APACHE CORPORATION — Warning Letter

420095008W_Warning_06262009_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 26, 2009 Mr. David Carmony Vice President Operations Gulf Coast Region Apache Corporation 2000 Post Oak Blvd Suite 100 Houston, TX 77056 CPF 4-2009-5008W Dear Mr. Carmony: On October 27-31 2008, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your Gibbstown crude oil pipeline in Cameron Parish, Louisiana and your Grand Isle crude oil pipeline in Jefferson Parish, Louisiana. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are: 1. §195.406 Maximum operating pressure. (a) Except for surge pressures and other variations from normal operations, no operator may operate a pipeline at a pressure that exceeds any of the following: (1) The internal design pressure of the pipe determined in accordance with §195.106. However, for steel pipe in pipelines being converted under §195.5, if one or more factors of the design formula (§195.106) are unknown, one of the following pressures is to be used as design pressure:#

420095008W_Warning_06262009_text.pdf, page 2(i) Eighty percent of the first test pressure that produces yield under section N5.0 of Appendix N of ASME B31.8, reduced by the appropriate factors in §§195.106(a) and (e); or (ii) If the pipe is 323.8 mm (12¾ in) or less outside diameter and is not tested to yield under this paragraph, 1379 kPa (200 psig). (2) The design pressure of any other component of the pipeline. (3) Eighty percent of the test pressure for any part of the pipeline which has been pressure tested under Subpart E of this part. (4) Eighty percent of the factory test pressure or of the prototype test pressure for any individually installed component which is excepted from testing under §195.305. (5) For pipelines under §§195.302(b)(1) and (b)(2)(i), that have not been pressure tested under Subpart E of this part, 80 percent of the test pressure or highest operating pressure to which the pipeline was subjected for 4 or more continuous hours that can be demonstrated by recording charts or logs made at the time the test or operations were conducted. (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. There were no records provided, at the time of the inspection, to substantiate MOP determination. Apache had acquired this pipeline from BP in 2006 and apparently MOP was only provided verbally with no test or other documentation. Apache has since performed a hydro test on February 14, 2009, and established MOP accordingly. 2. §195.567 Which pipelines must have test leads and what must I do to install and maintain the leads? (a) General. Except for offshore pipelines, each buried or submerged pipeline or segment of pipeline under cathodic protection required by this subpart must have electrical test leads for external corrosion control. However, this requirement does not apply until December 27, 2004, to pipelines or pipeline segments on which test leads were not required by regulations in effect before January 28, 2002. (b) Installation. You must install test leads as follows: (1) Locate the leads at intervals frequent enough to obtain electrical measurements indicating the adequacy of cathodic protection. 2#

420095008W_Warning_06262009_text.pdf, page 3(2) Provide enough looping or slack so backfilling will not unduly stress or break the lead and the lead will otherwise remain mechanically secure and electrically conductive. (3) Prevent lead attachments from causing stress concentrations on pipe. (4) For leads installed in conduits, suitably insulate the lead from the conduit. (5) At the connection to the pipeline, coat each bared test lead wire and bared metallic area with an electrical insulating material compatible with the pipe coating and the insulation on the wire. (c) Maintenance. You must maintain the test lead wires in a condition that enables you to obtain electrical measurements to determine whether cathodic protection complies with Sec. 195.571. At the time of the inspection, it was observed that there was no test lead attached to the pipe at LA Rd 1143 (Dorcelie Rd) cased crossing. There was a casing vent which had a casing to soil potential of -1.162 volt at the time of the inspection, indicating a probable short. A casing potential of -0.676 volt was documented on the Apache 2008 annual survey which also had no indication of pipe to soil potential at that location. 3. §195.573 What must I do to monitor external corrosion control? (a) Protected pipelines. You must do the following to determine whether cathodic protection required by this subpart complies with Sec. 195.571: (1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months. During the inspection a visit was made to the pipeline crossing at Louisiana Hwy 82. There is a casing vent and cathodic protection test station at that location, however there is no record of a reading being taken by Apache. The 2008 annual survey had no record of cathodic protection readings at this test station location. 4. § 195.573 What must I do to monitor external corrosion control? 3#

420095008W_Warning_06262009_text.pdf, page 4(d) Breakout tanks. You must inspect each cathodic protection system used to control corrosion on the bottom of an aboveground breakout tank to ensure that operation and maintenance of the system are in accordance with API Recommended Practice 651. However, this inspection is not required if you note in the corrosion control procedures established under Sec. 195.402(c)(3) why compliance with all or certain operation and maintenance provisions of API Recommended Practice 651 is not necessary for the safety of the tank. There was no documentation available at the inspection to demonstrate that tank bottom cathodic protection readings were being taken on Tank 4. There were no tank cathodic protection readings on the 2008 annual survey documentation provided at the inspection. 5. §195.589 What corrosion control information do I have to maintain? a) You must maintain current records or maps to show the location of-- (1) Cathodically protected pipelines; (2) Cathodic protection facilities, including galvanic anodes, installed after January 28, 2002; and (3) Neighboring structures bonded to cathodic protection systems. (b) Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode. (c) You must maintain a record of each analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. You must retain these records for at least 5 years, except that records related to Secs. 195.569, 195.573(a) and (b), and 195.579(b)(3) and (c) must be retained for as long as the pipeline remains in service. At the time of the inspection, the inspector was informed by Apache personnel that the rectifier northwest of, and nearest to, Tank #4 was returned to service approximately a week before the inspection. This rectifier was not on the rectifier survey, and had apparently not been in service since before the purchase of the system from BP in 2006. Although Tank #4 cathodic protection readings taken at the inspection ranged from - 0.860 to -1.318 it is not known exactly how long this rectifier had been out of service and how cathodic protection of the breakout tank may have been compromised. Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1,000,000 for any related series of violations. We have reviewed the circumstances and supporting documents 4#

420095008W_Warning_06262009_text.pdf, page 5involved 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 Apache 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 4-2009-5008W. 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, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration 5#