverifiable, quantitative data.

     The staff conducted its analysis by considering the purpose of the rule, the reason for the new rule or change to the rule, and the cost of compliance asserted by the company. Staff then evaluated whether the cost alleged was reasonable or already a cost of compliance, and in weighing all the information, determined if any mitigation of the requirements of the draft rule were appropriate. Although the commission is not required by RCW 19.85.030 to mitigate the impact of the rule on large businesses, staff has evaluated the cost of compliance with the draft rules and whether to mitigate the impact of the rules on the fifteen natural gas companies under commission jurisdiction for pipeline safety in order to ensure that the effect of the rule making is fair and does not impose undue financial burden on the affected companies.

     4. Compliance Requirements of the Draft Proposed Rules: The proposed rules clarify existing state rules and definitions, and add additional safety requirements to certain federal rules adopted by reference. Specifically, the proposed rules will require gas pipeline companies to:

•	Perform monthly odorization tests;
•	Calibrate and maintain all equipment when feasible;
•	Comply with welding procedures qualified to API standards;
•	Require welders be qualified every six months;
•	Maintain a detailed written emergency valve maintenance program; and
•	Require service valves on churches, schools, hospitals and commercial businesses.

     When corrosion is detected on a pipeline, a company must take remedial action within 90 days and take corrosion protection reads on all steel pipe when it is exposed. The rules require companies to install pipeline markers on all railroad crossings, river crossings, creeks, and survey the markers every three years, and maintain the records for ten years. The proposed rules include a new rule for the protection of plastic pipe requiring companies to monitor all above ground installations. In addition, the proposed rules include additional reporting requirements that require companies to report more severe incidents within two hours of discovery and other types of incidents within six to twenty-four hours. The incident reporting requirements will provide data to enable the commission to compile statistics on incidents.

     5. Results of the Analysis: Of the fifteen natural gas pipeline companies regulated by the commission, two local distribution companies ("LDCs") and one direct sales company responded to the survey. These companies identified costs associated with ten of the draft rules. These rules and the specific cost impacts identified by the companies are discussed and evaluated in detail below. The companies' responses indicate that the cost of compliance with most of the draft rules appears to be reasonable. The only exception is the estimated cost to comply with the proposed revisions to WAC 480-93-100, which addresses the maintenance of valves and WAC 480-93-188, which addresses gas leak surveys. One company estimates the cost of compliance with these two rules to be very high.

     The three responding companies identified compliance costs associated with the following draft rules:

     WAC 480-93-005 Business district, the proposed definition clarifies the meaning of the term "business district." Existing federal and state rules use the term "business district" with no associated definition. The term "business district" is used in federal and state rules addressing valve maintenance and leak survey requirements. Given the lack of a definition, companies in Washington state interpret the term differently. The meaning of the term in the proposed definition is based on federal interpretations and a definition adopted by the state of Arizona. The proposed definition requires companies to identify areas where the public congregates for economic, industrial, religious, educational, health, or recreational purposes, and if two buildings are within one hundred yards of each used for these purposes. The proposed definition require companies to identify such areas, install shut off valves and conduct leak surveys at least once annually, but not to exceed fifteen months between surveys.

     PSE: The company estimates that the proposed definition will increase the areas they have recognized as business districts to 1,200 and require maintenance on an estimated 10,000 valves. In addition PSE asserts that it will be required to conduct additional leak surveys. PSE's estimated annual compliance cost to identify "business districts" and conduct additional leak surveys where a "business district" is identified will be $910,500.

     Discussion: The proposed definition for "business district" affects the proposed valve rule WAC 480-93-100, and the proposed leak survey rule, WAC 480-93-188 (3)(a). As more areas could be designated as business districts under the new definition, valves will now be required on schools, hospitals, churches, and commercial services within a business district, and leak surveys must be conducted at least annually but not to exceed fifteen months. Because of differing interpretations of the term "business district" by companies in the state and the effect of this interpretation on emergency valve identification and maintenance, and conducting leak surveys, the term needs to be better defined. The cost of compliance with the proposed definition in relation to WAC 480-93-100, and WAC 480-93-188 (3)(a) will not be known until after the rule is adopted and companies evaluate the actual number of valves affected by the rule. Given the potential effect of the definition on these two rules, it is appropriate to defer the effective date of the two rules for three years. This mitigation measure is discussed in more detail below.

     WAC 480-93-015 Odorization of gas, the proposed rule requires that all gas must be odorized once each month. The proposed requirement will assist companies in verifying the odorant level in gas and determining whether a pipeline is leaking. The existing state rule and current federal rules require odorization to be conducted periodically. In addition, the proposed rule requires odorant testing equipment be calibrated in accordance with the manufacturer's recommendations. Where there is no recommended interval, calibration must be performed at least annually.

     Camas Mill (Georgia Pacific), estimated that the cost to comply with the draft rules would be approximately $1800 per year, as it will increase the number of tests from six to twelve per year.

     Discussion: The estimated cost of $1,800 per year to comply with the new requirements of the rule would establish a cost of $300 per test. Staff believes the cost of $300 per test to be high. Consistent levels of odorization allow the public or company personnel to detect leaks.

     The requirement to "sniff test" once each month will create consistency among companies. Currently companies are testing, on many different timeframes, e.g., bi-monthly, every six months, and yearly. In addition, most LDCs are already testing on a monthly basis.

     WAC 480-93-080 Welder and plastic identification and qualification certificates, the proposed rule requires that all C.F.R. Appendix C welders be requalified once every six months as opposed to yearly, and requires an annual requalification test for plastic joiners. Commission inspection records have shown that welders have a higher fail rate when they are qualified only on a yearly basis. The proposed test frequency of every six months will be more consistent with industry welder qualification requirements such as American Society Mechanical Engineers (ASME), Section 9 and American Petroleum Institute (API) 1104, which are referenced in the federal rules. The rule also disallows Appendix C welders from welding high pressure, large diameter pipelines.

     Camas Mill (Georgia Pacific): The company responded that the effect of the proposed rule is that welders must physically carry identification cards and may not rely on certificates that are most times filed in the office. The company estimates an annual compliance cost of $100.

     PSE: The company reports that the draft proposed rule will require PSE to requalify nineteen fitters on a semi-annual basis as opposed to annually, and estimates an annual compliance cost of $4,275.

     Discussion: Staff believes that the estimated cost for each company to comply is reasonable. The current rule requires welders to carry certification certificates, which are the same as identification cards required in the proposed rule. The proposed rule will provide an inspector the opportunity to verify on site that a welder is qualified to perform the welding being performed. The proposed rule also adopts industry standards for welding qualifications, standards that staff believe will increase the safety and reliability of pipelines in the state.

     WAC 480-93-100 Valves, the proposed rule requires operators to develop and maintain a detailed written maintenance program that outlines how emergency valves required by C.F.R. Parts 192.747 and 192.745 will be selected and maintained. It also requires that valves be installed on service lines to churches, schools, hospitals and commercial buildings within business districts and that they be maintained and operated annually.

     Camas Mill (Georgia Pacific): Camas Mill stated that they will have to rewrite the company's manual for its already-defined valve maintenance program. The proposed rule will require the company to rewrite the portion of the manual relating to operations and maintenance. The company estimates an additional expense of $1,600 to complete the project. Camas Mill did not identify any additional annual cost of compliance.

     CNG: The company identified additional costs for its valve maintenance program. CNG has estimated that the proposed rule will increase its current valve maintenance program to include 21,000 new valves, and estimates that the annual cost of compliance of the draft rule will be $567,000.

     PSE: The company states that the proposed rule will increase valve installation and maintenance by an estimated 32,000 valves per year, and estimates the annual cost of compliance will be $2,736,000.

     Discussion: In past inspections, staff has reviewed records indicating that, in many cases, it has taken emergency responders and company personnel longer than necessary (more than one to two hours) to shut off the flow of gas in an emergency situation because valves were not accessible either because they have been paved over or their location is not readily marked. This has posed an increased risk to the general public due to the lengthened time of escaping gas in emergencies. Operators generally rely on valves as their first means of shutting down pipelines in emergency situations. Operators install many valves in their systems but only select a small number and designate them as emergency valves. Unless valves are designated as emergency valves they usually are not maintained.

     Many fire departments carry valve keys that allow them to shut off the flow of gas to services in emergency situations. Operators in many cases provide training and equipment to local fire departments on how to respond to natural gas emergencies and shut down services. A new definition in proposed rule WAC 480-93-005 for "business district" affects the valve rule since more areas could be designated as business districts and valves will now be required on commercial services within these areas. The cost of compliance with WAC 480-93-100 will not be known until after the rule is adopted and companies evaluate the actual number of valves affected by the rule. Given the potential compliance cost to the companies, staff believes it is appropriate to allow companies time to comply with the new rule. The proposed rule has been modified to provide for a three-year delay in the effective date.

     WAC 480-93-110 Corrosion control, the proposed rule requires companies to maintain detailed written cathodic protection (CP) procedures. It also clarifies the existing rules, both state and federal, by detailing the requirements more clearly and by adding remedial action timeframes. The proposed rule also requires that a company have a written internal corrosion monitoring program. In addition, the proposed rule requires that a CP test read be taken when steel pipe is exposed, requires calibration of instruments used in CP, and requires annual monitoring for pipelines that are less than one hundred feet in length and have been cathodically protected due to corrosion or leakage instead of monitoring every ten years as required by the federal rules.

     Camas Mill (Georgia Pacific): The company asserts that the cost of calibrating a multimeter, the instrument used to test for corrosion control, would be $110 per unit. The company argues that the calibration cost is more than 50% of the replacement cost and that multimeters would be replaced annually rather than calibrated. The company estimates the annual cost of compliance to be $376.

     CNG: The company currently conducts leak surveys every ninety days. If they choose to survey for leaks every six months as required by the proposed rule, the company will incur a savings of $4,050 per year.

     CNG and PSE: The proposed rule requires companies to take cathodic protection readings whenever the coating is removed from an existing underground pipe. In addition, the proposed rule requires companies to monitor separate short sections of mains and services that have been protected against corrosion due to leakage, annually not to exceed fifteen months as opposed to every ten years. CNG reports an annual compliance cost of $20,000 and PSE estimates an annual compliance cost of $11,800.

     Discussion: The changes to the proposed rule are intended to clarify the current state and federal CP rules. There appears to be confusion among operators on how to interpret certain existing rules. Staff has therefore, attempted to rewrite the existing rules and clarify them in the process. Lack of adequate CP was for many years the leading cause of leaks among pipeline companies. It is now the second leading cause of leaks. Proper interpretation and implementation of a CP program will ensure that pipelines are at a minimal risk for corrosion and leakage.

     The requirement that a CP read be taken each time steel pipe is exposed is to determine whether there are adequate levels of CP without waiting up to a year in between the currently required annual tests.

     The requirement for a written internal CP program is based on the New Mexico incident that resulted in numerous deaths. The cause was determined to be internal corrosion. While LDCs generally do not have internal corrosion problems, staff believes companies should still monitor for it.

     Annual monitoring of short pipes that have been cathodically protected due to corrosion or leakage instead of monitoring is necessary to ensure that the cathodic protection is working to prevent future corrosion or leaks.

     Instruments should be calibrated according to the manufacturer's recommendations to ensure that tests are performed accurately. Remedial action timeframes are necessary due to the inconsistency among operators for remedial action. Some operators complete it immediately and others take over a year or more.

     WAC 480-93-124 Pipeline markers, the proposed rule requires companies to place markers on all mains above 250 psig, and at river crossings, creeks and railroad crossings. When a marker is discovered missing the marker must be replaced within forty-five days of discovery. Companies must survey the markers every five years, and maintain the documentation on its surveys for ten years. In addition, companies must maintain records that identify class locations and where markers are required.

     Camas Mill (Georgia Pacific): The company states that the proposed rule will require that they identify on their maps the class location of their pipelines and will further require a revision to its manual and compliance tracking software, additional surveys, and map conversion. Camas Mill estimates a compliance cost of $7,800.

     PSE: The company estimates that they will need to add three hundred eighty markers on railroad crossings. The estimated cost to add markers to the railroad crossings represents a one-time cost of $5,000 and an annual compliance cost of $36,800.

     Discussion: Staff believes that the estimated cost to comply is reasonable given the importance of properly marking pipelines. The requirement will make excavators aware that there is a pipeline facility in the vicinity of where digging will take place. If markers are not present, an excavator may not be aware of the pipeline and the line may be hit and damaged. The damage can be costly to repair. In addition, identifying class locations on a company's maps is to determine where markers are required and verify compliance during field inspections.

     WAC 480-93-140 Service regulators, the proposed rule requires companies to follow the manufacturer's recommended installation and maintenance practices to insure the proper and safe operation of service regulators. The prescriptive tests required in the proposed rule are recognized as standard industry practices. In addition, verifying the set points at the initial turn-on performs a quality control check that will ensure that the gas company is delivering the correct amount of gas to a customer.

     PSE: The proposed rule requires companies to verify set points at initial turn-ons. PSE estimates that the annual compliance cost will be $718,300, and that the company will incur a one-time compliance cost of $5,000.

     Discussion: The proposed rule requires a company to follow federal and state rules governing service regulators as well as the manufacturer's recommended installation and maintenance procedures. The rule is prescriptive, identifies these practices as industry standards, and provides for the elimination of potential over pressure of a fuel line that leads into residential homes, the elimination of leaks, and other potential hazards.

     Based upon information inspectors have collected during inspections, staff believes that PSE has not been verifying set points at initial turn-ons, a practice included in the manufacturer's recommended installation procedures. While Staff cannot verify PSE's estimated compliance costs, staff believes that PSE should have already been verifying set points as do all LDCs.

     WAC 480-93-178 Protection of plastic pipe, the proposed rule requires companies to monitor aboveground temporary installations of plastic pipe. It also adds requirements to keep pipe separated from other utilities when buried, requires a weak-link when pulling pipe so it isn't damaged, and has a maximum ultraviolet light exposure limit.

     PSE: PSE states that the proposed new rule will require that the company establish a monitoring program for above-ground installation of plastic pipe. The company estimates a one-time compliance cost of $5,000 and an annual compliance cost of $2,500.

     Discussion: Staff believes that PSE's estimated cost of compliance is very reasonable. Monitoring above-ground installation will ensure that pipe installed above ground is monitored similarly to pipe installed in the ground. This will ensure the integrity of the pipeline, and protect against any leaks or incidents.

     WAC 480-93-186 Leakage classifications and action criteria, the proposed rule requires companies to repair a leak when the leak has been graded as a grade one or a grade two leak. Current company practices are to fix a leak by sucking the gas out of the ground and taking a new read, which at that time identifies the leak as fixed. The leak is then regraded as a grade three leak. This practice prevents leaks from being permanently fixed. The proposed rule will allow a company to downgrade a leak only once, then require that the leak be repaired. The proposed rule also requires companies to conduct follow-up inspections for all leaks with residual gas.

     PSE: PSE states that the proposed rule allows for a leak to be downgraded only once, requiring it to repair an additional seventy-eight leaks per year. The company estimates an annual compliance cost of $163,500.

     Discussion: The rule revisions will require companies to fix leaks and not regrade leaks numerous times. Staff strongly believes that if a leak has been regraded and the same leak is found at a more severe grade than when left, the leak must be repaired. This practice provides additional pipeline safety.

     WAC 480-93-188 Gas leak surveys, the proposed rule specifies that companies must follow the manufacturer's recommendation for calibration, and if an instrument does not have a manufacturer's recommendation for calibration, then it must be calibrated once each month. Subsection (3)(a) of the rule has been modified to require gas leak surveys in "business districts," rather than "business areas." The proposed rule does not change the frequency of surveys, i.e., annually, but may change the area covered by the existing rule.

     Camas Mill (Georgia Pacific): The company states that if their equipment does not have a manufacturer's recommendation for calibration, they send it out to be calibrated. Because of the cost of recalibration, the proposed requirement will require Camas to purchase a second instrument instead of recalibration. The company estimates an annual cost of compliance with this requirement of $1,800.

     PSE: The company estimates that it will be required to conduct additional leak surveys under this proposed rule. As discussed above in relation to the definition of the term "business district," PSE estimates the annual compliance cost to identify "business districts" and conduct additional leak surveys where a "business district" is identified will be $910,500.

     Discussion: The rule does not require a company to send their equipment to the manufacturer for calibration. They must first follow the manufacturer's recommendation if there is one. If there is no manufacturer's recommendation they will need to calibrate. This does not require a company to send the equipment off-site. Staff disagrees with the need to purchase a second instrument and the company's estimated cost of compliance. Given the potential cost to the companies of compliance with the requirement to survey "business districts," however, staff believes it is appropriate to allow companies time to comply with the new rule. The proposed rule has been modified to provide for a three-year delay in the effective date of subsection (3)(a).

     WAC 480-93-200 Reports associated with operator facilities and operations, the proposed rule incorporates current rule WAC 480-93-190. The proposed rule has been drafted to improve clarity and consistency with federal regulations. The proposed rule requires that drug and alcohol forms be submitted to the commission, changes the telephonic incident reporting requirement for more serious incidents from six to two hours and reporting for other reportable incidents from six to twenty-four hours and requires companies to submit daily reports of construction and repair activities. In addition, the proposed rule requirements will allow the commission to better track statistics on incidents.

     CNG: The company states that the proposed requirement to notify the commission when an evacuation takes place in a dwelling, building, or area of public assembly, will impose an annual compliance cost of $1,800.

     CNG objects to daily reports to the commission concerning construction activities, arguing that existing rules do not require such reporting. CNG estimates this requirement will create an additional annual compliance cost of $22,500.

     Discussion: The requirement to notify the commission of an evacuation in relation to a pipeline incident allows the commission to respond to media or public inquiries, and allows the commission to keep statistics applicable to such incidents. The proposed cost of compliance is reasonable. Staff disagrees with CNG's estimated annual compliance cost. Companies should incur no additional compliance costs for such reporting, as all LDCs have voluntarily provided daily construction activity reports for the past few years.

     6. Proposed Rules That May Create Cost Savings: Staff believes that three of the proposed rules will provide cost savings to companies. In CNG's reply to the SBEIS they identified some cost savings with the proposed rule change to WAC 480-93-110 addressing leak surveys of shorted casings. The current rule requires leak surveys to be performed every ninety days, while the proposed rule requires such surveys to be performed every six months. Other companies should also realize cost savings under this proposed rule.

     The second rule that staff believes will provide cost savings to companies is the change in the definition of "transmission" in WAC 480-93-005. The proposed definition will reduce the number of pipelines defined as transmission lines and will result in fewer pipelines having to meet the more stringent transmission operations, maintenance, and construction requirements in the chapter.

     The third rule that staff believes will provide a cost savings is WAC 480-93-175, which addresses the moving and lowering of metallic pipeline. The proposed rule should reduce the amount of short steel replacements that are required due to other utility construction conflicts. The majority of all steel replaced for this reason is 2" diameter pipeline, which would be exempt from the required study of the steel toughness under the proposed rule.

     7. Summary of Findings: The proposed rule changes provide additional pipeline safety and will provide assurances that companies are maintaining pipelines as safely as possible. Requiring companies to odorize gas on a monthly basis, take remedial action when corrosion is found on a pipeline, identify and maintain emergency valves, have qualified welders, verify that set points are set properly before a customer begins receiving gas, and repair leaks permanently as opposed to regrading them on a continual basis will improve safety on gas pipelines in the state. The estimated cost to comply with the proposed rules appears to be reasonable and does not appear to be significant, except for the effect of the definition of the term "business district" on the proposed valve rule and proposed gas leak survey rule. As stated in the analysis above, the true cost of compliance with these proposed rules will not be known until companies evaluate their pipeline facilities, determine which valves are within business districts, and determine the need for additional leak surveys.

     8. Mitigation: Changes to the definition of "business district" in WAC 480-93-005, and the effect of using the term in both the valve rule, WAC 480-93-100, and the leak survey rule, WAC 480-93-188 (3)(a), have the potential to cause significant compliance costs for gas pipeline companies. As described above, staff believes that the changes in these rules are necessary to address concerns over how pipeline companies survey leaks, and identify and maintain valves necessary to shut off gas in an emergency. In order to address the potentially significant effect of these proposed rules on companies, staff proposes to mitigate the cost impact by delaying the effective date of WAC 480-93-100 and 480-93-188 (3)(a) for three years to allow companies to conduct the necessary surveys and studies to implement the proposed rules.

     9. Conclusion: Chapter 19.85 RCW requires that an SBEIS be prepared to assess whether the proposed rules impose more than minor costs on businesses in an industry, in this case, gas pipeline companies. Staff mailed surveys designed to obtain information about the cost of compliance with the draft proposed rules to all fifteen natural gas pipeline companies regulated by the commission. Staff received responses from only three companies.

     Staff has reviewed the cost data submitted by the three companies and found the cost of compliance not to be significant except for cost estimates submitted by one of the companies associated with the proposed revisions to WAC 480-93-100 and 480-93-188 (3)(a).

     Based on an analysis of the cost impacts of the proposed rules on gas pipeline companies, staff concludes that:

     1) Pipeline companies will incur costs to comply with some of the proposed rules, in some cases costs that are more than minor, and may reduce the costs of complying with other rules;

     2) No small businesses are affected by the proposed rules;

     3) The changes in the rules are expected to provide additional safety to pipelines operating within the commission's jurisdiction;

     4) Although it was not possible to directly compare the costs and benefits of implementing the proposed rules, staff believes that, on balance, the benefits of implementing the proposed rules relating to pipeline safety are at least equal to the costs of compliance; and

     5) Staff proposes to mitigate the cost impact of the proposed requirements in WAC 480-93-005(3), pertaining to the proposed definition of "business district"; WAC 480-93-100, concerning valves; and WAC 480-93-188 (3)(a) as it pertains to leaks surveys in an identified "business district" by delaying the effective date of WAC 480-93-100 and 480-93-188 (3)(a) by three years to allow companies time to conduct surveys and studies to implement the proposed rules.

     A copy of the statement may be obtained by contacting Washington Utilities and Transportation Commission, Records Center, Docket No. UG-011073, 1300 South Evergreen Park Drive S.W., P.O. Box 47250, Olympia, WA 98504-7250, phone (360) 664-1286, fax (360) 664-1150, e-mail swalsh@wutc.wa.gov.

     A cost-benefit analysis is not required under RCW 34.05.328. The commission is not an agency to which RCW 34.05.328 applies. The proposed rules are not significant legislative rules of the sort referenced in RCW 34.05.328(5).

July 21, 2004

Carole J. Washburn

Executive Secretary

OTS-7389.1

AMENDATORY SECTION(Amending Docket No. A-010827, General Order No. R-491, filed 9/28/01, effective 10/29/01)

WAC 480-93-005   Definitions.   (((1) Bar hole - a hole that has been made in the soil or paving for the specific purpose of testing the subsurface atmosphere with a combustible gas indicator.

     (2) Building - any structure which is normally or occasionally entered by humans for business, residential, or other purposes and within which gas could accumulate.

     (3) Combustible gas indicator (CGI) - a device capable of detecting and measuring gas concentrations of the gas being transported.

     (4) Confined space - any subsurface structure of sufficient size which could accommodate a person and within which gas could accumulate, e.g., vaults, catch basins, manholes, etc.

     (5) Follow-up inspection - an inspection performed after a repair has been completed in order to determine the effectiveness of the repair.

     (6) Gas - natural gas, flammable gas, or gas which is toxic or corrosive.

     (7) Gas associated substructures - those devices or facilities utilized by a gas company which are not intended for storing, transporting, or distributing gas, such as valve boxes, vaults, test boxes, and vented casing pipe.

     (8) Gas company - the term "gas company" shall mean:

     (a) Every gas company otherwise subject to the jurisdiction of the commission under Title 80 RCW as to rates and service; and

     (b) Every person, corporation, city, or town which owns or operates a pipeline transporting gas in this state, even though such person, corporation, city, or town is not a public service company under chapter 80.28 RCW, and even though such person, corporation, city, or town does not deliver, sell, or furnish gas to any person or corporation within this state.

     (9) Gathering line - a gas pipeline which transports gas from the outlet of a well and any associated compressor to the connection with a second gathering line or with a transmission line.

     (10) Indication - a response indicated by a gas detection instrument that has not been verified as a reading.

     (11) L.E.L. - the lower explosive limit of the gas being transported.

     (12) Main - a gas pipeline, not a gathering or transmission line:

     (a) Which serves as a common source of gas for more than one service line;

     (b) Which crosses a public right of way; or

     (c) Which crosses property not owned by the customer or the gas company.

     (13) Master meter system - a pipeline system for distributing gas to more than one building within, but not limited to, a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for distribution to ultimate consumers other than the system operator's immediate family through a gas distribution pipeline system.

     (14) Maximum operating pressure - a maximum pressure selected by a gas company for operation of a pipeline or segment of a pipeline, which is equal to or less than the maximum allowable operating pressure derived pursuant to 49 CFR, Part 192 on the date specified in WAC 480-93-999.

     (15) Prompt action - shall consist of dispatching qualified personnel without undue delay for the purpose of evaluating and where necessary abating an existing or probable hazard.

     (16) Reading - a repeatable deviation on a combustible gas indicator or equivalent instrument expressed in percent L.E.L. or gas-air ratio. Where the reading is in an unvented, confined space, consideration shall be given to the rate of dissipation when the space is ventilated and the rate of accumulation when the space is resealed.

     (17) Service line - a gas pipeline, not a main, gathering or transmission line, which provides service to one building. Service lines shall include gas pipelines extended from a main to provide service to one building, which traverse a public right of way or an easement immediately adjacent to a public right of way or another easement.

     (18) Transmission line - a gas pipeline which connects to an existing transmission line without pressure regulation to lower the pressure; which is downstream of the connection of two or more gathering lines; and as defined in 49 CFR, Part 192, section 192.3 on the date specified in WAC 480-93-999.

     (19) Tunnel - a subsurface passageway large enough for a person to enter and within which gas could accumulate.

     (20) Other terms which correspond to those used in 49 CFR, Parts 191, 192 and 199 (Minimum Federal Safety Standards for Gas Pipelines) shall be construed as used therein on the date specified in WAC 480-93-999.)) (1) "Bar hole" means a hole made in the soil or paving for the specific purpose of testing the subsurface atmosphere with a combustible gas indicator.

     (2) "Building" means any structure that is normally or occasionally entered by humans for business, residential, or other purposes and where gas could accumulate.

     (3) "Business district" means an area where the public congregates for economic, industrial, religious, educational, health, or recreational purposes, and where two or more buildings within one hundred yards of each other are used for these purposes.

     (4) "CFR" means the Code of Federal Regulations.

     (5) "Combustible gas indicator" (CGI) means a device capable of detecting and measuring gas concentrations in air.

     (6) "Commission" means the Washington utilities and transportation commission.

     (7) "Follow-up inspection" means an inspection performed after a repair has been completed in order to determine the effectiveness of the repair.

     (8) "Gas" means natural gas, flammable gas, or gas that is toxic or corrosive.

     (9) "Gas associated substructures" means those devices or facilities utilized by an operator which are not intended for storing, transporting, or distributing gas, such as valve boxes, vaults, test boxes, and vented casing pipe.

     (10) "Gas company" means, as defined in RCW 80.04.010, every corporation, company, association, joint stock association, partnership and person, their lessees, trustees or receiver appointed by any court whatsoever, and every city or town, owning, controlling, operating or managing any gas plant within this state.

     (11) "Indication" means a response indicated by a gas detection instrument that has not been verified as a reading.

     (12) "LEL" means the lower explosive limit of the gas being transported.

     (13) "MAOP" means maximum allowable operating pressure.

     (14) "Master meters system" is defined as set forth in 49 CFR § 191.3.

     (15) "Operator":

     (a) For purposes of chapter 480-93 WAC, the term "operator" means:

     (i) Every natural gas distribution company that has tariffs on file with the commission;

     (ii) Every city or town that owns, controls, operates, or manages any gas plant in this state; and

     (iii) Every other person or corporation transporting natural gas by pipeline, or having for one or more of its principal purposes the construction, maintenance, or operation of pipelines for transporting natural gas in this state; even though such person or corporation does not deliver, sell, or furnish any such gas to any person or corporation within this state. The terms "person" and "corporation" are defined in RCW 80.04.010. "Transporting natural gas by pipeline" means transmission or distribution of natural gas through a pipe.

     (b) A single entity may qualify as an operator under one or more of the provisions of this subsection.

     (c) The term "operator" includes operators of master meter systems, as that term is defined in WAC 480-93-005.

     (16) "Building of public assembly" means a building that is occupied by twenty or more people for sixty days in any twelve-month period.

     (17) "Prompt action" means to consistently dispatch qualified personnel without undue delay for the purpose of evaluating and, where necessary, abating an existing or probable hazard.

     (18) "Psig" means pounds per square inch gauge.

     (19) "Public service company" is defined in RCW 80.04.010.

     (20) "Reading" means a repeatable representation on a combustible gas indicator or equivalent instrument expressed in percent LEL or gas-air ratio.

     (21) "Sniff test" means a qualitative test utilizing both threshold and readily detectable methods for determining proper concentrations of odorant.

     (22) "Transmission line" means a gas pipeline as defined in 49 CFR § 192.3 on the date specified in WAC 480-93-999.

     (23) "Weak link" means a device or method used when pulling polyethylene pipe to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed.

     (24) Other terms that correspond to those used in 49 CFR Parts 191, 192 and 199 (Minimum Federal Safety Standards for Gas Pipelines) must be construed as used therein on the date specified in WAC 480-93-999.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-005, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040 and 80.28.210. 95-13-082 (Order R-427, Docket No. UG-950061), § 480-93-005, filed 6/20/95, effective 7/21/95. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-005, filed 8/5/92, effective 9/5/92; Order R-100, § 480-93-005, filed 5/18/77. Formerly WAC 480-93-001.]

     (2) This chapter does not apply to customer-owned facilities, where the customer is the end user, and the customer-owned facilities are on the customer's side of the distribution meter. Customer-owned transmission lines are subject to the rules in this chapter.

     (3) This chapter does not apply to those operators of gas facilities exclusively under federal jurisdiction for compliance with pipeline safety regulations.

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     (2) The commission retains the authority to impose additional or different requirements on any operator in appropriate circumstances, consistent with the requirements of law.

[]

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     (1) "Monthly" means any time within the calendar month.

     (2) "Annually" means any time within the calendar year.

     (3) "Six months" means the same calendar date of the sixth consecutive month (e.g., January 1, to July 1, would be six months).

     (4) "Seven and one-half months" means the same calendar date of the seventh consecutive month plus an additional fifteen days.

     (5) "Fifteen months" means the same calendar date of the fifteenth consecutive month.

     (6) "Three years" means the same calendar date of the third consecutive year.

     (7) "Thirty-nine months" means the same calendar date of the thirty-ninth consecutive month.

     (8) "Five years" means the same calendar date of the fifth consecutive year.

     (9) "Ten years" means the same calendar date of the tenth consecutive year.

     (10) "Calendar year" means twelve consecutive months beginning January 1 and ending December 31.

     (11) For calendar dates that end on a weekend or holiday, the next business day shall be considered the time frame end date.

[]

     (4) Operators must keep all records of odorant usage, sniff tests performed, and equipment calibration for five years.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-015, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-015, filed 8/5/92, effective 9/5/92.]

     (2) With the exception of emergency situations, any construction plans that do not conform with a gas company's existing and accepted design, specifications, and construction procedures on file with the commission, must be submitted to the commission for review at least forty-five days prior to the initiation of construction activity.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-017, filed 8/5/92, effective 9/5/92.]

     (3) Operators must update records within six months of completion of construction activity and make them available to appropriate company operations personnel.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-018, filed 8/5/92, effective 9/5/92.]

     In requesting prior written authorization of the commission, the petitioning gas company shall certify that it is not practical to select an alternative route which will avoid such locations and further certify that management has given due consideration to the possibility of the future development of the area and has designed its facilities accordingly. The petition shall include, upon request of the commission, an aerial photograph showing the exact location of the pipeline in reference to places listed above that are within five hundred feet of the pipeline right of way.)) (1) Each operator must submit a written request and receive commission approval prior to operating any gas pipeline facility that has the following characteristics:

     (a) Operating or intending to operate at greater than five hundred pounds per square inch gauge (psig) that is within five hundred feet of any of the following places:

     (i) A building intended for human occupancy that is in existence or under construction prior to the date authorization for construction is filed with the commission, and that is not owned and used by the petitioning operator in its gas operations; or

     (ii) A building or an outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by twenty or more people for sixty days in any twelve-month period, which is in existence or under construction prior to the date authorization for construction is filed with the commission; or

     (iii) A public highway, as defined in RCW 81.80.010(3).

     (b) Operating or intending to operate at greater than two hundred fifty psig, up to and including five hundred psig, that is operated within one hundred feet of either of the following places:

     (i) A building intended for human occupancy that is in existence or under construction prior to the date authorization for construction is filed with the commission, and that is not owned and used by the petitioning operator in its gas operations; or

     (ii) A building or an outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by twenty or more people for sixty days in any twelve-month period, which is in existence or under construction prior to the date authorization for construction is filed with the commission.

     (2) For proposed new construction of pipelines having the characteristics listed in subsection (1)(a) or (b) of this section, operators must provide documentation proving that it is not practical to select an alternate route that will avoid such locations and further provide documents that demonstrate that the operator has considered the possibility of the future development of the area and has designed their pipeline facilities accordingly.

     (3) During the review process, operators must provide maps and records to the commission showing the exact location of the pipeline and the shortest direct distance to the places described in subsection (1)(a) and (b) of this section. Upon request of the commission, the operator must provide the maintenance, construction, and operational history of the pipeline system and an aerial photograph showing the exact location of the pipeline in reference to places listed in subsection (1)(a) and (b) of this section.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-020, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-020, filed 7/15/71; Order R-5, § 480-93-020, filed 6/6/69, effective 10/9/69.]

     (2) Gas compressor stations that are designed to operate at pressures in excess of two hundred fifty psig, and having an installed capacity of less than one thousand horsepower must be located at least two hundred fifty feet away from existing buildings that are not under the control of the operator.

[Order R-28, § 480-93-040, filed 7/15/71; Order R-5, § 480-93-040, filed 6/6/69, effective 10/9/69.]

     (3) Welders and plastic joiners must carry appropriate identification and qualification cards showing the name of the welder or joiner, their qualifications, the date of qualification and the operator whose procedures were followed for the qualification. Welders and plastic joiners qualification cards will be subject to commission inspection at all times when qualified personnel are working on facilities subject to commission jurisdiction.

[Order R-28, § 480-93-080, filed 7/15/71; Order R-5, § 480-93-080, filed 6/6/69, effective 10/9/69.]

     (5) This rule is effective on January 1, 2008.

[Order R-28, § 480-93-100, filed 7/15/71; Order R-5, § 480-93-100, filed 6/6/69, effective 10/9/69.]

     Whenever a gas company finds from investigation as required by 49 CFR, Part 192 in effect on the date specified in WAC 480-93-999, that cathodic protection of gas pipelines is not needed, the company shall submit to the commission a report setting forth good and sufficient reasons why such protection is not required. The report shall include the results of soil tests and other supporting data.)) (1) Each operator must ensure that all of their metallic gas pipelines, except cast iron and ductile iron, are protected by a recognized method or combination of methods of cathodic protection.

     (2) Operators must record and retain a record of each cathodic protection test, survey, or inspection required by 49 CFR Subpart I, and chapter 480-93 WAC. Records of each test, survey, or inspection must be kept for a minimum of five years except those specified in 49 CFR § 192.491(c) requiring retention for the life of the facility.

     (3) Each operator must complete remedial action within ninety days to correct any cathodic protection deficiencies known and indicated by any test, survey, or inspection. An additional thirty days may be allowed for remedial action if due to circumstances beyond the operator's control if it is not possible to complete remedial action within ninety days. Each operator must be able to provide documentation to the commission indicating that remedial action was started in a timely manner and that all efforts were made to complete remedial action within ninety days. (Examples of circumstances allowing operators to exceed the ninety-day time frame include right of way permitting issues, availability of repair materials, or unusually long investigation or repair requirements.)

     (4) Operators must have written procedures for the proper use, maintenance, and where feasible the calibration of cathodic protection equipment and instrumentation. At a minimum, each operator must follow the manufacturer's recommended practices for equipment and instrumentation maintenance and calibration. Equipment or instruments that are incapable of being calibrated must be checked for accuracy on a scheduled frequency.

     (5) Each operator's procedures manual must have written procedures explaining how cathodic protection related surveys, reads, and tests will be conducted. Examples of such procedures include, but are not limited to, how to determine IR drop (as defined in 49 CFR § 192 Appendix D), how to conduct electrical surveys, how to test casings for electrical isolation, how to test casings for shorted conditions, and how to measure and interpret 49 CFR § 192 Appendix D criteria.

     (6) Operators must conduct inspections or tests for electrical isolation between metallic pipeline casings and metallic pipelines at least once annually, but not to exceed fifteen months between inspections or tests. The test or inspection must also determine whether the pipeline has adequate levels of cathodic protection at the casing to pipeline interface. These requirements do not apply to unprotected copper inserted in ferrous pipe.

     (a) For each casing installed prior to September 5, 1992, that does not have test leads, the operator must be able to demonstrate that other test or inspection methods are acceptable and that test lead wires are not necessary to monitor for electrical isolation and adequate cathodic protection levels.

     (b) Whenever electrical isolation tests or inspections indicate that a possible shorted condition exists between a casing and a pipeline, the operator must conduct a follow-up test within ninety days to determine whether an actual short exists. The operator's procedures manual must have a level or threshold that would indicate a potential shorted condition and must also detail the method of determining whether the casing is actually shorted to the pipeline.

     (c) The operator must clear the shorted condition where practical.

     (d) Whenever a short exists between a pipeline and casing, the operator must perform a leak survey within ninety days of discovery and at least twice annually thereafter, but not to exceed seven and one-half months between leak surveys until the shorted condition is eliminated.

     (7) Each short segment of pipeline measuring less than one hundred feet in length, that has experienced leakage due to corrosion, and that has subsequently been cathodically protected must be tested annually not to exceed fifteen months to determine whether the facility has adequate levels of cathodic protection.

     (8) Operators must record the condition of all underground metallic facilities each time the facilities are exposed.

     (9) Operators must have a written program to monitor for indications of internal corrosion. The program must also have remedial action requirements for areas where internal corrosion is detected.

     (10) On all cathodically protected pipelines, the operator must take a cathodic protection test reading each time an employee or representative of the operator exposes the facility and the protective coating is removed.

     (11) Each operator must have a written atmospheric corrosion control monitoring program. The program must have time frames for completing remedial action.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-110, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-110, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-110, filed 7/15/71; Order R-5, § 480-93-110, filed 6/6/69, effective 10/9/69.]

     (4) Whenever an operator installs a service line in a casing or conduit, the operator must seal the casing at the end nearest the building wall to prevent or slow the migration of gas towards the building in the event of a leak.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-115, filed 8/5/92, effective 9/5/92.]

     (6) Operators must have maps, drawings or other sufficient records indicating class locations and other areas where pipeline markers are required.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-124, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-124, filed 8/5/92, effective 9/5/92.]

[Order R-28, § 480-93-130, filed 7/15/71; Order R-5, § 480-93-130, filed 6/6/69, effective 10/9/69.]

     (2) Operators must inspect and test service regulators and associated safety devices during the initial turn-on, and when a customer experiences a pressure problem. Testing must include determining the gas regulator's outlet set pressure at a specified flow rate. Operators must use pressure gauges downstream of the regulator during testing. Safety devices such as fracture discs are not required to be tested.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-140, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-140, filed 7/15/71; Order R-5, § 480-93-140, filed 6/6/69, effective 10/9/69.]

     The plan shall conform with the requirements of 49 CFR, Part 192 in effect on the date specified in WAC 480-93-999.)) (1) At least forty-five days before uprating to a maximum allowable operating pressure (MAOP) greater than sixty pounds per square inch gauge (psig), each operator must submit to the commission for review a written plan of procedures including all applicable specifications with drawings of the affected pipeline systems. At a minimum, the plan must include a review of the following:

     (a) A list of all affected gas facilities, including pipes, fittings, valves, and other affected equipment, with the manufacturer's specified maximum operating pressure limits, their specified minimum yield strength (SMYS) at the intended MAOP, and any other applicable specifications or limitations;

     (b) Original design and construction standards;

     (c) Original pressure test records;

     (d) Previous operating pressures identifying the dates and lengths of time at that pressure;

     (e) Records of all leaks, regardless of cause, and the dates and methods of repair;

     (f) Where the pipeline is being uprated to an MAOP of over twenty percent of the SMYS, records of the original welding standards and welders;

     (g) Maintenance records of all affected regulators and relief valves for the past three years or three most recent inspections, whichever is longer;

     (h) Where applicable, relief valve capacities compared to regulator flow capacities, with calculations;

     (i) Cathodic protection readings of the affected pipeline and facilities, including rectifier readings, for the past three years or three most recent inspections, whichever is longer; and

     (j) Any additional records that commission staff may deem necessary to evaluate the pressure increase.

     (2) Uprates must be based on a previous pressure test that will substantiate the intended MAOP. When there is no documented history of a pressure test or where the original pressure test would not substantiate the intended MAOP, an operator must either conduct a new pressure test, or where allowed by 49 CFR § 192.503(c), conduct a pressure test in conjunction with the uprate.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-155, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-155, filed 8/5/92, effective 9/5/92.]

     (2) Every gas company shall on the fifteenth day of each month submit a report to the commission setting forth the progress of such construction or major reconstruction as of the end of the preceding month.)) (1) Each operator must file a proposed construction report at least forty-five days prior to construction or replacement of any segment of a gas transmission pipeline equal to or greater than one hundred feet in length. Emergency repairs are exempt from this section.

     (2) The report must describe the proposed route and the specifications for the pipeline and must include, but is not limited to, the following items:

     (a) Description and purpose of the proposed pipeline;

     (b) Route map showing the type of construction to be used throughout the length of the line, and delineation of class location as defined in 49 CFR Part 192.5, and incorporated boundaries along the route;

     (c) Location and specification of principal valves, regulators, and other auxiliary equipment to be installed as a part of the pipeline system to be constructed. The operator must submit aerial photographs upon request;

     (d) Maximum allowable operating pressure for the pipeline being constructed;

     (e) Location and construction details of all river crossings or other unusual construction requirements encountered en route, e.g., places where pipe will be exposed or it is impractical to provide required cover, bridge crossings, lines to be laid parallel to railroads or state highways, including encroachments, and any other areas requiring special or unusual design and construction considerations;

     (f) Proposed corrosion control program to be followed including specifications for coating and wrapping, and the method to ensure the integrity of the coating using holiday detection equipment;

     (g) Welding specifications; and

     (h) Bending procedures to be followed if needed.

     (3) Emergency repairs are exempt from this section.

[Order R-28, § 480-93-160, filed 7/15/71; Order R-5, § 480-93-160, filed 6/6/69, effective 10/9/69.]

     (6) The requirements of paragraphs (3) and (4) will be waived in an emergency where it is necessary to maintain continuity of service.)) (1) Operators must notify the commission in writing at least two business days prior to the commencement of any pressure test of a gas pipeline that will have an MAOP in excess of twenty percent of the specified minimum yield strength of the pipe used.

     (a) The pressure tests of any such gas pipeline built in Class 3 or Class 4 locations, as defined in 49 CFR Part 192.5, or within one hundred yards of a building intended for human occupancy, must be at least eight hours in duration.

     (b) When the test medium is to be a gas or compressible fluid, each operator must notify the appropriate public officials so that adequate public protection can be provided for during the test.

     (c) In an emergency situation where it is necessary to maintain continuity of service, the requirements of subsection (1) of this section and subsection (1)(a) of this section may be waived by notifying the commission by telephone prior to performing the test.

     (2) For each steel service line or main intended to be operated at or above eighty-two psig, the minimum test pressure must be determined by multiplying the intended MAOP by a factor determined in accordance with the table located in 49 CFR § 192.619 (a)(2)(ii).

     (3) Operators must perform pressure tests for all new or replacement pipeline installations.

     (4) All service lines that are broken, pulled, or damaged, resulting in the interruption of gas supply to the customer, must be pressure tested from the point of damage to the service termination valve (generally the meter set) prior to being placed back into service.

     (5) Operators may only use pretested pipe when it is not feasible to conduct a pressure test.

     (6) Operators must perform soap tests at the tie-in joints at not less than the current operating pressure of the pipeline.

     (7) Operators must keep records of all pressure tests performed for the life of the pipeline and must document the following information:

     (a) Operator's name;

     (b) Employee's name;

     (c) Test medium used;

     (d) Test pressure;

     (e) Test duration;

     (f) Pipe size and length;

     (g) Dates and times; and

     (h) Test results.

     (8) Where feasible, operators must install and backfill plastic pipe prior to pressure testing to expose any potential damage that could have occurred during the installation and backfill process.

     (9) Where multiple pressure tests are performed on a single installation, operators must maintain a record of each test. An example of a single installation with multiple tests would be any continuous on-going job or installation such as a new plat or long main installation where more than one pressure test was conducted during construction.

     (10) Pressure testing equipment must be maintained, calibrated, or where calibration is not possible, checked for accuracy according to the manufacturer's recommended schedule. If no manufacturer's schedule is available, an operator must determine a schedule and include it in the operations and maintenance procedures manual. Test equipment must be tagged with the calibration or accuracy check expiration date. The requirements of this section also apply to equipment such as pressure charts, gauges, dead weights or other devices used to test, monitor or check system pressures or set-points.

[Order R-28, § 480-93-170, filed 7/15/71; Order R-5, § 480-93-170, filed 6/6/69, effective 10/9/69.]

     If the toughness of the pipe is unknown, it shall be considered to be brittle, and the pipeline shall not be moved.)) (1) Except those pipelines detailed in subsection (3) of this section, each operator must prepare a study prior to moving or lowering any metallic pipeline to determine whether the proposed action will cause an unsafe condition. This study must be reviewed and approved by the operator's engineering department and retained in the operator's files for the life of the pipeline. This requirement does not apply to cast iron pipelines, which may not be lowered, or to copper pipelines. The study must include, but is not limited to, the following criteria:

     (a) The required deflection of the pipe;

     (b) The diameter, wall thickness, and grade of pipe;

     (c) The characteristics of the pipeline;

     (d) The terrain and class location;

     (e) The present condition of the pipeline;

     (f) The anticipated stresses of the pipeline including the safe allowable stress limits; and

     (g) The toughness of the steel.

     (2) Pipelines with mechanical or threaded joints must not be moved or lowered.

     (3) Pipelines operating at sixty pounds per square inch gauge (psig) or less which have a nominal diameter of two inches or less may be moved or lowered without the required study, if the operator can certify that no undue stresses will be placed on the pipeline and that it can be moved or lowered in a safe manner. The operator must consider factors such as the type of materials, proximity to fittings, joints, and welds, and any other factors that could place undue stress on the pipeline or create an unsafe condition.

     (4) A leak survey must be conducted within thirty days from the date any pipeline has been moved or lowered under subsection (3) of this section.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-175, filed 8/5/92, effective 9/5/92.]

     (2) The maximum cumulative ultraviolet light exposure limit for plastic pipe is two years, or the manufacturer's recommended limit. The acceptable time limit must be detailed in the operator's procedures manual.

     (3) Plastic pipe that is pulled through the ground by mechanical means must have a weak link installed that will ensure the pipe will not be damaged by excessive tensile forces.

     (4) When installing plastic pipelines parallel to other underground utilities, operators must ensure there is a minimum of twelve inches of separation from the other utilities. Where a minimum twelve inches of separation is not possible, operators must take adequate precautions to minimize any potential hazards resulting from the close proximity to the other utilities.

     (5) When installing plastic pipelines perpendicular to other underground utilities, operators must ensure there is a minimum of six inches of separation from the other utilities. Where a minimum six inches of separation is not possible, an operator must take adequate precautions to minimize any potential hazards resulting from the close proximity to the other utilities.

     (6) Except for approved steel encased plastic pipe, and except where allowed by (b) of this subsection, the maximum time limit that plastic pipe may be temporarily installed above ground is thirty days.

     (a) During temporary installations, operators must monitor and protect above ground plastic pipe from potential damage.

     (b) Operators may install above ground plastic pipe for periods longer than thirty days if they have a written monitoring program and notify the commission by telephone prior to exceeding the thirty-day time limit.

     (7) Plastic pipe must be bedded in a suitable material as recommended by the pipe manufacturer. Unless otherwise permitted by the manufacturer, plastic pipe must be bedded in an essentially rock-free material.

     (8) Plastic pipe may not be squeezed more than one time in the same location.

     (9) Plastic pipe must not be squeezed within twelve inches or three pipe diameters, whichever is greater, from any joint or fitting.

[]

     Furthermore, every gas company shall be responsible for establishing and maintaining such records, making such reports, and providing such information as the commission may reasonably require to enable it to determine whether the gas company has acted and is acting in compliance with these rules and regulations and the standards established thereunder. Every gas company shall, upon request of the commission and its authorized representatives, permit the commission and its authorized representatives to inspect books, papers, records, and documents relevant to determining whether the gas company and its agents have acted and are acting in compliance with these rules and regulations and the standards established thereunder. Such commission inspections shall be conducted at reasonable times, within reasonable limits, and in a reasonable manner, and each inspection shall be commenced and completed with reasonable promptness.)) (1) Each operator must have a plan and procedure manual for operation, maintenance, construction, inspection, and emergency response activities. The manual must comply with the provisions and general intent of the "Pipeline Safety Improvement Act of 2002." The manual must include plans and procedures for all requirements of 49 CFR § 192 and chapter 480-93 WAC, and any plans or procedures used by an operator's associated contractors.

     (2) Plans must be filed with the commission as soon as practical for review and determination as to their adequacy, when properly executed, to achieve an acceptable level of safety. The commission may, after notice and opportunity for hearing, require that a manual be revised or amended. Applicable portions of the manual related to a procedure being performed on the pipeline must be retained on-site where the activity is being performed.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-180, filed 9/28/01, effective 10/29/01. Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-180, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-180, filed 7/15/71; Order R-5, § 480-93-180, filed 6/6/69, effective 10/9/69.]

     When leak indications are found to originate from a foreign source or facility, such as gasoline vapors, sewer or marsh gas, or customer-owned piping, prompt action shall be taken at that time, where appropriate, to protect life and property. Leaks that represent an ongoing, potentially hazardous situation shall be reported promptly to the owner or operator of the source facility and, where appropriate, to the police department, or other appropriate governmental agency. In all cases, the property owner or the adult person occupying the premises shall be notified of the leak conditions. If no methane indication is found, the gas company employee on-site shall so inform the property owner or the adult person occupying the premises, and shall request the adult person occupying the premises sign the gas company work order indicating that a gas leak was not the source of the leak indication. The gas company employee shall provide the adult person occupying the premises an odor sniff card which identifies the odor of natural gas and indicates the name, address, and telephone number of the gas company representative to be contacted if the leak indications are again noticed. If the property owner or an adult person occupying the premises is not available, the gas company shall, within twenty-four hours of the leak notification, send by first-class mail addressed to the person occupying the premises, a letter explaining the results of the investigation. A copy of the letter shall be retained by the gas company and kept with the leak report. A leak investigation report form shall be maintained in the gas company's leak report files for all leaks investigated, indicating gas company employee making the initial leak evaluation.)) (1) The operator must promptly investigate any notification of a leak, explosion, or fire, which may involve gas pipelines or other gas facilities, received from any outside source such as a police or fire department, other utility, contractor, customer, or the general public. Where the investigation reveals a leak, the operator must grade the leak in accordance with WAC 480-93-186, and take appropriate action. The operator must retain the leak investigation record for the life of the pipeline.

     (2) In the event of an explosion, fire, death, or injury, the operator must not remove any suspected gas facility until the commission or the lead investigative authority have designated the release of the gas facility. Once the situation is made safe, the operator must keep the facility intact until directed by the lead investigative authority.

     (3) When leak indications, such as gasoline vapors, sewer or marsh gas, are found to originate from a foreign source or facility such as gasoline vapors, sewer, marsh gas, or from customer-owned piping, the operator must take appropriate action to protect life and property. Leaks that represent an on-going, potentially hazardous situation must be reported promptly to the owner or operator of the source facility and, where appropriate, to the police department, fire department, or other appropriate governmental agency. If the property owner or an adult person occupying the premises is not available, the operator must, within twenty-four hours of the leak investigation, send by first-class mail, addressed to the person occupying the premises, a letter explaining the results of the investigation. The operator must keep a record of each letter sent for five years.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-185, filed 8/5/92, effective 9/5/92; Order R-102, § 480-93-185, filed 5/18/77.]

     (2) Regrading of leaks. Leaks are to be reinspected using the same criteria used to grade leaks when they are first detected and graded.)) (1) Based on an evaluation of the location and/or magnitude of a leak, the operator must assign one of the leak grades in subsection (3) of this section, thereby establishing the leak repair priority. An operator may use an alphabetical grade classification, i.e., Grade A for Grade 1, Grade B for Grade 2, and Grade C for Grade 3 if it has historically used such a grading designation. Operators must apply the same criteria used for initial leak grading to reinspected leaks.

     (2) Gas leak classification and repair. Each operator must establish a procedure for evaluating the concentration and extent of gas leakage. When evaluating any leak, the operator must determine and document the perimeter of the leak area. If the perimeter of the leak extends to a building wall, the operator must extend the investigation inside the building. Where the reading is in an unvented, confined space, the operator must consider the rate of dissipation when the space is ventilated and the rate of accumulation when the space is resealed.

     (3) Follow-up inspections. The operator must check the perimeter of the leak area with a combustible gas indicator. The operator must reinspect all leaks with residual gas remaining in the ground as soon as practical, but not later than thirty days following the repair.

     (4) Leak grades.

     (a) Grade 1 means a leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until conditions are no longer hazardous.

     (b) Grade 2 means a leak recognized as not being hazardous at the time of detection but requiring scheduled repair based on potential future hazard.

     (c) Grade 3 means a leak that is not hazardous at the time of detection and can reasonably be expected to remain not hazardous.

     (d) Grade 1 and 2 leaks can only be downgraded once to a Grade 3 leak without a physical repair. After a leak has been downgraded once, the maximum repair time for that leak is twenty-one months.

     (5) Leakage classification and control requirements are provided in WAC 480-93-18601.

[Order R-103, § 480-93-186, filed 5/18/77.]

A leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous.

((PRIORITY OF LEAK REPAIR			EXAMPLES
Requires prompt action*to protect life and property and continuous action until the conditions are no longer hazardous.			Leaks requiring prompt action:
			1.	Any leak which, in the judgment of operating personnel at the scene, is regarded as an immediate hazard.
*The prompt action in some instances may require one or more of the following:
a.	Implementation of company emergency plan (192.615).		2.	Escaping gas that has ignited unintentionally.
b.	Evacuating premises.		3.	Any indication of gas which has migrated into or under a building or tunnel.
c.	Blocking off an area.
d.	Rerouting traffic.		4.	Any reading at the outside wall of a building or where the gas would likely migrate to the outside wall of a building.
e.	Eliminating sources of ignition.
f.	Venting the area, or		5.	Any reading of 80% LEL or greater in a confined space.
g.	Stopping the flow of gas by closing valves or other means.		6.	Any reading of 80% LEL, or greater in small substructures not associated with gas likely migrate to the outside wall of a building.
h.	Notifying police and fire departments.
			7.	Any leak that can be seen, heard, or felt and which is in a location that may endanger the general public or property.

A leak that is recognized as being nonhazardous at the time of detection but justifies scheduled repair based on probable future hazard.

PRIORITY OF LEAK REPAIRS			EXAMPLES
Leaks should be repaired or cleared in one year but shall not exceed fifteen months from the date reported. If a Grade 2 leak occurs in a segment of pipeline which is under consideration for replacement, an additional 6 months may be added to the 15 months maximum time for repair noted above. In determining the repair priority, criteria such as the following should be considered:			A.	Leaks requiring action ahead of ground freezing or other adverse changes in venting conditions:
				1.	Any leak, which under frozen or other adverse soil conditions, would likely migrate to the outside of a building.
a.	Amount and migration of gas,		B.	Leaks requiring action within six months:
				1.	Any reading of 40% LEL or greater under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak and where gas is likely to migrate to the outside wall of a building.
b.	Proximity of gas to buildings and subsurface structures,
c.	Extent of pavement, and
d.	Soil type and conditions, such as frost cap, moisture and natural venting.
				2.	Any reading of 100% LEL or greater under a street in a wall-to-wall paved area that does not qualify as a Grade 1 leak and where the gas is likely to migrate to the outside wall of a building.
Grade 2 leaks shall be re-evaluated at least once every six months until cleared. The frequency of reevaluation should be determined by the location and magnitude of the leakage condition.
				3.	Any reading less than 80% LEL in small substructures not associated with gas facilities where gas would likely migrate creating a probable future hazard.
It should be recognized that Grade 2 leaks will vary greatly in degree of potential hazard. There will be some Grade 2 leaks, which when evaluated by the above criteria, will justify scheduled repair within the next 5 working days. Others will justify repair within 30 days. These situations shall be brought to the attention of the individual responsible for scheduling leakage repair at the end of the working day.
				4.	Any reading between 20% LEL and 80% LEL in a confined space.
				5.	Any reading on a pipeline operating at 30% SMYS or greater in Class 3 or 4 locations that does not qualify as a Grade 1 leak.
On the other hand, there will be many Grade 2 leaks, which because of their location and magnitude, can be scheduled for repair on a normal routine basis with periodic reinspection as necessary.				6.	Any leak which in the judgment of operating personnel at the scene is of sufficient magnitude to justify scheduled repair.

A leak that is nonhazardous at the time of detection and can reasonably be expected to remain nonhazardous.

PRIORITY OF LEAK REPAIRS		EXAMPLES
Grade 3 leaks should be re-evaluated during the next scheduled survey, or within 15 months of the reporting date, whichever occurs first, until the leak is regraded or no longer results in a reading.		Leaks requiring reevaluation at periodic intervals:
		1.	Any reading of less than 80% LEL in small gas associated substructures such as small meter boxes or gas valve boxes.
		2.	Any reading under a street in areas without wall-to-wall paving where it is unlikely the gas could migrate to the outside wall of a building.
		3.	Any reading of less than 20% LEL in a confined space.))

     (1) Grade 1 leak. A "Grade 1 leak" is a leak that represents an existing or probable hazard to persons or property and requiring prompt action, immediate repair, or continuous action until the conditions are no longer hazardous.

     (a) Prompt action in response to a Grade 1 leak may require one or more of the following:

     (i) Implementation of the operator's emergency plan pursuant 49 CFR § 192.615;

     (ii) Evacuating the premises;

     (iii) Blocking off an area;

     (iv) Rerouting traffic;

     (v) Eliminating sources of ignition;

     (vi) Venting the area;

     (vii) Stopping the flow of gas by closing valves or other means; or

     (viii) Notifying police and fire departments.

     (b) Examples. Examples of Grade 1 leaks requiring prompt action include, but are not limited to:

     (i) Any leak, which in the judgment of operating personnel at the scene, is regarded as an immediate hazard;

     (ii) Escaping gas that has ignited unintentionally;

     (iii) Any indication of gas that has migrated into or under a building or tunnel;

     (iv) Any reading at the outside wall of a building or where the gas could potentially migrate to the outside wall of a building;

     (v) Any reading of eighty percent LEL or greater in a confined space;

     (vi) Any reading of eighty percent LEL, or greater in small substructures not associated with gas facilities where the gas could potentially migrate to the outside wall of a building; or

     (vii) Any leak that can be seen, heard, or felt and which is in a location that may endanger the general public or property.

     (2) Grade 2 leak. A "Grade 2 leak" is a leak that is recognized as being not hazardous at the time of detection but justifies scheduled repair based on potential future hazard.

     (a) Operators must repair or clear Grade 2 leaks within fifteen months from the date the leak is reported. If a Grade 2 leak occurs in a segment of pipeline that is under consideration for replacement, an additional six months may be added to the fifteen months maximum time for repair provided above. In determining the repair priority, operators should consider the following criteria:

     (i) Amount and migration of gas;

     (ii) Proximity of gas to buildings and subsurface structures;

     (iii) Extent of pavement; and

     (iv) Soil type and conditions, such as frost cap, moisture and natural venting.

     (b) Operators must reevaluate Grade 2 leaks at least once every six months until cleared. The frequency of reevaluation should be determined by the location and magnitude of the leakage condition.

     (c) Grade 2 leaks vary greatly in degree of potential hazard. Some Grade 2 leaks, when evaluated by the criteria, will require prompt scheduled repair within the next five working days. Others in (a) of this subsection require repair within thirty days. The operator must bring these situations to the attention of the individual responsible for scheduling leakage repair at the end of the working day. Many Grade 2 leaks, because of their location and magnitude, can be scheduled for repair on a normal routine basis with periodic reinspection as necessary.

     (d) When evaluating Grade 2 leaks, operators should consider leaks requiring action ahead of ground freezing or other adverse changes in venting conditions, and any leak that could potentially migrate to the outside of a building, under frozen or other adverse soil conditions.

     (e) Examples. Grade 2 leaks requiring action within six months include, but are not limited to:

     (i) Any reading of forty percent LEL or greater under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak where gas could potentially migrate to the outside wall of a building;

     (ii) Any reading of one hundred percent LEL or greater under a street in a wall-to-wall paved area that does not qualify as a Grade 1 leak where gas could potentially migrate to the outside wall of a building;

     (iii) Any reading less than eighty percent LEL in small substructures not associated with gas facilities where gas could potentially migrate creating a probable future hazard;

     (iv) Any reading between twenty percent LEL and eighty percent LEL in a confined space;

     (v) Any reading on a pipeline operating at thirty percent specified minimum yield strength or greater in Class 3 or 4 locations that does not qualify as a Grade 1 leak; or

     (vi) Any leak which in the judgment of operating personnel at the scene is of sufficient magnitude to justify scheduled repair.

     (3) Grade 3 leak. A "Grade 3 leak" is a leak that is not hazardous at the time of detection and can reasonably be expected to remain not hazardous.

     (a) Operators should reevaluate Grade 3 leaks during the next scheduled survey, or within fifteen months of the reporting date, whichever occurs first, until the leak is regraded or no longer results in a reading.

     (b) Examples. Grade 3 leaks requiring reevaluation at periodic intervals include, but are not limited to:

     (i) Any reading of less than eighty percent LEL in small gas associated substructures, such as small meter boxes or gas valve boxes; or

     (ii) Any reading under a street in areas without wall-to-wall paving where it is unlikely the gas could migrate to the outside wall of a building.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-18601, filed 8/5/92, effective 9/5/92; Order R-103, Table 1 (codified as WAC 480-93-18601), filed 5/18/77.]

     (c) Check adequacy of records.)) Each operator must prepare and maintain permanent gas leak repair records. The leak records must contain sufficient data and information to permit the commission to assess the adequacy of the operator's leakage program. Gas leak records must contain, at a minimum, the following information:

     (1) Date and time the leak was detected, investigated, reported, and the name of the employee(s) conducting the investigation;

     (2) Date and time the leak was reevaluated before repair, and the name of the employee(s) involved;

     (3) Date and time of repair and the name of the employee(s) in charge of the repair;

     (4) Date and time of any rechecks performed, and the name of the employee(s) involved;

     (5) Location of the leak (sufficiently described to allow ready location by other qualified personnel);

     (6) Leak grade;

     (7) Pipeline classification (e.g., distribution, transmission, service);

     (8) If reported by an outside party, list the name and address of the reporting party;

     (9) Component that leaked (e.g., pipe, tee, flange, valve);

     (10) Size and material that leaked (e.g., steel, plastic, cast iron);

     (11) Pipe condition;

     (12) Type of repair;

     (13) Leak cause;

     (14) Date pipe installed (if known);

     (15) Magnitude and location of CGI readings left;

     (16) Magnitude and location of CGI readings as found (showing spread of gas); and

     (17) Unique identification numbers (such as serial numbers) of leak detection equipment.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-187, filed 8/5/92, effective 9/5/92; Order R-104, § 480-93-187, filed 5/18/77.]

     (c) Check adequacy of records.)) (1) Operators must perform gas leak surveys using a gas detection instrument covering the following areas:

     (a) Over all mains, services, and transmission lines including the testing of the atmosphere near other utility (gas, electric, telephone, sewer, or water) boxes or manholes, and other underground structures;

     (b) Through cracks in paving, and sidewalks;

     (c) Along walls of businesses and buildings of public assembly that are within one hundred feet of an active pipeline facility;

     (d) On all above ground piping (may be checked with either a gas detection instrument or with a soap solution);

     (e) Where a gas service line exists, at the building wall point of entrance, using a bar hole where necessary; and

     (f) Within all buildings where gas leakage has been detected at the outside wall, at locations where escaping gas could potentially migrate into and accumulate inside the building.

     (2) Gas detection instruments must be maintained, calibrated, and operated in accordance with the manufacturer's recommendation. If there is no manufacturer's recommendation, then instruments must be calibrated at least once monthly, but not to exceed forty-five days between calibrations, but at least twelve times per year.

     (3) Gas leak surveys must be conducted according to the following minimum frequencies:

     (a) Business districts - at least once annually, but not to exceed fifteen months between surveys;

     (b) Residential areas - as frequently as necessary, but not to exceed five years between surveys;

     (c) Buildings of public assembly - at least once annually, but not to exceed fifteen months between surveys;

     (d) Mains operating above two hundred fifty psig - at least once annually, but not to exceed fifteen months between surveys; and

     (e) Where the gas system has cast iron, wrought iron, copper, or noncathodically protected steel - at least twice annually, but not to exceed seven and one-half months between surveys.

     (4) Special leak surveys must be conducted under the following circumstances:

     (a) Prior to paving or resurfacing, following street alterations or repairs where gas facilities are under the area to be paved, and where there is potential that damage could have occurred to gas facilities;

     (b) In areas where substructure construction occurs adjacent to underground gas facilities, and there is potential that damage could have occurred to the gas facilities, operators must perform a gas leak survey following the completion of construction, but prior to paving;

     (c) Unstable soil areas where active gas lines could be affected;

     (d) In areas and at times of unusual activity, such as earthquake, floods, and explosions; and

     (e) After third-party excavation damage to services, operators must perform a gas leak survey from the point of damage to the service tie-in.

     (5) Survey records must be kept for a minimum of five years. At a minimum, survey records must contain the following information:

     (a) Description of the system and area surveyed (including maps and leak survey logs);

     (b) Survey results;

     (c) Survey method;

     (d) Name of the employee who performed the survey;

     (e) Survey dates; and

     (f) Instrument tracking or identification number.

     (6) Each operator must perform self audits of the effectiveness of its leak detection and recordkeeping programs. Operators must maintain records of the self audits for five years. Self audits must be performed as frequently as necessary, but not to exceed three years between audits. At a minimum, self audits should ensure that:

     (a) Leak survey schedules meet the minimum federal and state safety requirements for gas pipelines;

     (b) Consistent evaluations of leaks are being made throughout the system;

     (c) Repairs are made within the time frame allowed;

     (d) Repairs are effective; and

     (e) Records are accurate and complete.

     (7) Subsection (3)(a) of this section is effective on January 1, 2008.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-188, filed 8/5/92, effective 9/5/92; Order R-105, § 480-93-188, filed 5/18/77.]

     (4) All gas companies shall file with the commission, and with appropriate officials of all municipalities within which such gas companies have facilities, the names, addresses, and telephone numbers of responsible officials of such gas companies who may be contacted in the event of an emergency. In the event of any changes in gas company personnel, immediate notification thereof shall be given to the commission and municipalities.)) (1) Every operator must give notice to the commission by telephone within two hours of discovering an incident or hazardous condition arising out of its operations that:

     (a) Results in a fatality or personal injury requiring hospitalization;

     (b) Results in damage to the property of the operator and others of a combined total exceeding five thousand dollars (automobile collisions and other equipment accidents not involving gas or gas handling equipment need not be reported under this rule);

     (c) Results in the evacuation of a dwelling, building, or area of public assembly;

     (d) Results in the unintentional ignition of gas;

     (e) Results in the unscheduled interruption of service furnished by any operator to twenty or more distribution customers;

     (f) Is significant, in the judgment of the operator, even though it does not meet the criteria of (a) through (e) of this subsection; or

     (g) Results in the news media reporting the occurrence, even though it does not meet the criteria of (a) through (e) of this subsection.

     (2) Operators must give notice to the commission by telephone within twenty-four hours of occurrence of every incident or hazardous condition arising out of its operations that:

     (a) Results from construction defects or material failure;

     (b) Results in the uncontrolled release of gas for more than two hours;

     (c) Results in the taking of a high pressure supply or transmission pipeline or a major distribution supply pipeline out of service;

     (d) Results in a pipeline or system operating at low pressure dropping below the safe operating conditions of attached appliances and gas equipment; or

     (e) When a pipeline or system pressure exceeds the maximum allowable operating pressure.

     (3) Routine or planned maintenance and operational activities of the operator that result in operator-controlled plant and equipment shut downs, reduction in system pressures except as noted in subsection (1) of this section, flaring or venting of gas, and normal leak repairs are not reportable items under this section.

     (4) When a pipeline or system pressure exceeds the maximum allowable operating pressure plus ten percent or the maximum pressure allowed by proximity considerations outlined in WAC 480-93-020, the operator must notify the commission by telephone within two hours, to be followed by written explanation within thirty days;

     (5) Operators must provide to the commission the reports required in subsection (1) of this section, verified in detail in writing within thirty days of the initial telephonic report. At a minimum, written reports must include the following:

     (a) Name(s) and address(es) of any person or persons injured or killed, or whose property was damaged;

     (b) The extent of such injuries and damage;

     (c) A description of the incident or hazardous condition including the date, time, and place;

     (d) A description of the gas facilities involved in the incident or hazardous condition, the system operating pressure at that time, and the maximum allowable operating pressure of the facilities involved;

     (e) The date and time the gas facility was made safe;

     (f) The date, time, and type of any temporary or permanent repair made; and

     (g) The cost of the incident to the operator.

     (6) Operators must provide to the commission a written report within forty-five days of receiving the failure analysis of any incident or hazardous condition that was due to construction defects or material failure.

     (7) Operators must file with the commission a copy of every Research and Special Programs Administration (RSPA) F-7100.1-1 and F-7100.2-1 annual report required by U.S. Department of Transportation, Office of Pipeline Safety. In addition to the above required forms, operators must file with the commission the report titled, "Damage Prevention Statistics," with the corresponding RSPA fiscal year. The Damage Prevention Statistics report must include in detail the following information:

     (a) Number of gas-related one-call locate requests completed in the field;

     (b) Number of third-party damages incurred; and

     (c) Cause of damage:

     (i) A locate is not accurate;

     (ii) The operator failed to use reasonable care; or

     (iii) Excavated prior to a locate being conducted.

     (8) Operators must file with the commission, and with appropriate officials of all municipalities where operators have facilities, the names, addresses, and telephone numbers of the responsible officials of the operator who may be contacted in the event of an emergency. In the event of any changes in operator personnel, the operator must notify immediately the commission and municipalities.

     (9) Operators must send daily reports of construction and repair activities electronically to the commission. Operators may send reports either by facsimile or e-mail to the commission. The reports must be received no later than 10:00 a.m. each day of the scheduled work, and must include both operator and contractor construction and repair activities.

     (10) When an operator is required to file a copy of a RSPA Drug Testing and Alcohol Testing Management Information System (MIS) "EZ" Data Collection Form with the U.S. Department of Transportation, Office of Pipeline Safety, the operator must simultaneously submit a copy of the form to the commission.

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-200, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-200, filed 7/15/71; Order R-5, § 480-93-200, filed 6/6/69, effective 10/9/69.]

     (3) The commission may compromise any civil penalty pursuant to RCW 80.28.210.)) (1) Any gas company that violates any provisions of chapter 480-93 WAC or WAC 480-93-303 has failed to construct and/or maintain its facilities in a safe and efficient manner in violation of RCW 80.28.210, and is subject to a civil penalty under RCW 80.28.212.

     (a) The maximum civil penalty under RCW 80.28.212 for violations by a gas company of any provision of chapter 480-93 WAC (other than WAC 480-93-160 and 480-93-200 (1)(e)) or WAC 480-93-303 is five thousand dollars for each violation for each day that the violation persists up to a maximum civil penalty of five hundred thousand dollars for a related series of violations.

     (b) The maximum civil penalty under RCW 80.28.212 for violations by a gas company of WAC 480-93-160 or 480-93-200 (1)(e) is one thousand dollars for each violation for each day that the violation persists, up to a maximum civil penalty of two hundred thousand dollars for a related series of violations.

     (c) The commission may compromise any civil penalty issued under RCW 80.28.212.

     (2) In addition to a civil penalty under RCW 80.28.212, any public service company that violates RCW 80.28.210 or any rule issued thereunder, may also be subject to civil penalties under RCW 80.04.405 and/or 80.04.380.

     (3) Any officer, agent, or employee of any public service company who aids or abets in the violations of RCW 80.24.210 or any rule issued thereunder, is subject to a civil penalty under RCW 80.04.405.

     (4) Any officer, agent, or employee of any public service company violating RCW 80.28.210 or who procures or aids and abets such a violation, may be subject to civil penalties under RCW 80.04.385.

     (5) Any corporation other than a public service company that is subject to RCW 80.28.210 and that violates any provision of chapter 480-93 WAC, has failed to construct and/or maintain its facilities in a safe and efficient manner in violation of RCW 80.28.210, and is subject to a civil penalty under RCW 80.04.387.

[Statutory Authority: RCW 80.01.040 and 80.28.210. 95-19-057 (Order R-433, Docket No. UG-950625), § 480-93-223, filed 9/15/95, effective 10/16/95.]

[Statutory Authority: RCW 80.01.040. 92-16-100 (Order R-375, Docket No. UG-911261), § 480-93-230, filed 8/5/92, effective 9/5/92; Order R-28, § 480-93-230, filed 7/15/71; Order R-5, § 480-93-230, filed 6/6/69, effective 10/9/69.]

     (3) Copies of Title 49 Code of Federal Regulations are available from the Seattle office of the Government Printing Office and from various third-party vendors.)) In this chapter, the commission adopts by reference each of the regulations and/or standards identified below. For each regulation or standard the commission is adopting by reference is listed the publisher, the scope of what the commission is adopting, the effective date of the regulation or standard the commission is adopting, the place within the commission's rules the regulation or standard is referenced, and the availability of the publication in which the regulation or standard is found.

     (1) Title 49 Code of Federal Regulations, cited as 49 CFR, Parts 191, 192, 193, and 199 including all appendices and amendments thereto as published by the United States Government Printing Office.

     (a) The commission adopts the version of the above regulations that were in effect on October 1, 2003, except the following sections are not adopted by reference: 191.1, 192.1(a), 193.2001(a), 199.1. In addition the activities listed in section 192.801 (b)(i)-(4) should be interpreted to include new construction of pipeline facilities.

     (b) This publication is referenced in WAC 480-93-005, 480-93-080, 480-93-100, 480-93-110, 480-93-124, 480-93-155, 480-93-170, 480-93-180, and 480-93-18601.

     (c) The Code of Federal Regulations is published by the federal government. Copies of Title 49 Code of Federal Regulations are available from most Government Printing Offices, including the Seattle office of the Government Printing Office, as well as from various third-party vendors and various libraries, including the branch of the state library located at the commission. It is also available for inspection at the commission.

     (2) Section IX of the ASME Boiler and Pressure Vessel Code.

     (a) The commission adopts the 2001 edition of Section IX of the ASME Boiler and Pressure Vessel Code.

     (b) This publication is referenced in WAC 480-93-080.

     (c) Copies of Section IX of the ASME Boiler and Pressure Vessel Code (2001 edition) are available from The American Society of Mechanical Engineers, Park Avenue, New York, New York, and various libraries, including the branch of the state library located at the commission. It is also available for inspection at the commission.

     (3) The American Petroleum Institute (API) standard 1104.

     (a) The commission adopts the 18th edition of this standard.

     (b) This standard is referenced in WAC 480-93-080.

     (c) Copies of API standard 1104 (18th edition) are available from the Office of API Publishing Services in Washington DC, and various libraries, including the branch of the state library located at the commission. It is also available for inspection at the commission.

[Statutory Authority: RCW 80.01.040, 80.04.160, 81.04.160, and 34.05.310. 01-20-061 (Docket No. A-010827, General Order No. R-491), § 480-93-999, filed 9/28/01, effective 10/29/01.]

     The following sections of the Washington Administrative Code are repealed:

WAC 480-93-002	Application of rules.
WAC 480-93-010	Compliance with federal standards.
WAC 480-93-030	Proscribed areas.
WAC 480-93-082	Qualification of employees.
WAC 480-93-111	Noncathodically protected gas facilities.
WAC 480-93-112	Corrosive condition investigation.
WAC 480-93-120	Exposed pipelines.
WAC 480-93-150	Station maintenance.
WAC 480-93-183	Pipeline and system pressure reporting.
WAC 480-93-184	Gas leak responsibility.
WAC 480-93-190	Being aware of construction work near gas company facilities.
WAC 480-93-210	Interruptions to service.
WAC 480-93-220	Rule of precedence.

© Washington State Code Reviser's Office