LOVELACE GAS SERVICE INC — Warning Letter

220190006W_Warning Letter_11072019_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED November 7, 2019 Garry Lovelace President Lovelace Gas Service, Inc. 10606 East Colonial Drive Orlando, FL 32817 CPF 2-2019-0006W Dear Mr. Lovelace: From September 4 to 7, 2018, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Southern Region Office of Pipeline Safety (OPS) inspected the Lovelace Gas Service, Inc. (LGS) procedures and records in its Orlando, Florida, office and liquefied petroleum gas (LP-Gas) pipeline systems in Orange county, Florida, pursuant to Chapter 601 of 49 United States Code. As a result of the inspection, it is alleged that LGS has committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violations are: 1. § 192.11 Petroleum gas systems. (a) . . . . (b) Each pipeline system subject to this part that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this part and of ANSI/NFPA 58 and 59. LGS failed to meet the requirements of NFPA 58 (2004) for each pipeline system that transports petroleum gas, as follows: A. NFPA 58 § 6.6.1.2 LP-Gas containers or systems of which they are a part shall be protected from damage from vehicles.#

220190006W_Warning Letter_11072019_text.pdf, page 2LGS failed to meet the requirements of NFPA 58 § 6.6.1.2, which, in part, required it to protect LP-Gas containers from damage from vehicles. The PHMSA inspector observed and photographed aboveground containers, serving the Alafaya Palms system, in and adjacent to a parking lot, that were not protected from damage from vehicles. During a follow-up call, LGS reported that it corrected the condition. B. NFPA 58 § 6.7.4.5 The point of discharge from the required pressure relief device on regulating equipment installed outside of buildings in fixed piping systems shall be located not less than 3 ft (1 m) horizontally away from any building opening below the level of such discharge, and not beneath any building unless this space is well ventilated to the outside and is not enclosed for more than 50 percent of its perimeter. LGS failed to meet the requirements of NFPA 58 § 6.7.4.5, which, in part, required it to install the point of discharge of pressure regulating equipment installed outside of buildings not less than 3 feet horizontally away from any building opening below the level of such discharge. The PHMSA inspector observed and documented second-stage regulators whose point of discharge was located less than 3 feet horizontally away from building openings below the level of the discharge at addresses on Scranton Avenue, West Pointe Drive, Pittsburg Court, and Wesleyan Boulevard on the Alafaya Palms system. C. NFPA 58 § 6.7.4.6 The point of discharge [of a regulator] shall also be located not less than 5 ft (1.5 m) in any direction away from any source of ignition, openings into direct-vent (sealed combustion system) appliances, or mechanical ventilation air intakes. LGS failed to meet the requirements of NFPA 58 § 6.7.4.6, which required it to install the point of discharge of regulators not less than 5 feet in any direction away from any source of ignition, openings into direct-vent (sealed combustion system) appliances, or mechanical ventilation air intakes. The PHMSA inspector observed and documented a second-stage regulator whose point of discharge was located less than 5 feet away from a source of ignition at an address on Annapolis Avenue in the Alafaya Palms system. 2. § 192.465 External corrosion control: Monitoring. (a) Each pipeline that is under cathodic protection must be tested at least once each calendar year, but with intervals not exceeding 15 months, to determine whether the cathodic protection meets the requirements of §192.463. However, if tests at#

220190006W_Warning Letter_11072019_text.pdf, page 3those intervals are impractical for separately protected short sections of mains or transmission lines, not in excess of 100 feet (30 meters), or separately protected service lines, these pipelines may be surveyed on a sampling basis. At least 10 percent of these protected structures, distributed over the entire system must be surveyed each calendar year, with a different 10 percent checked each subsequent year, so that the entire system is tested in each 10-year period. LGS failed to meet the regulation because it did not test each pipeline under cathodic protection at least once each calendar year, but with intervals not exceeding 15 months, to determine whether the cathodic protection met the requirements of § 192.463. LGS cathodic protection testing records for the Starlight Ranch (front) system, for calendar years 2015, 2016, and 2017, did not include cathodic protection readings for the buried LP Gas containers that served the system. During a follow-up call, LGS reported that it replaced its buried LP-Gas containers with aboveground LP-Gas containers. 3. § 192.491 Corrosion control records. (a) . . . . (c) Each operator shall maintain a record of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least 5 years, except that records related to §§192.465 (a) and (e) and 192.475(b) must be retained for as long as the pipeline remains in service. § 192.459 External corrosion control: Examination of buried pipeline when exposed. Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion must be examined for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If external corrosion requiring remedial action under §§192.483 through 192.489 is found, the operator shall investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion. LGS failed to meet the regulation because it did not maintain a record of each inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition did not exist. Specifically, LGS did not document and maintain records demonstrating that it examined buried pipelines, when they were exposed, for evidence of corrosion or coating deterioration, as required by § 192.459,#

220190006W_Warning Letter_11072019_text.pdf, page 4During the inspection, the PHMSA inspector reviewed records documenting three repairs to steel pipelines which exposed buried portions - two on the Starlight (back) system on October 5, 2015, and July 21, 2017, and one on the Starlight (front) system on August 12, 2016. None of the referenced records documented the examination of the exposed pipe for signs of external corrosion or coating deterioration. 4. §192.603 General provisions. (a) . . . . under §192.605. (b) Each operator shall keep records necessary to administer the procedures established LGS failed to meet the regulation because it did not keep records necessary to administer the procedures established under §192.605. Specifically, LGS did not keep records demonstrating that it: A. Re-qualified, in accordance with §192.285(c), persons to join plastic pipe under an applicable procedure once each calendar year at intervals not exceeding 15 months. B. Trained, in accordance with §192.615(b)(2), the appropriate operating personnel to assure that they were knowledgeable of the emergency procedures and verified that the training was effective. C. Reviewed, in accordance with §192.615(b)(3), employee activities to determine whether the procedures were effectively followed in each emergency. D. Established and maintained, in accordance with §192.615(c), liaison with appropriate fire, police, and other public officials. E. Provided, in accordance with §192.616(j), public awareness messages twice annually to persons, other than customers, who controlled property that contained portions of the operator’s petroleum gas systems. F. Documented, in accordance with §§ 192.619 and 192.621, the maximum allowable operating pressure (MAOP) for each of its pipeline systems, including the basis of the MAOP determination. During the inspection, the PHMSA inspector requested records demonstrating compliance with each of the listed items. LGS representatives acknowledged that they did not have records for the requested items. 5. § 192.625 Odorization of gas. (a) . . . . (f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement by— (1) Receiving written verification from their gas source that the gas has the proper concentration of odorant; and#

220190006W_Warning Letter_11072019_text.pdf, page 5(2) Conducting periodic “sniff” tests at the extremities of the system to confirm that the gas contains odorant. LGS failed to meet the regulation because it did not conduct periodic sampling of gases using an instrument capable of determining the percentage of gas in air at which the odor became readily detectable to assure the proper concentration of odorant. PHMSA’s review revealed that LGS attempted to comply with the regulation through a combination of sniff testing and the use of stain tubes. Neither a sniff test nor stain tubes can determine the percentage of gas, in air, at which the odor becomes readily detectable. Under 49 U.S.C. § 60122 and 49 CFR § 190.223, LGS is subject to a civil penalty not to exceed $218,647 per violation per day the violation persists, up to a maximum of $2,186,465 for a related series of violations. For violation occurring on or after November 27, 2018 and before July 31, 2019, the maximum penalty may not exceed $213,268 per violation per day, with a maximum penalty not to exceed $2,132,679. For violation occurring on or after November 2, 2015 and before November 27, 2018, the maximum penalty may not exceed $209,002 per violation per day, with a maximum penalty not to exceed $2,090,022. For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. We have reviewed the circumstances and supporting documents involved in this case, and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the items identified in this letter. Failure to do so will result in Lovelace Gas Service, Inc. being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 2-2019-0006W. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). Sincerely, James A. Urisko Director, Office of Pipeline Safety PHMSA Southern Region#