State California Regulations TITLE 2 ADMINISTRATION DIVISION 3 STATE PROPERTY OPERATIONS database is current through 09/29/06, Register 2006, No. 39 <<(Chapter Originally Printed 1-22-45)>> s 1900. Definitions. The following definitions shall apply to this Chapter unless otherwise provided. (a) The term "applicant" includes any person who files an application under these regulations. (b) The term "person" includes any individual, firm, partnership, business entity, business trust, association, corporation, or governmental entity or agency. (c) The term "lease" includes a permit, right-of-way, easement, license, compensatory agreement, or other entitlement of use. (d) The term "structure" means any manmade construction. (e) The term "submerged lands" means the area lying below the elevation of ordinary low water in the beds of all tidal and nontidal navigable waters. (f) The term "tidelands" means the area lying between the elevations of ordinary low water and ordinary high water on lands subject to tidal action. (g) The term "uplands" shall mean lands bordering on navigable waterways. (h) The term "school lands" refers to all Sections 16 and 36 granted to the State for the benefit of common schools by Chapter 145 of the Federal Statutes of 1853. (i) The term "lieu or indemnity lands" refers to those lands acquired by the State in place of school lands it previously acquired or school lands to which it did not receive title because they were either mineral in character, had not been sectionalized, or were subject to prior established rights. (j) The terms "merchandise," "product" and "commodity" are interchangeable and shall include, goods, wares, chattels, personal property of every description, cargo, freight, mail, vessel's stores and supplies, articles, matter and material. Note: Authority cited: Sections 6002, 6105, 6108, 6301, and 6501, Public Resources Code; and 3 Cal. 3d 462, 478 (tide and submerged lands). Reference: Sections 6301 and 6501, Public Resources Code. s 1901. Office of Commission. The principal office of the Commission is 100 Howe Avenue, Suite 100-South, Sacramento, California 95825, telephone (916) 574-1900. The Commission's Mineral Resources Management Division is located at 200 Oceangate, Suite 1200, Long Beach, California 90802, telephone (310) 590-5201. Applications for exploration or extraction of minerals, oil and gas, or geothermal resources shall be sent to the Mineral Resources Management Division. All other applications shall be sent to the principal office. Note: Authority cited: Sections 6102, 6103.2, 6105, 6108, and 6216, Public Resources Code. Reference: Section 6102, Public Resources Code. s 1902. Meetings of the Commission. The commission shall meet at Sacramento on the last Thursday of each month unless, upon due notice, the date and place of meeting are otherwise designated by at least two members. Note: Authority cited: Sections 6104, 6105, and 6108, Public Resources Code. Reference: Section 6104, Public Resources Code. s 1904. Application Requirements and Priority. Application requirements and priority shall be as set forth in Public Resources Code Sections 6801 and 6223 respectively. Note: Authority cited: Sections 6105, 6108, 6216, 6223, 6301, 6501.2, and 6801, Public Resources Code; and Section 65940, Government Code. Reference: Sections 6223 and 6501.2, Public Resources Code. s 1905. Filing and Processing Fees. Filing and processing fees shall be paid by applicants at the time of filing an application as follows: (a) Filing fee $25.00 (b) Processing fee for Commission services computed and charged as follows: (1) A non-refundable expense deposit for routine or uncomplicated services based on an average cost of such services; or (2) A refundable expense deposit for non-routine and complicated services based on the estimated costs of such services. Any unexpended portion of such expense deposit shall be refunded to the applicant; (3) An additional expense deposit for additional or unanticipated services, to be paid within 21 days of written notice being mailed to the applicant. Any unexpended portion of such expense deposit shall be refunded to the applicant. Note: Authority cited: Sections 6105, 6108, 6214, 6218, 6309, 6321, 6502, 6503.5, 6703, and 7706, Public Resources Code. Reference: Sections 6214, 6218, and 7706, Public Resources Code. s 1906. Guaranty Deposits. The Commission may require deposits of either bond, cash or other acceptable security to insure compliance with terms and conditions of bids, leases, contracts, or any other agreements. Note: Authority cited: Sections 6005, 6105, 6108, 6301, 6405, 6501.2, 6829(d), and 6899, Public Resources Code. Reference: Sections 6501.2, and 6829(d), Public Resources Code. s 1907. Insurance. The Commission may require insurance against such risks and in such amounts that it may determine to be within the best interests of the state. Note: Authority cited: Sections 6005, 6105, 6108, 6301, 6405, 6501.2, 6829, and 6899, Public Resources Code. Reference: Sections 6501.2, 6829, and 6899, Public Resources Code. s 1909. Bidding Procedure. (a) Except as otherwise provided in this chapter, when competitive bidding is required, it shall be conducted generally as follows: (1) The Commission shall cause a notice of intent to receive bids to be published at least once in a newspaper of general circulation in the county in which the lands, interest or project is located and may have such notice published at least once in a newspaper of general circulation in the City of Los Angeles, or San Francisco, or Sacramento. Such notice shall specify the lands or interest (oil, gas or mineral lease; easement; timber; land; etc. for sale or project (public works or consultant contracts, oil, gas or mineral exploration, etc.) for bid, the time and place for the receipt and opening of bids, and the availability of appropriate approved bid packages and forms at the office of the Commission. (2) The Commission shall at the specified time and place publicly open or have opened the sealed bids and shall award the highest or lowest responsible bidder, as appropriate, unless, in the opinion of the Commission such award is not in the best interest of the State, in which case the Commission may reject all existing bids and call for new ones or terminate bidding. (3) The Commission shall have broad discretion as to whether a bidder is "responsible" based on what it deems to be in the best interest of the State. (4) Except as otherwise provided in the bid instructions specifying a shorter period, and/or limiting the firm bid requirement to a specific number of high or low bidders as appropriate, each bid shall be a firm bid, irrevocable for a period not to exceed ninety (90) days from the date of bid opening. (b) Bidders shall bear all reasonable expenses incurred by the Commission for bid processing and award including costs of approval, advertising and environmental review, in accordance with terms set forth in the approved bid package. Note: Authority cited: Sections 6005, 6105, 6108, 6218, 6405, 6406, 6501.2, 6811, 6815.2, 6827, 6834, 6835, 6836, 6852, 6871.3, 6874, 6900, 6992, 6993, 7052, 7301, 7361, 7501, and 7604, Public Resources Code. Reference: Sections 6005, 6811, 6827, 6834, 6835, 6836, 6852, 6871.3, 6912, 6992, and 7059, Public Resources Code. s 1910. Execution and Delivery of Documents. All documents to be executed by applicant shall be signed by the applicant and certified, witnessed or acknowledged as required, prior to their execution and delivery by the Commission. Note: Authority cited: Sections 6105, 6106, 6108, and 6504, Public Resources Code. Reference: Sections 6106 and 6108, Public Resources Code. s 1911. Interest and Penalty Payments. (a) Time of Payment (1) Any payment pursuant to any permit, lease, contract, or other agreement due the Commission shall be paid on or before the date specified in the instrument. (2) If the date that a sum becomes due and payable to the Commission is a Saturday, Sunday, Federal or State holiday, the due date is extended to the next business day. (3) Timeliness of receipt of remittances sent by mail to the Commission shall be governed by the postmark date as described in Government Code Section 11002. (4) In case of a postmark by a private postage meter, the date specified thereon shall be considered as the date of payment. Where a payment is received after the due date and where a question arises as to the actual date of mailing, a declaration executed under penalty of perjury by the person responsible for the mailing of payment to the State specifying the date of mailing shall be considered as evidence of the date of actual mailing. (b) Interest and Penalty Unless otherwise provided in the permit, lease, contract, or other agreement: (1) Simple interest shall be calculated at the rate of one and one-half percent (1 1/2 %) per month on the amount due the Commission from the date payment was due the Commission until the date the payment is received. (2) Penalties shall be calculated at the rate of five percent (5%) on the principal sum due the Commission. (3) Interest and penalty shall be charged for failure to make a timely payment; or the mode of payment is not honored by a bank, savings and loan, post office, or other financial institution. (c) Exemption from Interest and Penalty (1) The Commission may waive the assessment of interest and/or penalty where: (A) Incorrect instructions were rendered to a party by the Commission's staff, or use by the party of an accounting procedure pursuant to an agreement with a member of the Commission staff; or (B) Notwithstanding the provisions of paragraph (2) infra, negotiated settlements are approved by the Commission and provide for a waiver of penalty and/or interest. (2) Penalty only shall be excused where failure to make a timely payment was due to one of the following: (A) The death or serious illness of a natural party; (B) Catastrophe, such as fire, flood, theft, vandalism, or riot; (C) The fact the books and records of a party were impounded by court order, or were in the hands of a Federal or State agency, and unavailable for use by the party; (D) The discovery by a party, before that of the Commission staff, of the erroneous amount of a party's original payment and the prompt tender by the party of the balance due. (d) Payments Payments shall be applied to retire obligations in the following order: (1) interest and penalty (2) past principal (3) current principal (e) Any person who uses or occupies any lands owned or controlled by the State under the jurisdiction of the Commission without a lease, permit or other agreement and who subsequently obtains a lease, permit or other agreement providing for the payment of back rent, shall pay penalty and interest in accordance with the provisions in (b), (c), and (d) above. Note: Authority cited: Sections 6108 and 6224, Public Resources Code. Reference: Section 6224, Public Resources Code; and Section 11002, Government Code. Note: Authority cited: Section 6108, Public Resources Code. Reference: Division 6, Public Resources Code. s 2000. General. (a) This article applies to the leasing of all lands under the Commission's jurisdiction for all surface uses except the exploration for or extraction of natural resources including minerals, oil, gas or other hydrocarbons, or geothermal resources or any other natural resources, excluding timber. (b) Leases or permits may be issued to qualified applicants and the Commission shall have broad discretion in all aspects of leasing including category of lease or permit and which use, method or amount of rental is most appropriate, whether competitive bidding should be used in awarding a lease, what term should apply, how rental should be adjusted during the term, whether bonding and insurance should be required and in what amounts, whether an applicant is "qualified," etc. based on what it deems to be in the best interest of the State. (c) Leases or permits for tide or submerged lands shall generally only be issued to riparian or littoral upland owners or use right holders, provided however that such leases or permits may be granted to the best qualified applicant irrespective of riparian or littoral status. (d) Leases or permits for school, lieu or indemnity lands shall be for value or value enhancement purposes. Note: Authority cited: Sections 6005, 6105, 6108, 6216, 6301, 6309, 6321, 6501, 6501.1, and 6501.2, Public Resources Code. Reference: Sections 6216, 6501.1, and 6501.2, Public Resources Code. s 2001. Applications Forms. Applications for leases or permits under this article are available from and shall be submitted to the principal office of the Commission. Note: Authority cited: Sections 6105, 6108, 6223, 6321, 6501, 6501.2, and 6502, Public Resources Code. Reference: Sections 6321 and 6502, Public Resources Code. s 2002. Categories of Leases or Permits. (a) General Lease: Uses may include the following: (1) Commercial: Income producing uses such as marinas, restaurants, clubhouses, recreation piers or facilities, docks, moorings, buoys, helicopter pads, decks or gas service facilities. (2) Industrial: Uses such as oil terminals, piers, wharves, warehouses, stowage sites, moorings, dolphins and islands; together with necessary appurtenances. (3) Right of Way: Uses such as roadways, power lines, pipelines or outfall lines, except when used only as necessary appurtenances. (b) General Permit: Uses may include the following: (1) Public agency uses such as public roads, bridges, recreation areas or wildlife refuges having a statewide public benefit; (2) Public Resources Code Section 6321 protective structures such as groins, jetties, sea walls, breakwaters and bulkheads; (3) Non income producing uses such as piers, buoys, floats, boathouses, docks, waterski facilities, and campsites not qualifying for a private recreational pier permit under 2002(f). Other uses may include campsites, cabins, dwellings, arks, houseboats, or boathouses provided that when such uses are located on sovereign lands that such uses are not found to be inconsistent with public trust needs. (c) Grazing Lease: Use includes the feeding of livestock on forage. (d) Agricultural Lease: Uses may include farming, silviculture and horticulture. (e) Forest Management Agreement: Uses may include reforestation, improvement of timber growth and soil productivity, vegetation control, reduction of fire and erosion hazards, insect or disease control or any other use that enhances the value of lands subject to the agreement. (f) Private Recreational Pier Permit: Use is limited to any fixed facility for the docking or mooring of boats constructed for the use of the littoral landowner, as specified in Public Resources Code Section 6503.5, and does not include swimming floats or platforms, sun decks, swim areas, fishing platforms, residential, recreational dressing, storage or eating facilities or areas attached or adjacent to recreational piers, or any other facilities not constructed for the docking or mooring of boats. (g) Salvage Permit: Use includes the salvage of all abandoned property over and upon ungranted tide and submerged lands of the State which property belongs to the State and is under the Commission's jurisdiction pursuant to Public Resources Code Section 6309. The Commission may retain or sell any or all salvaged property or may allow the permit applicant to retain it. Note: Authority cited: Sections 6105, 6108, 6201, 6210.3, 6221, 6309, 6321, 6322, 6501, 6501.1, and 6501.2, Public Resources Code. Reference: Sections 6201, 6309, 6321, 6501.1, and 6503.5, Public Resources Code. s 2003. Rental. (a) Rental for the various categories of uses shall be generally as follows: (1) Commercial Use: An annual rental based on any one or combination of the following rental methods, with a minimum rental of $250: (A) A percentage of annual gross income (the percentage being based on an analysis of the market for like uses and other relevant factors); (B) 9% of the appraised value of the leased land; (C) The volume of commodities passing over the lease premises. (2) Industrial Use: An annual rental based on any one or combination of the following rental methods with a minimum rental of $250: (A) 9% of the appraised value of the leased land together with 2H per diameter inch per lineal foot of pipelines and conduits on the leased premises; (B) The volume of commodities passing over the lease premises. (3) Right-of-Way Use: An annual rental based on any one or combination of the following rental methods with a minimum rental of $100: (A) 9% of the appraised value of the leased lands, together with compensation for any damage caused to such lands; (B) 2¢ per diameter inch per lineal foot; (C) The volume of commodities passing over the lease premises. (4) General Permits: Annual rental shall be based on 9% of the appraised value of the leased lands with a minimum rental of $50. (A) No rental shall be charged for public agency use of tide and submerged lands if the Commission at its sole discretion, determines that a statewide public benefit accrues from such use. (B) Monetary rental for Public Resources Code Section 6321 protective structures may be waived if the Commission determines that a public benefit accrues from the installation of such structures. (5) Private Recreational Pier Permits: Pursuant to Public Resources Code Section 6503.5 a rent free permit shall be issued to those applicants demonstrating their qualifications under that section as implemented by 2002(f). (6) Grazing: An annual rental based on appraised value for the intended use. (7) Agricultural: An annual rental based on any one or a combination of the following rental methods with a minimum rental of $250: (A) A percentage of annual gross income (the percentage being based on analysis of the market for like uses and other relevant factors); (B) 9% of appraised value of the leased lands. (8) Forest Management Agreements: Rental shall constitute enhancement of the land's value resulting from the use. (9) Salvage Permit: Rental shall be as follows: (A) A rental of $25.00 per annum per acre, computed on a whole or fractional basis, for the total acreage of the permit area; and (B) 25% of the net salvage value up to $25,000 and 50% of all such value over that amount for all salvaged property the salvor is permitted to retain; or (C) The net salvage value of any property the State retains less any rental to which it is entitled; and (D) Such other consideration as may be deemed by the Commission to be in the best interest of the State. (b) The following factors shall be considered by the Commission in determining which rental method should apply: (1) The amount of rental the State would receive under various rental methods; (2) Whether relevant, reliable and comparable data is available concerning the value of the land proposed to be leased; (3) Whether a particular method or amount of rental would effectively cause an applicant to use more competitive substitute land or to abandon its project altogether; (4) Whether the land proposed to be leased has been classified as environmentally significant pursuant to Public Resources Code Section 6371. (5) The monetary value of actual or potential environmental damage anticipated from an applicant's proposed use to the extent such damage is quantifiable; (6) Other factors relating to the appropriateness of the proposed rental method. (c) The following limitations shall apply to rental based on the volume of commodities passing over State lands: (1) Rental shall not be imposed more than once for the identical commodity passing over the same State land if the ownership of that commodity has not changed. (2) The rental rate for a right-of-way for passage of a commodity across State lands shall be made proportional to the percentage of the total length of the pipeline or conduit that such right-of-way comprises. For the purposes of this section, the total length of a pipeline or conduit shall be the length of the pipeline or conduit between two facilities, uninterrupted by another facility . "Facility" includes terminal, production, storage, refining, manufacturing, processing, mixing or intermixing facilities. (d) Rental adjustment during the lease term shall be provided for as appropriate. Note: Authority cited: Sections 6105, 6108, 6309, 6321.2, 6503, 6503.5, and 6504, Public Resources Code. Reference: Sections 6321.2, 6503, 6503.5, and 6504, Public Resources Code. s 2004. Term. (a) The term for leases and permits including any optional renewal periods shall be no longer than necessary to accomplish the intended use or purpose. (b) The term shall be limited according to standard commercial practices with maximum terms as follows: (1) General Lease 49 years General Permit Forest Management Agreement (2) Agricultural Lease 25 years (3) Grazing Lease 10 years Private Recreational Pier Permit General Permit Recreational Use (4) Salvage Permit 1 year but extendable for one additional year. Note: Authority cited: Sections 6008, 6105, 6108, 6309, 6321, 6501, 6501.2, and 6505.5, Public Resources Code. Reference: Sections 6501.2 and 6505.5, Public Resources Code. s 2030. Sale Restrictions. (a) Sales of tide and submerged lands are prohibited. (b) Sales of school, lieu or indemnity lands are restricted as follows: (1) No new purchase applications shall be accepted except those from public agencies, entities or utilities or under the circumstances determined by the Commission to be in the best interest of the State. Such sales may be accomplished with or without competitive bidding. (2) The Commission on a selective basis may offer individual parcels for sale to the general public pursuant to competitive bidding on terms and conditions set forth in an approved bid package. (3) An existing lessee on any parcel offered for sale shall have the right to match the highest bid. Note: Authority cited: Sections 6005, 6105, 6108, 6210.2, 6216, 6301, 7301, 7351, 7352, 7357, 7405, 7406, 7409, 7410, and 7418, Public Resources Code. Reference: Sections 6216, 7301, 7352, 7357, and 7410, Public Resources Code. s 2031. Applications. Applications for purchase of lands or interests under this article shall be available from and shall be filed with the principal office of the Commission. Purchase applications shall be processed according to the date the application is accepted as complete by the State. Note: Authority cited: Sections 6105, 6108, 6223, 6301, 7301, 7352, 7353, 7355, 7356, 7358, and 7410, Public Resources Code. Reference: Sections 6223 and 7356, Public Resources Code. s 2032. Sales Price. The sale price of lands sold under this article shall be equal to or greater than the appraised fair market value of such lands. Note: Authority cited: Sections 6105, 6108, 7301, 7305, 7352, 7410, and 7413, Public Resources Code. Reference: Section 7305, Public Resources Code. s 2034. Timber Sales. (a) Timber sales shall be conducted pursuant to competitive bidding, on terms and conditions set forth in an approved bid package for a price of no less than appraised fair market value except that: (1) Sales of small volumes of timber valued at $25,000 or less or emergency salvage sales of fire, insect or disease damaged timber may be sold by direct solicitation of bids; and (2) The removal of pre-commercial or dead or down trees for the purpose of stimulating the growth of residual trees or to reduce fire, insects, disease or other hazards may be conducted without charge. (b) Payment shall be: (1) Based on an estimated volume of standing timber or when appropriate by log scale of the timber designated for sale by species; and (2) Made in cash in full at the time of bidder award for sales having a price of $25,000 or less, and (3) Made in two or more installments covering separate cutting blocks for sales having a price greater than $25,000, the first payment to be made at the time of bidder award and subsequent payments to be made at specified times. (c) Reforestation or rehabilitation may be required as a condition of sale. Note: Authority cited: Sections 6105, 6108, 6211, 6216, 6301, and 7361, Public Resources Code. Reference: Sections 6216 and 7361, Public Resources Code. Note: Authority cited: Section 6108, Public Resources Code. s 2100. Application for Exploration Permits. General permits are required for the conduct of geophysical surveys and geological surveys on State lands. (a) Any person who meets the requirements of Section 6801 of the Public Resources Code may apply to the Commission for a geophysical survey or geological survey general permit. Such application shall contain the following: (1) A description and map of the State lands involved. (2) Name, address, and status of citizenship of applicant; if the applicant is a corporation, the corporate name and status, the name of the president, the secretary, and an officer authorized to execute contracts and leases and receive service of process. (3) A description of the proposed survey methods. (4) The dates when the survey will be commenced and completed. (5) The purpose for conducting the survey. Note: Authority cited: Section 6108, Public Resources Code. Reference: Sections 6212.2, 6801 and 6826, Public Resources Code. s 2101. Records. s 2102. Alteration of Facilities. Any proposed change in, or addition to, pipe line systems or any proposed installation or removal of equipment which can result in a different routing of production to or from the gauge tanks shall be reported to the state inspector giving the reason for such proposed change, addition, installation or removal at least 24 hours prior thereto. Plats and drawings showing the change shall be furnished to the Division of State Lands upon request. s 2103. Tankage. (a) All oil shall be stored in tanks suitable for accepted methods of calibration, gauging and sampling as expressed by the American Petroleum Institute Code. (b) Tanks shall be equipped with such safety devices and fire walls as are required in the area in which such tanks are located. (c) Sufficient tankage shall be provided by the lessee. (d) No tank trucks, trailers, tank cars, or vessels will be gauged unless proper certified gauge tables or other adequate evidence of container capacity is presented to the inspector and approved by him in advance of use. (e) Sediment and other material deposited on or near the bottom of tanks shall be removed to permit proper gauging and sampling at the request of the inspector. (f) All gauge tanks shall be strapped and calibrated by a disinterested party. The process shall be in accordance with that expressed in the American Petroleum Institute Code. Strapping and calibration of gauge tanks by a representative of an interested party may be permitted only upon advance notification of such action to and approval by the Division of State Lands. (g) When tanks are to be strapped or restrapped, the inspector shall be notified at least 24 hours in advance to permit him to be a witness to the procedure. (h) All tanks shall be calibrated in barrels (of 42 gallons per barrel) and the volume expressed in gauge tables computed to the nearest one-hundredth of a barrel for each one-eighth of an inch in tank height, or in accordance with the procedure expressed in the American Petroleum Institute Code. (i) Gauge tables in duplicate for each gauge tank shall be furnished to the Division of State Lands immediately upon preparation. Additional sets of gauge tables shall be furnished to the Division of State Lands upon request. s 2104. Sealing of Tanks. (a) At the time of taking the high gauge of a tank the inspector shall seal or lock all inlet lines to the tank and any seals on the tank outlet line shall be removed. (b) At the time of taking the low gauge of a tank the inspector shall seal or lock all outlet lines from the tank and any seals on the inlet line shall be removed. (c) In the event any such state tank seal is removed, except by those authorized to do so, payments shall be made to the State for the run as estimated by the inspector at the rate then prevailing for oil of the highest gravity run from the tank during the previous 30 days. (d) Under no circumstances shall any person other than the inspector remove, break, or alter, any seal or lock installed by the State unless the consent of the inspector in charge of the field is first obtained. Such consent must be confirmed by the inspector in writing, otherwise the procedure specified in Section 2104(c) will govern. Where operations require, seals on bleeder valves and meter by-passes may be removed on the condition that such removal and the time thereof are reported on the applicable daily operating reports. Failure to report such removal may result in the recession of permission to the operator to remove seals from bleeder valves and meter by-passes under any operating conditions. s 2105. Shipments from Sumps or Pits. Before any shipment of fluid is made any sump or pit, notice shall be given to the inspector. The quantity of the fluid shipped from any sump or pit shall be determined by the inspector and the quality shall be fixed by laboratory tests made pursuant to Section 2108 hereof. In the event that any fluid is shipped from any sump or pit without such determination by the inspector, the full capacity of the sump or pit will be considered to have been run and payments shall be made to the State for this presumed run at the rate then prevailing for oil of the highest gravity run from the lease during the previous 30 days. s 2106. Condition of Oil. (a) Previous to high or opening gauge all free water shall be drawn from the tank until the maximum level of nonmerchantable oil and water shall be at least four inches below the bottom of the outlet connection. (b) All oil to be gauged and shipped shall be in a marketable condition, i.e., the percentage of bottom sediment and water as shown on test shall not exceed 3 percent, if dehydration or cleaning costs are to be allowed. (c) Where a tank sample shows a bottom sediment and water content greater than 3 percent and the contents are shipped, the gravity of the wet oil shall be reduced to 3 percent wet gravity and such gravity shall form the payment of the state royalty. (d) Where an adjustment is made from a wet gravity to another wet gravity or to a dry gravity, the adjustment shall be made by the calculation of the American Petroleum Institute gravity of the oil in the mixture or emulsion or by means of the correction chart published by the Division of State Lands for that purpose, such chart being known as "Gravity of Oil in Mixtures or Emulsions of Oil and Water." In all adjustments of gravity by calculation, or the use of a correction chart, the specific gravity of the water in the mixture or emulsion shall be considered as 1.0000 at 60 degrees F. unless prior written approval has been secured for another value of specific gravity as determined by tests of the water produced. s 2107. Gauging and Sampling. (a) Gauges shall be taken by an inspector in the presence of a representative of the lessee. In the event of disagreement, gauges shall be retaken, the average of which shall be binding. In the event that a representative of the lessee is not present after having been given an opportunity to be present, gauges taken by the State shall be binding on the lessee. (b) Gauges shall be taken as specified in the American Petroleum Institute Code. (c) Temperature of the oil in a tank shall be taken at the time of gauging with a standard thermometer which shall be immersed not less than two minutes at or about the midpoint of the column of oil, not less than 12 inches from the tank shell, and in the manner expressed in the American Petroleum Institute Code. (d) Samples for laboratory testing shall be taken at the time of the high or opening gauge. (e) The method of sampling shall correspond with the method expressed in the American Petroleum Institute Code. (f) A sample shall consist of one liquid quart and the means for taking such sample shall be furnished by the lessee. s 2107.5. Automatic Custody Transfer. (a) Any applicant holding a lease may submit an application to install lease automatic custody transfer equipment. The application shall include (1) a schematic drawing of the proposed system, and (2) specifications of the major equipment components. The lessee shall afford access to any manufacturer's drawings and equipment specifications of the major equipment components which the commission may deem necessary. (b) Positive displacement meter installations in lease automatic custody transfer equipment shall comply with specifications outlined in the latest revision of American Petroleum Institute Code No. 1101, unless specifically modified with the approval of the State Lands Division. The equipment shall include a means for proportional sampling for securing laboratory test samples, or a means for quality measurement. (c) Upon determination that acceptable standards of accuracy for measuring oil shipments have been obtained, the commission will approve oil shipments by lease automatic custody transfer. (d) The equipment shall be maintained and operated in a manner so as to meet the accepted standards of accuracy for the measurement of oil shipments. Use of this equipment shall be discontinued at any time upon determination by the lessee or the inspector that the standards of measurement of accuracy or quality are not being obtained. (e) The opening and closing meter readings shall be made with a state gauger present. (f) A memorandum of transfer (run ticket) shall be furnished the State for each run of oil within 24 hours of the completion of such run. (g) For each run of oil, a copy of official "Gauger's Report of Oil Run" will be furnished to the lessee. (h) Where approved lease automatic custody transfer equipment is in operation, the provisions of Sections 2104, 2106(d), 2107 and 2109 of this title are not applicable. Where circumstances require conventional gauging for custody transfer, the aforesaid sections shall apply. s 2108. Laboratory Tests. (a) All laboratory tests shall be made in accordance with the procedure expressed in the American Petroleum Institute Code and shall consist primarily of the gravity and bottom sediment and water content determination. Samples for laboratory tests shall be furnished by the lessee as required by the State. (b) Laboratory tests shall be run not later than 24 hours after the time of taking the samples. (c) The readings and results of tests of oil samples made by the State shall be binding upon the lessee. (d) Lessee may furnish necessary laboratory equipment to American Petroleum Institute standards, in which event the inspector may make use thereof. s 2109. Record of Oil Run. (a) A memorandum of transfer shall be furnished the State for each run of oil from lessee's gauged tanks within 24 hours of the completion of such run. (b) For each run of oil from the lessee's gauged tanks a copy of an official "Gauger's Report of Oil Run" will be furnished to the lessee. s 2110. Quantity Determination. The volume of oil run shall be the volume corrected to 60 degrees F. according to the schedule "American Petroleum Institute Standard 2540, Table 6 (ASTMD-1250, Tables 6 and 24)." s 2111. Tests and Measurements of Gas. (a) Gasoline content tests shall be made by or for the lessee at least once a month and at such other intervals as appear to be necessary in the opinion of the inspector. (b) An inspector shall be permitted to witness any tests for the gasoline content of casinghead gas. (c) All tests and measurements of gas shall be in accordance with the procedure expressed by the California Natural Gas Association in Bulletins T.S. 351, T.S. 353, T.S. 354, and any revisions thereof. s 2112. Production Reports. (a) A daily report in the form prescribed by the Division of State Lands shall be furnished as required. (b) Monthly reports shall be furnished to the Division of State Lands as required. s 2113. Redrilling Operations. No oil or gas well shall be redrilled except upon prior approval of the Division of State Lands. No application to redrill a well shall be approved unless it is shown that such redrill is necessary and in the public interest, and then only provided that: (a) No point in the redrilled portion of the well, including the bottom thereof, shall be more than 100 feet from the original hole; (b) No point in the redrilled hole shall be closer than 50 feet to the blanked off portion of any well not under the control of the drilling operator, other than the well to be redrilled; (c) All redrilling within an oil zone shall be done with any standard circulating medium as used in good engineering practice and as approved specifically by the Division of State Lands. (d) In case any point in the redrilled hole may come within 200 feet of the portion open to production of any well, other than the well to be redrilled, the applicant shall file with the Division of State Lands: (1) Written consent from the operator of each well within said 200 feet, waiving any objection to the proposed redrilling operations; (2) For each well, within said 200 feet, a surety bond, in an amount and for a period to be fixed by the commission, indemnifying the State against any loss, damage, claim, demand or action caused by or connected with the redrilling operations. s 2114. Drilling Operations. (a) No lessee shall drill an oil or gas well on state lands except on prior approval of the Division of State Lands and subject to the terms of the enabling statute and lease and then only provided that any well so drilled within any oil zone, shall be at least 50 feet away from the blanked off portions of any well not within control of the lessee and at least 200 feet away from the perforated section of any well not within the control of the lessee. (b) As a preliminary condition to approval of the drilling of a well, the lessee shall submit the proposed course of the well with vertical and horizontal projections of said course drawn upon graph paper to a scale of 100 feet to the inch. Upon completion of the well, the lessee shall file with the Division of State Lands a complete survey of the well, electric log, well history, driller's log and all core data. s 2115. Perforations, Plug Backs and Reperforations. For any well to be perforated or plugged back and reperforated within 200 feet of any well not within the control of the lessee, lessee shall file with the Division of State Lands: (a) Written consent from any lessee having a well within said 200 feet, waiving any objection to the proposed plug back and reperforating operations, or; (b) For each well within 200 feet of any well or wells a corporate surety bond in an amount and for a period to be fixed by the commission, for each application, indemnifying the State against any loss, damage, claim, demand or action, caused by or connected with the plug back, perforation or reperforation operations. s 2116. Drilling Fluid. All drilling, redrilling, perforating, or reperforating operations within any oil zones shall be done with any standard circulating medium as used in good engineering practice and as approved specifically by the Division of State Lands. Whenever, in the opinion of the inspector, circulation is lost the lessee shall immediately start pumping into the hold such circulation regaining media as are approved in good engineering practice and are most applicable, in the opinion of the inspector, to the zone in which the hole is located. s 2117. Washing Perforations. Whenever the production of a well is determined to have been decreased because of the plugging of the well's perforations, the inspector may require the lessee to wash the well with a suitable perforation washing fluid. s 2118. Accounting for Royalty. (a) No allowance shall be made for cost of dehydration unless specifically authorized in an existing lease, in which event the allowance shall be the actual cost of dehydration not to exceed 5 cents per net barrel of oil so dehydrated, or the allowance as specified in the lease, whichever is the lesser. Allowance for dehydration will be granted only after lessee has filed with the Division of State Lands an application in duplicate requesting the right to make deduction for dehydration, setting forth the method proposed to be employed and listing the equipment and value thereof installed exclusively for the dehydration of the oil produced from state oil and gas leases. After approval of the application, each operator shall file with the Division of State Lands before the tenth of the month subsequent to that for which dehydration deduction is requested, a detailed statement of the actual cost of dehydration proposed to be deducted from the gross royalty payable for the preceding month. (b) Tank bottoms and sump oil shipments are to be reported on the following value basis: Shipments of 0.0 percent to 3.0 percent cut -quoted market price for applicable dry gravity. Shipments of 3.1 percent to 15.0 percent cut -quoted market price for applicable dry gravity less 5 cents per gross barrel at 60 degrees F. Shipments of 15.1 percent cut and up -quoted market price for applicable dry gravity less 15 cents per gross barrel at 60 degrees F. (c) All transfers of dry gas "Returned to Lease" or elsewhere, made by an operator for the use or benefit of other leases or of third parties, will be considered as sales under the terms of the lease. (d) Whenever under Section 2116 crude oil is used as a circulating medium, the operator shall be allowed a credit of 25 percent of the volume of any foreign circulating oil used. This credit shall be deducted from the total number of barrels produced from the well during the 30-day period immediately following the well's completion. (e) Whenever the State shall require the operator to use foreign oil to wash perforations of a producing well (Section 2117), the operator shall be allowed credit of 50 percent of the volume of the oil used in such washing as a deduction from the total number of barrel's produced from the well during the period of 30 days immediately succeeding such operations. (f) Subsection (d) and (e) shall not apply to cases where the volume of circulating oil lost exceeds 5,000 barrels for any one operation. Such cases will be the subject of specific determinations as to periods and the amount of credit to be allowed. (g) The value of oil used as a circulating medium or for washing perforations shall be that fixed by the lease for the quality and gravity of the oil so produced. Foreign oil is any oil not produced from the specific lease of the affected lessee. s 2119. Diligence of Operation. All wells capable of producing oil, gas or other petroleum products in commercial quantities shall be operated continuously at the maximum efficient rate of recovery as determined by recognized engineering standards and in accordance with field production schedules acceptable to the Division of State Lands, unless written authorization is otherwise granted. s 2120. Conformance to Rules. All offshore filled lands or piers or other structure or structures constructed for operations on a state oil and gas lease and all operations including drilling, whether from upland, littoral or offshore locations, shall conform with the rules and regulations of the commission in effect at the time of invitation for bids, in pursuance of which the lease may be awarded, and with the conditions as specified in the bid-lease form. Note: Authority cited for Sections 2120 through 2124; Public Resources Code, Division VI, Sections 6103, 6105, 6108, 6216, 6301, 6873 and 6873.1. s 2121. Suspension of Operations. The lessee shall suspend any drilling and production operations, except those which are corrective, protective, or mitigative, immediately in the event of any disaster or of contamination or pollution caused in any manner or resulting from operations under a lease. Such drilling and production operations shall not be resumed until adequate corrective measures have been taken and authorization of resumption of operations has been made by the commission. s 2122. Lease Operation Offshore. For all wells drilled from filled land or other drill sites or structure or structures located seaward of the ordinary high water mark, operations that may be conducted shall conform with the following: (a) The lessee shall remove the derrick from each well within sixty (60) days after lessee has ceased making use of such derrick in its operations on and with respect to such well. (b) In the discretion of the commission, all permanent operating sites shall be landscaped with shrubbery, or fenced, so as to screen from public view as far as possible the tanks, pumps or other permanent equipment. Such landscaping and shrubbery, or fencing, are to be kept in good condition. (c) Oil, tar, or other residuary products of oil, or any refuse of any kind from any well or works, shall be disposed of on shore in a dumping area in conformance with local regulatory requirements. (d) Suitable and adequate sanitary toilet and washing facilities shall be installed and maintained in a clean and sanitary condition at all times for the use of lessee's personnel. (e) All drilling and production operations shall be conducted in such manner as to eliminate as far as practicable dust, noise, vibration, or noxious odors. (f) Pollution and contamination of the ocean and tide lands and all impairment of and interference with bathing, fishing, or navigation in the waters of the ocean or any bay or inlet thereof is prohibited, and no oil, tar, residuary product of oil or any refuse of any kind from any well or works shall be permitted to be deposited on or pass into the waters of the ocean or any bay or inlet thereof. (g) No permanent filled lands, piers, platforms, or other fixed or floating structures in, on, or over the tide and submerged lands covered by the lease or otherwise available to the lessee shall be permitted to be constructed, used, maintained, or operated where service of less than 20 wells is provided for, without specific authority by the commission. Operating wells not meeting the foregoing requirement shall be completed below such elevation as may be required in each case by the United States, the State, or other competent authority, with the production piped along or below the floor of the ocean to such receiving points as the commission may determine or approve. For nonoperative wells the structures or facilities used for their drilling shall be removed to the satisfaction of the commission within ninety (90) days' time after such wells have been determined to be nonoperative unless a longer period is approved by the commission. s 2123. Lease Operations on Uplands. For all wells drilled from an upland or littoral drillsite landward of the ordinary high water mark, operations that may be conducted shall conform with the following: (a) The lessee shall remove the derrick from each well within sixty (60) days after lessee has ceased making use of such derrick in its operations on and with respect to such well. (b) In the discretion of the commission, all permanent operating sites shall be landscaped with shrubbery, or fenced, so as to screen from public view as far as possible the tanks, pumps, or other permanent equipment. Such landscaping and shrubbery, or fencing, are to be kept in good condition. (c) All drilling and production operations shall be conducted in such manner as to eliminate, as far as practicable, dust, noise, vibration or noxious odors. (d) Suitable and adequate sanitary toilet and washing facilities shall be installed and maintained in a clean and sanitary condition at all times for the use of lessee's personnel. (e) No sign shall be constructed or erected, maintained or placed on the premises except those required by law or ordinance to be displayed in connection with the drilling or maintenance of the well. (f) Pollution and contamination of the ocean and tide lands and all impairment of and interference with bathing, fishing, or navigation in the waters of the ocean or any bay or inlet thereof is prohibited; and no oil, tar, residuary product of oil or any refuse of any kind from any well or works shall be permitted to be deposited on or pass into the waters of the ocean or any bay or inlet thereof. (g) Oil, tar, or other residuary products of oil, or any refuse of any kind from any well or works, shall be disposed of onshore in a dumping area in conformance with local regulatory requirements. s 2124. Surrender of Leased Premises. Each lease shall provide that at the expiration of the lease or sooner termination thereof the lessee shall surrender the premises leased, with all permanent improvements thereon, in good order and condition, or, at the option of the commission and as specified by the commission, the lessee shall remove such structures, fixtures and other things as have been put on the lease by the lessee, all removal costs to be borne by the lessee, subject to the lessee's right to remove his equipment as provided in the statutes. Notwithstanding any provision of these regulations, the lessee shall have the right to remove any and all drilling and producing platforms and other oil field development and producing equipment having a re-use or salvage value. s 2125. General Provisions. (a) This Article 3.2 pertains to oil and gas drilling operations on State oil and gas leases located on State tide and submerged lands under the jurisdiction of the State Lands Commission, and is applicable to operations conducted from mobile rigs, fixed offshore structures and upland locations serving these leases. (b) In addition to complying with Division 6 of the California Public Resources Code and with Title 2, Division 3, Chapter 1 of the California Administrative Code, the lessee shall comply with all applicable laws, rules and regulations, now or hereafter promulgated, of the United States and of the State of California and of any respective political subdivision thereof, including, but not limited to, those of the Division of Oil and Gas, the Department of Fish and Game, the Division of Industrial Safety, the State Water Resources Control Board, the Regional Water Quality Control Boards, the California Coastal Commission, and any respective successors thereto. (c) All drilling operations conducted on State oil and gas leases shall be carried on in a proper and workmanlike manner in accordance with accepted good oilfield practice. Note: Authority cited: Sections 6103, 6108, 6216, 6301, and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2126. Definitions. For purposes of this Article 3.2, the following definitions shall apply: (a) "Drilling operations" include, but are not necessarily limited to, exploratory and development well drilling, redrilling and deepening of a well and well abandonment. (b) "Staff" shall mean the Executive Officer or other duly authorized member of the staff of the State Lands Commission. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2127. Administration. (a) The Staff shall administer this Article 3.2 and shall thereby seek to provide for the prevention and elimination of any contamination or pollution of the ocean and tidelands, for the prevention of waste, for the conservation of natural resources, and for the protection of human health and safety and of property. (b) The Commission has designed these regulations in as great detail as possible. However, the Commission recognizes that situations may arise which are not specifically covered by this Article 3.2 and that emergency situations may arise which will require immediate decisions by the Staff. In such situations, the Executive Officer or his designee may authorize or direct appropriate procedures to be followed. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2128. Drilling Regulations. (a) General Provisions. (1) All drilling for oil and gas on State oil and gas leases shall be conducted in accordance with the provisions of this Section 2128. (2) Prior to the commencement of drilling operations on any well, each well drilling proposal shall be approved by the Staff. (3) Prior to the commencement of drilling operations on any well, the lessee shall obtain all necessary permits and approvals required by all applicable laws and regulations. The lessee shall file copies of those permits and approvals and related documents with the State Lands Commission prior to the commencement of drilling operations. The lessee shall abide by the terms of those permits and approvals, including but not limited to, any required notifications prior to the lessee's commencement of drilling operations. (b) Field Drilling Rules. When sufficient geological and engineering information has been compiled on a lease from exploratory and initial development well drilling, the lessee may make application to the Staff for the establishment of field drilling rules. After the Staff has established field drilling rules, subsequent development well drilling shall be drilled in accordance with these rules. Field drilling rules may include but may not be limited to those relative to casing setting depths, casing cementing requirements and blowout prevention equipment. (c) Well Site Investigation. Prior to commencing drilling operations on any well from a mobile drilling rig, the lessee shall investigate the conditions of the ocean floor and near sub-bottom including sediment characteristics in the area of the proposed well site. The investigation shall be adequate to (1) ascertain the presence of shallow geological anomalies and gather other information to be used as an aid in the design of a safe well drilling and casing program, and (2) determine the presence and location of significant cultural resources. A report of the findings and provisions for mitigating any problems disclosed by the investigation shall be provided to and must be approved by the Staff. Where a number of wells are proposed to be drilled, the area of study may be expanded to cover all the well sites. The plan(s) of investigation shall be in accordance with guidelines provided by the Staff. (d) Drilling Program. Prior to drilling a well the lessee shall submit with the drilling proposal a detailed well-drilling program to the State Lands Commission that shall include but may not be limited to, the following information: (1) Well location map; proposed well course; detailed drilling procedures; casing and cementing program; blowout prevention program; drilling mud program; directional survey program; electrical logging, mud logging and sampling programs; and well testing procedures. (A) In all exploratory well drilling proposals, the lessee shall provide in the detailed drilling procedures a description and depth of the possible drilling hazards that might be encountered in drilling the well. The drilling hazards shall include, but may not be limited to, possible unstable bottom sediments, shallow gas-charged sediments, zones of lost circulation, oil and gas bearing zones, and abnormal pressured zones. (B) In drilling operations using a mobile drilling rig, the lessee shall provide in the detailed drilling procedures an operational program which describes procedures and personnel assignments to be employed for rig and personnel safety while drilling the hole for and running the surface casing string(s). The program shall cover, but may not be limited to, requirements and procedures for testing and use of the diverter system; establishment of safe penetration rates; monitoring of mud returns for indication of gas and loss of circulation; evaluation of drilling breaks; evaluation of severity of gas shows or kicks; stand-by liquid mud and use in well control; emergency plugging of the well; safeguards while removing the drilling riser for running and cementing the casing string(s); pre cautionary measures for fire prevention; and, emergency movement of drilling rig off location. (2) Specifications and performance data of drilling rig; critical operations and curtailment plan; oil spill contingency plan, and hydrogen sulfide contingency plan. (e) Well Casing Requirements. (1) All wells shall be cased and cemented in such a manner as to protect all zones that contain oil, gas, or fresh water, so as to provide well control during drilling operations. (2) The casing setting depths shall be based upon all relevant geological and engineering factors, including the presence of shallow geological anomalies, the presence or absence of hydrocarbons, formation fracture gradients, formation pore pressures, water depth, and zones of lost circulation or of other unusual characteristics. Casing setting depths below the second surface casing shall be justified by calculations of the competency of the preceding casing seat to withstand anticipated mud weights, as well as the pressure generated by simulated well kicks from known or potential gas bearing zones, taking into consideration actual or estimated reservoir pressures, formation fracture gradients, minimum programmed mud weights and anticipated kick volumes. In situations where formation fracture gradients are not known, a formation leak-off or predetermined equivalent mud weight test shall be conducted to obtain estimated formation fracture gradients for use in the calculations. These tests shall be conducted after drilling a maximum of 50 feet of new hole below the shoe of the second surface casing and intermediate casing strings. Additional tests should be performed as the drilling progresses in order to verify the competency of the formation to withstand anticipated pressures, and to further refine casing setting depths. The results of all the tests shall be recorded on the driller's log and reported to the Staff. The known and estimated factors and calculations used to determine the casing setting depths, as well as the casing design safety factors and specifications shall be shown in the casing and cementing program required in Section 2128(d)(1). (3) The lessee shall utilize current technological methods during drilling operations to aid in the prediction of possible abnormal pressured zones in order to minimize the potential for the development of a formation flow or kick. (4) All casing shall be new pipe or the equivalent and shall be inspected by the lessee in a manner approved by the Staff. The inspection shall be sufficient to detect transverse and longitudinal defects, to determine wall thickness, pipe eccentricity and grade uniformity, and shall include a 100 percent thread check of the exposed threads. Casing inspection reports shall be maintained by the lessee in its district office for a period of five years, and shall be available to the Staff. (5) Except in cases where casing requirements have been established by field drilling rules or where geological and engineering factors indicate that a different program should be used, the following casing and setting-depth requirements shall be included in all well casing programs. All depths refer to true vertical depth (TVD) below the ocean floor or ground level unless otherwise specified. In order of normal installation the casing strings are identified as conductor, first and second surface, intermediate, and production casing. (A) Conductor Casing (Referred to as drive or structural casing in USGS Order No. 2). This casing shall be set by drilling, driving, or jetting to a depth of approximately 100 feet below the ocean floor or ground level in order to support unconsolidated sediments and thereby provide hole stability for initial drilling operations. If drilled or jetted in, the fluid circulated to the ocean floor shall be of a type that will not pollute the ocean environment. (B) First Surface Casing (Referred to as conductor casing in USGS Order No. 2). This casing shall be set at a depth between 300 feet and 500 feet below the ocean floor; provided, however, that this casing shall be set before drilling into shallow formations known to contain oil or gas or, if unknown, upon encountering such formations. (C) Second Surface Casing (Referred to as surface casing in USGS Order No. 2). This casing shall be set at a depth between 1,000 feet and 1,200 feet below the ocean floor, but may be set as deep as 1,500 feet in the event the first surface casing is set at least 450 feet below the ocean floor. (D) Intermediate Casing. Intermediate casing shall be set in accordance with the requirements of Section 2128(e)(2). Notwithstanding these requirements, the Staff may specify the use and the setting depth of the intermediate casing. Also, protective casing shall be set at any depth below the second surface casing when required by well conditions such as abnormal pressure, loss of circulation, hole problems, and for the protection of productive zones while performing deeper drilling. A blank liner may be used as intermediate casing provided the existing casing string is of adequate strength for conducting deeper drilling. The top of the liner shall overlap a minimum of 100 feet into the next larger casing string. The lap shall be tested by a fluid entry or pressure test to determine whether a seal between the liner top and next larger string has been achieved. The test shall be recorded on the driller's log. If the test indicates an improper seal, the top of the liner shall be squeezed with cement and retested. (E) Production Casing. This casing shall be set before completing the well for production. A blank or combination liner may be run and cemented as production casing providing the existing casing string is of adequate strength for the safe conduct of production operations. The overlap requirement and the testing of the seal between the liner top and next larger casing string shall be conducted as specified in Section 2128(e)(5)d for intermediate liners. The surface casing shall not be used as production casing. (f) Casing Cementing Requirements. (1) The lessee shall utilize appropriate cementing technology and casing equipment in order to achieve adequate cement fillup and bonding on all casing cementing operations. (2) The conductor (if drilled or jetted) and surface casing strings shall be cemented with sufficient cement to fill the annular space back to the surface or ocean floor. Cement fill shall be verified by the observation of cement returns. The cementing operation may be considered adequate if cement is circulated to the surface or ocean floor within the range of the calculated hole volume. In the event that cement returns are not obtained or cement channeling occurs during cementing of the surface casing strings, the lessee shall run a temperature and/or cement bond survey and/or pressure test the casing shoe to evaluate the adequacy of the cement job. If the casing string is thereby determined to be inadequately cemented, the lessee shall recement the casing string or perform other operations as approved by the Staff to ensure the competency of the cement job. (3) The intermediate casing string(s) shall be cemented with sufficient cement to fill the annular space a minimum of 200 feet into the preceding larger casing string. The protective and production casing strings shall be cemented in a manner such that cement will cover or isolate zones of unusually high or low pressure and zones containing hydrocarbons. Sufficient cement shall be used to provide annular fillup at least 500 feet above the zones to be covered or isolated or above the casing shoe in cases where zonal coverage is not required. A cement bond survey shall be run following primary cementing of the intermediate, protective, and production casing strings to aid in determining whether each string is cemented in accordance with this Section 2128(f)(3). If a casing string is thereby determined not be adequately cemented, the lessee shall recement the casing string as necessary to achieve annular fillup and isolation of zones. If following a primary cementing operation, it has been determined without the aid of a cement bond survey that remedial cementing is necessary, the running of such survey may be deferred until after recementing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the staff. (4) A copy of each temperature and cement bond survey shall be filed immediately with the Staff. (5) After cementing any of the above casing strings, drilling shall not be commenced until after a time lapse of: (A) 24 hours; or (B) Sufficient time for the cement to reach a compressive strength of at least 500 pounds per square inch for the bottom 20 percent of the casing string. To determine the time that a minimum compressive strength of 500 pounds per square inch has been attained, the operator shall pretest the cement slurry at the projected hole temperature and pressure at the cementing depth in accordance with API recommended procedures. (g) Pressure Testing of Casing. Prior to drilling out the plug after cementing, all casing strings except the conductor casing shall be pressure tested to at least the minimum pressure shown in the table below. In the event that the cement is under-displaced, the pressure test shall be conducted after drilling out cement to at least the float collar depth. This test shall not exceed 70% of the minimum internal yield pressure for the casing. If during the test, the pressure declines more than 10 percent in 30 minutes, or if there is any indication of a leak, corrective measures shall be taken so that a satisfactory test is obtained. Casing String Minimum Surface Pressure Test (psi) First Surface........... 200 Second Surface.......... 1,000 Intermediate............ 1,500 or 0.2 psi/ft., whichever is greater Protective.............. 1,500 or 0.2 psi/ft., whichever is greater Liner and Liner Lap..... 1,500 or 0.2 psi/ft., whichever is greater Production.............. 1,500 or 0.2 psi/ft., whichever is greater All casing pressure tests shall be recorded on the driller's log. (h) Directional Surveys. Each well shall be drilled in accordance with the approved well course. Except as otherwise provided in field drilling rules, all wells drilled into the leased lands shall be directionally surveyed as drilling progresses giving both inclination and azimuth measurements. Directional survey shots shall be taken below the setting depth of the conductor casing string at intervals not exceeding 250 feet during the normal course of drilling and at intervals not exceeding 60 feet in angle changing portions of the hole. A multishot directional survey shall be run at casing setting depths and/or at total depth. Results of directional and inclination survey shots shall be reported promptly to the Staff. Copies of all composite and multishot directional surveys shall be filed with the Staff. (i) Blowout Prevention Equipment Requirements. Blowout prevention equipment systems consist of several component systems that function to operate the blowout preventers and to assist in well control under varying rig and well conditions. These systems include the blowout preventers, closing unit, kill and choke lines, choke manifold, fill-up line, diverter, marine riser, and auxiliary equipment. Blowout prevention equipment shall be installed, used, maintained, and tested in a manner necessary to assure well control throughout the drilling, completion or abandonment of a well. All portions of a blowout prevention system shall be designed so that alternate methods of well control are available in the event of failure of any one portion of the system. If one component of the system that is vital to well control becomes inoperative, drilling operations shall be suspended as soon as possible without danger to the well until the inoperative equipment is repaired or replaced. Unless stated otherwise below, the following requirements pertaining to blowout prevention equipment shall apply to both surface and subsea equipment installations. All blowout prevention systems shall include the following: (1) Blowout Preventers. (A) There shall be a specified minimum number of annular and ram-type preventers on each casing string as tabulated below. On surface installations one preventer shall be a blind ram and on subsea installations one preventer shall be a blind shear ram. Pipe rams shall be provided to fit the pipe in use. Locking devices shall be provided on all ram-type preventers. On subsea installations a remotely operated or automatic locking system shall be required. 1. Surface Installations: Conductor.......... 1-Diverter System First Surface...... 1-Annular 1-Pipe Rams 1-Blind Ram Second Surface..... 1-Annular 2-Pipe Rams 1-Blind Ram Intermediate....... 1-Annular 2-Pipe Rams 1-Blind Ram 2. Subsea Installations: Conductor.......... 1-Diverter System First Surface...... 1-Annular 1-Pipe Ram 1-Blind Shear Ram Second Surface..... 2-Annular 3-Pipe Rams 1-Blind Shear Ram Intermediate....... 2-Annular 3-Pipe Rams 1-Blind Shear Ram (B) In floating drilling operations a bypass valve located on the bottom of the riser may be employed to direct returns to the ocean floor when the formation competency at the conductor setting depth is not adequate to permit circulation of drilling fluids to the vessel. (C) All blowout preventers and wellhead assemblies shall have a working pressure exceeding the anticipated surface pressure to which it may be subjected. The lessee shall submit in the blowout prevention program required in Section 2128(d) (1) the anticipated surface pressure of the well and its method of determination for each casing string. (D) Notwithstanding the working pressure requirements determined in (1)b above, all blowout preventers that are used while drilling the hole for surface or intermediate casing shall have a minimum working pressure rating of 2000 psi (2M), except for diverter systems or annular preventers used on the conductor. (2) Closing Unit System. The closing unit system shall incorporate the following general specifications: (A) An accumulator unit having a minimum usable hydraulic fluid operating volume, with pumps inoperative, to close all blowout prevention units and still retain a 50 percent volumetric operating reserve at 1200 psi. (B) A fluid reservoir with a capacity equal to approximately twice the usable fluid capacity of the accumulator system. (C) The capability to close each ram type preventer within 30 seconds. Closing time shall not exceed 30 seconds for annular preventers size 20 inches and smaller, and 45 seconds for annular preventers larger than 20 inches. (D) A dual pump system having a discharge pressure equivalent to the rated working pressure of the closing unit. Each pump system shall have an independent alternate source of power and be equipped with automatic switches that activate the pumps when the closing unit manifold pressure drops below 90 percent of the accumulator operating pressure. With the accumulator system removed from service, each pump system shall be capable of closing the annular preventer on the drill pipe being used, plus be capable of opening the hydraulically operated choke line valve and of obtaining a minimum of 200 psi pressure above accumulator precharge on the closing unit manifold within two minutes or less. (E) There shall be one master control panel which contains a manifold capable of operating and monitoring all of the functions of the closing unit system. All of the controls and gauges in the panel shall be clearly marked and arranged in the same sequence as the valves and the other equipment in the blowout preventer stack which they control. In addition to the master control panel, there shall be a second "remote" or 'mini" panel capable of operating all of the functions of the closing unit system. One of the two panels shall be located at the driller's station and the other at least 50 feet from the centerline of the wellbore. Each of the two control panels shall be capable of controlling the hydraulic manifold but the actual hydraulic manifold shall be located away from the rig floor. The driller's control panel shall have a power source independent of the accumulator pump system, or be designed so that in the event of complete destruction of the panel, inter-connecting cable or hose, there would be no interference with the operation of the accumulator pump system. (F) In addition to the above requirements, closing unit systems for subsea blowout equipment installations shall include the following: 1. The blowout preventer stack shall be equipped with duplicate subsea control pods, each of which shall contain all of the required pilot valves and regulators necessary to operate all blowout preventer stack functions. The control hose bundles may be hydraulic or electro-hydraulic. If hydraulic, the pilot hoses contained within the bundle shall have a minimum internal diameter of 3/16 inch and the power hose shall have a minimum internal diameter of 1 inch. If electro-hydraulic, the electric signal cables may be run integral with the hydraulic power hose or may be run separately. The hose reels shall be so designed that a minimum of four subsea hydraulic functions are operable while running or pulling the blowout preventer stack. 2. The subsea blowout preventer stack shall contain an accumulator volume sufficient to close one annular-type preventer and to open the riser connection without recharge from the surface. 3. The Staff may require that the subsea blowout preventer stack be equipped with an emergency shut-in system that on signal from the surface, will shut in the well in the event the drill vessel loses contact with the stack and the primary blowout prevention control system is lost. (3) Kill and Choke Lines. The blowout preventer stack shall contain a drilling spool or equivalent connections in the blowout preventer body to provide for separate kill and choke lines. Each kill and choke line shall have a master valve located next to the stack followed by a control valve. Both valves shall be full-opening. The master valve shall not be used for normal opening or closing on flowing fluids. On surface installations, the control valve on the choke line shall be remotely controllable. On subsea installations, the valves on both the kill and choke lines shall be hydraulically operated. One of the valves on each line shall be "fail-safe" in the closed position. The kill and choke lines on the subsea installation shall be connected through the surface choke manifold to permit pumping into the well through either line. All connections for valves and fittings shall be flanged, welded or clamped. All lines, including flexible lines, valves and flow fittings shall have a working pressure rating at least equal to the rated working pressure of the blowout preventer stack in use. On surface installations the kill line, valves and fittings shall have a minimum diameter of 2 inch nominal. The choke line, valves, and fittings shall have a minimum diameter of 3 inch nominal. On subsea installations both kill and choke line assemblies shall have a minimum diameter of 3 inch nominal. (4) Choke Manifold. A choke manifold shall be installed on the drilling rig and be so located that it is readily accessible to drilling personnel. The choke manifold design shall consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids. The portion of the manifold subject to well and/or pump pressure shall have a working pressure equal to the rated working pressure of the blowout preventer stack in use. All connections for valves and fittings shall be flanged, welded or clamped. The choke manifold shall be equipped with a minimum of two adjustable chokes, one of which shall be remotely controlled. These chokes shall be isolated by at least one valve on each side to allow for repairs or replacement. All valves shall be full-opening. There shall be at least one bleed line with a minimum diameter of 3 inch nominal. The lines downstream of the chokes shall have a minimum diameter of 2 inch nominal. All lines shall be securely anchored and connected in such a manner as to permit flow to a mud/gas separator, vent lines, or to production facilities or emergency storage. Two vent lines shall be provided if necessary to accomplish the downwind diversion. The choke manifold shall be equipped with accurate pressure gauges so that all control operations can be properly monitored. The choke manifold for a subsea installation shall be equipped with duplicate adjustable choke systems to permit control through either the choke or kill line in addition to a remotely controlled adjustable choke, and to provide tie-is for both drilling fluid and high pressure pump systems. A choke control station shall be provided that includes all monitors necessary to furnish a complete overview of the well control situation. (5) Fill-up Line. A fill-up line shall be installed on top of the blowout preventer stack on surface installations and on top of the marine riser on subsea installations. (6) Diverter System. A diverter system shall be installed on the well prior to drilling below the conductor casing for the purpose of directing flowing formation fluids from the well safely away from the rig and personnel. Low-pressure annular preventers, rotating heads or special diverters may be used for the diversion of well fluids. All such equipment shall be able to pack-off around the kelly, drill string and casing if run through the diverter. There shall be two diverter vent lines to permit diversion of well fluids while minimizing back pressure on the well. All vent lines shall be at least 6 inch nominal diameter unless otherwise justified by engineering analysis. The two vent lines shall be installed in a manner to accomplish downwind diversion. Valves on the vent lines shall be full-opening and so designed that the proper valve automatically opens when the diverter is activated or can be opened by remote control from the driller's control panel. A description and diagram of the diverter system and information justifying the sizing of vent lines shall be included in the blowout prevention program required in Section 2128(d)(1). (7) Marine Riser. The marine riser system and its component parts that are employed in drilling operations from mobile drilling rigs shall conform to the design, operation, inspection and maintenance specifications set forth in Sections 6B and 11 of the "API Recommended Practices for Blowout Prevention Equipment Systems, API RP 53, First Edition, February 1976, reissued February 1978," or subsequent revisions thereto that are approved by the Staff. (8) Auxiliary Equipment. (A) The following auxiliary equipment shall be provided and maintained as operationally ready at all times. Any equipment that may be subjected to well pressures shall have a working pressure rating at least equal to the rated working pressure of the blowout preventer stack in use. 1. A kelly cock shall be installed below the swivel and a full-opening lower kelly valve shall be installed below the kelly. The lower kelly valve shall have an outer diameter such that it may be run through the blowout preventers and the last casing string cemented in the well. A wrench to fit each valve shall be maintained at a conspicuous location readily accessible to the drilling crew. 2. A full-opening drill pipe safety valve shall be available on the rig floor at all times and shall be equipped to screw into any drill string member in use. This valve shall have an outer diameter such that it may be run through the blowout preventers and the last casing string cemented in the well. 3. An inside blowout preventer, drill pipe float valve, or drop-in check valve shall be available on the rig floor at all times for use in kick-control and stripping operations. The valve, sub, or profile nipple shall be equipped to screw into any drill string member in use. 4. A safety valve shall be readily available on the rig floor and shall be equipped to screw into the casing string that is being run into the well. (B) A subsea test tree shall be used in the blowout preventer stack while performing drill stem or production tests from mobile drilling rigs. (j) Pressure Testing, Operational Testing, Inspection and Maintenance of Blowout Prevention Equipment. (1) Pressure Testing of Blowout Prevention Equipment. (A) Ram-type blowout preventers and related control equipment used in surface and subsea installations shall be tested at the rated working pressure of the preventer stack, wellhead, or 70% of the internal yield pressure of the casing, whichever is the lesser. Annular-type preventers shall be tested at 70 percent of this pressure requirement. Both types of preventers and related control equipment shall be tested at low pressure, 200-300 psi. These tests shall be performed as follows: 1. When installed on the well. 2. After setting each casing string. 3. Before drilling into any known or suspected high pressure zone. 4. At least once a week while drilling. 5. Following repairs or replacement that necessitates breaking any pressure seal in the system. (B) In addition, the subsea blowout prevention system shall be stump-tested on the drilling rig to the applicable rated working pressure before the equipment is installed on the well. The test record shall include the opening and closing times and the hydraulic fluid volumes required for each function. (C) Diverters shall be tested to their rated working pressure when installed on the well. (D) The blowout preventer equipment pressure testing procedure shall be alternated between control panel stations and shall be conducted at staggered intervals in order to allow each drilling crew to perform the tests. On subsea installations alternate control pods may be used on successive test periods. (E) The kelly cock, lower kelly valve, drill pipe safety valve, and inside blowout preventer shall be tested at the same time and pressure as the ram-type blowout preventers. (F) The testing of all blowout preventer equipment shall be properly recorded in the driller's log. (2) Operational Testing of Blowout Prevention Equipment. (A) Ram-type and annular-type blowout preventers and diverters shall be actuated to test for proper functioning on each round trip of the drill pipe, but not more than once every 24 hours during normal drilling operations. Each choke manifold valve and choke, subsea kill and choke line valve, kelly cock, lower kelly valve, and drill pipe safety valve shall be operated daily. (B) During the operational tests the choke manifold and subsea kill and choke line valves shall be flushed with water to ensure that plugging does not occur. The diverter and vent lines shall be checked daily for plugging as a result of drill cuttings or other debris. (C) The actuation of preventers and other remotely controlled equipment shall be alternated between control panel stations and shall be conducted at staggered intervals to allow each drilling crew to operate the equipment. On subsea installations alternate control pods may be used on successive operational tests. (D) A closing unit pump capability test, and accumulator precharge-pressure and closing tests shall be conducted before testing the blowout preventer stack on a well. The tests shall be performed in accordance with the requirements set forth in Section 5A of the "API Recommended Practices for Blowout Prevention Equipment Systems, API RP 53, First Edition, February 1978," or subsequent revisions thereof that are approved by the Staff. (E) The emergency shut-in system for the subsea blowout preventer stack described in Section 2128(i)(2)F3. shall be tested when installed on a well and at least once every two weeks thereafter. In the test, the emergency shut-in system shall activate at least one blowout preventer function. (F) All operational tests shall be properly recorded in the driller's log. (3) Inspection and Maintenance of Blowout Prevention Equipment. All blowout prevention equipment systems shall be inspected and maintained in accordance with the manufacturer's recommended procedures. All systems shall be visually inspected at least once each day. Subsea blowout preventer and riser systems may be inspected by use of divers or television equipment. Any necessary equipment repair or replacement shall be accomplished without delay; however, full consideration shall be given to well safety before starting any work. (k) Supervision and Training. (1) The lessee shall provide on-site company supervision (company toolpusher) of drilling operations on a 24-hour basis. At least one member of the drilling crew or the toolpusher shall maintain rig-floor surveillance at all times, unless the well is secured with blowout preventers, bridge plugs, or cement plugs. (2) Except as provided below in Section 2128(k)(3), the lessee and drilling contractor personnel engaged in drilling operations on State oil and gas leases located on State tide and submerged lands shall be trained and qualified in well-control equipment, operations and techniques in accordance with the provisions of the USGS Outer Continental Shelf Standard "Training and Qualifications of Personnel in Well-Control Equipment and Techniques for Drilling on Offshore Locations," No. T 1 (GSS-OCS-T1), First Edition, December 1977, and subsequent revisions thereto that are approved by the Staff. Written certification shall be filed with the Staff on compliance with this provision before commencing drilling operations. (3) Additional requirements to be included in subsection 3.6 of document GSS-OCS-T1 aforesaid are: (A) A well control drill plan shall be prepared by the lessee for each well drilling proposal and shall be submitted for Staff approval along with the blowout prevention program that is required in Section 2128(d)(1). The plan shall also stipulate the total time allotted for the crew to complete each type of operational drill. (B) Well control drills shall be held for each crew on a daily basis until each crew demonstrates its ability to effect proper closure of the well within the time established by the well control drill plan. Thereafter, the drills may be held on a weekly basis for each crew as set forth in subsection 3.6 of document GSS-OCS-T1 aforesaid. (l) Hydrogen Sulfide. (1) When drilling operations are planned which will penetrate reservoirs known or expected to contain hydrogen sulfide (H 2 S), or in those areas where the presence of H 2 S is unknown, or upon encountering H 2 S, the preventive measures and the operating practices set forth in U.S.G.S. Outer Continental Shelf Standard, "Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment," No. 1 (GSS-OCS-1) Second Edition, June 1979, or subsequent revisions thereto that are approved by the Staff, shall be followed. (2) The lessee shall submit to the Staff for its approval, a hydrogen sulfide contingency plan for each well proposal as required in Section 2128(d)(2). (m) Mud Program. The characteristics, use, and testing of drilling mud properties, and the related procedures to be followed during drilling operations, shall be designed so as to prevent loss of well control. Adequate quantities of mud materials shall be maintained at the drill-site and shall be readily accessible for use in well control. (1) Mud Control (A) Before starting out of the hole with the drill pipe, the mud shall be circulated with the drill pipe just off bottom, until the mud is properly conditioned. Proper conditioning requires, at a minimum, circulation to the extent that the annulus volume is displaced to insure that the hole is clean and zonal pressures are being controlled by the mud column. When pulling the drill pipe, the annulus shall be filled with mud so that the mud level does not drop below a calculated depth of 100 feet. The number of stands of drill pipe and drill collars that may be pulled before stopping to fill the hole and their equivalent mud displacement volumes shall be calculated and posted at the driller's station. A mechanical, volumetric, or electronic device shall be utilized for accurate measurement of the amount of mud used to fill the hole. (B) A degasser and mud/gas separator shall be employed on all wells unless not required by field rules. This equipment shall be installed on the mud system prior to commencement of drilling operations, and shall be maintained for use throughout the drilling and completion of the well. (2) Mud Quantities. (A) The lessee shall include in the drilling mud program a tabulation by well depths of the minimum quantities of mud material to be maintained at the drill-site. The minimum quantities of mud material required shall be at least equal to the capacity of the downhole and active surface mud system. Sufficient weight material shall be maintained in order to condition the reserve mud to the maximum density programmed. (B) A daily inventory of the mud materials shall be recorded and maintained at the drill-site. Drilling operations shall be suspended whenever the required minimum quantities of mud materials are not maintained at the drill-site. (3) Mud-Testing Equipment. (A) Mud-testing equipment shall be maintained on the drilling rig at all times, and mud tests that are consistent with good operating practice shall be performed at least once each 8-hour period while drilling, or more frequently if conditions warrant. Continuous mud-logging equipment shall be employed on all exploratory drilling. (B) The following mud-system monitoring equipment shall be installed (with indicators located at the driller's station) and used throughout the period of drilling, after setting and cementing the conductor casing: 1. Recording mud pit level indicator (volume totalizing type) to determine mud pit volume gains and losses. This indicator shall include a visual audio warning device. 2. Mud-volume measuring device for accurately determining mud volumes that are required to fill the hole on trips. 3. Mud-return or full-hole indicator to determine when returns have been obtained, when returns occur unintentionally, and to determine that returns are approximately equal to the pump discharge rate. 4. Gas-detection equipment to monitor the drilling mud returns. (n) Drilling Practices. (1) The volume of mud required to fill the hole shall be carefully observed, and if at any time there is an indication of swabbing or influx of formation fluids, the necessary safety device(s) shall be installed on the drill pipe. The drill pipe shall be run to bottom and the mud properly conditioned to stabilize the well. The mud shall not be circulated and conditioned except on or near bottom, unless well conditions prevent the running of pipe to bottom. (2) The lessee shall post at the driller's station, for each casing string, the maximum pressure that is allowed to build up against the blowout preventers before controlling the pressure by bleeding through the choke. (3) The rate of pulling or running drill pipe shall be controlled to ensure that the hole is not being swabbed or that formations exposed to the well bore will not be broken down. Special precautions shall be observed to prevent swabbing when full-hole tools are employed. (4) All formation fluid that is produced during drlllstem testing shall be directed to the producing or test facilities, and that remaining in the drill string after drillstem testing shall be reverse-circulated from the drill pipe. The mud shall be adequately conditioned prior to pulling the drillstem test tools. (o) Drilling Inspection. Staff may perform inspections of drilling operations on each rig to verify that the operations are being conducted in accordance with these regulations and the approved well-drilling program. (p) Redrilling and Deepening. Drilling operations to redrill or deepen a well shall be conducted in accordance with the foregoing drilling regulations and the additional regulations listed below. (1) A well shall not be redrilled or deepened unless it is determined that the casing exposed in the well will provide adequate strength for the proposed drilling and for subsequent production operations. Where well conditions permit, a casing inspection survey, indicating remaining wall thickness and internal diameter, shall be run to determine the condition of the casing and whether or not it is of adequate strength. (2) If it is not possible to run a casing inspection survey, the casing shall be pressure tested to at 70% of minimum internal yield pressure or 1.25 times the anticipated surface pressure that it might be subjected to either during the drilling operations or subsequent production operations (including injection), or to the amount stipulated in Section 2128(g), whichever is greater. (3) If the casing inspection survey indicates that the casing strength is adequate, then the casing also shall be pressure tested as stipulated above in Section 2128(p)(2). (4) In the event it is determined that the condition of the casing is inadequate, drilling shall not be initiated until corrective measures approved by the Staff are taken by the lessee. This shall include testing of the casing to the maximum pressure stipulated above in Section 2128(p)(2). (5) A copy of the casing inspection survey shall be filed immediately with the Staff. (6) Prior to redrilling or deepening a well the lessee shall demonstrate to the Staff that the casing is adequately cemented above the point of new drilling. In the event it is thereby determined that the casing is not adequately cemented, the lessee shall properly recement the casing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the Staff. (7) Prior to redrilling a well, all oil, gas and water zones exposed in the well below the kickoff depth shall be properly abandoned in accordance with the plugging and abandonment regulations in Section 2128(q). (8) If a well is to be redrilled or deepened to a zone(s) having a pressure significantly higher or lower than that of the shallower producing zone(s), which drilling might cause lost circulation and thereby endanger the well, the shallower producing zones shall be squeeze cemented or cased and cemented, prior to penetrating the lower zone(s). (q) Plugging and Abandonment of Wells. Before any work is commenced to abandon any well, the lessee shall file with the Staff a written notice of intention to abandon the well. The notice shall show the condition of the well and proposed method of abandonment. Written approval shall be obtained from the Staff prior to commencement of abandonment operations. In the case of a newly drilled dry hole or where other approved operations on a well are in progress, the lessee may commence plugging operations by securing oral approval from the Staff as to the abandonment procedure and the time that plugging operations are to begin. Prior to requesting oral approval, the lessee shall furnish the Staff a description of the mechanical condition of the well, an electric log, a description of all oil and gas shows and tests, and any other well data necessary for review of the abandonment procedure. The lessee shall immediately file a written notice with the Staff of its intention to abandon the well in confirmation of the approved abandonment procedure. The lessee shall plug and abandon all wells in accordance with the following minimum requirements: (1) Permanent Abandonment. (A) Isolation of Zones in Open Hole. In open hole portion of the well, cement plugs shall be spaced to extend from 100 feet below to 100 feet above each oil or gas bearing zone or zone that is productive of hydrocarbons elsewhere in a field, and a cement plug at least 200 feet long shall be placed across the intrazone freshwater-saltwater interface, so as to isolate fluids in the strata in which they are found and to prevent them from migrating into other strata. (B) Isolation of Open Hole from Casing. Where there is open hole below the casing, a cement plug shall be placed in the deepest casing string by 1. or 2. below, or, in the event lost circulation conditions exist or are anticipated, the plug may be placed in accordance with 3. below: 1. A cement plug placed by displacement method so as to extend from 100 feet below to 100 feet above the casing shoe. 2. A cement retainer with effective back-pressure control set not less than 50 feet, nor more than 100 feet, above the casing shoe with a cement plug calculated to extend from 100 feet below the casing shoe to 50 feet above the retainer. 3. A permanent type bridge plug set within 150 feet above the casing shoe with 50 feet of cement placed on top of the bridge plug. This plug shall be tested prior to placing subsequent plugs. (C) Plugging or Isolating Perforated Intervals. A cement plug shall be placed opposite all open perforations not previously squeezed with cement. This plug shall extend from 100 feet below to 100 feet above the perforated interval. (D) Isolation of Zones Behind Uncemented Casing. All oil, gas or fresh water-bearing zones located behind casing in the uncemented portion of the hole shall be squeeze cemented so as to isolate fluids in the strata in which they occur. (E) Isolating Zones Behind Cemented Casing. Inside cemented casing, a 100 foot cement plug shall be placed above each oil or gas zone and above the shoe of the intermediate or second surface casing. A cement plug at least 200 feet long also shall be placed across the intrazone freshwater-saltwater interface. (F) Junk in Hole or Collapsed Casing. In the event that junk cannot be removed from the hole and the hole below the junk is not properly plugged, cement plugs shall be placed as follows: 1. Sufficient cement shall be squeezed through the junk to isolate the lower oil, gas, or fresh water zones and 100 feet of cement placed on top of the junk. 2. If the top of the junk is opposite uncemented casing, the casing annulus immediately above the junk shall be cemented with sufficient cement to insure isolation of the lower zones. (G) Plugging of Casing Stubs. If casing is cut and recovered, a cement plug shall be placed so as to extend from 100 feet within the casing stub to 100 feet above the top of the casing stub. 1. If the stub extends up into the next larger casing string, then a retainer may be set 50 feet above the top of the stub and cement placed 150 feet below and 50 feet above the retainer. If the foregoing methods cannot be used, a bridge plug shall be set 50 feet above the top of the stub and capped with 50 feet of cement. 2. If the stub is below the next larger string, plugging of the open hole interval above the stub shall be accomplished in accordance with Section 2128(q)(1)(A), and, in addition, a cement plug shall be placed so as to extend from 100 feet below to 100 feet above the casing shoe that is exposed above the stub in accordance with Section 2128(q)(1)(B). (H) Plugging of Annular Space. No casing annular space that extends to the ocean floor shall be left open to drilled hole below. If this condition exists, 200 feet of the annulus immediately above the shoe of the preceding casing string shall be plugged with cement. If an uncemented inner casing string is cut and recovered to accomplish this requirement, the casing stub shall be plugged in accordance with Section 2128(q)(1)(G). (I) Surface Plug Requirement. A cement plug of at least 100 feet, with the top of the plug not more than 150 feet or less than 50 feet below the ocean floor, shall be placed in the well. Prior to the placement of the surface plug all inside casing strings which are uncemented at the surface plugging depth shall be cut and recovered. Casing cutting methods shall be employed that will not damage the well casing so as to prevent reentry of the well. (J) Testing of Plugs. The location and hardness of all cement plugs shall be tested by placement of drill string weight (10,000 pounds minimum) on the plug, and by application of pump circulation. A cement plug placed on top of a previously tested bridge plug or retainer need not be tested. (K) Mud. Each of the respective intervals of the hole between the various plugs shall be filled with mud fluid of sufficient density to exert hydrostatic pressure exceeding the greatest formation pressure encountered while drilling such intervals. (L) Clearance of Location. All casing and conductor shall be severed and removed from not more than 5 feet below the ocean floor, unless other plans are approved by the Staff. The ocean floor shall be cleared of any other obstructions. A method shall be employed to sever or cut the casing that will not damage the well casing so as to prevent reentry of the well. (M) Record of Abandonment. All plugging and abandonment operations shall be recorded on the driller's log. (2) Temporary Abandonment (A) Any drilling well which is to be temporarily abandoned shall be mudded and cemented as required for permanent abandonment except that the requirements of Section 2128(q)(1), (E), (H), (I), and (L) shall thereupon be deferred. When casing extends above the ocean floor, a mechanical bridge plug (retrievable or permanent) shall be set in the casing between 15 and 200 feet below the ocean floor. (B) The use of a bridge plug to temporarily exclude an interval when recompleting a well is not permitted, unless the Staff approves in advance adequate plans for its future recovery and proper abandonment of the zone. (r) Daily Drilling Reports. The lessee shall provide daily telephone reports of drilling activities as required by the Staff. (s) Log and History of Well. (1) The lessee shall keep a careful and accurate log, core record, and history of the drilling of each well. (2) The lessee shall provide field copies of electric logs and other surveys as necessary for the Staff to expeditiously approve subsequent well operations. (3) Within 60 days following the completion, abandonment, or the suspension of operations of any well, the lessee shall file with the Staff copies of all logs, including electric logs, surveys, drilling records, well histories, core records and related information as measured and recorded for the wells drilled by the lessee into the leased lands. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2129. General Provisions. (a) This Article 3.3 pertains to oil and gas production operations on State oil and gas leases located on State tide and submerged lands under the jurisdiction of the State Lands Commission, and is applicable to operations conducted from mobile rigs, fixed offshore structures and upland locations serving these leases. (b) In addition to complying with Division 6 of the California Public Resources Code and with Title 2, Division 3, Chapter 1 of the California Administrative Code, the lessee shall comply with all applicable laws, rules and regulations of the United States and of the State of California and with any respective political subdivision thereof, including, but not limited to, the Division of Oil and Gas, the Department of Fish and Game, the Division of Industrial Safety, the State Water Resources Control Board, and the Regional Water Quality Control Boards, the California Coastal Commission, and any respective successor thereto. (c) All production operations on State oil and gas leases shall be carried on in a proper and workmanlike manner in accordance with accepted good oilfield practice. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d). Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2130. Definitions. For the purposes of this Article 3.3 the following definitions shall apply: (a) "Production operations" include but are not limited to well completion or recompletion, remedial and well maintenance work, and production facility and pipeline operation. (b) "Staff" shall mean the Executive Officer or other duly authorized member of the Staff of the State Lands Commission. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2131. Administration. (a) The Staff shall administer this Article 3.3 and shall thereby provide for the prevention and elimination of any contamination or pollution of the ocean and tidelands, for the prevention of waste, for the conservation of natural resources, and for the protection of human health, safety and property. (b) The Commission has designed these regulations in as great detail as possible. However, the Commission recognizes that situations may arise which are not specifically covered by this Article 3.3 and that emergency situations may arise which will require immediate decisions by the Staff. In such situations, the Executive Officer or his designee may authorize appropriate procedures to be followed. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2132. Production Regulations. (a) Well Completion. (1) A well-completion program for each well, whether surface or subsea completed, shall be submitted as a part of the drilling program (Refer to Article 3.2, Section 2128(d)(1)) for approval by the Staff. In the event a completion program cannot be provided with the well-drilling program, the lessee shall submit a completion program for Staff approval prior to commencement of the completion work. (2) The program shall include detailed information and working drawings as appropriate, of the wellhead assembly, surface and downhole production control equipment, and safety system. (3) Proposals for subsea well completions shall be reviewed and approved by the Staff on an individual well basis. (4) Wellhead Equipment. (A) The wellhead equipment associated with each casing string and tubing string and all valves and fittings which may be subjected to wellbore pressure under any condition, shall have a rated working pressure exceeding the maximum anticipated surface pressure to which they may be subjected. (B) All wellhead equipment, valves and flow lines installed on offshore wells shall be flange or other nonthread connected. All wellhead equipment, valves and flow lines on upland wells that are designed for a working pressure of 2,000 psi or greater shall be flange or other nonthread connected. (C) Valves shall be installed to permit fluids to be pumped into each casing string. Two master valves shall be installed on any well capable of flowing. (D) All wellhead equipment shall be tested by a fluid pressure equal to its rated working pressure after installation on a well. (E) All wellhead components, valves and flow lines in service upon adoption of these regulations are exempted from the requirements in Section 2132(a) (4)(B); except that any modification to existing equipment or piping, unless otherwise approved in writing by the Staff shall be flange or other nonthread connected. (F) All wellhead equipment, valves and flow lines on any well to be redrilled, recompleted or converted to fluid injection shall comply with the provisions of Sections 2132(a) (4)(A)-(E) above. (G) All pressure test results shall be recorded on the daily well work report. (5) Blowout Preventer Removal. If a well is capable of flowing oil or gas, a back-pressure valve or suitable tubing plug shall be installed in the tubing string(s) to seal the bore of the tubing while removing the blowout preventer stack and installing the Christmas tree. (6) Sealing of Casing -Tubing Annulus. All wells capable of flowing oil or gas shall be equipped with a tubing packer(s) to effectively seal the casing-tubing annulus. All production packers shall be properly tested upon installation. (7) Perforation and Wireline Operations Under Pressure. All perforation and wireline operations conducted under pressure shall be performed through a lubricator installed on appropriate wireline blowout-prevention equipment. The pressure rating of the lubricator shall be equal to or greater than the maximum possible surface shut-in pressure of the well. The well shall not be left unattended unless all wellhead flow valves and the wireline blowout preventer are closed in or unless the tools are pulled up into the lubricator and the master valve closed. (8) Subsurface Safety Valves. (A) All wells capable of flowing oil or gas shall be equipped with a surface-controlled subsurface safety valve installed in the tubing string(s) at a depth of 100 feet or more below the ocean floor, or ground level for upland wells. Such valve shall be installed in artificial lift wells, unless proof is provided to the Staff that such wells are incapable of flowing. Wells which are presently equipped with direct-controlled subsurface safety valves shall have surface-controlled subsurface safety valves installed the first time the tubing is pulled. The control system for the surface-controlled subsurface safety valves shall be connected to the facility integrated safety-control system, where applicable. (B) Subsurface safety valves at the time of installation shall conform to the "American Petroleum Institute (API) Specification for Subsurface Safety Valves," API Spec 14 A, Third Edition, November 1978, or subsequent revisions thereto that are approved by the Staff. (C) Subsurface safety valves shall be installed, adjusted and maintained in accordance with the "American Petroleum Institute (API) Recommended Practice for Design, Installation and Operation of Subsurface Safety Valve Systems," API RP 14B, First Edition, October 1973, or subsequent revisions thereto that are approved by the Staff. (D) Each subsurface safety valve installed in a well shall be tested by the lessee for proper operation each month. The Staff may adjust the testing frequency based upon the performance record of the valve. Permission to increase the testing frequency shall require substantiation by the lessee and written approval by the Staff. The tests may be witnessed and approved by the Staff. If the valve does not operate properly, it shall be repaired or replaced and again tested for proper operation. (E) When a subsurface safety valve is removed from a well for repair or replacement it shall be replaced immediately or a tubing plug shall be installed before the well is left unattended. (F) The well history and any subsequent report of workover shall state the type and depth of the subsurface safety valve or tubing plug installed in the well. (G) Records shall be maintained at the facility or at the nearest onshore office of the lessee. The records shall contain a description and show the present status and past history of each subsurface safety valve or tubing plug, including dates and details of any inspection, testing, repairing, and reinstallation or replacement. The lessee shall submit a copy of such records semiannually to the Staff. (9) Wellhead Surface Safety Valves. (A) All wells capable of flowing oil or gas and all artificial lift wells capable of afterflow when the source of power is shut off shall be equipped with an automatic, fail-close, wellhead surface safety valve. High-low pressure sensors shall be located in the flowline close to the wellhead and shall be set to cause shut-in of the valve in the event of abnormally high or low flowline pressures. In addition, each valve shall be connected to the integrated safety control system on the facility. (B) Wellhead surface safety valves shall be employed in the safety control system on the facility and shall be tested in accordance with the provisions of the "American Petroleum Institute (API) Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface-Safety Systems on Offshore Production Platforms," API RP 14C, Second Edition, January 1978, or subsequent revisions thereto that are approved by the Staff. (C) Wellhead surface safety valves at the time of installation shall conform to the "American Petroleum Institute (API) Specification for Wellhead Surface Safety Valves for Offshore Service," API Spec. 14D, Sec ond Edition, November 1977, as amended by supplement 2, November 1978, or subsequent revisions thereto that are approved by the Staff. (D) All wellhead surface safety valves shall be tested by the lessee for operation and holding pressure monthly. If the valve fails to test properly, it shall be repaired or replaced and again tested for proper operation. Pressure sensors shall be operated and tested by the lessee for proper pressure settings monthly. The monthly tests may be witnessed and approved by the Staff. Results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee. (10) Wells on Artificial Lift. (A) Artificial lift wells not equipped with a wellhead surface safety valve shall have safety devices installed to shut off the source of power in the event of abnormally high or low flowline pressures. The source of power shall be controllable by the integrated safety system. (B) The safety devices shall be actuated and tested monthly by the lessee. If the device fails to test properly, it shall be repaired or replaced and again tested for proper operation. The monthly tests may be witnessed and approved by the Staff. The results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee. (11) Production Headers. (A) All well flowlines shall be equipped with a check valve located downstream at the production header. All check and header valves, as well as any piping that might be subjected to wellhead pressure, shall be of sufficient strength to withstand any possible shut-in wellhead pressure. (B) The flowline check valve shall be tested for holding pressure monthly by the lessee. If the valve fails to test properly, it shall be repaired or replaced and again tested for proper operation. The monthly tests may be witnessed and approved by the Staff. The results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee. (b) Remedial and Well-Maintenance Work. (1) The lessee shall obtain written approval from the Staff prior to performing remedial work on any well that involves the alteration of its casing or that will result in changing its producing interval. Such work includes, but is not necessarily limited to, casing and liner repair or replacement, squeeze cementing, plugging, perforating, and the installation or removal of bridge plugs and packers. (A) Each proposal for remedial work shall be accompanied by a statement reflecting the reason for the work and a detailed work and blowout prevention equipment program. The work program also shall include the static formation pore pressure of all zones exposed or to be exposed in the well, the type and densities of circulating fluids to be used, and any other data that is pertinent to well control. (2) The lessee shall provide written notification to the Staff of its intention to perform nonroutine well-maintenance work on any well. Such work may include, but may not be limited to, formation fracturing, acidization or solvent stimulation, snubbing operations, wireline work resulting in a change of producing interval, any work on a subsea completed well that involves entry of the well, and any other well work that involves a higher than normal degree of risk. (A) The written notification shall include a description of the work to be performed, the type of blowout prevention equipment and safety equipment to be used, and the anticipated date that the work will commence. (3) Routine well-maintenance work such as pump changes and wireline work not resulting in a change in the producing interval shall not require advance Staff notification or approval. However, routine well-maintenance work shall be recorded on the lessee's daily operations report and copies of the report shall be provided to the Staff at its request. (4) Minimum blowout prevention equipment requirements for remedial and well-maintenance work shall be in accordance with the Division of Oil and Gas Manual No. M07 entitled "Oil and Gas Well Blowout Prevention in California," Second Edition, 1978, or subsequent revisions thereof that are approved by the Staff. (5) On wells capable of flowing oil or gas, the bore of the tubing string(s) shall be sealed with a back-pressure valve, safety valve or suitable tubing plug during the removal or installation of the Christmas tree. (6) All perforating and wireline operations conducted under pressure shall be performed through a lubricator installed on appropriate wireline-blowout-prevention equipment. The pressure rating of the lubricator shall be equal to or greater than the maximum possible surface shut-in pressure of the well. The well shall not be left unattended unless all wellhead flow valves and the wireline blowout preventer are closed in, or tools are pulled up into the lubricator and the master valve closed. (7) Within 60 days after the completion of remedial and nonroutine well-maintenance work, the lessee shall file a history with the Staff that describes the work performed and final condition of the well. (c) Supervision and Training. (1) The lessee shall provide full-time onsite company supervision of well completion and other production well work which is performed on any well that may be capable of flowing oil, gas or water. This also includes wireline perforating and any well work performed under pressure. (2) At least one member of the production well work crew or the production supervisor shall maintain surveillance of the well at all times, unless the well is secured with blowout preventers, bridge plugs, tubing plugs or appropriate valving. (3) Lessee and contractor supervisory personnel and crew chiefs who are engaged in production well work operations on State leases shall be trained and qualified in well-control equipment, operations and techniques. These persons shall successfully complete a basic well-control course every four years and take a refresher course in well-control each year. The basic and refresher course curriculums shall be submitted to and be approved by the Staff. Written certification shall be filed with the Staff on compliance with these training requirements. (4) A well control drill plan shall be prepared by the lessee for each well production facility for the training of crews engaged in production well work. The plan shall be submitted to and approved by the Staff. (5) Well control drills shall be held for each crew on a daily basis until each crew member demonstrates the ability to satisfactorily perform his well control assignment. Thereafter, drills shall be held at least once a week for each crew. All drills shall be recorded on the daily well work report. (d) Anomalous Casing Annulus Pressure. (1) The casing annulus pressure(s) on each well shall be checked monthly and a record of the pressure readings shall be maintained at the facility or at the nearest onshore office of the lessee if the facility is notmanned. The lessee shall give immediate written notification to the Staff of the occurrence of an anomalous pressure between casing strings in any well. (2) The lessee shall investigate to determine the source of any anomalous pressure and, if appropriate, shall seal off the source in a manner approved by the Staff. (3) Any attempt by the lessee to reduce the surface pressure by producing the fluid from the casing annulus, must include a monthly production test of each annulus. (e) Subsurface Injection Projects. (1) All subsurface injection projects proposed on State leases, whether injection is for the purpose of reservoir stimulation or waste disposal, shall require prior approval of the Staff. A lessee requesting approval of an injection project shall provide the Staff with all pertinent geological, engineering, and well data that is requested for the evaluation of the project. The lessee shall also file with the Staff copies of all relevant information furnished to the Division of Oil and Gas. (2) Recompletion or conversion of a well to fluid injection shall require the prior approval of the Staff. (3) Within 90 days after the start of injection and annually thereafter, the lessee shall file with the Staff information to confirm that injection is limited to the objective zone. This information shall include, but shall not be limited to, dynamic injection profile surveys, daily injection vol ume and pressure data . In the event that injection is determined not to be restricted to the objective zone, then the lessee shall take corrective action as soon as possible. The well-work program shall be approved in writing by the Staff prior to commencement of the work. (f) Waste Disposal. (1) All waste discharged into the ocean from production operations shall be treated so as to comply with the discharge requirements of the appropriate Regional Water Quality Control Board. Oil, tar, or other residuary products of oil, or refuse of any kind from any well or facility, such as circulating fluids that contain substances which are toxic to fish life, and chemicals shall be disposed of on shore in a dumping area in conformance with local regulatory requirements. The lessee shall inform the Staff of the method of waste disposal and any changes that are required to comply with the discharge requirements of the Regional Water Quality Control Board. Refer to Article 3.4, Section 2138, for requirements concerning the disposal of drill cuttings and drilling muds. (g) Production Facility Safety Equipment and Procedures. Unless otherwise provided for in this Section 2132(g), safety equipment, systems and procedures on offshore production facilities shall be based upon the "American Petroleum Institute (API) Recommend Practice for Analysis, Design, Installation and Testing of Basic Surface Safety Systems on Offshore Production Platforms," API RP 14C, Second Edition, January 1978, or subsequent revisions thereto that are approved by the Staff. (1) Integrated Safety-Control System. Each offshore production facility shall be equipped with an approved integrated safety-control system that will cause shut-in of all wells and shut-down of the complete production facility in the event of fire, pipeline failure or other catastrophe. A complete testing of the safety-control system to the satisfaction of the Staff shall be conducted by the lessee every six months and may be witnessed and approved by the Staff. The integrated safety-control system shall be actuated by the following devices which shall be installed and maintained in an operating condition at all times. The devices shall be tested monthly by the lessee, which tests shall be witnessed and approved by the Staff. The lessee shall maintain records at the production facility or at its nearest onshore office showing the present status and past history of each such device, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement. (A) Emergency manually operated controls to actuate the integrated safety system shall be located on the helicopter deck and on all exit stairway landings leading to the helicopter deck and to all boat landings. (B) All oil and gas pipelines receiving production from offshore production facilities shall be equipped with high-low-pressure shut-in sensors. The low-pressure sensor shall be set so as to actuate the integrated safety-control system in the event of pipeline failure. The pressure settings shall be determined by pipeline operating characteristics, and shall be set as close as practicable to the normal operating pressure of the pipeline. (C) All pneumatic, hydraulic, and other shut-in control lines shall be equipped with fusible material at strategic points. Fire-detector systems shall be equipped with devices to actuate the integrated safety-control system. (D) The automatic gas-detector system shall be so equipped as to actuate the integrated safety-control system at a point not higher than 80% of the lower explosive limit. (2) Safety Devices on Vessels and Tanks. All production vessels and tanks shall be equipped with safety devices as listed below that will cause shut-in of the wells connected to the vessel or tank. The devices shall be tested monthly by the lessee, which tests shall be witnessed and approved by the Staff. The lessee shall maintain records on the production facility showing the present status and past history of each such device, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement. (A) All separators shall be equipped with high-low-pressure shut-in sensors and high-low-level shut-in controls. (B) All pressure surge tanks shall be equipped with a high- and low-pressure shut-in sensor and high-low-level shut-in controls. (C) Atmospheric surge tanks shall be equipped with a high-level shut-in sensor. (D) All other hydrocarbon-handling pressure vessels shall be equipped with high-low-pressure shut-in sensors and high-level shut-in controls unless they are determined by the Staff to be otherwise protected. High-pressure shut-in sensors shall be set no higher than 5% below the rated or designed working pressure, and low-pressure shut-in sensors shall be set no lower than 10% below the lowest pressure in the operating pressure range on all vessels with a rated or designed working pressure of more than 400 psi. On lower pressure vessels, the above percentages shall be used as guidelines for sensor settings considering pressure and operating conditions involved, except that sensor settings shall not be within 5 psi of the rated or designed working pressure or the lowest pressure in the operating pressure range. All pressure-operated sensors shall be equipped to permit testing with an external pressure source. (3) Pressure Relief Valves. (A) All pressure vessels shall be equipped with relief valves connected into a gas vent line. All gas vent line systems shall be equipped with a scrubber or similar separation equipment. (B) A relief valve shall be set no higher than the safe working pressure of the vessel to which it is attached. (C) Pilot-operated pressure-relief valves shall be equipped to permit testing with an external pressure source. Spring-loaded pressure relief valves shall either be bench-tested or equipped to permit testing with an external pressure source. (D) Relief valves shall be tested by the lessee every six months. The lessee shall maintain records on the production facility showing the present status and past history of each relief valve, including dates and details of inspection, testing, repairing, adjustment and reinstallation or replacement. (4) Firefighting System. A firefighting system shall be installed and maintained in operating condition in accordance with the applicable standards of the National Fire Protection Association. (A) A fixed automatic water spray system or other system approved by the Staff shall be installed in all wellhead areas and in areas where production handling equipment is located. (B) A firewater system of rigid pipe with fire-hose stations shall be installed on all levels of the facility. (C) A system employing chemicals or chemical additives may be used in appropriate areas in lieu of or in addition to a firewater system to provide more effective fire protection and control. (D) An auxiliary connection to the firewater piping shall be installed at a remote location to supply the firefighting system in case of need. (E) The firefighting system shall be equipped with reserve water pumps to provide for the operating of the system during routine pump maintenance work and in the event of pump failure. The firewater pumps shall be test-operated weekly and the automatic water spray systems shall be test-operated monthly by the lessee. Testing methods other than the use of water shall be approved by the Staff. Monthly tests of the firewater pumps and of the automatic water spray systems may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office. (F) Portable fire extinguishers shall be located in the living quarters and in other strategic areas. A record showing the date when fire extinguishers were last inspected, tested, or recharged shall be maintained on the production facility. (G) A diagram of the firefighting system showing the location of all equipment shall be posted in a prominent place on the production facility. (H) Fire drills shall be conducted weekly by the supervisor in charge of the production facility. A record showing the date that fire drills were conducted shall be maintained on the production facility for at least one year. (5) Combustible Gas Detector and Alarm System. An automatic hydrocarbon/combustible gas detector and alarm system shall be installed and maintained, on each offshore production facility, in accordance with the following: (A) Gas-detection systems shall be installed in all areas containing gas-handling facilities or equipment and in enclosed areas which are classified as hazardous areas as defined in the California Administrative Code, Title 24, Part 3. (B) All gas-detection systems shall be capable of continuously monitoring for the presence of combustible gas in the areas in which the detection devices are located. (C) The central control shall be capable of giving an audible alarm at a point not higher that 60 percent of the lower explosive limit. (D) The central control shall automatically activate the shut-in sequences of the integrated safety control system and emergency equipment at a point not higher than 80 percent of the lower explosive limit. (E) A diagram of the gas-detection systems showing the location of all gas-detection points shall be posted in a prominent place on the production facility. (F) The gas detection systems shall be tested monthly by the lessee, which tests may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office. (6) Hydrogen Sulfide Gas Detection and Precaution. Any offshore production facility that handles production known to contain hydrogen sulfide (H 2 S) gas shall be equipped and maintained in accordance with following requirements to provide for the safety of personnel: (A) Hydrogen Sulfide Gas Detection and Alarm System. 1. A separate automatic hydrogen sulfide (H 2 S) gas detector and alarm system. This equipment shall be capable of sensing a minimum of five parts per million H 2 S in air, with sensing points located at all enclosed and hazardous areas where gas handling facilities are located, as well as any living quarters and other areas where H 2 S might accumulate in hazardous quantities. The H 2 S detection devices shall activate audible and visible alarms when the concentration of H 2 S reaches 20 parts per million in air. 2. H 2 S detector ampules or other approved devices shall be available for use by all working personnel. After H 2 S has been initially detected by any device, frequent inspections of all area of poor ventilation shall be made with a portable H 2 S-detector instrument. (B) Contingency Plan. A contingency plan shall be developed for each production facility that handles production known to contain hydrogen sulfide (H 2 S). The plan shall include the following: 1. General information and physiological responses to H 2 S and SO 2 exposure. 2. Safety procedures, equipment, training, and smoking rules. 3. Procedures for normal operating conditions and for H 2 S emergency conditions. 4. Responsibilities and duties of personnel for the emergency operating condition. 5. Designation of briefing areas as locations for assembly of personnel during an emergency condition. At least two briefing areas shall be established on each facility. Of these two areas, the one upwind at any given time is the safe briefing area. 6. Evacuation plan. 7. Agencies to be notified in case of an emergency. 8. A list of medical personnel and facilities, including addresses and telephone numbers. (C) Personnel Training Program. 1. To promote efficient safety procedures, an on-site H 2 S safety program, which includes a monthly drill and training session, shall be established. Records of attendance shall be maintained on the production facility. 2. Supervisory personnel shall have completed a recognized basic first-aid course and shall be responsible for training of work crews and facility operators. All personnel in the working crew shall have been indoctrinated in basic first-aid procedures applicable to victims of H 2 S exposure. During on-site training sessions and drills, emphasis shall be placed upon rescue and first aid for H 2 S victims. 3. Each production facility shall have the following equipment, and the facility operator and each crew member shall be thoroughly familiar with the location and use of these items: - A first-aid kit sized for the normal working number of personnel. - Resuscitators, complete with face masks, oxygen bottles, and spare oxygen bottles. - A Strokes litter or equivalent. 4. All personnel, whether regularly assigned, contracted, or employed on an unscheduled basis, shall be informed as to the hazards of H 2 S and SO 2. They shall also be instructed in the proper use of personnel safety equipment which they may be required to use, informed of H 2 S detectors and alarms, ventilation equipment, prevailing winds, briefing areas, warning systems, and evacuation procedures. (D) Personnel Protective Equipment. 1. All personnel on a production facility or aboard marine vessels serving the production facility shall be equipped with proper personnel protective-breathing apparatus. The protective-breathing apparatus used in an H 2 S environment shall conform to all applicable Occupational Safety and Health Administration regulations as set forth in the Code of Federal Register 29 CFR 1910.134 and American National Standards Institute standards. Optional equipment, such as nose cups and spectacle kits, shall be available for use as needed. 2. A system of breathing-air manifolds, hoses, and masks shall be provided in the briefing areas. A cascade air-bottle system shall be provided to refill individual protective-breathing-apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere. All breathing-air bottles shall be labeled as containing breathing-quality air fit for human usage. The compressor and compressed air system shall comply with 29 CFR 1910.134 (OSHA). 3. The storage locations of protective-breathing apparatus shall be such that they are quickly and easily available to all personnel. Storage locations shall include the following: - Facility operator's office. - Each working deck. - Crew quarters. - Equipment storage room. - Designated briefing areas. - Heliport. 4. Workboats attendant to facility operations shall be equipped with a protective-breathing apparatus for all workboat crew members. Additional protective-breathing apparatus shall be available for evacuees. Whenever possible, boats shall be stationed upwind. 5. Helicopters attendant to facility operations shall be equipped with a protective-breathing apparatus for the pilot. 6. The following additional personnel safety equipment shall be available for use as needed: - Portable H 2 S detectors. - Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas. - Chalkboards and note pads at convenient locations for communication purposes. - Bull horns and flashing lights. - Resuscitators. (E) Visible Warning System. 1. Wind-direction equipment shall be installed at prominent locations to indicate to all personnel, on or in the immediate vicinity of the production facility, the wind direction at all times for determining safe upwind areas in the event that H 2 S or SO 2 is present in the atmosphere. 2. Operational danger signs shall be displayed from each side of the facility, and a number of rectangular red flags shall be hoisted in a manner visible to watercraft and aircraft. The signs shall have a minimum width of eight feet and a minimum height of four feet, and shall be painted a high-visibility yellow color with black lettering of a minimum of 12 inches in height, indicating: "DANGER -HYDROGEN SULFIDE -H 2 S" Each flag shall be of a minimum width of three feet and a minimum height of two feet. All signs and flags shall be illuminated under conditions of poor visibility and at night when in use. These signs shall indicate the following operational conditions and requirements: - When H 2 S is present, signs shall be displayed. - When H 2 S is determined to have reached or exceeded a level of 20 parts per million in environmental areas, protective equipment shall be worn by all personnel in those areas and red flags shall be hoisted. Nonworking personnel and nonessential personnel shall be removed to a safe location, or evacuated as appropriate. Radio communications shall be used to alert all known air-and-watercraft in the immediate vicinity of this condition. (F) Ventilation Equipment. All ventilation devices shall be explosion-proof when used in areas where H 2 S may accumulate. Movable ventilation devices shall be provided in work areas and be multidirectional and capable of dispersing H 2 S or SO 2 vapors away from working personnel. (G) Flare System. The flare system shall be designed to safely gather and burn H 2 S gas. Flare lines shall be located as far from the other facilities as feasible, in a manner to compensate for wind changes. The flare system shall be equipped with a pilot and an automatic igniter. Backup ignition for each flare shall be provided. (H) Drilling Operations. Any well drilling operation conducted from a production facility and which will penetrate reservoirs known or expected to contain hydrogen sulfide (H 2 S) shall follow whatever additional requirements as are set forth in USGS Outer Continental Shelf Standard "Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment," No. 1 (GSS-OCS) Second Edition, June 1979, or subsequent revisions thereto approved by the Staff. (I) Remedial and Well Maintenance Operations. Any well remedial or well maintenance operation conducted from a production facility, where the subject well has penetrated reservoirs known to contain hydrogen sulfide, shall follow whatever additional requirements, as may be applicable to that particular job, as are set forth in aforementioned USGS "Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment." (J) Notification of Regulatory Agencies. The following agencies shall be notified immediately if H 2 S has been determined to have reached or exceeded a level of 20 ppm in the environmental area: 1. State Lands Commission. 2. U. S. Coast Guard. (7) Electrical Equipment and Systems. (A) An auxiliary electrical power supply shall be installed to provide sufficient emergency power for all electrical equipment required to maintain safety of operation in the event the primary electrical power supply fails. The auxiliary electrical power-supply system shall be tested monthly by the lessee and may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office. (B) All electrical generators, motors, electric power, control, lighting systems shall be installed, protected, and maintained in accordance with the California Administrative Code, Title 24, Part 3. (8) Welding Practices and Procedures. The following requirements shall apply to all production facilities during any time in which drilling or producing operations are taking place. The term "welding and burning" is defined to include arc or acetylene welding and arc or acetylene cutting. (A) All welding and burning shall be minimized by fabrication ashore. (B) If possible, all welding and burning shall be done in an approved, properly functioning welding room. (C) If welding or burning is necessary outside the weldingroom it shall be conducted in accordance with welding procedures approved by the Staff, which shall include the following minimum requirements: 1. The lessee's supervisor in charge at the installation shall issue written authorization for the work after he has inspected the area in which the work is to be done. If both drilling and producing operations are taking place, the drilling supervisor and the production supervisor shall both sign this authorization. 2. During all welding and burning operations, a man designated as a "fire watch" shall operate a portable gas detector and shall have in his possession a portable fire extinguisher. In addition, a fire hose shall be laid out to the welding area and it shall remain pressurized to the nozzle during the entire period of welding and burning. He shall inspect the area with the gas detector prior to commencement of the welding or burning. He shall continuously monitor the area and shall cause the welding or burning to cease at any time that conditions become unsafe. 3. If welding or burning must be done on a vessel which has contained a flammable substance, all connections to the vessel shall be broken and displaced or slip blanked, and the vessel shall be thoroughly cleaned and rendered free of such flammable substance and tested for gas before the work begins. Prior to performing hot work on the outside of a vessel, the vessel shall be completely flooded with water. 4. If welding or burning must be done on in-service or connected-up piping that section of pipe shall be isolated by the installation of slip blanks or blind flanges, thoroughly purged and cleaned to render it free of any flammable substance, and tested for gas before the work begins. When welding or burning on an isolated, clean and gas-free piping section, one end must remain open. 5. If welding or burning must be done in confined spaces, the space shall be adequately vented and a continuous source of fresh air shall be supplied while work is in progress. If fresh air is supplied by blowers, they shall be so positioned that the intakes will not pick up exhausted gases, fumes, or vapors. 6. If any welding or burning is done on bulkheads, decks, or overheads, the adjacent, overlying or underlying spaces shall be examined to determine that it is safe for the work to proceed. If deemed advisable, a second "fire watch" shall be employed in the contiguous area. 7. If any welding or burning must be done on structural members, it shall be determined by a competent authority that such welding or burning does not endanger the integrity of the structure. (h) Pipeline Operations and Maintenance. All oil and gas pipelines on State tide and submerged lands shall be operated and maintained in accordance with the following minimum requirements: (1) General Requirements. (A) Each lessee shall establish and maintain current written procedures: 1. To insure the safe operation and maintenance of its pipeline system, in accordance with this Section 2132(h), during normal operations. 2. To be followed during abnormal operations and emergencies. (B) A lessee shall not operate or maintain its pipeline system at a level of safety lower than that required by Section 2132(h) and the procedures that the lessee is directed to establish under Section 2132(h)(1)(A) above. (C) Whenever a lessee discovers any conditions that present any immediate hazard to persons, property, or the environment, the lessee shall not operate the affected part of the system until the unsafe condition has been corrected. (2) Maximum Operating Pressures. (A) Except for surge pressures and other variations from normal operations, a lessee shall not operate a pipeline at a pressure which exceeds any of the following: 1. The internal design pressure of the pipe as determined in accordance with ANSI Code B31.4 for Liquid Petroleum Transportation Piping Systems and ANSI Code B31.8 for Gas Transmission and Distribution Piping Systems. 2. The design pressure of any other component of the pipeline. 3. Eighty percent of hydrostatic test pressure to which the pipeline has been hydrostatically tested. (B) A lessee shall not permit the pressure in a pipeline during surges or other variation from normal operations to exceed 110 percent of the maximum allowable operating pressure limit established under Section 2132 (h)(2)(A) above. The lessee shall provide adequate controls and protective equipment to control the pressure within this limit. (3) Communications. Each lessee shall have a communications system for the transmission of the information required for the safe operation of its pipeline system. (4) External Corrosion Control. All pipelines shall be cathodically protected to prevent external corrosion. The lessee shall conduct tests annually on all cathodically protected pipelines to assure an adequate level of protection. Cathodic protection rectifiers shall be inspected by a qualified electrical inspector every three months. The output of the rectifiers shall be checked daily. The lessee shall maintain records on the production facility showing the daily output readings and the dates, details of inspection, and repairs to each rectifier. (5) Internal Corrosion Control. Where corrosion inhibitors are necessary to mitigate internal corrosion, they shall be used in sufficient quantities to protect the entire pipeline. The lessee shall use coupons or other monitoring equipment to determine the effectiveness of the inhibitors. The lessee shall, at intervals not exceeding six months, examine coupons or other corrosion-monitoring equipment to assure effectiveness of any inhibitors used. (6) Pipeline Inspections. (A) All unburied oil and gas pipelines shall be visually inspected annually by the lessee for damage, evidence of corrosion, and conditions that may be hazardous to the pipelines. (B) Where mechanically possible, all oil and gas pipelines shall be inspected annually by the lessee using an electronic survey tool. Upon request of the lessee, the frequency of inspection may be reduced depending upon the degree of corrosion observed. (C) If it is not mechanically possible to run an electronic survey tool, the lessee shall hydrostatically pressure test each oil and gas pipeline to at least 1.5 times its maximum operating pressure. The test procedure shall be approved by the Staff. (D) The ocean surface above all pipelines that service offshore facilities shall be inspected a minimum of once each week for indication of leakage, using aircraft or boats. Records of these inspections, including the date, methods, and results of each inspection, shall be maintained by the lessee at its nearest onshore office. (7) Reports of Inspection. The lessee shall file a report with the Staff describing the testing procedure and results of (1) the annual test of the cathodic protection system on each pipeline and (2) the annual visual and electronic inspection of hydrostatic test of each oil and gas pipeline. The reports shall be filed within 60 days following completion of the work. (8) Safety Equipment and Procedures. (A) All oil and gas pipelines receiving production from offshore production facilities shall be equipped with high-low-pressure shut-in sensors and with an automatic shut-in valve located at the offshore facility. The pressure sensors shall be connected so as to actuate the automatic shut-in valves on the pipelines as well as all shut-in devices on input sources to the pipelines. The pressure settings shall be determined by pipeline operating characteristics, and shall be set as close as practicable to the normal operating pressure of the pipeline. The automatic shut-in valves also shall be actuated by the integrated safety-control system of the production facility. (B) All oil and gas pipelines that deliver production to an onshore production facility shall be equipped with a remote-controlled shut-in valve or check valve at or near the receiving facility. (C) All oil and gas pipelines that cross an offshore facility which do not deliver production to the facility, and may or may not receive production from the facility, shall be equipped with an automatic shut-in valve to be located in the upstream portion of the pipeline at the facility, so as to prevent uncontrolled flow at the facility. This automatic shut-in valve shall be controllable by the integrated safety-control system of the facility. (D) Any pipeline that delivers gas to an offshore facility for the purpose of gas lift or other operations shall be equipped with an automatic shut-in valve to be located in the upstream portion of the pipeline at the facility, so as to prevent uncontrolled flow at the facility. This automatic shut-in valve shall be controllable by the integrated safety-control system of the facility. (E) All oil pumps and gas compressors shall be equipped with high-low-pressure shut-in devices. (F) All pressure sensors, pressure shut-in devices, and automatic shut-in valves shall be tested monthly by the lessee, and shall be witnessed and approved by the Staff. The lessee shall maintain records on the production facility showing the present status and past history of each device, including dates and details of inspection, testing and repairing, adjustment, and reinstallation or replacement. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2133. General Provisions. (a) This Article 3.4 pertains to oil and gas drilling and production operations on State oil and gas leases located on State tide and submerged lands under the jurisdiction of the State Lands Commission, and is applicable to operations conducted from mobile rigs, fixed offshore structures and upland locations serving these leases. (b) In addition to complying with Division 6 of the California Public Resources Code and with Title 2, Division 3, Chapter 1 of the California Administrative Code, the lessee shall comply with all applicable laws, rules and regulations now or hereafter promulgated of the United States of the State of California and of any respective political subdivision thereof, including, but not limited to, those of the Division of Oil and Gas, the Department of Fish and Game, the Division of Industrial Safety, the State Water Resources Control Board, and the Regional Water Quality Control Board, the California Coastal Commission, and any respective successors thereto. (c) All operations conducted on State oil and gas leases shall be carried on in a proper and workmanlike manner in accordance with accepted good oilfield practice. Note: Authority cited: Sections 6103, 6108, 6216, 6301, and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2134. Definitions. For purposes of this Article 3.4 the following definition shall apply: (a) "Staff" shall mean the Executive Officer or other duly authorized member of the Staff of the State Lands Commission. Note: Authority cited: Sections 6103, 6108, 6216, 6301, and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2135. Administration. (a) The Staff shall administer this Article 3.4 and shall thereby seek to provide for the prevention and elimination of any contamination or pollution of the ocean and tidelands, for the prevention of waste and for the conservation of natural resources, and for the protection of human health and safety and of property. (b) The Commission has designed these regulations in as great detail as possible. However, the Commission recognizes that situations may arise which are not specifically covered by this Article 3.4 and that emergency situations may arise which will require immediate decisions by the Staff. In such situations, the Executive Officer or his designee may authorize appropriate procedures to be followed. Note: Authority cited: Sections 6103, 6108, 6216, 6301, and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2136. Prohibition of Pollution. (a) Pollution and contamination of the ocean and tidelands and any impairment of or interference with recreation, fishing, or navigation in the waters of the ocean or any bay or any inlet thereof is prohibited; and no oil, tar, residuary product of oil or any refuse of any kind from any well or facility that is deleterious to marine life shall be permitted to be deposited on or pass into the waters of the ocean or any bay or any inlet thereof. (b) All drilling and production operations shall be conducted in a manner that will eliminate, insofar as is practical, any dust, noise, vibration, or noxious odors. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2137. Suspension of Operations and Corrective Action. A lessee shall suspend immediately any drilling and production operations, except those which are corrective, protective, or mitigative, in the event of any disaster of or contamination or pollution caused in any manner or resulting from drilling and/or production operations under its lease. Such drilling and/or production operations shall not be resumed until adequate corrective measures have been taken and authorization for resumption of such operations has been made by the Staff. Corrective measures shall be taken immediately whenever pollution has occurred. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2138. Disposal of Drill Cuttings and Drilling Muds. The lessee shall dispose of those drill cuttings and drilling muds associated with drilling and production well work, in accordance with regulations promulgated by the appropriate Regional Water Quality Control Board. The method employed to dispose of the drill cuttings and drilling muds shall be submitted to the Staff for approval along with the drilling mud program that is required in Section 2128(d)(1). Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2139. Oil Spill Contingency Plan. Each lessee shall prepare and maintain a current oil spill contingency plan for initiating corrective action to control and recover oil spilled in or on the ocean. The plan shall cover both minor and major oil spills associated with lease drilling and production operations. The plan and any subsequent revisions thereto shall be submitted for approval by the Staff. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2140. Pollution Control and Removal Equipment. (a) Pollution control equipment and material shall be available immediately to each lessee for use in oil pollution control and removal operations on its lease. The equipment and material shall include, but need not be limited to, containment booms, skimming apparatus, licensed chemicals, and absorbents, and shall be the most effective available given the current state of pollution control and removal research and development at the time of acquisition. The lessee shall, however, update such equipment whenever any significant technological improvements are developed. (b) Emergency equipment shall be maintained on each mobile drilling rig and fixed offshore drilling or production facility for immediate cleanup of small oil spills. Each mobile drilling rig shall be equipped with a minimum of 1500 feet of oil containment boom, an oil skimming or recovery device that is capable of open ocean use, and an amount of absorbent material sufficient to remove 15 barrels of spilled oil. In addition, a boat that is capable of deploying this equipment shall be maintained onsite or available to the rig within 15 minutes. The equipment and material required on each fixed offshore drilling or production facility shall be determined and approved by the staff on an individual basis considering the type of structure, location, current activity, oil production capability, method of well production and other factors peculiar to the facility. Equipment for the control and removal of larger oil spills shall be maintained at an offshore or onshore location near the area of lease operations where deployment and response to the spill would provide the most feasible protection of coastal resources. All equipment shall be inspected regularly and shall be maintained in good condition for immediate use. (c) The lessee shall conduct training classes and periodic drills in the deployment and use of pollution control and removal equipment, to ensure that designated personnel can carry out the assignments which are necessary for effective control and removal of oil spilled in or on the ocean. (d) The lessee shall maintain an inventory of the emergency equipment that is stored on each mobile drilling rig and offshore drilling or production facility as well as an inventory showing the description, application, and location of all pollution control and removal equipment that is immediately available for a major oil spill. In addition, the lessee shall maintain a listing of equipment, material, services, and labor forces that are immediately available for beach cleanup and restoration operations. The inventories shall be updated as changes occur and current copies shall be filed with the Staff annually. (e) All mobile drilling rigs and offshore drilling or production facilities shall be equipped in a manner that will prevent spilling of contaminants in the ocean. Any fluids spilled shall be collected in a sump(s) that is provided with appropriate pumping equipment, liquid level controls, and alarms to prevent accidental discharge of contaminants into the ocean waters. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2141. Critical Operations and Curtailment Plans. The primary purpose of a Critical Operations and Curtailment Plan is to provide additional precautionary measures to minimize the likelihood of an oil spill incident occurring from offshore drilling and production well work during (1) adverse weather and sea conditions when oil spill containment and recovery equipment, material and techniques are not effective and marine transportation is severely hampered; and (2) the time that oil spill containment and recovery equipment, material, manpower, and transportation thereof are not readily available to the site of operation. Certain operations performed in drilling and production well work are more critical than others with respect to well control and accidental discharge of oil and gas. This is particularly so when subsurface forations are exposed in the well that are capable of flowing oil and gas to the surface or when the well has been pressured by outside means. It is these critical operations that should be ceased, limited or not commenced in order to minimize the likelihood of an oil spill occurring during adverse weather and sea conditions which could seriously impede both well control and oil cleanup efforts. The lessee shall file with the Staff, for its approval, a Critical Operations and Curtailment Plan to be followed while conducting drilling and/or production well work on the lease. A plan shall be filed for each exploratory well as required in Section 2128(d)(2) in order to accommodate different drilling rigs, circumstances and conditions. A separate plan shall be filed for development drilling and production well work on the lease. These plans shall contain the following: (a) A descriptive list of the critical drilling and production well work that is likely to be conducted on the lease, such as: (1) Drilling in close proximity to another well. (2) Drilling into a known lost circulation zone or into a zone capable of flowing oil and/or gas. (3) Continuation of drilling into zones that are suspected to be capable of flowing oil and/or gas or into zones suspected to be abnormally pressured. (4) If zones capable of flowing oil and/or gas are exposed or suspected to be exposed in the well then the following are considered to be critical operations: (A) Pulling out of the hole. (B) Fishing operations. (C) Drill-Stem testing. (D) Wireline logging in open hole. (E) Running casing. (F) Cutting and recovering casing. (G) Perforating casing. (H) Well completion work. (I) Remedial well work. (J) Well stimulation. (b) A descriptive list of circumstances or conditions under which the critical drilling and production well work shall be ceased, limited, or not commenced. This list shall be developed from all the factors and conditions relating to the lease and shall take into account but may not to be limited to the following: (1) Whether or not well operations are being conducted from a mobile rig or a fixed structure. (2) Adverse meteorological or oceanographical conditions exist or are anticipated soon. (3) Limited availability and capability of oil containment and cleanup equipment. (4) Significant increase in oil spill control system response time for any reason. (5) Personnel or equipment for conducting a particular critical operation are not available. (6) Insufficient supply of drilling mud materials on the drill site for emergency well control purposes. (7) Transportation equipment for personnel, supplies and oil spill containment and cleanup equipment is not readily available. (8) Construction and maintenance work involving welding, moving heavy equipment, etc. is being performed. (9) Other factors peculiar to the particular lease under consideration. (c) When any circumstance or condition listed or described in the plan occurs or other operational limits are encountered, the lessee shall cease, limit, or not commence the affected critical operation(s) as set forth in Section 2141(a). (d) Any deviation from the approved plan shall require prior written approval by the Staff. If emergency action requires deviation from the plan, and there is inadequate time to seek the Staff's approval, the Staff shall be notified immediately after said deviation occurs. (e) The plan shall be reviewed at least annually and any changes thereto shall be submitted to the Staff for approval. s 2142. Pollution Reports. (a) All spills or leakage of oil and liquid pollutants originating from operations on State oil and gas leases shall be reported orally without delay to the United States Coast Guard and to the State Office of Emergency Services in Sacramento. Subsequent to oral notification, a written report shall be filed with the State Lands Commission, stating the source, cause, size of spill and the action taken. (b) Lessees shall report orally to the three authorities indicated in Section 2142(a) any pollution of unknown source or pollution unassociated with lease operations that is observed on or in State waters. (c) Lessees shall notify one another of information regarding equipment malfunction or of information regarding pollution resulting from another's operation. Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code. s 2150. Purpose. Whenever the Commission determines that it is in the best interests of the State to take its royalty share of oil, gas, or other hydrocarbons in kind, the Commission shall enter into agreements for the disposition and sale of such oil, gas, or other hydrocarbons in accordance with procedures set forth in this Article. Note: Authority cited: Sections 6108 and 6815.1, Public Resources Code. s 2151. Definitions. As used in this article unless otherwise specified: (a) The term "royalty oil" includes oil, gas, natural gasoline, other products extracted from gas, and all other hydrocarbons. (b) The term "purchaser" means any person or corporation that has entered into a contract to purchase royalty oil from the State. (c) The term "lease" means oil and gas lease, easement, or other agreement for the extraction of oil, gas, or other hydrocarbons from lands owned by the State. (d) The term "lessee" means holder of a lease. (e) The term "base price" means, in relation to royalty oil, a price to be determined in accordance with a standard to be adopted by the Commission for each contract to purchase royalty oil and to be included in each such contract when it is adopted pursuant to Section 2153. The standard to be adopted shall relate, to the extent practical, to objective criteria and to data easily ascertainable, such as posted prices or prices paid for products of like quality, taking into account location, so that both the State and a purchaser will be able to establish the base price with reasonable ease and accuracy. Prices paid under any contract to purchase royalty oil pursuant to these rules and regulations shall not, under any circumstances, be used in determining such base price. s 2152. Eligibility to Hold Sales Contracts. A sales contract for royalty oil shall be issued only to and held by: (a) Persons or associations of persons who are citizens of the United States or who have declared their intention of becoming such, or who are citizens of any country, dependency, colony, or province, the laws, customs, and regulations of which permit the grant of similar or like privileges to citizens of the United States. (b) Any corporation or corporations organized and existing under and by virtue of the laws of the United States or of any state or territory thereof; or any corporation or corporations 90 per cent or more of the shares of which are owned by persons eligible to hold a lease or permit under subdivision (a) or (c) of this section; or any corporation or corporations 90 per cent or more of the shares of which are owned either by a corporation eligible to hold a lease or permit hereunder, or by any combination of such eligible persons or corporations, or both. (c) Any alien person entitled thereto by virtue of any treaty between the United States and the nation or country of which the alien person is a citizen or subject. s 2153. Selection of Royalty Oil. The Commission shall, in advance, select the lease or leases from which royalty oil will be taken in kind and the particular hydrocarbons to be taken, determine the increments, if any, in which such oil will be sold, and adopt the bid-form, notice inviting bids, bid-proposal, and the sales contract. The proposal shall remain on file in the Commissions' Offices and shall contain the notice, bid-form, contract, copies of the lease or leases involved, and pertinent production and lease data. s 2154. Bid Factor. The Commission shall select for each sales contract, prior to offering royalty oil for bid, one of the bid factors listed below: (a) $________ per barrel plus the base price. (b) ________% plus 100% of the base price. (c) $________ per barrel, provided that the purchaser shall at all times pay the bid price or the base price plus a specified percent of the base price as determined by the Commission, whichever is higher. (d) $________ bonus plus the base price. (e) $________ per barrel for a specified gravity with a gravity differential schedule as specified in advance by the Commission, provided that the purchaser shall at all times pay the bid price or the base price plus a specified percent of the base price as determined by the Commission, whichever is higher. The Commission may, in offering a sales contract, require a minimum bid. s 2155. Other Conditions. Any sales contract issued under the provisions of this article shall contain such other covenants, conditions, requirements, and reservations as may be deemed advisable by the Commission to protect the interests of the State. s 2156. Notice Inviting Bids. Whenever the Commission elects to dispose of royalty oil by competitive public bid, the Commission shall cause notice of intention to receive bids to be published. (a) The notice shall identify the lease from which the oil is to be offered, the proposed point of delivery, the time for receiving and opening bids, and indicate that forms for bidding may be obtained at an office of the Commission. Such notice shall be published at least once in a newspaper of general circulation in the county in which the point of delivery is situated, and may be published at least once in a newspaper of general circulation in the City of Los Angeles, or San Francisco, or Sacramento. (b) At the time and place specified in the notice, not earlier than fourteen (14) days after the last date of publication the sealed bids shall be opened publicly and an award shall be made to the highest responsible bidder unless, in the opinion o the Commission, the acceptance of the highest qualified bid is not in the best interests of the State, in which event the Commission may reject all bids. Thereupon new bids may be called for or the Commission may refuse to call for new bids, or the Commission may negotiate and enter into agreements for sale under terms and conditions deemed to be in the best interests of the State. The Commission reserves the right at any time to reject any and all bids or to cancel the invitation to bid. (c) At the time of the bid award, the Commission shall direct the Executive Officer or his agent to notify the lessee that the State intends to take royalty oil in kind commencing on the date specified in the sales contract. s 2157. Submission of Bids. Bids submitted pursuant to a published notice shall contain the following documents: (a) Two copies of the bid-form completed, and executed. In the event of a joint bid, or a bid by a partnership, each bidder shall execute the bid-form. The insertion of any additional condition, qualification, or provision on said bid-form will invalidate the bid . In the case of joint bidding, or bidding by a partnership, bid data shall be submitted as required by Section 1913, and Section 1914, Title 2 of the California Administrative Code. Corporations executing a bid shall submit with the bid evidence of the authority of the officer or officers executing the bid on behalf of the corporation and shall affix the corporate seal upon the signature page of the bid-form. (b) Each bidder must submit with his bid evidence of qualification to enter a contract as specified in this Section. (c) Each bid submitted pursuant to this notice shall be accompanied by a certified or cashier's check or checks of a responsible bank in California and made payable to the State of California in an amount to be determined by the Commission before the offering as a deposit as evidence of the bidder's good faith. (d) Each bidder shall submit with the bid a certified financial statement establishing to the satisfaction of the Commission such bidder's financial ability to undertake and fulfill all obligations under the prospective contract. Said financial statements shall be certified as to their truth and accuracy by each bidder, as a bidder, or by the person by whom or under whose direction the statements were prepared. Said financial statements shall be accurate as of the date of certification, which date shall be not earlier than the date the Notice of Intention herein was first published. Previously prepared financial statements and/or annual reports may be used by bidders provided that (a) such statements and/or reports are certified, as aforesaid, and (b) the bidder submits a certified statement by the bidder or a responsible financial officer of the bidder that there has been no material change in the financial or other condition of the bidder since the date of preparation of said statement and/or report that would impair the bidder's financial ability to undertake and fulfill all obligations of the bidder under the prospective contract. The certification of such financial statement must be signed by the individual or firm by whom the statement was prepared, as well as by the bidder. (e) Each bidder shall submit with the bid evidence establishing to the satisfaction of the Commission such bidder's ability to take oil at the point of delivery. An agreement providing for the exchange of royalty oil for their oil or hydrocarbons may be submitted as evidence to establish bidder's ability to take royalty oil at the point of delivery. (f) Each bidder shall also submit with the bid information concerning installation and maintenance of metering facilities, shipping pumps, pipelines, storage, loading facilities, or any other facilities that may be required to facilitate said royalty oil deliveries. The installation of any such facilities shall be only with the prior approval of the State. (g) Each bidder shall nominate by letter of authority the name and address of a person authorized to give or receive any notice to or from the State Lands Commission with respect to such bidding and to receive refund of sums accompanying an unsuccessful bid. Said letter shall be submitted with the bid and shall be signed by the bidder, and in the case of joint bids shall be signed by each person or other entity joining in said bid. Unless otherwise expressly provided, the person so authorized to receive notice shall, in the case of the successful bidder, be deemed to be the person duly authorized to give and receive notices on behalf of the bidder. s 2158. Term. Sales contracts for the disposition of royalty oil shall be entered into for a term as determined y the Commission not to exceed five years. s 2159. Delivery Adjustments. Lessee may make deliveries of royalty oil to purchaser on a regular basis, and adjustments to deliveries, overages, or underages, including quality considerations, will be made up by the last day of the following calendar month. s 2160. Delivery and Dehydration Costs. The lessee, where so provided in the lease, shall be reimbursed for the actual allowable cost of dehydration of the royalty share of crude oil and, in the case of offshore leases, for the actual cost of delivery of the royalty share of crude oil to onshore storage and transportation facilities. Only those costs approved by the State in writing shall be allowed. The Commission shall select, prior to the bid offer, one of the methods listed below: (a) The State shall reimburse the lessee monthly for such costs upon submission of an invoice by the lessee. (b) The purchaser shall monthly, or as designated by the State, reimburse the lessee for such costs. Such costs may be deducted by the pur chaser from the amounts to be submitted to the State pursuant to the sales contract. s 2161. Security. Purchaser shall, at the time of the execution of the contract, furnish and thereafter maintain in favor of the State a good and sufficient bond or other such security in such sum as may be specified by the State Lands Commission, guaranteeing faithful performance by the purchaser of the terms, covenants, and conditions of the contract. Such bond or other such security will be used to indemnify the State for all costs and damages, including, but not limited to, damages caused by default of the purchaser of royalty oil. The cost of the bond or other security shall be paid for by the purchaser. The Commission may in its discretion reduce, eliminate, or reinstate the security requirement during the term of the sales contract. s 2162. Disposition of Royalty Oil in the Event of Default. In the event purchaser fails to take the royalty oil as provided by the contract, the Executive Officer or his designee is authorized to dispose of the royalty oil in the most expeditious manner possible. All cost incurred therein shall be deemed as a charge against the purchaser. Purchaser shall be responsible to the State for the difference, if any, between the amount of money received by the State in such disposition and the amount due the State pursuant to the sales contract. s 2163. Assignment of Contract. Any sales contract issued under the provisions of this article may be assigned, subject to approval by the Commission, to any person, association of persons, or corporation who, at the time of the proposed assignment, possesses the qualifications provided in this article. Any assignment shall take effect as of the first day of the month following the approval by the Commission and filing with the Commission of an executed counterpart thereof, together with any bond and proof of qualification of the assignee to take or hold such sales contract. Unless approved by the Commission, no assignment shall be of any effect. Such assignment shall be made upon the express condition that such assignment does not and shall not release or relieve the Assignor from any obligation to the State under the terms of said sales contract, and that the State may hold the Assignor liable for the faithful performance of any and all obligation of the Purchaser under said sales contract; and, further, that the Assignee shall be bound by the terms of said sales contract to the same extent as if such Assignee were the original Purchaser, any conditions in the assignment agreement to the contrary notwithstanding. s 2170. General Provisions. This Article 3.6 pertains to all exploration and production oil and gas facilities on tide and submerged lands under the jurisdiction of the State Lands Commission. For the purposes of this Article only, the term "marine facility" shall not include terminals used exclusively for transferring oil to or from vessels. Note: Authority cited: Sections 6103, 6108, 6216, 6301, 6873, 8755, 8756, and 8758, Public Resources Code. Reference: Sections 6005, 6216, 6871, 6871.1, 6873, 8755, 8756 and 8758, Public Resources Code. s 2171. Definitions. (a) "Commission" means the California State Lands Commission. (b) "Staff" means the Executive Officer or other duly authorized member of the staff of the State Lands Commission. (c) "Oil" means any kind of petroleum, liquid, hydrocarbons, or petroleum products or any fraction or residues therefrom, including, but not limited to, crude oil, bunker fuel, gasoline, diesel fuel, aviation fuel, oil sludge, oil refuse, oil mixed with waste, and liquid distillates from unprocessed natural gas. (d) "Spill" or "discharge" means any release or discharge of oil or other refuse of any kind from any well or facility into marine waters not authorized by any federal, state, or local government entity. (e) "Marine waters" means those waters subject to tidal influence, except for waters in the Sacramento-San Joaquin Rivers and Delta upstream from a line running north and south through the point where Contra Costa, Sacramento, and Solano Counties meet. Note: Authority cited: Sections 6103, 6108, 6216, 6301, 6873, 8755, 8756, and 8758, Public Resources Code. Reference: Sections 6005, 6216, 6871, 6871.1, 6873, 8755, 8756 and 8758, Public Resources Code. s 2172. Administration. The Staff shall administer this Article 3.6 and shall thereby seek to provide for the prevention and elimination of any contamination or pollution of the ocean and tidelands, and marine waters for the prevention of waste, for the conservation of natural resources, and for the protection of human health and safety, and the environment. Note: Authority cited: Sections 6103, 6108, 6216, 6301, 6873, 8755, 8756, and 8758, Public Resources Code. Reference: Sections 6005, 6216, 6871, 6871.1, 6873, 8755, 8756 and 8758, Public Resources Code. s 2173. General Requirements. (a) Each operator of a marine facility shall prepare an operations manual describing equipment and procedures which the operator employs or will employ to protect the public health and safety and the environment and to prevent oil spills. (b) The operation manual shall demonstrate compliance with all applicable marine facility operating rules and regulations of the State Lands Commission and the lease terms (if applicable). (c) Copies of the manual shall be available and accessible to every employee at the field facility and at the next supervising level location. Two current approved copies shall be filed with the State Lands Commission Mineral Resources Management Division Staff. Note: Authority cited: Sections 6108, 6216, 8755, and 8758, Public Resources Code. Reference: Sections 6108, 6216, 6873(b), 8755 and 8758, Public Resources Code. s 2174. Manual Review. (a) Submission of Manual. (1) The operations manual for any existing facility shall be submitted to Staff for review and approval within one year of the effective date of these regulations. (2) For any facilities not presently is existence, and operations manual shall be submitted to Staff for review and approval as part of the application for approval of the facility. (3) Staff shall review and respond to the operator within 90 days after a complete application for review has been submitted and acknowledged. (b) Updates and Changes to Approved Manual (1) The operations manual shall be kept current at all times. (2) Whenever any routine changes (administrative or clerical) is made in the operation, an update amendment reflecting that change shall be sent to Staff within 30 days. (3) Any substantial changes to the manual or its content shall require prior approval by Staff. A substantial change is one which is non-routine, or which would increase or decrease the ability of the operator to respond to a spill, to provide for personnel safety, or to protect the environment. (4) Subsequent reviews will be required as necessary when facility operations or technology changes, or when the Commission finds that the manual of any operator is no longer consistent with the provisions of this article or other rules, regulations, or guidelines of the Commission. Staff shall review and respond to the operator within 90 days after a complete application for review has been submitted and acknowledged. (c) Denial (1) Approval shall be denied if the Operations Manual does not comply with the conditions set forth in this article. (2) If approval is denied, Staff shall notify the operator of the reasons for denial and provide an explanation of those actions necessary to secure approval. (d) Appeal (1) If Staff denies approval of the Operations Manual, the operator may appeal this decision by submission of a written appeal to the Commission. Any appeal must be submitted within 10 calendar days from the date the operator receives notice that approval of the manual has been denied. The request must contain the basis for the appeal and provide evidence which rebuts the basis for the Staff's denial of the manual. (2) Upon receipt of an appeal, the Staff shall place the appeal on the calendar for the next Commission meeting taking place at least thirty (30) days after the appeal is received. The Commission may consider the appeal at that meeting or may delay consideration until a later meeting. Within 15 days after the Commission makes a decision on the appeal, the Staff shall send the operator written notice as to the Commission's decision. (e) Proof of Approval The operator shall keep the Letter of Approval filed in the front of the approved operations manual that is kept on the facility. The approval letter shall be presented upon request to any official representing the Commission or Administrator. Note: Authority cited: Sections 6108, 6216, 8755, 8756, and 8758, Public Resources Code. Reference: Sections 6108, 6216, 6873(b), 8755 and 8758, Public Resources Code. s 2175. Manual Content. (a) The manual shall be arranged in a logical order and with clearly defined tabs for quick reference to emergency plans and procedures, a comprehensive table of contents and numbered pages. (b) Each manual shall as a minimum include the following: (1) Location: Appropriate maps, charts and geographic descriptions shall be included, indicating clearly the location of the facility and its relationship to nearby geographic features. (2) Ownership and Responsibility: Information shall be included identifying the owner or owners of the facility and all those who may be responsible for the operation of the facility or for implementation of operation or contingency plans. Addresses and telephone numbers shall be included and kept current for each person or entity listed. (3) Purpose: The manual shall include general explanations of the purposes of the facility and its various components. (4) Personnel: A listing of operating staff positions shall be provided, showing the chain of command and the responsibility of each position. Employee qualifications for responsible positions must be outlined and staffing levels of the facility must be justified. On any facility which does not maintain 24- hour surveillance, justification and description of safety and security systems shall be discussed. (5) Description of Operations: (A) The manual shall include plot plans of the facility and flow diagrams for each of the production flow streams, including oil, gas, and water injection. Each major component and associated equipment including, but not limited to, wells, piping, process vessels, tanks compressors, pumps, and alarm, control and safety systems shall be narratively described, including function, capacity, physical size and pressure rating. (B) Detailed information regarding preventives maintenance programs and procedures shall be provided. (6) Personnel Safety: Detailed information shall be provided regarding equipment and procedures employed for the purpose of ensuring personnel safety, including, but not limited to, information concerning the following: (A) Personnel safety; (B) Safety responsibilities of each personnel position; (C) Training; (D) Safety Drills; (E) Inspection of Personnel Safety Equipment; and (F) Compliance with applicable provisions of Division 5 of the Labor Code and regulations adopted pursuant thereto. (7) Systems Safety: Detailed information shall be provided regarding equipment and procedures employed for the purpose of preventing oil discharges or other accidents which may harm or threaten public health and safety or the environment, including, but not limited to, information concerning the following: (A) Systems Safety Equipment; (B) Systems Safety Training; (C) All operations and procedures employed for the prevention of oil discharges or other pollution; and (D) Inspection and testing of system safety equipment and operations. (8) Automatic Control Systems and Equipment: Subsection (b)(7) shall include information concerning the identification, use and operation of any safety equipment that can be operated remotely, automatically, or by pre-program and any appropriate manual override information. The following information should be included: (A) Normal process and operation; (B) Safety shut-down; and (C) Emergency shut-down (9) Production Processing: All production streams must be identified, with the minimum following information included for each fluid: (A) Chemical makeup; (B) Fluid volumes; (C) Pressures; (D) Flow rates; (E) Temperatures; (F) Appearance; (G) Odor; (H) Instructions for safe emergency handling; and (I) Any hazards which might be encountered in dealing with the fluid. (10) Oil Spill Contingency and Hazardous Materials Plans: The manual shall include or have attached (or otherwise incorporate by reference) copies of the following: (A) Any oil spill contingency plan required under the lease issued by the Commission or under Chapter 7.4 of Division 1 of Title 2 (ss 8670.1 et seq. ) of the Government Code; and (B) For each fluid identified under subsection (b)(9) of this section, any business plan for responding to hazardous materials releases required under Chapter 6.95 of Division 20 of the Health and Safety Code. (11) Fire Fighting Response: The manual shall also include information regarding response to fire, including at minimum the following: (A) Information regarding primary response, including, but not limited to, detailed descriptions of response equipment and their use and operation, personnel, training, drills, communications equipment and procedures, and evacuation plans; and (B) Information regarding secondary response, including, but not limited to, detailed descriptions of response equipment and their use and operation, use of mutual aid organization or cooperatives for fire suppression, interagency agreements or memoranda of understanding, and communications equipment and procedures. (12) Other Emergency Response Plans. (A) In addition to the plans set forth in subsections (b)(10) and (b)(11) of this section, any other emergency response plans shall also be included in or attached (or otherwise incorporate by reference) to the manual. (B) Every plan submitted shall have included or attached the names and telephone and facsimile numbers of all relevant contact personnel with the facility operator, State and Federal response agencies, local fire, police, and medical responders, security personnel, and mutual aid cooperatives or organizations. (C) Among the additional plans to be submitted shall be at minimum the following: 1. A Well Control Plan (Drilling and Workover); 2. A Critical Operations and Curtailment Plan (Drilling & Production, or substantial construction project); 3. An H 2 S Contingency Plan (if applicable); 4. A Facility Emergency Evacuation Plan; 5. Natural Disaster Response Plans; and 6. Security Plans (13) Communication System: The manual shall describe in detail how communications systems employed at the facility provide for redundancy and interface with other area facilities, emergency responders, and agencies. (14) Operational Support: The manual shall also include a description of normal and emergency operational support, including, but not limited to, the type and use of helicopters and vessels. (A) Helicopters (B) Boats & Vessels (C) Other (15) Other Information: The manual shall also include any other information necessary or appropriate for the Commission and for those work ing at the facility to know and understand the equipment, operations and systems employed at the facility both for ordinary operations, generally, and for the specific purpose of preventing harm to public health and safety or to the environment. Note: Authority cited: Sections 6108, 6216, 8755, 8756, and 8758, Public Resources Code. Reference: Sections 6108, 6216, 6873(b), 8755 and 8758, Public Resources Code. s 2200. Character and Extent of Lands. (a) Lands subject to lease include: (1) Those containing known deposits of minerals; (2) Those embraced in a prospecting permit not subject to preferential lease. (b) For tide and submerged lands and those underlying navigable streams and lakes the commission may determine the extent thereof subject to lease under any application. For all other lands the application shall be for a compact area and may include any number of acres not in excess of 160. (c) The commission may include in its lease offer, areas adjacent to that for which application has been made, should it determine that such additional areas contain commercially valuable mineral deposits. (d) Lands subject to prospecting permits are those not classified by the commission as containing commercially valuable mineral deposits. s 2201. Duration of Leases and Permits. (a) Leases (both preferential and bid) may be issued for a term of 20 years, with option of renewal for successive periods of 10 years upon such terms and conditions as may be prescribed by the commission at the time of renewal. (b) Prospecting permits are limited to a period not exceeding two years, extendable for a period of an additional one year at the discretion of the commission. s 2202. Prospecting Permit Procedures. (a) Applications. Any person desiring to apply for a prospecting permit on any land under the jurisdiction of the commission, shall file with the State Lands Division, 100 Oceangate, Suite 300, Long Beach, California 90802, a written application containing: (1) Name, address, and status of citizenship of applicant; if applicant is a corporation, the corporate name and name of president, secretary, and officer authorized to execute contracts and leases. (2) A description of the state lands involved. (3) A statement of the use proposed. (4) A statement of the character and use of adjoining lands. (5) A statement of the nature of the deposits proposed to be developed. (b) If the applicant has posted a notice on the lands and recorded a copy thereof, as provided by Section 6892 of the Public Resources Code, the application shall so state, describing the monument erected on the lands, giving the location thereof, and stating the dates of posting and recording. The recorded copy of the notice shall be attached to the application. (c) The application shall be accompanied by: (1) a filing fee, as provided in Section 1903(a) (2) a permit fee deposit equal to the amount of $1 per acre for each acre within the desired permit area. (3) an expense deposit as provided in Section 1903.2. (d) Upon the acceptance of an application, the commission shall determine the royalty rate to be paid under any ensuing preferential lease. (e) Upon authorization by the commission, permit forms shall be submitted for the applicant's acknowledged or witnessed execution. s 2203. Preferential Lease Procedures. (a) At any time during the life of a permit, the permittee may apply for a preferential lease upon discovery of a commercially valuable deposit of minerals within the permit area. (b) An application under this section shall contain, in addition to the data required in Section 2202(a), an affidavit of some responsible person having knowledge of the facts averring that a commercially valuable mineral deposit has been discovered within the permit area. (c) No lease shall be issued for unsurveyed lands. Upon request of the applicant, accompanied by a deposit of an amount sufficient to cover the costs of a survey, surveying services will be rendered by the Division of State Lands. (d) Upon determination by the Division of State Lands that a commercially valuable mineral deposit has been discovered and that the applicant is entitled to a preferential lease, the commission may, subject to the payment of the rental for the first year, authorize the execution and delivery of an appropriate lease. s 2204. Procedures for Nonpreferential Leases. Lands known to contain commercially valuable deposits of minerals not subject to a preferential lease under a prospecting permit, may be leased pursuant to a published notice of intention to receive bids. (See Section 1908). The minimum expense deposit required shall be determined by the Commission under the provisions of Section 1903.2. s 2205. Statements and Reports. On or before the fifteenth day of each month, a lessee or permittee shall deliver to the Division of State Lands statements in the form prescribed, showing the work performed upon the leased or permitted area and the amount, quality, and value of all minerals produced, shipped or sold during the preceding calendar month. Longer intervals for such reports may be authorized but such authorization shall be granted only in writing and may be revoked or changed at any time upon written notice to the lessee or permittee. s 2249. Competitive Lease Sales. Upon nomination, the Commission may designate State lands for lease by competitive bidding to the highest responsible qualified bidder. Such nominations may be made by holders of exploration permits or any other party qualified to hold a lease, pursuant to Public Resources Code Section 6801. Any State lands may be nominated and designated for competitive lease sale; provided that lands included within a valid and effective prospecting permit may be nominated and designated but may not be leased prior to the termination of that permit. Note: Authority cited: Section 6108, Public Resources Code. Reference: Sections 6910 and 6911, Public Resources Code. s 2250. Surface Owner Notification. When a competitive bid has been held for lands described in subdivision (a) of Public Resources Code Section 6912, and the Commission has determined the highest qualified bid, the Commission shall notify the surface owner of such bid. The notice shall be deemed to be effective when received by the surface owner or five days after being sent, whichever occurs first. Note: Authority cited: Section 6108, Public Resources Code. Reference: Sections 6911 and 6912(b), Public Resources Code. s 2270. Marine Invasive Species Control Act; Definitions. For purposes of this Article, the following definitions apply. (a) "Voyage" means any transit by a vessel destined for any California port from a port or place outside of the coastal waters of the state. (b) "Waters of the state" means any surface waters, including saline waters that are within the boundaries of the state. Note: Authority cited: Section 71215(b), Public Resources Code. Reference: Sections 71200(m) and (o) and 71215, Public Resources Code. s 2271. Fee Schedule for Marine Invasive Species Control Fund. (a) The fee required under Public Resources Code Section 71215 is four hundred dollars ($400) per vessel voyage. (b) The Commission may establish lower levels of fees and the maximum amount of fees for individual shipping companies or vessels. Any fee schedule established, including the level of the fees and the maximum amount of fees, shall take into account the impact of the fees on vessels operating from California in the Hawaii or Alaska trades, the frequency of calls by particular vessels to California ports within a year, the ballast water practices of the vessels, and other relevant considerations. (c) The fee shall be collected from the owner or operator of each vessel that arrives at a California port or place from a port or place outside of California. That fee may not be assessed on any vessel arriving at a California port or place if that vessel comes directly from another California port or place and during that transit has not first arrived at a port or place outside California or moved outside the EEZ prior to arrival at the subsequent California port or place. (d)(1) The Executive Officer of the California State Lands Commission shall invite representatives of persons and entities who must pay the fee required under Public Resource Code Section 71215 to participate in a technical advisory group to make recommendations regarding the amount of the fee, taking into account the provisions of Public Resources Code Sections 71200 through 71216. (2) The technical advisory group shall meet on a regular basis after July 1, 2000, as determined by the group. Note: Authority cited: Section 71215(b), Public Resources Code. Reference: Sections 71200 and 71215, Public Resources Code. s 2280. Purpose, Applicability, and Date of Implementation. (a) The purpose of the regulations in Title 2, Division 3, Chapter 1, Article 4.6 of the California Code of Regulations is to move the state expeditiously toward elimination of the discharge of nonindigenous species into the waters of the state or into waters that may impact the waters of the state, based on the best available technology economically achievable. (b) The provisions of Article 4.6 apply to all vessels arriving at a California port or place carrying ballast water from another port or place within the Pacific Coast Region. For the purposes of Article 4.6 all ports and places in the San Francisco Bay area east of the Golden Gate bridge including the Ports of Stockton and Sacramento, shall be construed as the same California port or place; and the Ports of Los Angeles, Long Beach and the El Segundo marine terminal shall be construed as the same California port or place. (c) The provisions of Article 4.6 do not apply to vessels that arrive at a California port or place after departing from ports or places outside of the Pacific Coast Region. (d) The provisions of these regulations become effective 180 days after they have been filed with the Secretary of State. Note: Authority cited: Sections 71201.7 and 71204.5, Public Resources Code. Reference: Sections 71201 and 71204.5, Public Resources Code. s 2281. Safety of Ballasting Operations. (a) The master, operator, or person in charge of a vessel is responsible for the safety of the vessel, its crew, and its passengers. (b)(1) The master, operator, or person in charge of a vessel is not required by this provision to conduct a ballast water management practice, including exchange, if the master determines that the practice would threaten the safety of the vessel, its crew, or its passengers because of adverse weather, vessel design limitations, equipment failure, or any other extraordinary conditions. (2) If a determination described in subsection (b)(1) is made, the master, operator, or person in charge of the vessel shall take all feasible measures, based on the best available technologies economically achievable, that do not compromise the safety of the vessel to minimize the discharge of ballast water containing nonindigenous species into the waters of the state, or waters that may impact the waters of the state. (c) Nothing in this provision relieves the master, operator, or person in charge of a vessel of the responsibility for ensuring the safety and stability of the vessel or the safety of the crew and passengers, or any other responsibility. Note: Authority cited: Sections 71201.7 and 71204.5, Public Resources Code. Reference: Sections 71203 and 71204.5, Public Resources Code. s 2282. Definitions. Unless the context otherwise requires, the following definitions shall govern the construction of this Article: (a) "Coastal waters" means estuarine and ocean waters within 200 nautical miles of land or less than 2,000 meters (6,560 feet, 1,093 fathoms) deep, and rivers, lakes, or other water bodies navigably connected to the ocean. (b) "Commission" means the California State Lands Commission. (c) "Exchange" means to replace the water in a ballast tank using either of the following methods: (1) "Flow through exchange," which means to flush out ballast water by pumping three full volumes of near-coastal water through the tank, continuously displacing water from the tank, to minimize the number of original coastal organisms remaining in the tank. (2) "Empty/refill exchange," which means to pump out, until the tank is empty or as close to 100 percent empty as is safe to do so, the ballast water taken on in ports, or estuarine or territorial waters, then to refill the tank with near-coastal waters. (f) "Near-coastal waters" means waters that are more than 50 nautical miles from land and at least 200 meters (656 feet, 109 fathoms) deep. (g) "Pacific Coast Region" means all coastal waters on the Pacific Coast of North America east of 154 degrees W longitude and north of 25 degrees N latitude, exclusive of the Gulf of California. (h) "Vessel" means a vessel of 300 gross registered tons or more. Note: Authority cited: Sections 71201.7 and 71204.5, Public Resources Code. Reference: Sections 71200(e), (j) and (n), 71201, 71204 and 71204.5, Public Resources Code. s 2283. Alternatives. (a) Petitions for Alternatives. (1) Any person subject to these regulations may submit a petition to the Commission for alternatives to the requirements of Article 4.6 as applied to the petitioner. (2) All petitions for alternatives must be submitted in writing. A petition may be in any form, but it must contain all data and information necessary to evaluate its merits in order to fulfill the purposes of these regulations. (b) Approval of Alternatives. (1) The Commission may approve any proposed alternatives to the requirements of Article 4.6 if it determines that the proposed alternatives will fulfill the purpose of these regulations as outlined in subsection (a) of Section 2280 of this Article. (2) If the Commission approves any proposed alternatives under this section, a letter of approval shall be issued to the petitioner setting forth the findings upon which the approval is based. (3) The Commission may withdraw the letter of approval of any alternative requirements at any time if it finds that the person or persons subject to these regulations have not complied with the approved alternative requirements. (4) Withdrawal of a letter of approval under this section shall be effective upon receipt by the petitioner of written notification of the withdrawal from the Commission. Note: Authority cited: Sections 71201.7 and 71204.5, Public Resources Code. Reference: Sections 71201 and 71204.5, Public Resources Code. s 2284. Ballast Water Management Requirements. (a) The master, operator, or person in charge of a vessel that arrives at a California port or place from another port or place within the Pacific Coast Region shall employ at least one of the following ballast water management practices: (1) Exchange the vessel's ballast water in near-coastal waters, before entering the waters of the state, if that ballast water has been taken on in a port or place within the Pacific Coast region. (2) Retain all ballast water on board the vessel. (3) Use an alternative, environmentally sound method of ballast water management that, before the vessel begins the voyage, has been approved by the commission or the United States Coast Guard as being at least as effective as exchange, using mid-ocean waters, in removing or killing nonindigenous species. (4) Discharge the ballast water to a reception facility approved by the commission. (5) Under extraordinary circumstances where compliance with subsections (a)(1) through (a)(4) of this section is not practicable, perform a ballast water exchange within an area agreed to by the commission in consultation with the United States Coast Guard at or before the time of the request. Note: Authority cited: Sections 71201.7 and 71204.5, Public Resources Code. Reference: Sections 71200, 71204 and 71204.5, Public Resources Code. s 2300. The Marine Facilities Division. (a) There is in the Staff of the California State Lands Commission the Marine Facilities Division, which has the primary responsibility for carrying out the provisions of the Lempert-Keene-Seastrand Oil Spill Prevention and Response Act of 1990 within the Commission's jurisdiction. (b) The primary office of the Division is at 200 Oceangate, Suite 900, Long Beach, California 90802-4335, telephone (562) 499-6312. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2301. The Marine Facilities Inspection and Management Division. Note: Authority cited: Sections 6005, 6105, 6108, 6216, 6301, 6321, 6501, 6501.1, 6501.2, 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2302. Compliance with Federal, State and Local Regulations. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2303. Inspections and Monitoring. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8670.25 through 8670.37.5, Government Code; Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2304. Prior Notice of Transfer Operation. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2305. Purpose, Applicability and Date of Implementation. (a) The purpose of the regulations in Title 2, Division 3, Chapter 1, Article 5 of the California Code of Regulations is to provide the best achievable protection of the public health and safety and of the environment by using the best achievable technology. (b) The provisions of this article shall not apply to: (1) Oil transfer operations conducted at offshore drilling and production platforms. (2) Tank cleaning operations which begin after the removal of cargo or fuel from any tank vessel or barge. (3) Oil transfer operations to or from vessels other than tank vessels or barges if such vessels have oil carrying capacities of less than 250 barrels. (c) Unless otherwise specified in these regulations any new sections or modifications to existing sections shall become effective 30 days after they have been filed with the Secretary of State. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2310. Alternative Requirements or Exemptions. (a) Petitions for Alternative Requirements or Exemptions. (1) Any person subject to these regulations may submit a petition to the Division Chief for alternative requirements or exemptions to the requirements of Article 5. (2) All petitions for alternative requirements or exemptions must be submitted in writing. A petition may be in any form, but it must contain all data and information necessary to evaluate its merits. (b) Review and Response to Petitions. (1) Upon receipt, the Division shall review a petition for an alternative to or an exemption from any provision of this Article 5 to ensure that it contains all necessary information to support the petition. (2) If the Division Chief determines that the proposed alternatives to or exemptions from the requirements of Article 5 will ensure an equivalent or greater level of protection of the public health and safety and the environment, he or she shall notify the petitioner that the petition is complete and proceed under the provisions of subsection (c)(3) of this section for approval of the petition. (3) If the Division Chief determines that the proposed alternatives to or exemptions from the requirements of Article 5 will not ensure an equivalent or greater level of protection of the public health and safety and the environment, he or she shall notify the petitioner, in writing, giving specific reasons for such determination. (4) In all cases, whether a petition is approved or not, the Division Chief shall respond in writing to the petitioner within 30 working days of receipt of a completed petition. (5) A petitioner who is in receipt of written notification from the Division Chief under subsection (b)(3) of this section shall not be precluded from resubmitting petition for alternatives to or exemptions from similar provisions of this Article 5. (c) Approval of Alternative Requirements or Exemptions. (1) Any person subject to these regulations may depart from the requirements of Article 5 if the Division Chief finds that the person subject to these regulations can and will comply with alternative measures which will ensure an equivalent or greater level of protection of the public health and safety and the environment were the person to comply with the provisions of Article 5. (2) Any person subject to these regulations may be exempt from one or more of the requirements of Article 5 if the Division Chief finds that compliance with a requirement or requirements cannot be achieved at that terminal because of unusual circumstances or conditions at that terminal because of unusual circumstances or conditions at that terminal or because materials or personnel needed for compliance are unavailable. (3) If the Division Chief approves an alternative requirement or an exemption under this section, a letter of approval shall be issued to the petitioner setting forth the findings upon which the approval is based, and a copy of that letter shall be maintained at all times at the terminal with the terminal's operations manual required under Section 2385. (4)(A) The Division Chief may withdraw the letter of approval of an alternative requirement at any time if he or she finds that the person or persons subject to these regulations have not regularly and consistently complied with the approved alternative requirement. (B) The Division Chief may withdraw the letter of approval of an exemption at any time if he or she determines that compliance with the requirement or requirements of Article 5 can be achieved. (C) Withdrawal of a letter of approval under this section shall be effective upon the receipt by the petitioner of written notification of the withdrawal. Note: Authority cited: Sections 8751, 8755, 8756 and 8758, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756 and 8758, Public Resources Code; and Sections 15375, 15376 and 15378, Government Code. s 2315. Definitions. Unless the context otherwise requires, the following definitions shall govern the construction of this article: (a) "Administrator" means the administrator for oil spill response, as referenced in Public Resources Code Section 8750, subsection (a). (b) "Apparent violation" means an act, course of action or omission which, in the opinion of an agent or employee of the Division authorized to make such a determination, appears to be in violation of one or more of the provisions of Article 5. (c) "Barge" means any vessel that carries oil in commercial quantities as cargo, but is not equipped with a means of self-propulsion. (d) "Bunkers" or "bunker fuel" means fuel oil or lubrication oil supplied to any vessel for operating its propulsion and auxiliary machinery. (e) "CFR" means the currently effective edition of the United States Code of Federal Regulations. (f) "Commission" means the California State Lands Commission. (g) "Division" means the Marine Facilities Division of the California State Lands Commission. (h) "Division Chief" means the Chief of the Marine Facilities Division or any employee of the Division authorized by the Chief to act on his behalf. (i) "HOSE TECHNICAL INFORMATION BULLETIN: No. IP-11-4" means the 1995 edition of the "Hose Technical Information Bulletin: No. IP-11-4; Oil Suction and Discharge Hose; Manual for Maintenance, Testing and Inspection", published by the Rubber Manufacturers Association (RMA), 1400 K Street, N.W., Washington, D.C. 20005. (j) "Hot work" means work involving sources of ignition or temperatures sufficiently high to cause the ignition of a flammable gas mixture. This includes any work requiring the use of welding, burning or soldering equipment; blow torches; permitted power driven tools; portable electrical equipment which is not intrinsically safe or contained within an approved explosion proof housing; sand blasting equipment; or internal combustion engines. (k) "ISGOTT" means the Fourth Edition of the International Safety Guide for Oil Tankers and Terminals, published in 1996 by the International Chamber of Shipping (ICS), 30/32 St. Mary Axe, London EC3A 8ET, England. (l) "International Safety Management (ISM) Code" or "ISM Code" means the International Management Code for the Safe Operation of Ships and for Pollution Prevention adopted by the International Maritime Organization (IMO) by resolution A.741(18), as an amendment to the Annex to the International Convention for the Safety of Life at Sea, 1974 (SOLAS), (new Chapter IX) at the IMO's May 1994 SOLAS Conference. (m) "Marine terminal" means a facility, including a mobile transfer unit, other than a vessel, located on or adjacent to marine waters in California, used for transferring oil to or from tank vessels or barges. The term references all parts of the facility including, but not limited to, structures, equipment and appurtenances thereto used or capable of being used to transfer oil to or from tank vessels or barges. For the purpose of these regulations, a marine terminal includes all piping not integrally connected to a tank facility. A tank facility means any one or combination of above ground storage tanks, including any piping which is integral to the tank, which contains crude oil or its fractions and which is used by a single business entity at a single location or site. A pipe is integrally related to an above ground storage tank if the pipe is connected to the tank and meets any of the following: (1) The pipe is within the dike or containment area; (2) The pipe is connected to the first flange or valve after the piping exits the containment area; or (3) The pipe is connected to the first flange or valve on the exterior of the tank, if state or federal law does not require a containment area. (n) "MARPOL 73/78" means the final act of the International Conference on Marine Pollution, 1973, including the International Convention for the Prevention of Pollution from Ships, 1973 and of the Protocol of 1978, published in MARPOL 73/78, Consolidated Edition, 1991, IMO Publications, International Maritime Organization (IMO), 4 Albert Embankment, London SE1 7SR, England. (o) "Mobile transfer unit" means a marine fueling facility that is a vehicle, truck, trailer, tank car, or land based transportable tank, including all connecting hoses and piping, used for the transferring of oil at a location where a discharge could impact marine waters. (p) "Offshore marine terminal" means any marine terminal at which tank vessels or barges are made fast to a buoy or buoys. (q) "Oil" means any kind of petroleum, liquid hydrocarbons, or petroleum products or any fraction or residues therefrom, including, but not limited to, crude oil, bunker fuel, gasoline, diesel fuel, aviation fuel, oil sludge, oil refuse, oil mixed with waste, and liquid distillates from unprocessed natural gas. (r) "Onshore marine terminal" means any marine terminal at which tank vessels or barges are made fast to land structures or substantially land structures. (s) "Operator" when used in connection with vessels, marine terminals, pipelines, or facilities, means any person or entity which owns, has an ownership interest in, charters, leases, rents, operates, participates in the operation of or uses that vessel, terminal, pipeline, or facility. "Operator" does not include any entity which owns the land underlying the terminal or the terminal itself, where the entity is not involved in the operations of the terminal. (t) "Spill" or "discharge" means any release of oil into marine waters which is not authorized by any federal, state, or local government entity. (u) "Tank vessel" or "tanker" means any self-propelled, waterborne vessel, constructed or adapted for the carriage of oil in bulk or in commercial quantities as cargo. (v) "Terminal" means marine terminal. (w) "Terminal person in charge" or "TPIC" means an individual designated by the terminal operator as the person in charge of a particular oil transfer operation at a particular terminal. (x) "Threatened violation" means any threatened act, course of action or omission which, if carried out, in the opinion of an agent or employee of the Division authorized to make such a determination, would appear to be in violation of one or more of the provisions of Article 5. (y) "Transfer" means any movement of oil, including movements of bunker fuel, between the terminal and the vessel by means of pumping, gravitation or displacement. The term "transfer" also includes those movements of oil to, from or within any part of the terminal or vessel that are directly associated with the movement of oil or bunker fuel between the terminal and the vessel. (z) "Transfer area" means that part of a terminal through which oil product moves between a vessel and the first manifold or shut-off valve outside the terminal area as described in the terminal operations manual. (aa) "Transfer operations" means the following: (1) For all terminals, all activities carried out with regard to a transfer, including, but not limited to: (A) Preparation for transfer; (B) Hookup and disconnect of hoses, mechanical loading arms and any other equipment used for transferring oil; and (C) Steady pumping. (2) For offshore terminals: (A) All activities set forth in subsection (aa)(1) of this section; and (B) The procedures and maneuvers for mooring and unmooring of the tank vessel or barge to and from the buoy or buoys as described in the terminal operations manual. (bb) "Vessel" means every description of watercraft or other artificial contrivance, used or capable of being used, as a means of transportation on water and includes, but is not limited to, tank vessels and barges. (cc) "Vessel person in charge" or "VPIC" means the person in charge of the vessel's oil transfer operations. Note: Authority cited: Sections 8750, 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8756, Public Resources Code. s 2320. Inspections and Monitoring. (a) The Division shall carry out an inspection program which shall include the following: (1) At least once a year, the Division shall cause to be carried out an inspection of each marine terminal in the state to determine whether all parts of the terminal are being maintained and operated in such a manner to ensure the public health and safety and the protection of the environment and in accordance with the operations manual required, and approved under Section 2385 of these regulations and 33 CFR Part 154. (2) On a continuing basis in accordance with Chapter 31F of Divisions 1 through 11, Title 24, Part 2, Volume 1 of the California Code of Regulations, the Division shall carry out or cause to be carried out inspections and investigations of each onshore marine terminal in the state to determine whether the structural integrity of the terminal, the oil transfer operations system and the safety equipment are designed and being maintained in a safe working condition. (3) On a continuing basis, the Division shall monitor transfer operations at all terminals. (b) Every agent or employee of the Division shall, prior to the inspection of a marine terminal or monitoring of an oil transfer operation, or at the time the agent or employee arrives at the terminal or vessel to carry out inspection or monitoring activities, make every reasonable attempt to notify the TPIC or VPIC, as appropriate, of the intended activity. (c)(1) Every terminal operator shall provide to the Division access at any time to any and all parts of the operator's terminal. (2)(A) Every terminal operator shall provide to the Division access at any time to any and all documents, records, policies, guidelines and reports relating to terminal personnel training, testing, inspections, maintenance and operation of the terminal, including but not limited to, the following: 1. A copy of the terminal operator's letter of intent; 2. A copy of the state approved terminal operations manual with its letter of adequacy; 3. The name of each person currently designated as a TPIC at that terminal; 4. The date and result of the most recent test or examination of each item tested or examined as required by 33 CFR 156.170; 5. The hose information required by Section 2380, subsections (a)(1)(E), (F) and (G), including that marked on the hose; 6. The record of all inspections and examinations of the terminal by the U.S. Coast Guard and the Division within the last 3 years; 7. The record of all safety related inspections and examinations of the terminal by the State Fire Marshal local fire department or any port police within the last 3 years; 8. Any current permits to perform work of a hazardous nature issued pursuant to Section 2360; and 9. The Declaration of Inspection required by Section 2335. (B) If policies, guidelines and reports described in subsection (A) of this section for a particular terminal are not available at the terminal except in an office or other location which is open and reasonably accessible only during reasonable business hours, the terminal operator shall not be required to provide the Division access to those policies, guidelines and reports except during reasonable business hours. (C) No terminal operator shall be required to provide access to policies, guidelines and reports except during reasonable business hours, during transfer operations or during investigations resulting from emergency situations, including, but not limited to, oil discharge events or situations where an oil discharge involving the terminal may be imminent. (3) Each operator of any vessel shall provide to the Division access on board the vessel at any and all times the vessel is engaged in oil transfer operations at any terminal. Access shall be provided to any and all parts of the vessel necessary, as deemed by the employee or agent of the Division, to monitor any and all phases, aspects and parts of transfer operations for compliance with regulations of the State of California. (4) Access under subsections (c)(1), (2) and (3) of this section shall be provided without warrant or prior notification by the Division. (5)(A) If any duly authorized employee or agent of the Division is denied access, as specified in this section, to any part of the terminal or to any vessels at the terminal, the employee or agent shall immediately make every reasonable attempt to notify the TPIC or VPIC, whichever is appropriate, that access has been denied. (B) No terminal may be used in transfer operations with any vessel during any period where any duly authorized employee or agent of the Division is denied access to that vessel. (6) If any duly authorized employee or agent of the Division is denied access as specified under this section, the Division shall do all of the following: (A) Provide notification of the denial of access to the Coast Guard Marine Safety Office having jurisdiction; (B) Provide notification of the denial of access to the Administrator; and (C) Take whatever legal action is necessary or appropriate to obtain access. (d) In the event of an oil spill, the presence of any employee or agent of the Commission shall in no way relieve or alter any responsibility any operator of a terminal or vessel may have to report the discharge to the Office of Emergency Services, as required under Government Code Section 8670.25.5, and to comply with all applicable contingency plans and all requirements under the Government Code regarding response to oil spills. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8670.1 through 8670.70, Government Code; and Sections 8750, 8751, 8755 and 8756, Public Resources Code. s 2325. Notification. (a) Unless the Division and a terminal operator agree otherwise, at least four (4) hours, but not more than twenty four (24) hours, prior to the initiation of any transfer operation, the operator of the terminal where the transfer is to take place shall provide notice of the transfer to the Division. For barge operations, where the terminal operator has less than four (4) hours advance notice of the transfer, the terminal operator shall provide the Division with notice of the transfer as soon as possible after receiving notice of the anticipated transfer, but in any case prior to the initiation of transfer operations. (b) Notifications shall be made in person, by telephone or by facsimile machine to the local area Division field office. For terminals located north of the boundary between Monterey and San Luis Obispo Counties, notifications are to be made to the Division field office in Hercules, (510) 741-4950; facsimile number (510) 741-4975. For terminals located south of the boundary between Monterey and San Luis Obispo Counties, notifications are to be made to the Division field office in Long Beach, (562) 499-6348; facsimile number (562) 499-6355. (c) The notification shall include the following: (1) The location of the transfer; (2) The expected time of arrival of the vessel; (3) Time anticipated for initiation of the transfer operations; (4) The name of the tank vessel or barge involved,; and (5) The type or types of oil, oil products, or mixtures containing oil expected to be transferred, including, but not limited to, cargo, bunker fuel, slops and dirty ballast. (6) The approximate quantity of material being transferred under the categories of feedstock, product or slops. (d) The terminal operator or TPIC shall promptly notify the local area Division field office of any report or notification received from the VPIC, that the tank vessel berthed at the terminal for the purpose of conducting a transfer operation does not have the ability to move away from the berth, under its own power, within 30 minutes, as described in Section 2340, subsection (c)(28)(A). (e) The terminal operator or TPIC shall promptly notify the local area Division field office of any damage to structure or equipment at the terminal that is likely to impact public health and safety and the environment adversely, or is damage in excess of $50,000 in value. Examples of incidents which may cause reportable damage shall include, but not be limited to, impact from vessel, heavy weather, fire, explosion, equipment failure, acts of terrorism or seismic activity. Note: Authority cited: Sections 8751, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2330. Exchange of Information. (a) Exchange of Information Prior to a Vessel's Arrival at a Terminal. (1) Prior to arrival of a tank vessel or barge at the terminal, the terminal operator shall acquire from the tank vessel or barge or its owners, operators or agents, and the vessel's owner, operator or agent shall provide, all of the following items of information which are applicable: (A) Draft on arrival; (B) Maximum draft and trim expected during transfer operation; (C) Whether tank cleaning or crude oil washing will be undertaken; (D) Any repairs that could delay commencement of cargo transfer; (E) Manifold details, including type and size; (F) Quantity and nature of slops, dirty ballast to be transferred at the terminal and any contamination thereof by chemical additives; (G) Any defect of hull, machinery, piping, valves or other equipment which may: 1. Affect the safe maneuverability of the tank vessel or barge; or 2. Constitute a hazard to public health and safety and the environment; and (H) Any other information pertinent to mooring, transfer of vessel's stores and cargo transfer operations. (2) Prior to arrival at the terminal, the terminal operator shall provide, as applicable to the operator of the tank vessel or barge, information which shall include but not be limited to: (A) Least depth of water expected at the berth while the vessel will be at the berth; (B) The minimum number, length, size and material of mooring lines and emergency towing wires and accessories which the vessel should have available for mooring operations; (C) Manifold, hose and mechanical loading arm details, including, but not limited to, type and size, used for oil transfer; (D) Details and requirements concerning any vapor control system; (E) Terminal requirements for crude oil washing and tank cleaning procedures; (F) Any arrangements for the reception of slop or oil ballast residues; (G) Any particular features of a dock or mooring or any significant damage which is considered essential to bring to the notice of the Master of the tank vessel, crew of the barge, Pilot or Mooring Master; (H) At offshore terminals, the number of tugs required and the number of mooring support vessels that will be provided for mooring and unmooring operations; (I) At offshore terminals information on wind, sea, swell, current, tide, visibility and load limitations and terminal restrictions including conditions under which mooring will not be permitted and conditions requiring cessation of transfer operations and departure from the moorings; and (J) Any other information pertinent to available port services, mooring and cargo transfer operations. (b) Exchange of Information upon Arrival (Pre-transfer Conference). (1) Transfer operations shall not commence until both persons in charge are present and mutually agree to commence transfer operations after having conducted a pre-transfer conference and completed the declaration of inspection. (2) The TPIC and VPIC shall hold a pre-transfer conference, to ensure that each person in charge clearly understands all information and agrees to all procedures necessary for a safe and pollution-free transfer operation. (3) Those matters to be addressed in the pre-transfer conference shall include, but not be limited to, detailed information concerning the following: (A) The quantities and temperatures of the products to be transferred; (B) The cargo information listed in Section 2385, subsection (d)(2)(E) for the products to be transferred; (C) The transferring and receiving systems, including, but not limited to, the following: 1. The sequence of transfer operations; 2. Maximum allowable working pressure; 3. Maximum allowable product temperature; 4. The control of line pressures; 5. The location of pressure gauges; 6. Settings of relief valves and the direction of their discharge; 7. Communications between vessel and terminal to compare and confirm quantities transferred and received; 8. Limitations on the movement of loading hoses and mechanical loading arms; 9. The initial, maximum and topping off transfer rates; 10. Tank changeover procedures; 11. Topping off procedures; 12. Transfer shutdown procedures; and 13. Signals to be used for standby, slowdown transfer rate, stop transfer, and emergency shutdown in case of a breakdown of communications systems; 14. If any part of the transfer is to be by gravity, the maximum marine terminal transfer rate possible using gravity; and 15. If the transfer is expected to take less than an hour, the approximate anticipated length of time needed for the transfer. (D) Critical stages of the transfer operation; (E) Federal, state, and local rules that apply to the transfer of oil; (F) Emergency procedures; (G) Discharge containment procedures; (H) Discharge reporting procedures and requirements; (I) Watch or shift arrangement; (J) Frequency and means of checking that communications systems are operating effectively; and (K) Minimum underkeel clearance required by the terminal operator. (4) In addition to the requirements of subsection (b)(3) of this section, the TPIC and VPIC shall verify the following during the pre-transfer conference: (A) The name or title and location of each person participating in the transfer operation; (B) That vessel's cargo tanks which are required by the Coast Guard to be inerted have an oxygen content in the vapor space of cargo tanks of 8 percent by volume or less; (C) That inerted tanks will remain inerted throughout the transfer operation or, if not, that Coast Guard approved alternate safety procedures will be employed; (D) Whether tank cleaning or crude oil washing will be conducted during the transfer operation; (E) The number and sizes of hose connections or loading arms to be used; (F) Arrangements for the transfer of slops and oily ballast residues; and (G) The maximum transfer rate of vapor control systems used during the transfer operation. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. s 2335. Declaration of Inspection. (a) No person may transfer oil to or from a vessel unless both the TPIC and VPIC have filled out and signed a declaration of inspection described in subsection (c) of this section. (b) No person in charge may sign the declaration of inspection unless he or she has determined by visual inspection, unless visual inspection is precluded, and indicated by initialling in the appropriate space on the declaration of inspection form, that the terminal, vessel, or both, as appropriate, meets the requirements of Section 2340. (c) The declaration of inspection may be in any form, but must contain at least the following: (1) The name or other identification of the transferring vessel and the terminal; (2) The address of the terminal; (3) A list of the requirements in Section 2340, subsection (c), with each requirement set forth separately and with spaces on the form following each requirement for the person in charge of the vessel, terminal, or both, as appropriate, to indicate by initialling that the requirement is met for the transfer operation; and (4) A space for the date, time of signing, signature, and title of each person in charge during transfer operations on the transferring vessel or terminal and space for the date, time of signing, signature, and title of each person in charge during transfer operations on the receiving terminal or vessel. (d) On completion of the transfer operation the TPIC and VPIC shall annotate the declaration of inspection with: (1) The date and time of hookup for the transfer operation; and (2) The date and time of disconnection upon completion of the cargo transfer; (e) The VPIC and TPIC shall each have a signed copy of the declaration of inspection available for inspection by any employee or agent of the Division during the transfer operation. (f) Each TPIC and VPIC who is different from the person who originally signed the declaration of inspection shall sign the declaration of inspection before assuming or re-assuming the duties of a person in charge. Prior to their signing or re-signing the declaration of inspection, each person in charge shall inspect the terminal or vessel, as appropriate, to ensure that the requirements of Section 2340, are being maintained. (g) The terminal operator shall retain a signed copy of the declaration of inspection for at least three (3) years from the date of signature. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2340. Requirements for all Transfer Operations. (a) No operator, crew member or personnel of a vessel or terminal shall carry out or perform any willful or negligent act or omission which causes the entry of any amount of oil into marine waters during any transfer operation. (b)(1) Unless, because of emergencies or unanticipated circumstances, doing so would harm public health or safety or the environment, all transfer operations shall be conducted in accordance with the terminal operations manual approved under s 2385 of these regulations or vessel transfer procedures required by 33 CFR 155.720, as appropriate, and with the mutual agreements and understanding established during the pre-transfer conference. (2) Notwithstanding the provisions of subsection (b)(1) of this section, in circumstances where for operational or safety reasons the sequence of transfer operations or any other conditions or procedures agreed to in the pre-transfer conference are to be changed, the TPIC and VPIC shall, prior to continuation of the transfer operation, confer with each other to ensure that each person in charge clearly understands all information regarding the changes and agrees to all procedures necessary for continuation of a safe and pollution free transfer operation. (c) The respective requirements with which the terminal and vessel must comply and which must be set forth on the declaration of inspection and initialled separately by both the TPIC and VPIC or both, as appropriate, as required by Section 2335, shall include, but not be limited to, the following: (1) The vessel's moorings are strong enough to hold during all expected conditions of surge, current, and weather that are long enough to allow adjustment for changes in draft, drift, and tide during the transfer operation. (2) Transfer hoses and loading arms are long enough to allow movement of the vessel while secured at the berth without placing strain on the hose, loading arm, or transfer piping system. (3) To prevent kinking or other damage to the hose and strain on its coupling, each hose is supported in accordance with the operational recommendations of the "HOSE TECHNICAL INFORMATION BULLETIN: No. IP-11-4." (4) Each party of the transfer system is aligned to allow the flow of oil. (5) Each part of the transfer system not necessary for the transfer operation is securely blanked off. Each test cock, sampling or bleeder valve is closed and securely capped. (6) The end of each hose, loading arm and manifold that is not connected for the transfer of oil is blanked off with a bolt in at least every other hole and in no case less than four (4) bolts. (7) The transfer system is attached to a fixed connection on the vessel and the terminal. (8) Except when used to receive ballast as agreed within the pre-transfer conference, each overboard discharge or sea suction valve that is connected to the vessel's transfer or cargo tank system is sealed or lashed in the closed position. (9) Each transfer hose has no unrepaired loose covers, kinks, bulges, soft spots, or other defect which would permit the discharge of oil through the hose material and no gouges, cuts, or slashes that penetrate any layer of hose reinforcement. "Reinforcement" means the strength members of the hose, consisting of fabric, cord or metal. (10) Each hose or loading arm in use meets the requirements of Section 2380, subsections (a) and (b), respectively. (11) Each connection meets the requirements of Section 2380, subsection (d). (12) Any monitoring devices used to detect or limit the size of a discharge of oil, if installed, are operating properly. (13) The small discharge containment equipment for the terminal, required by Section 2380, subsection (f), is readily accessible or deployed as applicable and will be periodically drained as required by subsection (g) of Section 2380. (14) The discharge containment equipment for the vessel is in place and will be periodically drained to provide the required capacity. (15) Each drain and scupper is securely closed by mechanical means. (16) All connections in the transfer system are leak free, except that a component in the transfer system, such as the packing glands of a pump which cannot be made leak free, shall not leak at a rate that exceeds the capacity of the discharge containment provided during the transfer operation. (17) The communications required by Section 2370 are operable for the transfer operation. (18) The emergency means of shutdown for the terminal, required by Section 2380, subsection (h) and the emergency means of shutdown for the vessel required by 33 CFR 155.780 are in position and operable. (19) There is a TPIC and a VPIC, and each: (A) Meets the appropriate requirements of Section 2375 for persons in charge; (B) Is at the site of the transfer operation and immediately available to the transfer personnel; (C) Has ready access to a copy of the terminal operations manual or vessel transfer procedures, as appropriate; and (D) Conducts the transfer operation in accordance with the terminal operations manual or vessel transfer procedures, as appropriate. (20) The personnel required, under the terminal operations manual and the vessel transfer procedures, to conduct the transfer operation: (A) Are on duty; and (B) Conduct the transfer operation in accordance with the terminal operations manual or vessel transfer procedures, as appropriate. (21) At least one person is at the site of the transfer operation who fluently speaks the language or languages spoken by both persons in charge. (22) The TPIC and VPIC of transfer operations have held a pre-transfer conference as required by Section 2330, subsection (b). (23) The TPIC and VPIC of transfer operations agree when the transfer operation is to begin. (24) If any part of the transfer operation may take place between sunset and sunrise or during periods of reduced visibility, the lighting required by Section 2365 will be provided. (25) A transfer operation which includes collection of vapor emitted from a vessel's cargo tanks through a vapor control system not located on the vessel must have the following verified by the TPIC: (A) Each manual valve in the vapor collection system is correctly positioned to allow the collection of cargo vapor. (B) A vapor collection hose or arm is connected to the vessel's vapor connection. (C) The electrical insulating device required under subsections (b) and (c) of Section 2341, is fitted between the terminal vapor connection and the vessel vapor connection. (D) The initial loading rate and the maximum transfer rate are confirmed by the TPIC and VPIC. (E) The maximum and minimum operating pressures at the terminal vapor connection are confirmed by the TPIC and VPIC. (F) The barge overfill control system, if compatible with the connection to the terminal, is connected to the terminal, is tested, and is operational. (G) The following have been performed not more than 24 hours prior to the start of the transfer operation: 1. Each alarm and automatic shutdown system has been tested and found to be operating properly; and 2. Hydrocarbon gas and oxygen analyzers have been checked for calibration by use of a span gas. (H) Each vapor control hose has no unrepaired loose covers, kinks, bulges, soft spots, or any other defect which would permit the discharge of vapor through the hose material, and no external gouges, cuts, or slashes that penetrate any layer of hose reinforcement. (I) The oxygen content of the tank vessel's cargo tanks, if inerted, is at or below 8 percent by volume. (26) Fire fighting equipment required in Section 2345 is in readiness. (27) Where required, the spill containment provisions of sections 2395 and 2396 are being complied with. (28) The tank vessel has either of the following capabilities: (A) The tank vessel's boilers, main engines, steering machinery and other equipment essential for maneuvering are maintained in a condition so that the tank vessel has the capability to move away from the berth within 30 minutes under its own power; or (B) Where the tank vessel does not have the capability specified in Section 2340, subsection (c)(28)(A), appropriate tug assistance is available so that the tank vessel can be moved away from the berth within 30 minutes. (29) Operations and practices are carried out in compliance with the following recommendations in ISGOTT: (A) Emergency towing wires are rigged forward and aft and the ends maintained not greater than 5 feet above the water (chapter 3). (B) Precautions regarding openings in superstructures are being observed (chapter 6). (C) Precautions regarding flame screens are being observed (chapter 6). (D) Precautions regarding unauthorized craft alongside a tank vessel or barge are being observed (chapter 6). (E) Precautions regarding entry to pumprooms, pumproom ventilation and bilges, are being observed (chapter 2). (30) The requirements of s 2341 to prevent electrical arcing at onshore terminals are being complied with. (31) The tank vessel is in compliance with the ISM Code and has on board a Document of Compliance and a Safety Management Certificate. A tank vessel of a country not party to Chapter IX of SOLAS has on board current valid documentation showing that the vessel's company has a safety management system which has been audited and assessed consistent with the ISM Code. The requirement to be certified under the ISM Code does not apply to barges. (d) No person shall conduct an oil transfer operation unless the TPIC and VPIC have: (1) Conducted the pre-transfer conference required under Section 2330, subsection (b); (2) Ensured that transfer connections have been made as specified in Section 2380, subsection (d); (3) Ensured that discharge containment equipment on the terminal and on or around the tank vessel or barge required under Sections 2380 and 2395 are in position or on stand-by, as appropriate; and (4) Filled out and signed the Declaration of Inspection as required by Section 2335, subsection (a). (e) No TPIC shall conduct a transfer operation with a tank vessel unless the tank vessel has either one of the capabilities of moving away from the berth within 30 minutes, as specified in Section 2340, subsection (c)(28). (f) During all transfer operations, the TPIC shall be in attendance at the terminal. (g) Each TPIC shall ensure that the means of operating the emergency shutdown is continually manned so that it can be activated in 30 seconds or less, as required in Section 2380, subsection (h)(5), while oil is being transferred between the terminal and the vessel. (h) Each person conducting an oil transfer shall stop the transfer operation whenever oil from any source is discharged into the water or upon the adjoining shoreline. The transfer operation shall not resume unless authorized by the U.S. Coast Guard and the operator has complied with, or is complying with, the contingency plan approved by the Administrator for the terminal where the transfer is taking place. (i)(1) Each person conducting a transfer operation shall stop the transfer operation whenever oil from any source is leaked onto the transfer operation work area, but not in the water, and shall not resume the transfer operation until after both of the following are completed: (A) The oil leaked into the oil transfer work area has been cleaned up; and (B) All necessary preventive measures have been taken to ensure that a similar leak of oil does not recur. (2) Transfer operations need not be stopped under subsection (i) of this section if all of the following occur: (A) The leak is directly into the small discharge containment of the terminal or the discharge containment aboard the vessel; (B) No oil is displaced outside of the small discharge containment of the terminal or the discharge containment of the vessel; and (C) Immediate corrective action is taken to stop the leakage of oil. (j) Notwithstanding the provisions of subsections (h) and (i) of this section, the transfer operation may resume or may continue without interruption if both of the following occur: (1) Continuation or resumption of the transfer operation is necessary to avoid further discharge of oil; and (2) Both the TPIC and VPIC agree that continuation or resumption is necessary to avoid further discharge of oil. (k) The provisions of subsections (h), (i) and (j) of this section are subject to any direction by the Administrator issued directly in response to the discharge into the water. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2341. Requirements to Prevent Electrical Arcing at Onshore Terminals. (a) Insulating Flange Joint. For the purpose of this section, an "insulating flange joint" means a typical insulating flange joint as described in Appendix D of ISGOTT or any other insulating flange that meets the electrical resistance requirements of subsection (e) of this section. (b) Insulating Flange Joints on Metallic Cargo or Vapor Control Arms. Each metallic cargo or vapor control arm used during a transfer operation shall be fitted with an insulating flange joint to ensure electrical discontinuity between the terminal and vessel. All metal on the vessel's side of the insulating flange joint shall be electrically continuous to the vessel and that on the terminal's side shall be electrically continuous to the terminal's grounding system. (c) Cargo and Vapor Control Hose Connections. Each cargo hose string or vapor control hose used during a transfer operation shall have either an insulating flange joint or a single length of non-conducting hose to ensure electrical discontinuity between the terminal and vessel. All metal on the vessel's side of the non-conducting length of hose shall be electrically continuous to the vessel and that on the terminal's side shall be electrically continuous to the terminal's grounding system. (d) Testing of Insulating Flange Joints. (1) The terminal operator shall test or cause to be tested each insulating flange joint by measuring the electrical resistance between the metal pipe on the terminal side of the flange joint and the end of the hose or metal arm when freely suspended. Such tests shall be conducted at intervals not exceeding three months. (2) At terminals which conduct infrequent transfers of oil and the interval between transfers exceeds three months, the test specified in subsection (d)(1) of this section need not be conducted at intervals not exceeding three months. However, such test shall be conducted no more than 7 days prior to the connection of any metallic loading or vapor recovery arm or hose string for the purpose of transferring oil. (3) The terminal operator shall maintain records of test dates, measured electrical resistance and name and designation of person conducting the test at the terminal for a period of at least one year from the date of testing. (e) Insulating Flange Joints: Minimum Resistance. No insulating flange joint whose measured electrical resistance is less than 1000 ohms shall be used in any metallic cargo or vapor recovery arm or hose string connection between the terminal and a vessel. (f) Vessel-to-shore Electrical Bonding Cables. No vessel-to-shore electrical bonding cables or wires shall be used for a transfer operation. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2345. Fire Prevention for Transfer Operations. (a) Immediately before or on arrival at a terminal at which it is intended to conduct an oil transfer operation, fire hoses shall be connected to the tank vessel's fire main, one forward and one aft of the tank vessel's manifold. Where monitors are provided, they shall be pointed towards the manifold and be ready for immediate use. (b) At least two type B-II portable fire extinguishers shall be placed near the manifold, one forward and one aft of the manifold. (c) When oil is being transferred, pressure shall be maintained on the tank vessel's fire main from the tank vessel's fire pump. Where this is impracticable, the tank vessel's fire pump shall be in a standby condition and ready for immediate use. Fire mains shall be pressurized or be capable of being pressurized within 2 minutes. (d) The vessel's fire extinguishing equipment shall be operational and ready for immediate use. (e) No packaged cargo or vessel's stores may be transferred between the terminal and the vessel during a transfer operation unless authorized by both the TPIC and VPIC. When authorizing transfers under this subsection, the TPIC and VPIC shall consider any potential risk of fire or explosion. (f) Blending of two or more oil products in any tank or tanks of a tank vessel or barge alongside a terminal by the introduction of pressurized air shall not be permitted. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2350. Unauthorized Visitors. (a) Except for authorized agents or employees of federal, state or local governmental entities, anyone who does not have the TPIC's permission shall not be allowed access to the terminal. (b) Except for authorized agents or employees of federal, state or local governmental entities, anyone who does not have the VPIC's permission shall not be allowed access to the vessel. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2351. Marine Terminal Physical Security Program. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2355. Warning Signs. (a) Vessel Warning Signs. Any vessel berthed at a terminal for the purpose of conducting a transfer operation shall display warning signs and notices indicating emergency escape routes as recommended in chapter 4 of ISGOTT. (b) Terminal Warning Signs. The terminal operator shall ensure that: (1) Permanent notices and signs indicating that smoking and naked lights are prohibited are conspicuously displayed in the terminal and on the berth and similar permanent notices and signs are displayed at the entrance to the terminal area or shore approaches to the berth; (2) In buildings and other shore locations where smoking is allowed, appropriate notices are conspicuously displayed; and (3) Emergency escape routes from the tank vessel berth to a safe place on the shore are clearly indicated. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2360. Precautions for Performing Hot Work. (a) Hot Work on Terminal. No construction, repair, maintenance, dismantling or modifications of facilities which include hotwork shall be carried out at a terminal without the written permission of the terminal operator. If a tank vessel or barge is moored at the terminal, the written agreement of the Master or the VPIC, as appropriate, shall also be obtained if the work is on the berth. The person or entity performing such work shall ensure that work does not commence until written permission is obtained. (b) Hot Work on Tank Vessel or Barge. (1) When any repair or maintenance is to be done on board a tank vessel or barge alongside a terminal, the Master or VPIC shall inform the terminal operator. Agreement shall be reached on the safety precautions to be taken, with due regard to the nature of the work. (2) Hot work on board a tank vessel or barge shall be prohibited unless all applicable regulations and safety requirements of the National Fire Protection Association's Standard for Fire Prevention in Use of Cutting and Welding Processes - NFPA 51B, 1994, NFPA, 1 Batterymarch Park, Quincy, MA 02269-9101 have been met. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2365. Lighting. (a) Except as provided in subsection (c) of this section, for all transfer operations between sunset and sunrise and during times of reduced visibility, a terminal shall have fixed lighting that adequately illuminates the following: (1) Each transfer connection point on the terminal; (2) Each transfer connection point in use on any barge moored at the terminal to or from which oil is being transferred; (3) Each transfer operations work area on the terminal; and (4) Each transfer operations work area on any barge moored at the terminal to or from which oil is being transferred. (b) Where the illumination appears to the Division to be inadequate, the Division may require verification by instrument of the levels of illumination. On a horizontal plane 3 feet above the barge deck or walking surface, illumination must measure at least: (1) 5.0 foot candles at transfer connection points; and (2) 1.0 foot candle in transfer operations work areas. (c) For small remote facilities, the Division may authorize operations with an adequate level of illumination provided by the vessel or by portable means. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2370. Communications. (a) Each terminal shall have a means that enables continuous two-way voice communication between the TPIC and the VPIC. (b) The means required by subsection (a) of this section shall be usable and effective in all phases of the transfer operation and all conditions of weather at the terminal. (c) A terminal may use the voice communications system for emergency shutdown specified in Section 2380, subsection (h)(6)(B), to meet the requirement of subsection (a) of this section. (d) An alternate continuous two-way voice communication system shall be available in the event that the primary communications system is disabled. (e) Portable radio devices used in compliance with this section shall be intrinsically safe, as defined in the Institute of Electrical and Electronics Engineers Standard Dictionary, 1984 edition, published by the Institute of Electrical and Electronics Engineers, available from the American Society of Mechanical Engineers, 22 Law Drive, Box 2300, Fairfield, New Jersey, and meet Class I, Division I, Group D requirements as defined in the National Electric Code, Article 500, 1996 edition, published by NFPA, 1 Batterymarch Park, P.O. Box 9101, Quincy, Massachusetts 02269-9101. (f) The means of communication shall be continuously manned during a transfer operation by a person or persons who can immediately contact the TPIC and VPIC. (g) If the means of communications has not been used within a period of 60 minutes during a transfer operation, the means of communications shall be checked to ensure that it is operative. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2375. Requirements for Persons in Charge. (a) Terminal Person in Charge (TPIC). (1) The TPIC of oil transfer operations shall have successfully complied with all of the following: (A) A program of operations and supervisory personnel training as prescribed in 2 CCR s 2542(e); (B) A testing and evaluation procedure to qualify for certification as prescribed in 2 CCR s 2545(f); (C) Recertification as prescribed in 2 CCR s 2545(g), as appropriate; (D) At least 48 hours of experience in oil transfer operations, including a minimum of 6 connections and transfers and 6 transfers and disconnects; and (E) Sufficient experience at the terminal for the terminal operator to determine that this experience is adequate for being in charge of oil transfer equipment and procedures. (2) The terminal operator shall ensure that each TPIC has valid documentation to authenticate that the requirements of subsections (a)(1)(A) through (E) of this section have been met. (3) The terminal operator shall designate in writing each person authorized to serve as a TPIC and advise the Division, in writing, of his or her designation. (4) Each TPIC shall carry evidence of their authorization to serve as a TPIC when they are engaged in transfer operations, unless such evidence is immediately available at the terminal. (b) Vessel Person in Charge (VPIC). (1) For the purpose of this subsection, a "PIC" means Person in Charge. (2) The operator of a tank vessel or barge with a capacity of 250 or more barrels of oil, shall designate, in writing, a person in charge of each transfer operation. (3) The VPIC of oil transfer operations shall have sufficient training and experience with respect to the cargo to be transferred and the relevant characteristics of the vessel or barge on which he or she is engaged, including, but not limited to, the cargo system, cargo containment system, transfer procedures, shipboard emergency equipment and procedures, control and monitoring systems, procedures for reporting pollution incidents, and, if installed, Crude Oil Washing (COW), inert gas, and vapor control systems, to conduct a transfer of oil safely. The minimum qualifications necessary to be designated as VPIC are those set forth in this Article 5 and 33 CFR 155.710. (4) Each designated VPIC of a tank vessel documented under the laws of the United States shall: (A) Hold a license issued under 46 CFR Part 10 authorizing service aboard a vessel certified for voyages beyond any Boundary Line described in 46 CFR Part 7, except on tank vessels not certified for voyages beyond the Boundary Line; and (B) Hold a Tankerman-PIC endorsement issued under 46 CFR Part 13 that authorizes the holder to supervise the transfer of oil or liquid cargo in bulk. (5) Each designated VPIC of a tank barge required to be inspected under Title 46, of the United States Code, Section 3703, shall hold a Tankerman-PIC or Tankerman-PIC (Barge) endorsement issued under 46 CFR Part 13 that authorizes the holder to supervise the transfer of oil or liquid cargo in bulk. (6) Each designated VPIC of a foreign tank vessel shall: (A) Hold a license or other document issued by the flag state or its authorized agent authorizing service as master, mate, pilot, engineer, or operator on that vessel; (B) Hold a Dangerous-Cargo Endorsement or Certificate issued by a flag state party to the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers, 1978 (STCW), or other form of evidence attesting that the VPIC meets the requirements of Chapter V of STCW as a PIC of the transfer of oil or liquid cargo in bulk; (C) Be capable of reading, speaking, and understanding in English, or a language mutually agreed upon with the TPIC, all instructions needed to commence, conduct, and complete a transfer of oil, or a liquid cargo in bulk, except that the use of an interpreter meets this requirement if the interpreter: 1. Fluently speaks the language spoken by each PIC; 2. Is immediately available to the VPIC on the tank vessel at all times during the transfer; and 3. Is knowledgeable about, and conversant with terminology of tank vessels and transfers; and (D) Be capable of effectively communicating with all crew members involved in the transfer, with or without an interpreter. (7) Each designated VPIC of foreign tank barge shall: (A) Hold a Dangerous-Cargo Endorsement or Certificate issued by a flag state party to STCW, or other form of evidence attesting that the VPIC meets the requirements of Chapter V of STCW as a PIC of the transfer of oil; (B) Be capable of reading, speaking, and understanding in English, or a language mutually agreed upon with the TPIC of the transfer, all instructions needed to commence, conduct, and complete a transfer of oil or liquid cargo in bulk, except that the use of an interpreter meets this requirement if the interpreter: 1. Fluently speaks the language spoken by each PIC; 2. Is immediately available to the VPIC on the tank barge at all times during the cargo transfer; and 3. Is knowledgeable about, and conversant with terminology of, tank vessels, barges and transfers; and (C) Be capable of effectively communicating with all crew members involved in the transfer, with or without an interpreter. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2376. Limitations on Hours of Work for Terminal Personnel. (a) For the purpose of this section, the term "work" includes any operational or administrative duties associated with a marine terminal. (b) Except in an emergency or a drill, no TPIC or terminal personnel engaged in transfer operations shall be permitted to work more than 16 hours in any 24 hour period, or more than 40 hours in any 72 hour period, or more than 72 hours in any period of seven consecutive days. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Sections 8750, 8751, 8752 and 8755, Public Resources Code. s 2380. Equipment Requirements: Testing and Inspections. (a) Hose Assemblies. (1) Each hose assembly used for transferring oil shall meet the following requirements: (A) The minimum design burst pressure for each hose assembly shall be: 1. At least 600 pounds per square inch; and 2. At least four times the sum of the pressure of the relief valve setting (or four times the maximum pump pressure when no relief valve is installed) plus the static head pressure of the transfer system at the point where the hose is installed. (B) The maximum allowable working pressure (MAWP) for each hose assembly shall be more than the sum of the pressure of the relief valve setting (or the maximum pump pressure when no valve is installed) plus the static head pressure of the transfer system at the point where the hose is installed. (C) Each nonmetallic hose shall be usable for oil service. (D) Each hose assembly shall have one of the following: 1. Full threaded connections; 2. Flanges that meet standard B16.5, Steel Pipe Flanges and Flange Fittings, 1988, or standard B16.24, Brass or Bronze Pipe Flanges, 1979, of the American National Standards Institute (ANSI), available from the American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2300, Fairfield, New Jersey 07007-2300; or 3. Quick disconnect couplings that either meet ASTM F-1122, Standard Specifications for Quick Disconnect Couplings, published in 1987 by the American Society for Testing and Materials, 1916 Race Street, Philadelphia, Pennsylvania 19103-1187 or have been accepted by the U.S. Coast Guard. (E) Except as provided in subsection (F) of this section, each hose shall be marked near the two ends in the vicinity of the flanges, where it can best be seen, with the following: 1. Any of the following: a. The name of each product for which the hose may be used; b. For oil products, the words "OIL SERVICE"; or c. For hazardous materials, the words "HAZMAT SERVICE - SEE LIST" followed immediately by a letter, number or other symbol that corresponds to a list or chart contained in the terminal's operations manual or the vessel's transfer procedure documents which identifies the products that may be transferred through a hose bearing that symbol; 2. Maximum allowable working pressure; 3. Date of manufacture; and 4. Date of the latest annual test required by either 33 CFR 156.170 or subsection (a)(2) of this section, whichever is later. Dates of previous tests shall be obliterated. (F) The information required by subsections (a)(1)(E)3. and (a)(1)(E)4. of this section need not be marked on the hose if it is recorded in the hose records of the terminal or vessel and the hose is marked to identify it with that information. (G) The hose burst pressure and the pressure used for the test required by 33 CFR 156.170 shall not be marked on the hose and shall be recorded elsewhere at the terminal. (H) Each non-conducting length of hose used for transferring oil or for vapor control at onshore terminals shall be clearly marked "NON-CONDUCTING" where it can best be seen. (2) Each hose used for transferring oil shall be inspected, maintained, handled, stored and tested in accordance with the recommended practices in "HOSE TECHNICAL INFORMATION BULLETIN: No. IP-11-4," except that the frequency of periodic hose testing shall be in accordance with 33 CFR 156.170 and subsections (A), (B) and (C) of this section. (A) All new hose and hose which has undergone a coupling repair shall be tested before it is placed in service. (B) Hose assemblies subjected to severe end pull, flattening, crushing or sharp kinking shall be immediately inspected and subjected to a pressure test, and if applicable, an electrical continuity test. (C) The following tests shall be conducted at intervals not to exceed twelve months: 1. A hydrostatic pressure test; 2. A vacuum test for hoses which have an inner tube liner; and 3. For electrically continuous lengths of hoses, an electrical continuity test which may be performed at the same time as the tests in subsection (d) of s 2341 of this Article 5. (b) Loading Arms. (1) Each mechanical loading arm used for transferring oil and placed into service after June 30, 1973, shall meet the design, fabrication, material, inspection, and testing requirements in American National Standards Institute (ANSI) B31.3, published in 1990 and available from the American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2300, Fairfield, New Jersey 07007-2300. (2) The manufacturer's certification that the standard American National Standards Institute (ANSI) B31.3 has been met shall be permanently marked on the loading arm or recorded elsewhere at the terminal with the loading arm marked to identify it with that information. (3) Each mechanical loading arm used for transferring oil shall have a means of being drained or closed before being disconnected. (4) Each mechanical loading arm shall be marked where it can best be seen, with the following: (A) Maximum allowable working pressure; and (B) Date of the latest annual test required by 33 CFR 156.170; dates of previous tests shall be obliterated. (5) Each mechanical loading arm shall have its maximum allowable lateral movement envelope limits conspicuously marked on the terminal at the position of the loading arm. The allowable extension limits of the loading arm shall also be indicated visibly. (c) Closure Devices. The terminal shall have sufficient blank flanges or other means acceptable to the Division to blank off the ends of each hose or loading arm that is not connected for the transfer of oil. New, unused hose is exempt from this requirement. (d) Connection. (1) Each person who makes a bolted connection for transfer operations shall: (A) Use suitable material in joints and couplings to ensure a leak-free seal; (B) Use a bolt in every hole; (C) Use bolts of the correct size in each bolted connection; and (D) Tighten each bolt and nut uniformly to distribute the load sufficiently and to ensure a leak free seal. (2) A person who makes a connection for transfer operations shall not use any bolt that shows signs of strain or is elongated or deteriorated. (3) Except as provided in subsection (4) of this section, no person may use a connection for transfer operations unless it is: (A) A bolted or full threaded connection; or (B) A quick disconnect coupling that either meets American Society for Testing and Materials (ASTM) F-1122, Standard Specifications for Quick Disconnect Couplings, published in 1987 by the American Society for Testing and Materials, 1916 Race Street, Philadelphia, Pennsylvania 19103-1187 or has been accepted by the U.S. Coast Guard. (4) No person may transfer oil to a vessel that has a fill pipe for which containment cannot practically be provided unless an automatic back pressure shutoff nozzle is used. (e) Monitoring Devices. Monitoring devices shall be installed and maintained at the terminal if required by the U.S. Coast Guard Captain of the Port. (f) Small Discharge Containment. (1) Except as provided in subsections (3) and (4) of this section, an onshore terminal shall have fixed catchments, curbing, or other fixed means to contain oil discharged at the following locations: (A) Each hose handling and loading arm area (that area on the terminal that is within the area traversed by the free end of the hose or loading arm when moved from its normal stowed or idle position into a position for connection); and (B) Each hose connection manifold area. (2) The discharge containment means required by subsection (f)(1) of this section shall have a capacity of at least: (A) Two barrels if it serves one or more hoses of 6-inch inside diameter or smaller or one or more loading arms of 6-inch nominal pipe size diameter or smaller; (B) Three barrels if it serves one or more hoses with an inside diameter of more than 6 inches, but less than 12 inches, or one or more loading arms with a nominal pipe size diameter of more than 6 inches, but less than 12 inches; or (C) Four barrels if it serves one or more hoses of 12-inch inside diameter or larger or one or more loading arms of 12-inch nominal pipe size diameter or larger. (3) The terminal may use portable means of not less than 1/2 barrel capacity each to meet the requirements of subsection (f)(1) of this section for part or all of the terminal if the Division finds that fixed means to contain oil discharges are not feasible. (4) A mobile transfer unit, may use portable means of not less than five gallons capacity to meet the requirements of subsection (f)(1) of this section, when conducting transfer operations to or from tank vessels or barges. (g) Discharge Removal. (1) Each onshore terminal and each mobile transfer unit shall have a means to remove discharged oil from the containment system required by subsection (f)(1) of this section safely and quickly without discharging the oil into the water. (2) Each onshore terminal and each mobile transfer unit shall safely remove discharged oil from the containment system within one hour of the completion of any transfer. (h) Emergency Shutdown. (1) The terminal shall have an emergency means to shutdown and stop the flow of oil from the terminal to the tank vessel or barge. (2) A point in the transfer system at which the emergency means stops the flow of oil on the terminal shall be located near the dock manifold connection to minimize the loss of oil in the event of the rupture or failure of the hose, loading arm, or manifold valve. (3) For oil transfers, the means used to stop the flow under the subsection (h)(1) of this section shall stop that flow within: (A) 60 seconds on any terminal or portion of a terminal that first transferred oil on or before November 1, 1980; and (B) 30 seconds on any terminal that first transfers oil after November 1, 1980. (4) The VPIC and TPIC shall each be capable of ordering or activating the emergency shutdown. (5) If the VPIC or TPIC orders an emergency shutdown, the shutdown shall be capable of being activated and shall be activated within 30 seconds of the order. (6) To meet the requirements of subsections (h)(4) and (5) of this section, the means to stop the flow of oil shall be either of the following: (A) An electrical, pneumatic or mechanical linkage to the terminal; or (B) A voice communications system continuously operated by a person on the terminal who at all times during the transfer can hear the communications and can, at any time, activate the emergency shutdown. (i) Vapor Control Systems. Any vapor control system at any marine terminal shall meet the following requirements of: (A) 2 CCR ss 2550 through 2556; (B) 33 CFR Part 154, Subpart E; and (C) Any other state and federal regulations governing vapor control systems. Note: Authority cited: Sections 8750, 8751, 8752, 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2381. Hose Tests. Note: Authority cited: Sections 8755, 8756 and 8758, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756, 8757 and 8758, Public Resources Code. s 2385. Operations Manuals. (a) Operations Manual Requirements. (1) No terminal may conduct transfer operations except in accordance with an operations manual approved by the Division. (2) Operators of terminals shall maintain their operations manual so that it is: (A) Current; and (B) Readily available for examination by the Division. (3) Operators of terminals shall ensure that a sufficient number of copies of their operations manual are readily available for each TPIC and VPIC while conducting a transfer operation. (b) Letter of Intent. (1) Any person who proposes to install a new marine terminal or proposes to assume control over the operation of an existing marine terminal shall, not less than 60 days prior to the intended assumption of operations, submit a letter of intent to operate the terminal to the Division. (2) The letter of intent required by subsection (b)(1) of this section may be in any form, but shall at least include the following: (A) The name, address, telephone number and facsimile number of the terminal operator; (B) The name, address, berth number, telephone number and facsimile number (if any) of the terminal; (C) The proposed operations manual for the terminal; and (D) The proposed oil spill prevention training and certification programs required by 2 CCR ss 2540 through 2548. (3) The operator of any terminal for which a letter of intent has been submitted shall, within five (5) days of any change in operations or information or a termination of use of the terminal, advise the Division in writing of the changes and shall cancel, in writing, the letter for any terminal at which transfer operations can no longer be conducted. (c) Operations Manual: Approval. (1) The Division shall review and, within 30 working days of receipt at the Division, approve any operations manual which meets the requirements of this section. If the Division finds that the manual does not meet the requirements of this section, then it shall notify the submitting party within 30 working days of the manual's receipt. (2) The approval by the Division is voided if the terminal operator: (A) Amends the operations manual without following the procedures in subsection (f) of this section; or (B) Fails to amend the operations manual when required by the Division. (3) Any terminal operator whose operations manual has been disapproved by the Division may appeal the disapproval to the Commission, provided that the appeal is submitted in writing to the Commission Executive Officer within 30 days after the operator receives notice of the disapproval. (d) Operations Manuals: Contents. (1) Each operations manual required by this section shall: (A) Describe how the applicant meets the operating rules and equipment requirements specified in this article and in 33 CFR Parts 154 and 156, Subpart A; and (B) Describe the responsibilities of personnel under this section and under 33 CFR Parts 154 and 156, Subpart A, in conducting oil transfer operations. (2) Each operations manual required by this section shall contain all of the following: (A) Maps and diagrams showing the location and configuration of the terminal, including, at minimum, the following: 1. Scale and direction; 2. A point on the map with its latitude and longitude taken with a geographic positioning system, with differential correction; 3. A site plan of the major structural components of the current facility, including, but not limited to, piers, mooring structures, buoys, manifolds, mechanical loading arms, pipelines, and pipeline end manifolds (PLEMs); 4. The location of the general and emergency shutdown system controls; 5. Locations of any environmental and discharge monitoring devices; 6. Storage locations for pollution containment equipment including those deployed during transfer operations; 7. Configuration of boom containment and arrangements for boom stand-off for each type of transfer operation that takes place at the terminal; 8. Location and type of fire extinguishing, first aid and other safety equipment; 9. Location of facilities used for personnel shelter, if any; 10. Locations of environmentally sensitive areas in the immediate vicinity of the terminal, if any; 11. Where applicable the locations of special shut-off valves and other safety equipment to be used in cases of earthquakes; 12. Locations of sump wells, if any, at or in the vicinity of the terminal; 13. Emergency exit routes for personnel; and 14. Bathymetry and sea floor characteristics; (B) A physical description of the terminal including a plan of the terminal showing mooring areas, transfer locations, control stations, and locations of safety equipment; (C) The hours of operation of the terminal; (D) The sizes, including the maximum size of tank vessel or barge that can be accommodated at the terminal, types, and number of tank vessels and barges to and from which the terminal can transfer oil at any time. The maximum tank vessel size shall be specified by its: 1. Length Overall; 2. Maximum or Loaded Draft; and 3. Deadweight Tonnage (DWT). (E) For each product transferred at the terminal: 1. Generic or chemical name; and 2. The following cargo information: a. The name of the cargo, as listed under Appendix II of Annex II of MARPOL 73/78, Table 30.25-1 of 46 CFR 30.25-1, Table 151.05 of 46 CFR 151.05-1, or Table 1 of 46 CFR 153; b. A description of the appearance of the cargo; c. A description of the odor of the cargo; d. The hazards involved in handling the cargo; e. Instructions for safe handling of the cargo; f. The procedures to be followed if the cargo spills or leaks or if a person is exposed to the cargo; and g. A list of fire fighting procedures and extinguishing agents effective with fires involving the cargo. (F) The minimum number of persons on duty during transfer operations and their duties; (G) The names and telephone numbers of the terminal operator or operators, U.S. Coast Guard, California State Office of Emergency Services, and other personnel who may be called by the employees of the terminal in an emergency; (H) A description of each communication system required by Section 2370 of these regulations; (I) A description of the facilities and the location of each personnel shelter, if any; (J) A description and instructions for the use of drip and discharge collection, and vessel slop reception facilities, if any; (K) A description of and instructions for seep monitoring from sump wells, if any; (L) A description of the operation of and the component location of each emergency shutdown system; (M) Quantity, types, locations, and instructions for use of oil discharge monitoring devices, if any; (N) Quantity, type, location, instructions for use, and time required for gaining access to and deployment of initial response containment equipment; (O) A description of the spill containment for transfer operations required under Section 2395 and, if applicable, the basis used for determining that the onshore marine terminal is subject to high velocity currents as defined in Section 2395, subsection (b)(3); (P) Quantity, type, location and instructions for uses of fire extinguishing equipment required by federal, state and local fire prevention regulations; (Q) The maximum relief valve setting or, where relief valves are not provided, maximum system pressure for each transfer system and the method used to determine that pressure; (R) Procedures for: 1. Operating each mechanical loading arm including the limitations of each loading arm; 2. Transferring oil; 3. Completion of pumping; 4. Emergencies; and 5. Notifying the Division of damage as required by subsection (e) of s 2325 of this Article 5. (S) Procedures for reporting and initially containing oil discharges; (T) A brief summary of applicable federal, state, and local oil pollution laws and regulations; (U) Procedures for shielding portable lighting authorized by the Division under Section 2365; (V) A description of the training and qualification program for TPIC's; (W) A list of all designated TPIC's for the terminal; (X) Statements explaining that each oil or hazardous materials transfer hose is marked either with the name of each product which may be transferred through the hose; with the words, "OIL SERVICE"; or with letters, number or other symbols representing all such products and the location in the operations manual where a chart or list of the symbols used and a list of the compatible products which may be transferred through the hose can be found for consultation before each transfer; and (Y) A list and brief description of all operating restrictions placed upon the terminal by federal, state or local authorities with proper jurisdiction. (3) If a terminal collects vapors emitted from vessel cargo tanks for recovery, destruction, or dispersion, the operations manual shall contain a description of the vapor control system at the terminal which includes the following: (A) A line diagram or simplified piping and instrumentation diagram (P&ID) of the terminal's vapor control system piping, including the location of each valve, control device, pressure-vacuum relief valve, pressure indicator, flame arrester and detonation arrester; and (B) A description of the vapor control system's design and operation, including: 1. The vapor line connection; 2. Startup and shutdown procedures; 3. Steady state operating procedures; 4. Provisions for dealing with pyrophoric sulfide (for facilities which handle inerted vapors of cargos containing sulfur); 5. Alarms, shutdown devices and Safety Analysis Function Evaluation (SAFE) chart as prescribed in Recommended Practice 14C, Fourth Edition, published on September 1, 1986, by the American Petroleum Institute (API), Publications and Distribution Section, 1220 L Street, NW, Washington, DC 20005; and; 6. Pre-transfer equipment inspection requirements. (4) Each operations manual shall also contain an electrical hazardous (classified) area diagram of the current terminal, as described in National Fire Protection Association (NFPA) No. 70, National Electrical Code, Articles 500 and 515, 1996 edition, published by NFPA, 1 Batterymarch Park, P.O. Box 9101, Quincy, Massachusetts 02269-9101. This diagram need not be bound with the operations manual, but must be located at the terminal. Copies of the operations manual submitted to the Division under subsection (a)(3)(B) of section 2385 need not contain the diagram. (5) For ease of amendment, the terminal's operations manual shall be contained in a binder which allows easy replacement of pages. The terminal operator shall incorporate a dated copy of each amendment to the operations manual under subsection (f) of this section in each copy of the manual with the related existing requirement or add the amendment at the end of each manual if not related to an existing requirement. Language in the manual which no longer applies shall be removed from the manual. (6) The operations manual shall be written in the order specified in subsections (d)(2) and (d)(3) of this section or contain a cross-referenced index page in that order. (e) Operations Manual; Offshore Terminals. (1) Each operations manual for an offshore marine terminal shall contain all applicable provisions of subsection (d) of this section and shall also include at least the following: (A) Calculations with supporting data and other documentation to show that the charted water depth at each berth of the terminal is sufficient to provide at least a 6-foot net underkeel clearance at all times and under all conditions for each tank vessel or barge that the terminal expects to be moored at the terminal. (B) A description of prevailing currents, tides, winds and other weather conditions most commonly experienced at the terminal and a description of the monitoring equipment, if any, employed at the terminal which relays information about wind, wave and current conditions at the terminal. (C) A description of specific limiting wind, wave, current and meteorological conditions under which each of the following will occur: 1. Oil transfer operations will be shut down; 2. Departure of the tank vessel or barge from the mooring will be required; and 3. Mooring operations will be prohibited. (D) A description of the navigational aids, if any, provide for approach to the berth and times of operation; (E) A description of mooring support vessels duties and services; (F) A detailed description of mooring and unmooring maneuvers with supporting graphical illustrations for each berth of the terminal; (G) A description of the duties and responsibilities of mooring masters and assistant mooring masters including the numbers of such personnel that will be in attendance at mooring, unmooring or cargo transfer operations; and (H) A description of each of the tugs available in compliance with Section 2390, subsection (b), including, at least, the following: 1. Bollard pull; and 2. Towing and pushing arrangements. (2) The additional provisions required by subsection (e)(1) of this section may be incorporated under appropriate existing headings of the operations manual or may be added to the end of the manual. (f) Operations Manual: Amendment. (1) Using the following proceedings, the Division may require the terminal operator to amend the operations manual if the Division finds that the operations manual does not meet the requirements of this section: (A) The Division shall notify the terminal operator in writing of any inadequacies in the operations manual within 30 days of receipt of the manual. (B) The terminal operator may submit written information, views, and arguments on and proposals for amending the manual within 30 days from the date of the Division notice. (C) After considering all relevant materials presented, the Division shall, within 30 days of receipt of the material submitted under subsection (f)(1)(B) of this section, notify the terminal operator of any amendment required or adopted, or rescind the notice. (2) The amendment becomes effective 30 days after the terminal operator receives the Division's notice, unless the terminal operator petitions the Division Chief to review the Division's notice, in which case its effective date is delayed pending a decision by the Division Chief. Petitions to the Division shall be submitted in writing. (3) If the Division finds that there is a condition requiring immediate action to prevent the discharge or risk of discharge of oil that makes the procedure in subsection (f)(1) of this section impractical or contrary to the public interest, the Division may issue an amendment effective on the date the terminal operator receives notice of it. In such a case, the Division shall include a brief statement of the reasons for the findings in the notice. The owner or operator may petition the Division Chief to review the amendment, but the petition shall not delay the amendment. (4) The terminal operator may propose amendments to the operations manual by submitting any proposed amendments in writing to the Division. (5) The proposed amendment shall take effect upon approval by the Division or, if the Division takes no action within 30 days of its receipt, then at the end of that period. If the operator requests that immediate action be taken, the Division may provide immediate approval if it determines that circumstances warrant it, provided that such approval is conditioned upon subsequent review within 30 days of receipt of the proposed amendment. (6) The Division shall respond to proposed amendments submitted under subsection (f)(4) of this section by: (A) Approving or disapproving the proposed amendments; (B) Advising the terminal operator whether the request is approved, in writing; (C) Including any reasons in the written response if the request is disapproved; and (D) If the request is made under subsection (f)(5) of this section, immediately approving or rejecting the request. (7) Amendments which do not affect compliance with the requirements of this article, such as amendments to personnel and telephone number lists required by subsection (d)(2)(G) of this section do not require prior Division approval, but the Division shall be advised of such amendments as they occur. Note: Authority cited: Sections 8750, 8751, 8755, and 8758, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8757, and 8758, Public Resources Code. s 2390. Additional Requirements at Offshore Terminals. (a) Applicability. The provisions of Section 2390, shall apply only at offshore terminals. (b) Tug Requirements. (1) During every mooring and unmooring operation, a tug or tugs shall be available and standing by in readiness to assist the tank vessel. The tug or tugs shall have bollard pull sufficient to assist the tank vessel. (2) At all times during a transfer operation a tug or tugs shall be available to the barge. The tug or tugs shall have bollard pull sufficient to assist the barge. (c) Mooring Masters. (1) For the purpose of this section, a "mooring master" means a person who holds a valid U.S. Coast Guard issued license as Master or Mate and an endorsement as First Class Pilot for the area at which the terminal is located. (2) A mooring master shall be aboard every tank vessel or barge for every mooring and unmooring operation at that terminal. (d) Assistant Mooring Master. (1) For the purpose of this section, an "assistant mooring master" means a person who holds a valid U.S. Coast Guard issued license as Master or Mate and has experience in mooring and unmooring operations at that terminal. This person shall not be a member of the vessel's crew. (2) In addition to the requirement in subsection (c)(2) of this section, an assistant mooring master shall be aboard the tank vessel for every mooring and unmooring operation at that terminal. (e) Diver Inspection of Submarine Hose. Each terminal operator shall ensure that a diver inspection of any submerged hose string to be used has been conducted prior to every hookup if: (1) The submarine hose has not been lifted within 15 days of the last previous transfers; or (2) There has been a passage of a storm or seismic event affecting the area which may have damaged or covered the submarine hose. (f) Pipeline Requirements. (1) At all times, offshore terminals shall have the capability of drawing and maintaining a vacuum on all submarine pipelines containing oil. (2) At all times during mooring and unmooring operations at offshore terminals, a vacuum shall be maintained on all submarine pipelines containing oil which do not lead to a berth where another vessel is already moored and which: (A) Serve the berth where the vessel is being moored or unmoored; or (B) Are in or near the approach path of the vessel being moored or unmoored. (g) Underkeel Clearance. Each tank vessel or barge that conducts or is intending to conduct a transfer operation at an offshore terminal shall at all times during the transfer operation and under all conditions have a net underkeel clearance of at least six (6) feet from the sea-floor and any known obstructions. (h) Bathymetric Surveys. Offshore terminals shall conduct annual bathymetric surveys of the berth and maneuvering areas adjacent to the berth. Note: Authority cited: Sections 8750, 8751 and 8755, Public Resources Code. Reference: Section 8670.17, Government Code; Sections 8750, 8751, and 8755, Public Resources Code. s 2395. Spill Containment for Transfer Operations. (a) Applicability. The provisions of this section apply to: (1) All transfer operations where the oil transferred is a persistent oil; and (2) All transfer operations into vessel's tanks containing persisent oil or residues of persistent oil. (b) General. (1) For the purpose of this section and section 2396, "persistent oil" means a petroleum-based oil that does not meet the distillation criteria for a non-persistent oil. "Non-persistent oil" means a petroleum-based oil, such as gasoline, diesel or jet fuel, which evaporates relatively quickly; specifically, an oil with hydrocarbon fractions, at least 50 percent of which, by volume, distills at a temperature of 645 degrees Fahrenheit and at least 95 percent of which, by volume, distills at a temperature of 700 degrees Fahrenheit. (2) For the purpose of this section and section 2396, the term "boom" means flotation boom or other effective barrier containment material suitable for containment of oil that is discharged onto the surface of the water. (3) For the purpose of this section and section 2396, an "offshore marine terminal subject to high velocity currents" means an onshore terminal at which the maximum current velocities are 1.5 knots or greater for the majority of the days in the calendar year. (c) Vessel Loading Operations at Onshore Terminals. (1) Prior to commencement of each transfer operation from the terminal to the vessel at an onshore terminal, the terminal operator shall deploy boom to enclose the water surface surrounding the vessel so as to provide common containment area for: (A) The entire vessel at the waterline; and (B) Either of the following: 1. The entire dock; or 2. Portions of the dock where oil may spill into the water. (2) To meet the requirements of subsection (c)(1)(B) of this section, where the face of the dock is capable of acting as an effective barrier on the inboard side of the vessel, the boom on that side may be deployed so that it provides containment between the vessel and the dock. (3) The boom shall be deployed so that it provides a stand-off of not less than 4 feet from the outboard side of the vessel. (4) For onshore marine terminals subject to high velocity currents, the terminal operator may provide sufficient boom appropriate to the conditions at the terminal, trained personnel and equipment, maintained in a standby condition at the berth for the duration of the entire transfer operation, so that a length of at least 600 feet of boom will be deployed for effective containment within 30 minutes of a spill as an alternative to the requirements set forth in subsections (c)(1) and (c)(2) of this section. (d) Vessel Offloading Operations at Onshore Terminals. (1) Prior to commencement of each transfer operation from the vessel to the terminal at an onshore terminal, the terminal operator shall deploy boom to enclose the water surface on the inboard side of the vessel, so as to provide common containment area for: (A) The vessel's entire inboard length, at the waterline; and (B) Either of the following: 1. The entire dock; or 2. Portions of the dock where oil may spill into the water. (2) Where the face of the dock is capable of acting as an effective barrier, the boom shall be deployed so that it provides containment between the vessel and the dock. (3) For onshore marine terminals subject to high velocity currents, the terminal operator may provide sufficient boom appropriate to the conditions at the terminal, trained personnel and equipment, maintained in a standby condition at the berth for the duration of the entire transfer operation, so that a length of at least 600 feet of boom will be deployed for effective containment within 30 minutes of a spill as an alternative to the requirements set forth in subsections (d)(1) and (d)(2) of this section. (e) Transfer Operations at Offshore Terminals. Prior to commencement of each transfer operation at offshore terminals, the terminal operator shall provide sufficient boom appropriate to the conditions at the terminal, trained personnel and equipment, maintained in a stand-by condition at the berth, so that a length of at least 600 feet of boom will be deployed for effective containment within 30 minutes of a spill. Note: Authority cited: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. Reference: Section 8670.28, Government Code; and Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2396. Spill Containment for Ballasting or Deballasting Operations for Tank Vessels at Marine Terminals. (a) Applicability. The provisions of s 2396 apply to tank vessels conducting ballasting or deballasting operations at terminals where any part of the cargo on board or any part of the cargo last carried is a persistent oil. These provisions do not apply to ballasting operations to a tank vessel's segregated ballast tanks. (b) Tank Vessel Ballasting or Deballasting Alongside Onshore Terminals. (1) Prior to commencement of any ballasting or deballasting operation at an onshore terminal, the terminal operator shall ensure that boom is deployed or maintained in a standby condition, as appropriate, as specified in subsections (c) or (d) of section 2395. (2) At onshore terminals not subject to high velocity currents, where the tank vessel uses the sea valves on the outboard side of the vessel, the booming shall conform to the requirements of subsections (c)(1), (c)(2) and (c)(3) of section 2395. Where the sea valves on the terminal side of the vessel are used, the booming shall conform to the requirements of subsections (d)(1) and (d)(2) of section 2395. (c) Tank Vessel Ballasting or Deballasting at Offshore Terminals. Prior to commencement of any ballasting or deballasting operation at an offshore terminal, the terminal operator shall ensure that the provisions of subsection (e)(2) of section 2395, have been complied with. Note: Authority cited: Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. Reference: Section 8670.28, Government Code; and Sections 8750, 8751, 8752, 8755, 8757 and 8758, Public Resources Code. s 2400. Mitigation Monitoring Requirements. If an environmental review is or has been conducted for all or any part of a terminal or for terminal operations pursuant to Sections 21002 through 21082.2 of the Public Resources Code and Title 14, California Code of Regulations, Sections 15000 et seq., and a lead or responsible agency requires compliance with mitigation measures as a condition for installation or operation of that terminal, then: (a) The terminal operator shall comply with the required mitigation measures; and (b) If the mitigation measures relate to operation of the terminal, both the mitigation measures and monitoring program required shall be incorporated into the terminal operations manual. Note: Authority cited: Sections 8750, 8751, 8755 and 8758, Public Resources Code. Reference: Sections 21002, 21004, 21067, 21069, 21081 and 21082.2, Public Resources Code; Sections 15051, 15052, and 15386, Title 14, California Code of Regulations. s 2405. Notifications Regarding Apparent or Threatened Violations. (a) Authorized Agents or Employees. (1) For the purposes of Sections 2405 and 2406, each of the following shall be referenced as an "authorized agent or employee" of the Division: (A) The Executive Officer of the Commission; (B) The Assistant Executive Officer of the Commission; (C) The Division Chief; (D) The Assistant Chief of the Division; (E) The Marine Terminal Safety Field Operations Supervisor of the Division; (F) Any Marine Terminal Safety Supervisor of the Division; (G) Any Marine Terminal Safety Specialist of the Division; (H) Any Marine Terminal Safety Inspector of the Division; or (I) Any other staff as designated by the Executive Officer or Division Chief. (2) Any and all of the referenced agents or employees listed in subsection (a)(1) of this section are authorized to make a determination as to apparent or threatened violations, as defined in Section 2315, subsection (b) and subsection (x) of Article 5. (b) Apparent or Threatened Violations: Reporting and Records. (1) In the event that an authorized agent or employee of the Division determines that there is an apparent or threatened violation, he or she shall notify the TPIC or VPIC, as appropriate, of the apparent or threatened violation as soon as he or she has an opportunity to do so. (2) Each and every authorized agent or employee of the Division shall report to the Division any and all apparent or threatened violations. (3) The Division shall maintain records of all reported violations for a period of not less than five (5) years. (4) The Division shall, upon request, make available to the Administrator or the U.S. Coast Guard copies of records of violations. Note: Authority cited: Sections 8750, 8751, 8755 and 8760, Public Resources Code. Reference: Sections 8670.66, 8670.67 and 8670.69.4, Government Code; and Sections 8750, 8751, 8755 and 8760, Public Resources Code. s 2406. Notifications Regarding Discharge Threat. (a) For the purpose of this section only, the term "discharge threat" means an apparent or threatened violation of regulations which, if unabated, would directly cause or substantially increase the risk of an unauthorized discharge of oil into marine waters at a terminal. (b)(1) In the event that an authorized agent or employee of the Division determines that there is a discharge threat, the agent or employee shall immediately notify the TPIC or VPIC, as appropriate, of the discharge threat. (2) Upon receiving notification of a discharge threat, the TPIC or VPIC, as appropriate, shall take immediate action to eliminate the threat, either by correcting the apparent or threatened violation or by suspending transfer operations until the apparent or threatened violation is corrected. (c) If the TPIC or VPIC does not take immediate action to eliminate the discharge threat, either by correcting the apparent or threatened violation or by suspending transfer operations until the apparent or threatened violation is corrected, then: (1) The authorized agent or employee shall notify the Division of the immediate threat; and (2) The Division shall then immediately notify: 1. The U.S. Coast Guard; 2. The Administrator; and 3. The District Attorney of the County in which the terminal is located. (3) The Division or the Executive Officer may also take whatever legal action is necessary and appropriate to obtain an order from the superior court having jurisdiction over the terminal to abate the discharge threat without first complying with the provisions of s 2407 of this Article 5. Note: Authority cited: Sections 8750, 8751, 8755 and 8760, Public Resources Code. Reference: Sections 8670.66, 8670.67 and 8670.69.4, Government Code; and Sections 8750, 8751, 8755 and 8760, Public Resources Code. s 2407. Enforcement Procedures. (a) For purposes of this section, the term, "cited party," means the person or entity which appears to have committed a violation of a provision or provisions of this Article 5 or Article 5.3. (b) Classifications of violations: (1) All violations of provisions of this article 5 and Article 5.3 shall be considered within one of three classes: (A) Class 1: Violations each of which could not directly result in a discharge of oil or pose a threat to public health and safety and the environment (B) Class 2: Violations each of which could result in a discharge of oil or pose a threat to public health and safety and the environment under certain circumstances, in combination with other violations or over time. (C) Class 3: 1. Violations each of which could, by itself, directly result in a discharge of oil or pose a threat to public health and safety and the environment; or 2. Violations of Section 2320, sub. (c), concerning access by the Division to the terminal, terminal records, or vessels at the terminal. (2) If a single person or entity has committed a number of Class 2 violations at the same time which, taken together, could directly result in discharge of oil or pose a threat to public health and safety and the environment, then each violation shall be considered a separate Class 2 violation and the total combination of violations may be considered a separate Class 3 violation. (3) If a single person or entity has committed three (3) Class 1 violations in any twelve-month period, five (5) in any 24-month period, or seven (7) in any 36-month period, that series of violations may be considered a single Class 2 violation. (4) If a single person or entity has committed three (3) Class 2 violations in any twelve-month period, five (5) in any 24-month period, or seven (7) in any 36-month period, that series of violations may be considered a single Class 3 violation. (c) When it appears to the Division Chief that a cited party has committed a Class 3 violation, the Division Chief shall report the apparent violation to the Executive Officer. (d) Prior to pursuing any enforcement action under the provisions of Government Code Sections 8670.65 through 8670.67, the following preliminary procedures shall be followed: (1) The Division Chief shall provide written notice to the cited party containing the following: (A) A description of the Class 3 violation or the lesser violations making up the Class 3 violation; (B) A statement that enforcement proceedings may be initiated; and (C) Notification that the cited party may, within ten working days after receipt of the notice, submit a request in writing to the Chief for a preliminary meeting. (2) If the cited party requests a preliminary meeting with the Chief, that meeting shall be held prior to any further enforcement actions and may include any discussions relating to the apparent violation or violations in question, including, but not limited to, the question as to whether a violation had in fact occurred, what evidence there was for the apparent violation, and what classification should apply for each violation. (3) If the cited party so requests and agrees to pay for all costs, the preliminary meeting shall be recorded and a transcript shall be prepared. (4) The preliminary meeting shall be scheduled at the Division Chief's discretion, but shall in no event be scheduled more than thirty (30) calendar days after the request for the meeting is received by the Division Chief. (5) Within ten (10) working days after the preliminary meeting, the Division Chief shall provide written notice to the cited party of the decision as to whether enforcement action is to proceed. (6)(A) Within ten working days after receipt of the notice regarding the decision of the Division Chief following the preliminary meeting, the cited party may appeal the decision to the Executive Officer of the Commission. (B) Any appeal to the Executive Officer shall be submitted in writing. (C) If the decision of the Division Chief is appealed to the Executive Officer, no enforcement action shall be taken unless and until the Executive Officer directs the Division Chief to proceed. (e) If, after the preliminary procedures under subsection (d) of this section are followed, it appears to the Executive Officer that the cited party has committed a Class 3 violation of any provision or provisions of this Article 5 or 5.3 the Executive Officer may take any or all of the following actions: (1) The Executive Officer may request that the Administrator do one or more of the following where appropriate: (A) Issue an order under Government Code s 8670.69.4 requiring that person to cease and desist; (B) Take whatever legal action that is necessary and appropriate, to obtain an order from the court enjoining the apparent and threatened violation; or (C) Initiate and pursue proceedings under Government Code s 8670.66 or 8670.67 to subject the cited party to statutory penalties. (2) The Executive Officer may do one or more of the following: (A) Take whatever legal action is necessary and appropriate to obtain an order from the court enjoining the apparent or threatened violation; or (B) If appropriate, take whatever action is necessary and appropriate to initiate and pursue proceedings under Government Code s 8670.66 to subject the cited party to statutory penalties. (f)(1) The Executive Officer shall notify the U.S. Coast Guard of any apparent violation which may also constitute violation of federal law or regulation. (2) The Executive Officer shall keep the Administrator fully apprised if any action is taken under subsection (e)(2). Note: Authority cited: Sections 8750, 8751, 8755 and 8760, Public Resource Code. Reference: Sections 8670.66, 8670.67 and 8670.69.4, Government Code; and Sections 8750, 8751, 8755 and 8760, Public Resources Code. s 2430. The Marine Facilities Division. (a) There is in the Staff of the California State Lands Commission the Marine Facilities Division, which has the primary responsibility for carrying out the provisions of the Lempert-Keene-Seastrand Oil Spill Prevention and Response Act of 1990 within the Commission's jurisdiction. (b) The primary office of the Division is at 200 Oceangate, Suite 900, Long Beach, California 90802-4335, telephone (562) 499-6312. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code. s 2431. Purpose and Applicability. (a) The purpose of the regulations in Title 2, Division 3, Chapter 1, Article 5.1 of the California Code of Regulations is to provide a physical security program which ensures the best achievable protection of the public health and safety and of the environment at marine terminals. (b) The provisions of this article shall apply to all marine terminals in the State of California. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756 and 8757, Public Resources Code. s 2432. Definitions. Unless the context otherwise requires, the following definitions shall govern the construction of this article: (a) "Division" means the Marine Facilities Division of the California State Lands Commission. (b) "Division Chief" means the Chief of the Marine Facilities Division or any employee of the Division authorized by the Chief to act on his behalf. (c) "Marine terminal" means a facility other than a vessel, located on or adjacent to marine waters in California, used for transferring oil to or from tank vessels or barges. The term references all parts of the facility including, but not limited to, structures, equipment and appurtenances thereto used or capable of being used to transfer oil to or from tank vessels or barges. For the purpose of these regulations, a marine oil terminal includes all piping not integrally connected to a tank facility. A tank facility means any one or combination of above ground storage tanks, including any piping which is integral to the tank, which contains crude oil or its fractions and which is used by a single business entity at a single location or site. A pipe is integrally related to an above ground storage tank if the pipe is connected to the tank and meets any of the following: (1) The pipe is within the dike or containment area; (2) The pipe is connected to the first flange or valve after the piping exits the containment area; or (3) The pipe is connected to the first flange or valve on the exterior of the tank, if state or federal law does not require a containment area. (d) "Marine Terminal Security Officer" or "MTSO" means a person employed by the terminal operator designated to be responsible for terminal security. (e) "Marine Terminal Physical Security Plan" means a written document describing the practices, procedures, responsibilities, equipment and structures that provide for the security of the terminal. (f) "Physical Security Survey and Assessment" means the terminal operator's identification and evaluation of weaknesses in physical security of important assets, infrastructures, appurtenances and procedures that are critical to the marine terminal, that, if damaged, could cause harm to people or to the environment. (g) "Terminal Operator" means any person or entity which owns, has an ownership interest in, charters, leases, rents, operates, participates in the operation of or uses a terminal, pipeline, or facility. "Terminal Operator" does not include any entity which owns the land underlying the terminal or the terminal itself, where the entity is not involved in the operations of the terminal. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756 and 8757, Public Resources Code; and Section 25270.2, Health and Safety Code. s 2433. Requirements for Marine Terminal Security Program. Each marine terminal operator must implement a marine terminal security program that, at a minimum: (a) Provides for the safety and security of persons, property and equipment on the terminal and along the dockside of vessels moored at the terminal; (b) Prevents or deters the carrying of any unauthorized weapon, incendiary, or explosive on or about any person inside the terminal, including within his or her personal articles; (c) Prevents or deters the introduction of any weapon, incendiary, or explosive in stores or carried by persons onto the terminal or onto the dockside of vessels moored at the terminal; and (d) Prevents or deters unauthorized access onto the terminal and onto the dockside of vessels moored at the terminal. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2434. Designation of MTSO and Alternates. Each terminal operator shall designate an MTSO by name with 24-hour contact information, and an alternate or alternates when the MTSO is unavailable. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2435. Responsibilities of the MTSO. Each MTSO must, at a minimum, ensure that all of the following are undertaken and completed: (a) An initial comprehensive physical security survey and assessment has been conducted, documented and maintained in a location determined by the MTSO; (b) Ongoing security surveys are conducted at least annually and whenever a security incident or circumstances warrant changes; (c) The comprehensive physical security survey and assessment are used to formulate a security plan; (d) The Marine Terminal Physical Security Plan is implemented, maintained and periodically updated; (e) Personnel responsible for security are trained in all aspects of the Marine Terminal Physical Security Plan; (f) Employees, visitors and contractors requiring access to the terminal are provided with security awareness information; (g) Vehicle access controls with designated parking areas and no-parking zones are established; (h) Periodic security drills and exercises are conducted; (i) The terminal has an identification and verification process for all employees, vendors and other persons whose duties require them to have access to the terminal and a tracking process for all vehicles allowed entry to the terminal; (j) All occurrences or suspected occurrences of terrorist acts and related activities are reported to National Response Center, telephone (800) 424-8802, and local law enforcement agencies having jurisdiction at the marine terminal. Such occurrences include bombings, bomb threats, suspicious letters or packages and incidents related to the intentional release of chemical, biological or radio active agents. Records of such occurrences shall be maintained at the marine terminal for three (3) years; and (k) Procedures for notification of security incidents or threats to terminal and vessel personnel are established. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2436. Marine Terminal Physical Security Plan. (a) The MTSO shall develop and maintain a Marine Terminal Physical Security Plan, in writing, for countering risks and threats. The plan shall, at a minimum, document the practices, procedures, responsibilities, equipment, and structures utilized in complying with all of the provisions of Section 2433. (b) The Marine Terminal Physical Security Plan shall, at a minimum, contain all of the following: (1) A map, diagram or site plan of the layout of the terminal showing: (A) Perimeter fencing; (B) Main access to the terminal; (C) Other accesses to the terminal; (D) Exit and entry routes for vessel crew members; (E) Waterfront areas and vessel berths; (F) Designated vehicle parking areas; (G) Emergency exit routes for personnel and vehicles from the terminal; (H) Location of lighting, motion detectors, cameras and other surveillance equipment; (I) Fixed security posts and mobile routes; and (J) Restricted areas. (2) The names and contact telephone numbers of the Terminal Manager, the MTSO and alternates, and all terminal security personnel; (3) The duties of the MTSO, alternates and terminal security personnel; (4) The minimum number of terminal security personnel on duty and their responsibilities when oil transfer operations are being conducted; (5) A description of the physical security arrangements for the terminal including the minimum number of security personnel on duty, if any, when no transfer operations are being conducted; (6) A description of the procedures and arrangements for elevated security in compliance with the U.S. Coast Guard Captain of the Port's directives regarding threat escalation; (7) Procedures for reporting security threats or breaches of security; (8) The telephone numbers of the National Response Center, (800) 424-8802 and other local agencies having jurisdiction at the marine oil terminal; (9) Findings of the initial comprehensive physical security survey and assessment; (10) Equipment, measures and procedures at the terminal that are used to prevent the introduction of unauthorized weapons, incendiaries or explosive devices or any other unauthorized dangerous devices that may be used to cause harm or damage to people, vessels or terminals by any means onto the terminal from the shore side; (11) Measures to prevent unauthorized persons gaining access onto the terminal, onto vessels moored at the terminal and to restricted areas of the terminal; (12) Measures or procedures to permit entry of persons without valid identification; (13) Procedures for verification of identity of terminal employees, vendors, contractors, vessel agents, truck drivers, government agents and other visitors to the terminal to ensure that they have legitimate business at the terminal; (14) Measures and procedures to permit entry for scheduled and unscheduled deliveries including hazardous materials to the terminal or vessel moored at the terminal in advance; (15) Procedures and measures for the terminal's security personnel's response to security threats or breaches of security; (16) Duties of terminal personnel other than security personnel in the event of a security threat or breach of security; (17) Procedures to be followed when unauthorized persons are discovered on the terminal; (18) Any standing agreements with local police and fire departments regarding terminal security; (19) Security procedures in the event of a loss of electrical power and other emergencies; (20) A description of the communications system that is used for maintaining security; and (21) A description of the procedures, equipment and operations used for compliance with the requirements of Sections 2437, 2438, 2439, 2440, 2441, 2442 and 2444. (c) The MTSO must restrict the distribution, disclosure, and availability of information contained in the Marine Terminal Physical Security Plan to those who have been determined by the terminal operator to have a need-to-know. The information required by subsection (b)(9) of this Section may be maintained at a separate location. (d) The Marine Terminal Physical Security Plan shall be reviewed and updated at least annually and whenever a security incident or circumstances warrants changes. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2437. Requirements for Identification of Terminal Employees, Contractors and Visitors to the Terminal. (a) All persons entering or leaving a terminal must possess and show a valid identification card or document as prescribed in subsection (b) of this Section to gain access to the terminal. All passengers in vehicles must have valid identification. Identification must be presented to security personnel or government agents upon request. In the event that an individual seeking access to the terminal does not have an identification card that meets the requirements of subsection (b) of this section, an alternative means of identification as prescribed in subsection (b)(13) of Section 2436, must be used. (b) Valid identification cards or documents must be tamper resistant and at a minimum include the holders name and a recent photograph of the holder. Any of the following may constitute a valid form of identification: (1) Employer issued employee identification cards; (2) Identification card issued by a government agency; (3) State issued drivers license; (4) Pacific Maritime Association card; (5) Labor Organization identity card; or (6) Passport. (c) Security personnel or competent authority shall verify that identification documents and applicable licenses or credentials match the person presenting them. Persons arriving by motorcycle shall be required to remove helmets to assist in identification. (d) Security personnel shall randomly verify the identity and identification of persons encountered during roving patrols. (e) The MTSO shall develop a verification process as prescribed in subsection (b)(14) of Section 2436, to ensure that all persons requiring access to the terminal have valid business on the terminal. Vendors, contractors, truck drivers and visitors arrivals shall be scheduled in advance. If their arrival is not prearranged, entry shall be prohibited until their need to enter is verified. (f) The MTSO shall require contractors and vendors who require access to the terminal or vessels at the terminal, to provide the terminal with a current pre-authorized list of persons requiring access. This requirement does not preclude such persons from having valid identification. (g) Vessel's crew members, agents, contractors and vendors on board vessels moored at terminal, shall not be permitted to exit or enter the terminal unless their names are provided and verified in advance. (h) The terminal shall have a process to account for all persons within the terminal at any given time. (i) All persons requiring access to the terminal shall be subject to search before being permitted to proceed beyond a terminal's access points. Signs shall be posted at access points being utilized to advise persons of this requirement. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2438. Requirements for Access Control. (a) Gates. All entry gates shall be locked and secured or guarded at all times or shall have an effective entry detection alert system. (b) Restricted Areas. The terminal shall establish and post restricted areas within the terminal to control unauthorized access to critical operating areas such as storage tanks, hazardous materials storage areas, communications and control centers. (c) Vehicle Control. Vehicle access controls shall, at a minimum, include the following: (1) Parking within the terminal shall be restricted to only those designated spaces indicated in the Marine Terminal Physical Security Plan. (2) Vehicle entry and exit routes on the terminal shall be clearly marked. (3) All vehicles entering or leaving the terminals shall be subject to search by terminal security personnel. Signs shall be posted to advise persons of this requirement. (4) Terminals shall have procedures for controlling vehicle access and parking. (d) Deliveries. (1) All packages entering or leaving the terminals are subject to search by terminal security personnel. Delivery orders shall be verified prior to being allowed access to restricted areas. Signs shall be posted at each access point being utilized by the terminal to advise persons of this requirement. (2) Bills of lading and shipping documents for cargo and stores deliveries shall be checked for accuracy and cargo and stores should be adequately described on documentation, including piece count if applicable. (e) Security Patrols. (1) Designated personnel shall conduct roving safety and security patrols when the terminal is manned at random intervals not exceeding four (4) hours. (2) Security patrols shall, at a minimum, cover restricted areas, main power supply switch gear, lighting controls, perimeter access points, vehicle parking areas, communications and operations control centers and waterside access areas. (3) Designated personnel must be able to respond immediately to a security signal in accordance with established procedures in the security plan. (4) Records of unusual occurrences encountered during security patrols shall be maintained in a log. Such records shall be maintained for a period of three years. Records must be available for inspection by the Division. (f) Tank Vessels, Barges and other Vessels Moored at the Terminal. (1) Vessel's crewmembers shall depart or arrive as prescribed in subsection (b)(1)(D) of Section 2436. (2) Arrival and departure routes for vessel's crewmembers must be posted or visually indicated to avoid their access to restricted areas within the terminal. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2439. Key Control Systems and Locking Devices. (1) Locks, locking devices, and key control systems shall be inspected by the MTSO regularly and malfunctioning equipment repaired or replaced. (2) Chains used in conjunction with locks shall be permanently attached to fence posts or gates. Locks shall be of case hardened construction. (3) Access to keys including duplicate keys shall be restricted to those terminal personnel as determined by the MTSO. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2440. Perimeter Fencing or Barriers. (a) Perimeter fences and other barriers shall be located and constructed so as to prevent the introduction of persons, dangerous substances or devices, and shall be of sufficient height and durability to deter unauthorized passage. (b) Fencing shall have barbed or razor wire tops and be constructed of 9 gauge or heavier wire and shall be no less than 8 feet or sufficient height and durability to deter unauthorized passage. The bottom of the fence shall be within 2 inches of the ground. (c) Areas adjacent to fences and barriers shall be cleared of vegetation and debris that could be used to breach them. Note: Authority: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2441. Lighting. (a) Security lighting shall provide a minimum illumination standard of one foot candle at one meter above the ground. Security lighting shall, at a minimum, illuminate access points to the terminal, the waterfront and dock areas. (b) Lighting control and switches shall be protected to prevent unauthorized access or tampering. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2442. Warning Systems, Signals and Communications. (a) Warning Systems or Signals. The terminal shall have a signal or system for warning terminal personnel of a security breach or incident. (b) Communications. In addition to the requirements of 2 CCR s2370, the terminal shall provide a means of communication for vessel's crews to contact terminal personnel. Note: Authority: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2443. Video and Electronic Surveillance. The MTSO shall determine whether or where video or other electronic surveillance and detection systems can be used to augment or replace, as appropriate, the following: (a) Detection and warning of breaches of security at perimeter fences and barriers; (b) Roving security patrols; (c) Control of entry points to the terminal; and (d) Surveillance of waterfront areas. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2444. Terminal Security Training and Security Awareness. (a) The MTSO shall develop a security training program for terminal security personnel and a security awareness program for all terminal employees. (b) The training program shall include initial and periodic refresher training. (c) Terminal security personnel shall complete security training programs established by the MTSO. (d) All terminal employees, contractors, vendors and visitors to the terminal shall undergo security training or security awareness training as deemed appropriate by the MTSO. The MTSO shall determine each individual's training requirements from those prescribed in subsection (e) of this Section. (e) The security training program shall, at a minimum, include all of the provisions of Section 2433, Section 2436 and the following elements: (1) The terminal's policies, practices and procedures for implementing the security program; (2) Coordination with local law enforcement agencies; (3) Coordination with federal, state and other local agencies having jurisdiction; (4) Procedures and duties for security personnel when a security signal is received; (5) Procedures and duties of terminal employees when a security signal is received; (6) Procedures for notifying all terminal personnel and vessel's crew when increased security threat levels are imposed by the U.S. Coast Guard Captain of the Port; (7) Procedures and arrangements for elevating security in compliance with the U.S. Coast Guard Captain of the Port's directives; (8) Procedures, actions and reporting of incidents involving breaches of security; (9) Procedures for notifying the National Response Center and local agencies having jurisdiction; (10) Communications, warning systems and signals operations; (11) Terminal security drills and exercises which must include periodic drills for implementing elevated security levels; (12) Awareness training for terminal employees to ensure that they have working knowledge of the terminal's security and emergency plans and procedures; and (13) Awareness training for contractors, vendors and visitors to the terminal. (f) Security training must emphasize vigilance and security awareness of all terminal employees. (g) The training program shall be reviewed at least annually. The program should be updated to include lessons learned from any breach of security occurrences. (h) Security drills and exercises may be either specific to the marine terminal or as part of a cooperative program with vessel, port or local agencies' security plans. Drills and exercises must be conducted at intervals not exceeding twelve (12) months. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code. s 2445. Marine Terminal Physical Security Plan: Approval Procedure. (a) The terminal operator must ensure completion of a Marine Terminal Physical Security Plan and notify the Division Chief of its completion in writing, within 90 days of the effective date of these regulations. (b) After the initial 90-day compliance period, the Division staff shall conduct an on-site inspection of the terminal's security arrangements to determine if the Marine Terminal Physical Security Plan meets the requirements of these regulations. (c) If the Marine Terminal Physical Security Plan meets the requirements of these regulations, the Division Chief shall approve the plan, in writing, within 30 days of the on-site inspection. (d) If the Marine Terminal Physical Security Plan does not meet the requirements of these regulations, the Division Chief shall notify the terminal operator, in writing, of any deficiencies within 30 days of the on-site inspection. Terminal operators shall correct any deficiencies within 30 days or a period agreed upon by the terminal operator and the Division Chief. When corrections have been made, the terminal operator shall notify the Division. (e) Upon receipt of such notification, the Division Chief shall, within 30 days, inspect and approve or disapprove the Marine Terminal Physical Security Plan as appropriate. (f) Terminal operators shall notify the Division Chief, of any proposed amendments to an approved Marine Terminal Physical Security Plan. Any such proposed amendments shall be communicated to the Division Chief for approval at least 30 days prior to the date that changes are to be adopted. The Division Chief shall approve or disapprove proposed amendments, in writing, within 30 days of receipt as set forth in subsections (c) and (d) of this section. (g)(1) Any information or documents relating to security at any marine terminal, where the information or document is identified by the terminal operator as confidential or as containing proprietary information, shall be treated as confidential information by the State Lands Commission and its Staff. (2) For purposes of subsection (g)(1), a document shall be considered identified as confidential or as containing proprietary information only if the document is designated as confidential or as containing proprietary information in writing either on the document so identified or in an accompanying document signed by the terminal operator. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755 and 8756, Public Resources Code; Sections 6254.15 and 15376, Government Code. s 2540. Purpose, Applicability and Date of Implementation. (a) The purpose of the regulations in Title 2, Division 3, Chapter 1, Article 5.3, of the California Code of Regulations is to establish onshore and offshore marine terminal personnel oil-handling training and certification requirements which, when followed, will: (1) Provide improved protection of California waters and natural resources by preventing oil spills caused by human factors; (2) Ensure that marine terminal personnel involved in oil-handling operations are adequately trained and have demonstrated competency; and (3) Establish certification that personnel are in compliance with training requirements. (b) The provisions of this article shall not apply to: (1) Operations conducted at offshore drilling and production facilities. (2) Tank cleaning operations which begin after the removal of cargo or fuel from any tank vessel or barge. (c) Unless otherwise specified in this article, all of the provisions of this article become effective 30 days after they have been filed with the Secretary of State. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2541. Definitions. Unless the context otherwise requires, the following definitions shall govern the construction of this article: (a) "Barge" means any vessel that carries oil in commercial quantities as cargo, but is not equipped with a means of self-propulsion. (b) "Certification" means the documentation that a terminal employee has met all of the requirements of an oil spill prevention training and job competency program that meets the requirements of this article. (c) "Division" means the Marine Facilities Division of the California State Lands Commission. (d) "Division Chief" means the Chief of the Marine Facilities Division or any employee of the Division authorized by the Chief to act on his behalf. (e) "Human factors" means human conditions, such as inadequate knowledge or fatigue, which can lead to operator error or poor judgement. (f) "Human factor risks" means risks of causing an oil spill due to the effects of human factors on competency and judgement. (g) "Indirect operations" means involvement in on-site activities, such as new construction, in a capacity that indirectly involves the risk of an oil spill to waters of the state due to potential impacts to nearby oil-handling operations (e.g., operating digging equipment next to an active oil transfer pipeline). (h) "Maintenance" means direct involvement in maintaining and repairing the equipment used for the transfer, storage, handling, or monitoring of oil at a marine terminal in a capacity that involves the risk of an oil spill to marine waters. (i) "Management" means the first line supervision with direct involvement in managing the transfer, storage, handling, or monitoring of oil at a marine terminal by administering operations policies and procedures that involve the risk of an oil spill to marine waters. (j) "Marine terminal" means a facility other than a vessel, located on or adjacent to marine waters in California, used for transferring oil to or from tank vessels or barges. The term references all parts of the facility including, but not limited to, structures, equipment and appurtenances thereto used or capable of being used to transfer oil to or from tank vessels or barges. For the purpose of these regulations, a marine terminal includes all piping not integrally connected to a tank facility. (k) "Maximum extent practicable" means the highest level of effectiveness that can be achieved through the use of terminal personnel and best achievable technology. In determining what is the maximum extent practicable, the Division shall consider, at a minimum, the effectiveness, engineering feasibility, commercial availability, safety, and the cost of the measures. ( l) "Offshore marine terminal" means any marine terminal at which tank vessels or barges are made fast to a buoy or buoys. (m) "Oil" means any kind of petroleum, liquid hydrocarbons, or petroleum products or any fraction or residues therefrom, including, but not limited to, crude oil, bunker fuel, gasoline, diesel fuel, aviation fuel, oil sludge, oil refuse, oil mixed with waste, and liquid distillates from unprocessed natural gas. (n) "Onshore marine terminal" means any marine terminal at which tank vessels or barges are made fast to land structures or substantially land structures. (o) "On-the-job training" means learning procedures and equipment use through observation of experienced and competent personnel, and supervised hands-on practice. (p) "Operations" means direct involvement in the transfer, storage, handling, or monitoring of oil at a terminal in a capacity that involves the risk of an oil spill to waters of the state. This functional group includes but is not limited to the Terminal person in charge, storage tank operators, pipeline operators, and oil transfer monitors. (q) "Operator" when used in connection with vessels, marine terminals, pipelines, or facilities, means any person or entity which owns, has an ownership interest in, charters, leases, rents, operates, participates in the operation of or uses that vessel, terminal, pipeline, or facility. "Operator" does not include any entity which owns the land underlying the terminal or the terminal itself, where the entity is not involved in the operations of the terminal. (r) "Personnel" means individuals employed by, or under contract with, a terminal. (s) "Spill" or "discharge" means any release of oil into marine waters which is not authorized by any federal, state, or local government entity. (t) "Supervisory" means involvement in directly supervising any transfer, storage, handling, or monitoring of oil at a marine terminal by implementing operations policies and procedures that involve risk of an oil spill to marine waters. (u) "Tank facility" means any one or combination of above ground storage tanks, including any piping which is integral to the tank, which contains crude oil or its fractions and which is used by a single business entity at a single location or site. A pipe is integrally related to an above ground storage tank if the pipe is connected to the tank and meets any of the following: (1) The pipe is within the dike or containment area; (2) The pipe is connected to the first flange or valve after the piping exists the containment area; or (3) The pipe is connected to the first flange or valve on the exterior of the tank, if state of federal law does not require a containment area. (v) "Tank vessel" or "tanker" means any self-propelled, water borne vessel, constructed or adapted for the carriage of oil in bulk or in commercial quantities as cargo. (w) "Terminal" means marine terminal. (x) "Terminal person in charge" or "TPIC" means an individual designated by the terminal operator as the person in charge of a particular oil transfer operation at a particular terminal. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756 and 8757, Public Resources Code. s 2542. Training Requirements. (a) Each onshore and offshore terminal shall develop and implement oil spill prevention training for supervisory, operations, maintenance, management, and indirect operations personnel identified pursuant to subsection (c) of this section. Training shall be designed to promote job competency and environmental awareness for the purpose of preventing oil spills. Non-English-speaking personnel subject to the terminal's training requirements shall be trained in a manner that allows comprehensionby such personnel. (b) Oil spill prevention training programs must be approved by the Division. (c) The terminal operator shall identify, in writing, the specific position titles which the terminal has identified to be subject to its oil spill prevention training requirements. In making this determination, the terminal shall evaluate the functions of terminal personnel positions using the definitions of "Supervisory," "Operations," "Maintenance," "Management," and "Indirect Operations" as defined in section 2541. For cases where certain job titles associated with maintenance and indirect operations can not be identified in advance, the terminal operator shall identify the types of job orders or work sites which may involve the need for maintenance or indirect operations oil spill prevention training. (d) The terminal operator shall identify, in writing, the specific initial classroom and on-the-job oil spill prevention training requirements for each position, including minimum hours, that are appropriate for each position given the terminal's training needs and human factor risks. (e) Requirements for training of operations and supervisory personnel shall focus on building personnel competency in operating procedures and spill prevention systems specific to the terminal. Oil spill prevention training requirements shall incorporate, at a minimum, the following training topics: (1) Overview of all oil handling, transfer, storage, and monitoring/leak detection operations at the terminal; (2) Operating procedures and checklists specific to trainee's job function; (3) Problem assessment including recognition of human factor risks and how they can be minimized; (4) Awareness of preventative maintenance procedures; (5) Awareness of local environmental sensitivity and oil spill impacts; (6) Major components of the terminal's operations manual; (7) Major components of the terminal's oil spill contingency plan including notification procedures for oil spills; (8) Decision-making for abnormal operating events and emergencies, including emergency spill prevention and safe shut down conditions, responsibilities and procedures; (9) Routine and emergency communications procedures; (10) Overview of applicable oil spill prevention and response laws and regulations; and (11) Drug and alcohol use awareness. (f) Requirements for initial oil spill prevention training of management personnel shall incorporate, at a minimum, the followingtraining topics: (1) Overview of all oil handling, transfer, storage, and monitoring/leak detection operations at the terminal; (2) Management role in operations and oil spill prevention; (3) Recognition of human factor risks and how they can be minimized; (4) Awareness of local environmental sensitivity and oil spill impacts; (5) Major components of the terminal's operations manual; (6) Major components of the terminal's oil spill contingency plan including notification procedures for oil spills and incident command systems; (7) Decision-making for abnormal operating events and emergencies, including emergency spill prevention and safe shut down conditions, responsibilities and procedures; (8) Overview of applicable oil spill prevention and response laws and regulations; and (9) Drug and alcohol use awareness. (g) Requirements for initial oil spill prevention training of maintenance or indirect operations personnel shall incorporate, at a minimum, the following training topics: (1) Overview of equipment, operations and hazards at specific maintenance and indirect operations work site(s) within the facility; (2) Awareness of local environmental sensitivity and oil spill impacts; (3) Notification procedures for oil spills; and (4) For terminal employees, drug and alcohol use awareness. (h) Training topics identified in subsections (e) to (g) of this section do not prescribe fixed subject titles for class outlines or training organization. Terminals may combine or integrate these topics, as appropriate, but must ensure that information on each topic is presented in the applicable personnel training program. (i) The terminal operator shall identify, in writing, the specific oil spill prevention continuing education requirements for each affected position, including minimum hours, that are appropriate given the terminal's training needs and human factor risks. Ongoing training shall occur at least annually and, at a minimum, address: (1) Any changes in the topics identified in subsections (e) to (g) of this section. (2) Refresher awareness training on environmental sensitivity and oil spill impacts; (3) Review and analysis of oil spills which have occurred during the past year; (4) Refresher training on oil spill prevention procedures; and (5) For supervisory, operations, and management personnel, a practice exercise of the terminal's procedures for preventing a spill during a particular abnormal operations event. (j) Terminal operators are encouraged to combine existing training programs required under federal Process Safety Management requirements (29 CFR 1910), Coast Guard Persons in charge requirements (33 CFR 154.710), and other federal and state training requirements in order to meet the above oil spill prevention training requirements. (k) Existing personnel that have entered their current positions prior to these regulations becoming effective can be regarded as having met the terminal's initial oil spill prevention training requirements if the terminal operator has documented that those personnel have received the required training in initial oil spill prevention within the previous five years. Existing personnel shall be recertified at least once every three years in accordance with subsection (g) of section 2545. ( l) Terminal operators shall develop follow up remedial training for personnel clearly responsible for causing an oil spill while functioning in their position, unless such personnel no longer occupy a position identified under subsection (c). (m) Contractors hired by the terminal operator to perform supervisory, operations, maintenance, management, or indirect operations functions, as identified by the terminal under subsection (c) of this section, are considered "personnel" for the purposes of these regulations, and shall be subject to the same oil spill prevention training requirements as terminal employees. The terminal operator is responsible to validate that such contractors have met the terminal's oil spill prevention training requirements before they perform a supervisory, operations, maintenance, management, or indirect operations function. (n) Terminal operators shall develop minimum training and experience qualifications for trainers who will demonstrate terminal specific procedures, equipment use, supervise practice sessions, and provide other on-the-job training to new personnel. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2543. Training Materials. Terminal operators shall develop and maintain written oil spill prevention training materials, such as training manuals, checklists and curricula. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2544. Certification Program. (a) Each onshore and offshore terminal operator shall develop and implement a program to certify that supervisory and operations personnel identified pursuant to subsection (c) of section 2542 of these regulations, have met the terminal's oil spill prevention training program requirements, and are competent to perform the functions associated with their positions. The certification program shall be designed, to the maximum extent practicable, to ensure job competency and environmental awareness for the purpose of preventing oil spills. (b) Certification programs must meet the minimum criteria set forth in section 2545 of these regulations. (c) All certification programs for supervisory and operations personnel must be approved by the Division as required by section 2546 of these regulations. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2545. Minimum Criteria for Certification. (a) The terminal oil spill prevention certification program shall address all supervisory and operations personnel identified pursuant to subsection (c) of section 2542. (b) The terminal operator shall develop and maintain written certification procedures, including: (1) Minimum competency requirements to achieve certification; (2) The process to develop and test competency in supervisory and operations personnel; and (3) The process of issuing and tracking certificates, including replacement of lost certificates. (c) The terminal operator shall maintain a written certificate or other record for supervisory and operations personnel which have met the terminal's certification requirements. This record shall document: (1) The certified individual's name and position; (2) Types and hours of training completed; (3) Name of trainer; (4) Results of performance tests and evaluations; (5) Signatures of the trainee and trainer; and (6) Date of certification. (d) Copies of certification records shall be kept at the terminal or in a location such as an office, so that they are readily accessible to Division staff, for at least five years from the date of certification. (e) A terminal's certification program shall incorporate methods to evaluate and confirm job competency, including: (1) A written examination, or oral examination documented in writing, which tests general knowledge about training topics identified under subsection (e) of section 2542, with an appropriate minimum passing score established by the terminal operator. (2) A practical evaluation of understanding and performance of routine and emergency operations specific to position's job function, including observation of performance of each oil handling, transfer, storage, and monitoring duties assigned to a position prior to unsupervised performance of those duties. (f) The terminal's program shall only provide for certification of an individual who has: (1) Met the terminal's oil spill prevention initial training requirements relevant to the individual's position, as developed pursuant to subsection (d) of section 2542; and (2) Passed a competency evaluation developed under subsection (e) of this section. (g) Recertification shall occur at least once every three years based on: (1) Successful completion of annual refresher training; and (2) Satisfactory performance in a reevaluation of competency as developed under subsection (e) of this section. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2546. Program Approval. (a) Terminal operators shall develop or modify their training and certification program to meet the requirements of Article 5.3, begin implementing the program, and, if necessary, update the description of this program within twelve months of the effective date of these regulations. (b) Within eighteen months of the effective date of these regulations the terminal operator shall have conducted certification procedures, as developed pursuant to subsection (b) of section 2545, for all existing personnel that are subject to the terminal's certification requirements and have entered their current position prior to these regulations becoming effective. (c) The Division shall review a terminal's training and certification program after the date determined by subsection (a) of this section. This review shall be accomplished by a general on-site inspection by the Division through evaluation of the terminal's training materials, testing and certification records, and consultation with terminal personnel. (d) The Division shall notify terminal operators regarding approval status within 30 calendar days of completing inspections under subsection (c) of this section. (e) Terminal operators who do not receive approval will have 90 days to address deficiencies in their training and certification program, with options for time extension at the discretion of the Division. For those personnel that were trained or certified after the dates established by subsection (a) of this section but prior to training program disapproval, retraining or recertification of such personnel due to changes required by the Division's approval process may be postponed until the next retraining or recertification cycle as established by the terminal pursuant to this Article. (f) Training and certification program approval is valid for five years. Significant changes to the terminal's program must be documented through an update of the terminal's training and certification program and submitted to the Division for approval. Minor upgrades in training programs, such as expansion of training hours or updates to training materials, are not required to be submitted. The Division may perform announced and unannounced inspections at terminals to verify compliance. (g) A training and certification program shall be approved if, in addition to meeting the requirements of sections 2544 and 2545 it demonstrates that, when implemented, it can, to the maximum extent practicable: (1) Provide protection from human factor oil spill risks identified in the risk analysis required by the terminal's oil spill contingency plan; (2) Minimize the likelihood that terminal oil spills will occur and minimize the size and impacts of those terminal oil spills which do occur; (3) Provide effective oil spill prevention training to supervisory, operations, maintenance, management, and indirect operations personnel; (4) Ensure proper evaluation of job competency; and (5) Provide an effective system to clearly document and track personnel training and certification. (h) The Division may approve a training and certification program with an expedited review as set out in this section if that program has been approved by a federal agency which the Division has deemed to apply approval criteria which equal or exceed those of the Division. (i) If the training and certification program receives approval, the terminal operator shall receive a letter of approval from the Division, describing the terms of approval, including expiration dates pursuant to subsection (f) of this section. (j) If approval is denied or revoked, the terminal operator shall receive, in writing, an explanation of the factors for disapproval and a list of deficiencies. The terminal operator may be subject to enforcement actions prescribed under sections 8670.57, 8670.58 8670.59 and 8670.61 of the Government Code. (k) Approval of a training and certification program by the Division does not constitute an express assurance regarding the adequacy of the program nor constitute a defense to liability imposed under state law. (1) The Division may review a program following any spill at the terminal. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8670.57, 8670.58, 8670.59 and 8670.61, Government Code; and Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2547. Inspections. (a) The Division may verify compliance with this article by announced and unannounced inspections in accordance with section 8757 of the Public Resources Code and section 2320 of Title 2, Division 3, Chapter 1, Article 5, of the California Code of Regulations. (b) During inspections, Division staff may require terminal operators to demonstrate proof of training and certification of supervisory and operations personnel. (c) The Division shall provide a copy of an inspection report to the terminal operator within thirty calendar days from the inspection date. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Section 8670.2, Government Code; and Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2548. Modifications or Alternatives. (a) Petitions for Modifications or Alternatives. (1) Any person subject to these regulations may submit a petition to the Division Chief for modifications or alternatives to the requirements of Article 5.3. (2) All petitions for modifications or alternatives must be submitted in writing. A petition may be in any form, but it must contain all data and information necessary to evaluate its merits. (b) Response to Petitions. The Division Chief shall respond in writing to any petition for modifications or alternatives within 30 days of receipt of the petition. (c) Approval of Modifications or Alternatives. (1) The Division Chief may approve any proposed modifications or alternatives to the requirements of Article 5.3 if he or she determines that the proposed modifications or alternatives will fulfill the purpose of these regulations as outlined in subsection (a) of section 2540 of this article. (2) If the Division Chief approves any proposed modification or alternatives under this section, a letter of approval shall be issued to the petitioner setting forth the findings upon which the approval is based, and a copy of that letter shall be maintained with the terminal's training manual or training records required by section 2543 of these regulations. (3) The Division Chief may withdraw the letter of approval of any modifications or alternative requirements at any time if he or she finds that the person or persons subject to these regulations have not regularly and consistently complied with the approved modified or alternative requirements. (4) Withdrawal of a letter of approval under this section shall be effective upon receipt by the petitioner of written notification of the withdrawal from the Division Chief. Note: Authority cited: Sections 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2550. Purpose, Applicability and Date of Implementation. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code. s 2551. Review of Engineering Practice, Structural Calculations, Drawings and Petitions. Note: Authority cited: Sections 8751, 8755, 8756, 8757 and 8758, Public Resources Code. Reference: Sections 8751, 8755, 8756, 8757 and 8758, Public Resources Code; Sections 15375, 15376 and 15378, Government Code. s 2552. Definitions. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8750, 8751, 8755, 8756 and 8757, Public Resources Code. s 2553. Structures Supporting NVCS or New VCS Equipment to Be Installed as Part of a Marine Terminal but Not on the Wharf or Pier. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code; Sections 15375, 15376 and 15378, Government Code. s 2554. Structures Supporting New VCS Equipment to Be Installed on Areas of Existing Wharves or Piers Overhanging the Water or Wetlands. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code; Sections 15375, 15376 and 15378, Government Code. s 2555. Inspection and Reassessment of EVCS Structural Installations. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code; Sections 15375, 15376 and 15378, Government Code. s 2556. Alternatives. Note: Authority cited: Sections 8751, 8755 and 8756, Public Resources Code. Reference: Sections 8751, 8755, 8756 and 8757, Public Resources Code; Sections 15375, 15376 and 15378, Government Code. s 2560. Purpose, Applicability, and Date of Implementation. (a) Unless otherwise specified in these regulations, all of the provisions of these regulations become effective on September 1, 1998. (b) The purpose of the regulations in Title 2, Division 3, Chapter 1, Article 5.5 of the California Code of Regulations is to provide the best achievable protection of the public health and safety and of the environment by using the best achievable technology in providing for marine terminal oil pipeline integrity. (c) The provisions of Article 5.5 apply only to pipelines that are within or a part of marine terminals and are used to transfer oil either: (1) Within the marine terminal; or (2) To or from tank vessels or barges. (d) The provisions of Article 5.5 do not apply to any pipelines: (1) That are within or part of marine terminals and are isolated and disconnected from any pipeline or manifold which can be used to transfer oil within the marine terminal or to and from tank vessels and barges; or (2) That are used exclusively to transport oil that are subject to the jurisdiction of the State Fire Marshal; or (3) That are part of a tank vessel or barge. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2561. Definitions. Unless the context otherwise requires, the following definitions shall govern the construction of this Article: (a) "Class I pipeline" means any pipeline or portion thereof which does not meet the criteria specified for a Class II pipeline. (b)(1) "Class II pipeline" means either of the following: (A) Any pipeline or portion thereof which has experienced two or more reportable leaks due to corrosion or defect in the prior three years. Leaks experienced during an SLPT shall not be counted as a leak for the purpose of classification of pipelines as Class II pipelines. For purposes of this definition, a leak which is taceable to an external force, but for which corrosion is partly responsible, shall be deemed caused by corrosion. (B) Any pipeline or pipeline system a part of which extends over marine waters or wetlands and does not have any form of permanently installed effective containment located between the pipeline and the water surface or wetland over its entire exposed length over the water or wetlands. (2) Each pipeline which has been classified as a Class II pipeline under subsection (b)(1)(A) of this section shall retain its classification as a Class II pipeline, until five years pass without a reportable leak due to corrosion or defect on that pipeline. After five years pass without a reportable leak, such Class II pipeline may be reclassified as a Class I pipeline following its next scheduled SLPT required by 2 CCR Section 2564(c)(3). (3) For the purpose of classification of pipelines as Class II pipelines under subsection (b)(1)(A) of this section, all reportable leaks that have occurred due to corrosion or defect in the three years prior to the effective date of these regulations shall be taken into account in making that determination. (4) For the purpose of reclassification of Class II pipelines as Class I pipelines under subsection (b)(2) of this section, any period of time without having a reportable leak shall commence from a date five years prior to the effective date of this regulation. (c) "Component" means any part of a pipeline or pipeline system which may be subjected to pump pressure or liquid gravitational pressure including, but not limited to, pipe, valves, elbows, tees, flanges, and closures. (d) "Defect" means manufacturing or construction defects. (e) "Division" means the Marine Facilities Division of the California State Lands Commission. (f) "Division Chief" means the Chief of the Marine Facilities Division or any employee of the Division authorized by the Chief to act on his behalf. (g) "Leak" or "reportable leak" means every unintentional liquid leak. A "reportable leak" does not include an unintentional leak from a gasket, gland or sealing material at a pump, valve, elbow, tee, flange or closure, which has been stopped by immediate tightening of bolts or any similar prompt corrective action. (h) "Marine terminal" means a facility, other than a vessel, located on or adjacent to marine waters in California and used for transferring oil to or from tank vessels or barges. The term references all parts of the facility, but not limited to, structures, equipment and appurtenances thereto used or capable of being used to transfer oil to or from tank vessels or barges. For the purpose of this article, a marine terminal includes all piping not integrally connected to a tank facility. (i) "Maximum allowable operating pressure" or "MAOP" means the highest safe operating pressure at any point in a pipeline system during normal flow or static conditions. (j) "Oil" means any kind of petroleum, liquid hydrocarbons, or petroleum products or any fraction or residues therefrom, including, but not limited to, crude oil, bunker fuel, gasoline, diesel fuel, aviation fuel, oil sludge, oil refuse, oil mixed with waste, and liquid distillates from unprocessed natural gas. (k) "Operator" when used in connection with marine terminals, pipelines, or facilities, means any person or entity which owns, has an ownership interest in, leases, rents, operates, participates in the operation of or uses that terminal, pipeline, or facility. "Operator" does not include any entity which owns the land underlying the terminal or the terminal itself, where the entity is not involved in the operations of the terminal. (l) "Person" means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof. (m) "Pipe" or "line pipe" means a tube, usually cylindrical, through which oil flows from one point to another. (n) "Pipeline or pipeline system" means a marine terminal pipeline through which oil moves within a marine terminal or between a marine terminal and a tank vessel or barge, including, but not limited to, line pipe, valves, other appurtenances connected to line pipe, fabricated assemblies associated with pumping units, and delivery stations and fabricated assemblies therein. (o) "Standard Cathodic Protection System" or "SCPS" means an external corrosion control system used on underground or submerged metallic piping systems that is in conformance with and meets the criteria of the National Association of Corrosion Engineers (NACE) Standard RPO 169-92, Item No. 53002, revised April 1992; published by NACE, P.O. Box 218340, Houston, Texas 77218-8340. (p) "State Fire Marshal" means the person, and any representative of the person, appointed by the Governor pursuant to Section 13101 of the Health and Safety Code. (q) "Static Liquid Pressure Test" or "SLPT" means the application of internal pressure above the normal or maximum operating pressure to a pipeline or a segment of pipeline, under no-flow conditions, for a fixed period of time, utilizing a liquid test medium. For the purpose of these regulations, the liquid test medium used may be either water or a liquid hydrocarbon with a flash point greater than 140 ° Fahrenheit. In circumstances where any other liquid medium is to be used for a SLPT, the operator shall petition the Division Chief using the procedures outlined in 2 CCR Section 2564(h). (r) "Tank facility" means any one or combination of above ground storage tanks, including any piping which is integral to the tank, which contains crude oil or its fractions and which is used by a single business entity at a single location or site. A pipe is integrally related to an above ground storage tank if the pipe is connected to the tank and meets any of the following: (1) The pipe is within the dike or containment area; (2) The pipe is connected to the first flange or valve after the piping exits the containment area; or (3) The pipe is connected to the first flange or valve on the exterior of the tank, if state or federal law does not require a containment area. (s) "Transfer pipeline" or "transfer pipeline system" means a pipeline that is within or a part of a marine terminal. A transfer pipeline does not include a pipeline that is subject to the jurisdiction of the State Fire Marshal. (t) "Wetlands" means streams, channels, lakes, reservoirs, bays, estuaries, lagoons, marshes, and the lands underlying and adjoining such waters, whether permanently or intermittently submerged, to the extent that such waters support and contain significant fish, wildlife, recreational, aesthetic, or scientific resources. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8750, 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2562. Notification and Reporting of Pipeline Incidents. (a) The operator of any marine terminal at which there occurs a rupture, explosion or fire involving a transfer pipeline, including, but not limited to, a transfer pipeline system undergoing testing, shall notify the California Office of Emergency Services of the incident as soon as possible, but in no event later than twenty-four (24) hours after the incident. (b) Within 30 days following any pipeline incident specified in subsection (a) of this section, the operator shall forward an incident report to the local area Division field office. The report shall include at a minimum; (1) The date and time of the pipeline incident; (2) The location and identity of the pipeline; (3) The product in the pipeline at the time of the incident; (4) The cause or causes of the incident; and (5) Any remedial action taken to restore the integrity of the pipeline. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2563. Design and Construction. (a) Any repairs, alterations or modifications to existing transfer pipeline systems shall meet the design and construction criteria specified in Subparts C and D of Part 195 of Title 49 of the Code of Federal Regulations as in effect on October 1, 1996. (b) Every new transfer pipeline installed after September 1, 1998, shall be designed and constructed in accordance with Subparts C and D of Part 195 of Title 49 of the Code of Federal Regulations as in effect on October 1, 1996. (c) Each component of a pipeline which is exposed to the atmosphere shall be coated with material suitable for protecting the component from atmospheric corrosion. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2564. Schedule for Static Liquid Pressure Testing. (a) No operator may operate any pipeline or pipeline system governed by this Article unless it has successfully completed an SLPT as specified in Section 2565, in accordance with the schedules prescribed in this section. (b) This subsection (b) applies only to Class I Pipelines. (1) Every newly installed pipeline or pipeline system shall have undergone a complete and successful SLPT prior to being used for any transfer of oil. Subsequent SLPTs shall be conducted at the appropriate intervals prescribed in subsection (b)(3) of this section. (2) Every existing pipeline or pipeline system which has any segment relocated or replaced shall undergo a complete and successful SLPT after completion of relocation or replacement and prior to being used for any transfer of oil. Subsequent SLPTs shall be conducted at the appropriate intervals prescribed in subsection (b)(3) of this section. The SLPT requirements of this subsection need not apply to cases where a component other than pipe is being replaced or added to the pipeline system and the manufacturer certifies that either: (A) The component was successfully tested with an SLPT at the factory where it was manufactured or at the operator's facility; or (B) The component was manufactured under a quality control system that ensures each component is at least equal in strength to a prototype that was successfully tested with an SLPT at the factory. (3) Every pipeline or pipeline system shall be subjected to an SLPT within five (5) years of the date of its initial SLPT prescribed in subsection (b)(1) of this section. Subsequent SLPTs shall be carried out in accordance with the following schedule: (A) For pipelines that do not have an SCPS and are buried or submerged either partially or wholly, at succeeding intervals not exceeding three year cycles from the date of test carried out under subsection (b)(3) of this section; (B) For pipelines that have an SCPS and are buried or submerged either partially or wholly, at succeeding intervals not exceeding five year cycles from the date of test carried out under subsection (b)(3) of this section; and (C) For pipelines or segments of pipelines situated entirely above the ground or water, at succeeding intervals not exceeding five year cycles from the date of test carried out under subsection (b)(3) of this section. (c) This subsection (c) applies only to Class II Pipelines. (1) Every newly installed pipeline or pipeline system shall undergo a complete and successful SLPT prior to being used for any transfer of oil. Subsequent SLPTs shall be conducted at the appropriate intervals prescribed in subsection (c)(3) of this section. (2) Every pipeline or pipeline system which has been classified as a Class II pipeline under subsection (b)(1)(A) of Section 2561, shall undergo a complete and successful SLPT after being classified as a Class II pipeline and prior to being used for any transfer of oil. Subsequent SLPTs shall be conducted at the appropriate intervals prescribed in subsection (c)(3) of this section. (3) In addition to the SLPTs required by either subsections (c)(1) or (2) of this section, subsequent SLPTs shall be conducted at the following intervals: (A) For pipelines or pipeline systems that do not have an SCPS and are buried or submerged either partially or wholly, at succeeding intervals not exceeding one year cycles from the date of tests conducted under either subsections (c)(1) or (2) of this section, whichever is appropriate. (B) For pipelines or pipeline systems that have an SCPS and are buried or submerged either partially or wholly, at intervals not exceeding three year cycles from the date of tests conducted under either subsections (c)(1) or (2) of this section, whichever is appropriate. (C) For pipelines or segments of pipelines situated entirely above the ground or water, at succeeding intervals not exceeding three year cycles from the date of test carried out under either subsections (c)(1) or (2) of this section, whichever is appropriate. (d) Each operator shall report any pipeline or segment thereof which meets the criteria of Class II pipeline to the local area Division field office within 30 days following the date the pipeline or portion thereof first meets the criteria as a Class II pipeline. Any pipeline determined to meet the criteria as a Class II pipeline which has not been so reported by the operator to the Division shall be deemed to have been a Class II pipeline on the date determined by the Division. The Division may determine that the period during which a Class II pipeline must have no reportable leaks in order to be reclassified as a Class I pipeline under s 2561(b)(2) does not begin until the required notice is given. Any operator failing to submit such notification report as required shall, as in the case of any violation of any provision of this article, be subject to enforcement actions prescribed under ss 8670.57 through 8670.69.6 of the Government Code. (e) Notwithstanding the requirements of subsection (c) of this section and subject to the approval of the Division Chief, an operator may implement an alternative method to assure the integrity of a segment of pipeline classified as Class II. When this alternative method has been implemented to the satisfaction of the Division Chief, the pipeline may be classified as a Class I pipeline. (f) Alternative test methods, including, but not limited to, inspection by instrumented internal inspection devices, may be approved by the Division Chief on an individual basis. In approving an alternative to an SLPT, the Division Chief may require that the alternative test be conducted more frequently than the testing schedules specified in subsections (b) and (c) of this section. (g) Notwithstanding the testing schedules specified in subsections (b) through (f) of this section, and in the event that the reported test results on a particular pipeline subject to this Article do not provide sufficient information as required by 2 CCR Section 2567(b), to the Division Chief to determine whether the affected pipeline could be the source of a discharge of oil or pose a threat to public health and safety or the environment, the Division Chief may require the terminal operator either: (1) To provide any extra information to substantiate that a successful SLPT has been conducted; or (2) To undergo an SLPT or any other non-destructive test or inspection. (h) An operator may request that the Division Chief authorize the use of a test medium other than water or liquid hydrocarbon with a flash point greater than 140 ° Fahrenheit. Such request must be submitted in writing at least 10 working days prior to beginning the SLPT. Such an alternative may be authorized where the Division Chief deems that it would provide a reasonably equivalent or better means of testing and that there will be no detriment to the public health, safety and the environment. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2565. Static Liquid Pressure Testing. (a) Each transfer pipeline system and mechanical loading arm must not leak when undergoing an SLPT of at least 125 percent of the maximum allowable operating pressure. (b) The pressure tests required by this section shall be conducted in accordance with Part 195 of Title 49 of the Code of Federal Regulations as in effect on October 1, 1996, except that an additional four-hour leak test under Section 195.303 of Title 49 of the Code of Federal Regulations as in effect on October 1, 1996, shall not be required. (c) A deadweight gauge capable of measuring to one-pound-per-square-inch (psi) increments shall be used during each pressure test. The deadweight gauge shall be calibrated to a standard directly traceable to the National Institute of Standards and Technology at least once every two years and shall have a valid Certificate of Traceability. (1) Deadweight pressure readings shall be taken at least once each hour during the test. (2) A pressure recording device shall continuously record the pipeline pressure versus time during the test. The pressure recording device shall be calibrated prior to every test. (d) Test Temperature Data. (1) Where circumstances permit, test temperature data shall be recorded as prescribed in the following subsections (d)(1)(A), (B) and (C): (A) A temperature recording device shall continuously record the internal test medium temperature versus time during the test. The temperature recording device shall be calibrated prior to every test and have a range suitable for anticipated temperatures. (B) The ambient air temperature shall be recorded at the same interval the deadweight pressure readings are taken. (C) The pipe wall temperature shall be recorded at the same interval the deadweight pressure readings are taken. (2) In circumstances where the test temperature data cannot be recorded as required by subsection (d)(1) of this section, temperature measuring devices shall be placed so as to provide representative sample temperatures of test medium, ambient air and pipe wall. (e) Where different sections of a pipeline or pipeline system are located in considerably different environments (e.g., in the open air or below ground or water), the temperature of each segment in each environment shall be monitored separately. For the purposes of pressure compensation calculations due to temperature variations, each segment's temperature in its respective environment shall be used. The total pipeline or pipeline system temperature change shall be determined by adding the temperature change of each segment and prorating the segment's length to the total pipeline length or pipeline system length. Alternatively, each segment in its respective environment may be treated as a separate pipeline under test and the compensated pressure variations due to each segment's temperature variations may be added to arrive at the system pressure variation. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2566. Notification Prior to Testing; Observation of Tests. (a) Notwithstanding any other statutory notification requirements, each operator shall notify the local area Division field office at least three working days prior to conducting any SLPT. The notification shall include all of the following information: (1) The name, address, and telephone number of the operator. (2) The specific location of the pipeline section to be tested and the location of the test equipment. (3) The date and time the test is to be conducted; and (4) The name and telephone number of the person responsible for certification of the test results. (b) In the event that the date or time of a proposed SLPT is to be changed, the operator shall, as soon as is practicable, notify the local area Division field office of the rescheduled date and time of such SLPT. (c) If, due to unforeseen circumstances, an unscheduled SLPT has to be conducted as soon as possible and within a period of three working days, the operator shall notify the local area Division field office as soon as it is practicable to do so, but in any case prior to commencement of the SLPT. (d) Staff of the Division may observe any test conducted pursuant to this Article. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2567. Static Liquid Pressure Testing; Witnessing of Tests and Certification of Results; Test Result Reports. (a) Witnessing of SLPTs. Any SLPT required by this Article shall be witnessed by either: (1) A person or persons who are registered on the current list of persons approved to witness testing activities of the State Fire Marshal; or (2) A person or persons who are certified by the terminal operator as having, at a minimum, the necessary experience and qualifications to witness SLPTs to ensure that they are effectively carried out. (b) Certification of SLPT Results. Any SLPT required by this Article shall have its test results certified by either: (1) A person who is registered on the current list of persons approved to certify test results of the State Fire Marshal; or (2) A person who is certified by the terminal operator as having, at a minimum, the necessary experience and qualifications to certify SLPT results and current valid Authorized Inspector certification under any one or more of the following programs: (A) The American Petroleum Institute's API 570, Piping Inspection Code, Appendix B-Inspector Certification; (B) The American Petroleum Institute's API 510, Pressure Vessel Inspection Code, Appendix B-API Authorized Pressure Vessel Inspector Certification; (C) The National Board of Boiler and Pressure Vessel Inspectors National Board Commissioned Inspector program NB-215, Revised October 24, 1995, 1055 Crupper Avenue, Columbus, Ohio 43229-1183; or (D) A California State accredited program for qualification for a Certificate of Competency as Authorized Inspector of Boiler and Pressure vessels under 8 CCR s 779. (c) Records of certified test results shall be maintained by the terminal operator for a period of at least ten (10) years following completion of testing. Each test record shall include at a minimum, all of the following information: (1) The date of the test; (2) A description of the pipeline or pipeline segment tested including, but not limited to, a map of suitable scale showing the route of the pipeline; and (3) The results of the test, including, but not limited to, calculations made to adjust for changes in volume due to temperature, pressure and elevation changes. (d) Test results of any SLPT shall be subject to review by Division staff. When requested, the terminal operator shall provide the certified test results of any SLPT to the Division. (e) Staff of the Division shall not supervise, control, or otherwise direct the testing. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2568. Leak Prevention and Detection. All Class II pipelines shall be provided with either a leak detection system or systems which meet the requirements of Section 2569, or be included in a preventative maintenance program which meets the requirements of Section 2570. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2569. Leak Detection System or Systems. (a) Operators may meet the requirements of providing a leak detection system or systems by any of the following: (1) Instrumentation with the capability of detecting a transfer pipeline leak equal to two percent (2%) of the maximum design flow rate within five minutes; (2) Completely containing the entire circumference of the pipeline provided that a leak can be detected within fifteen minutes; (3) For transfer operations which do not involve the use of hoses, conducting a pressure test of the pipeline acceptable to the Division Chief immediately before any oil transfer; or (4) A combination of the above strategies. (b) The operation of any leak detection system or systems provided under this section shall be described in the terminal's operations manual required by Section 2385 of Title 2, Division 3, Chapter 1, Article 5 of the California Code of Regulations. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2570. Preventative Maintenance Program. (a) A preventative maintenance program must ensure the continued operational reliability of any pipeline or pipeline system affecting quality, safety and pollution prevention. The program shall, at a minimum, include all applicable requirements and guidelines prescribed in API 570, Piping Inspection Code - Inspection, Repair, Alteration and Rerating of In-service Piping Systems, First Edition, June 1993, published by the American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 2005. (b) Inspection and Testing Requirements for Pipelines Included in a Preventative Maintenance Program. (1) For pipelines which are buried or submerged either partially or wholly the following shall be carried out: (A) Either annual SCPS inspections per API 570 guidelines and triennial SLPTs as prescribed in 2 CCR Section 2564(c)(3)(B) for pipelines fitted with SCPS, or annual SLPTs as prescribed in 2 CCR Section 2564(c)(3)(A) for pipelines not provided with SCPS, whichever is appropriate; and (B) An inspection program for emergency shut-off and isolation valves that control the flow of oil which shall, at a minimum, include that the stems of all such valves be stroked at least once a year. (2) For pipelines which are situated entirely above the ground or water, the following shall be carried out: (A) Triennial SLPTs as prescribed in 2 CCR Section 2564(c)(3)(C) and triennial pipewall thickness measurement inspections per API 570 guidelines; and (B) An inspection program for emergency shut-off and isolation valves that control the flow of oil which shall, at a minimum, include that the stems of all such valves be stroked at least once a year. (3) For any pipeline which is above ground for substantially all of its length, but which has a relatively short portion below ground buried beneath one or more berms or roads, the operator may petition the Division Chief for the application of testing and inspection requirements for the entire pipeline as prescribed under 2 CCR Section 2570(b)(2). Such petitions shall follow the procedures outlined in s 2571. (c) Any preventative maintenance program shall also include procedures to review proposed changes in operations, including materials transferred, to evaluate potential impacts on pipeline integrity. (d) Terminal operators shall validate that the preventative maintenance program is being effectively carried out by maintaining documentation which includes, at a minimum, all of the following: (1) The procedures for carrying out the preventative maintenance program in conformance with the requirements of API 570; (2) Dates of inspections and tests; (3) Inspections and test data evaluation including analyses, pipewall thickness measurements and remaining life calculations; (4) The terminal management's internal audits of the program, including descriptions of controls and corrections for non-conformities; (5) Repairs, alterations and rerating of piping systems; and (6) Any other information pertinent to the integrity of pipelines. (e) Every terminal operator shall provide to the Division access at any time to any documentation required under subsection (d) of this section. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. s 2571. Modifications or Alternatives. (a) Petitions for Modifications or Alternatives. (1) Any person subject to these regulations may submit a petition to the Division Chief for modifications or alternatives to the requirements of Article 5.5 as applied to the petitioner. (2) All petitions for modifications or alternatives must be submitted in writing. A petition may be in any form, but is must contain all data and information necessary to evaluate its merits. (b) Response to Petitions. The Division Chief shall respond in writing to any petition for modifications or alternatives within 30 days of receipt of the petition. (c) Approval of Modifications or Alternatives. (1) The Division Chief may approve any proposed modifications or alternatives to the requirements of Article 5.5 if he or she determines that the proposed modifications or alternatives will fulfill the purpose of these regulations as outlined in subsection (b) of Section 2560 of this Article. (2) If the Division Chief approves any proposed modification or alternatives under this section, a letter of approval shall be issued to the petitioner setting forth the findings upon which the approval is based. (3) The Division Chief may withdraw the letter of approval of any modifications or alternative requirements at any time if he or she finds that the person or persons subject to these regulations have not complied with the approved modified or alternative requirements. (4) Withdrawal of a letter of approval under this section shall be effective upon receipt by the petitioner of written notification of the withdrawal from the Division Chief. Note: Authority cited: Sections 8755 and 8757, Public Resources Code. Reference: Sections 8751, 8752, 8755, 8756 and 8757, Public Resources Code. Note: Authority cited: Section 6108, Public Resources Code. Division 6 (Section 6100, et seq.), Division 13 et seq.) and Division 20 (Section 30000, et seq.), Public Resources Code. s 2600. Costs. A contract to reimburse the Commission for costs associated with the cession shall be executed by the United States and the Commission prior to publication of notice of hearing. The procedure for determining the reimbursement shall be as set forth in Article 1 of this Chapter at Section 1905. Note: Authority cited: Section 126, Government Code. Reference: Section 126, Government Code. s 2601. Notice. Not more than 30 and not less than 15 days before the hearing, a notice of hearing shall be published one time in a newspaper of general circulation in the area in which the subject land is located. Not less than 10 days before the hearing, personal service shall be made on the clerk of the county board of supervisors and the city council if appropriate. Affidavit of publication and return of service shall be filed with the Commission before the hearing. The notice shall be entitled "Notice of Hearing to Determine Cession of Jurisdiction by the United States Over Land Known as __________." The notice shall contain a description of the lands and shall set forth the date, the time and place of the public hearing. The notice shall recite that the hearing shall be had pursuant to Government Code Section 126, and amendments, if any, and shall advise that interested parties may appear personally or through counsel or by letter to present evidence on whether cession of jurisdiction is in the best interests of the State. Note: Authority cited: Section 126, Government Code. Reference: Section 6110, Public Resources Code. s 2602. Type of Hearing. The hearing held pursuant to said published notice may be conducted by both oral and written presentations. The hearing may be before the Commission, or a staff member designated by the Commission to conduct the hearing. Note: Authority cited: Section 126, Government Code. Reference: Section 6110, Public Resources Code. s 2603. Procedure on Hearing Argument. Unless otherwise ordered by the Commission, the person requesting the hearing shall present material evidence in support of his application. After such person rests, any other interested person may present any material evidence in support of or in opposition to such application. The Commission may, in its discretion, limit cumulative evidence and may refuse or allow argument, and in case of allowance, may limit the same. Note: Authority cited: Section 126, Government Code. Reference: Section 126, Government Code. s 2604. Evidence. Oral evidence shall be taken only on oath or affirmation. The hearing need not be conducted according to technical rules relating to evidence and witnesses. Any relevant evidence shall be admitted if it is the sort of evidence on which responsible persons are accustomed to rely in the conduct of serious affairs, regardless of the existence of any common law or statutory rule which might make improper the admission of such evidence over objection in civil actions. Hearsay evidence may be used for the purpose of supplementing or explaining any direct evidence but shall not be sufficient in itself to support a finding unless it would be admissible over objection in civil actions. Hearsay evidence may be received upon a showing satisfactory to the Commission of the difficulty of obtaining direct evidence. Note: Authority cited: Section 126, Government Code. Reference: Section 126, Government Code. s 2605. Decision. After all of the evidence has been received, the Commission shall make its decision at the next regularly scheduled public meeting. Note: Authority cited: Section 126, Government Code. Reference: Section 6110, Public Resources Code. s 2606. Extension of Jurisdiction. Where concurrent criminal jurisdiction has been granted under Government Code Section 126 for five years, any application for renewal and extension of such jurisdiction shall be considered as a new application. The above regulations governing cessions of jurisdiction shall apply in all cases. Note: Authority cited: Section 126, Government Code. Reference: Section 126, Government Code. s 2700. Costs. A contract to reimburse the Commission for costs associated with the retrocession shall be executed by the United States and the Commission prior to publication of notice of hearing. The procedure for determining the reimbursement shall be as set forth in Article 1 of this Chapter at Section 1905. Note: Authority cited: Section 113, Government Code. Reference: Section 113, Government Code. s 2701. Notice. Not more than thirty (30) and not less than fifteen (15) days before the hearing, a notice of hearing shall be published one time in a newspaper of general circulation in the area in which the subject land is located. Not less than ten (10) days before the hearing, personal service shall be made on the clerk of the county board of supervisors and the city council if appropriate. Affidavit of publication and return of service shall be filed with the Commission before the hearing. The notice shall be entitled "Notice of Hearing to Determine Retrocession of Jurisdiction by the United States Over Land Known as ____________." The notice shall contain a description of the land and shall set forth the date, time, and place of the public hearing. The notice shall recite that the hearing shall be had pursuant to Government Code Section 113, and amendments, if any, and shall advise that interested parties may appear personally or through counsel or by letter to present evidence on whether retrocession of jurisdiction is in the best interest of the State. Note: Authority cited: Section 113, Government Code. Reference: Section 113, Government Code. s 2702. Type of Hearing. The hearing held pursuant to said published notice may be conducted by both oral and written presentations. The hearing may be before the Commission, or a staff member designated by the Commission to conduct the hearing. Note: Authority cited: Section 113, Government Code. Reference: Section 6110, Public Resources Code. s 2703. Procedure on Hearing Argument. Unless otherwise ordered by the Commission, the person requesting hearing shall present material evidence in support of his application. After such person rests, any other interested person may present any material evidence in support of or in opposition to such application. The Commission may, in its discretion, limit cumulative evidence and may refuse or allow argument, and in case of allowance, may limit the same. Note: Authority cited: Section 113, Government Code. Reference: Section 113, Government Code. s 2704. Evidence. Oral evidence shall be taken only on oath or affirmation. The hearing need not be conducted according to technical rules relating to evidence and witnesses. Any relevant evidence shall be admitted if it is the sort of evidence on which responsible persons are accustomed to rely in the conduct of serious affairs, regardless of the existence of any common law or statutory rule which might make improper the admission of such evidence over objection in civil actions. Hearsay evidence may be used for the purpose of supplementing or explaining any direct evidence but shall not be sufficient in itself to support a finding unless it would be admissible over objection in civil actions. Hearsay evidence may be received upon a showing satisfactory to the Commission of the difficulty of obtaining direct evidence. Note: Authority cited: Section 113, Government Code. Reference: Section 113, Government Code. s 2705. Decision. After all of the evidence has been received, the Commission shall make its decision at the next regularly scheduled public meeting. Note: Authority cited: Section 126, Government Code. Reference: Section 6110, Public Resources Code. s 2800. General. The provisions of this Article shall apply only to those lessees, lenders, or contract holders who wish to secure Commission findings specified in Public Resources Code Section 6702(b) regarding leases, contracts or other instrument involving granted tide and submerged lands. Note: Authority cited: Sections 6105, 6108, 6701, 6702, and 6703, Public Resources Code. Reference: Section 6702, Public Resources Code. s 2801. Procedure. (a) Applicants desiring Commission findings under Public Resources Code 6702(b) shall: (1) Complete in full and submit to the Commission, an application approved in form and content by the Commission; and (2) Cause a grantee report, approved in form and content by the Commission to be completed in full and submitted directly by the legislative grantee; and (3) Submit additional information as required if the application or grantee report are in any manner inadequate or incomplete. (b) An inadequate or incomplete application or grantee report for which required additional information is not forthcoming shall be rejected. (c) The 90-day time limitation specified in Public Resources Code Section 6704 shall commence to run when the application and grantee report, complete in all respects, have been received by the Commission. (d) Approved application and grantee report forms referred to in this Article are available from and shall be submitted to the principal office of the Commission. Note: Authority cited: Sections 6105, 6108, 6701, 6703, and 6704, Public Resources Code. Reference: Section 6704, Public Resources Code. s 2802. Commission Criteria. The Commission in determining pursuant to Public Resources Code Section 6702(b)(3) whether a lease, contract or other instrument is in the best interest of the State will consider whether the use, project or activity permitted by such instrument is: (a) Consistent with current Commission policies, practices and procedures used for administering lands within its jurisdiction; (b) economically viable, necessary and desirable; (c) appropriate for developmental mix; (d) conducive to public access; (e) consistent with environmental protection; (f) otherwise in the best interests of the state. Note: Authority cited: Sections 6005, 6105, 6108, 6701, and 6702, Public Resources Code. Reference: Sections 6005, 6701, and 6702, Public Resources Code. s 2803. Approval Limitation. Approval by the Commission of any lease, contract or other instrument pursuant to this Article shall not constitute approval of any modification or amendment of such instrument made pursuant to the provisions of such instrument or otherwise. Separate approval shall be required for such modifications or amendments. Note: Authority cited: Sections 6105, 6108, 6701, and 6706, Public Resources Code. Reference: Section 6706, Public Resources Code. s 2901. Authority and Purpose. These regulations are promulgated pursuant to the requirements of Section 21082 of the Public Resources Code and Section 15050 of the California Administrative Code to provide the State Lands Commission with definitions and procedures for orderly and consistent evaluations of projects that are subject to the requirements of the California Environmental Quality Act (CEQA). (Public Resources Code Section 21000, et seq.) Note: Authority cited: Section 21082, Public Resources Code. Reference: Title 14, Section 15050, California Administrative Code. s 2902. Applicability of the State EIR Guidelines. The State EIR Guidelines (14 California Administrative Code Sections 15000, et seq.) are hereby incorporated by reference as though set forth herein in full. Note: Authority cited: Sections 21082 and 21083, Public Resources Code. Reference: Section 15050(e), Title 14, California Administrative Code. s 2904. Statutory Exemptions. The following Commission activity shall be considered ministerial: The issuance of a patent upon presentation of a valid Certificate of Purchase. Note: Authority cited: Section 21082, Public Resources Code; and Section 15073(a), Title 14, California Administrative Code. Reference: Section 7729, Public Resources Code; and Sections 15050(c)(1)(B) and 15073(a), Title 14, California Administrative Code. s 2905. Categorical Exemptions. The following Commission activities are categorically exempted: (a) Class 1: Existing Facilities (1) Remedial, maintenance and abandonment work on oil and gas and geothermal wells involving the alteration of well casings, such as perforating, cementing, casing repair or replacement, installation or removal of down-hold production equipment, cement plugs, bridge plugs, and permanent packers or packers set to isolate producing intervals. (2) Commission action involving existing structure or facility that is in an acceptable state of repair. This is intended to cover actions of the Commission which in effect authorize continued operation, repair, maintenance or minor alteration of any existing public or private structure or facility, land fill or equipment which meets the above criteria. The Commission may exclude from this class any structure that has been erected without written authorization in the form of a lease or permit from the State Lands Commission. (b) Class 2: Replacement or Reconstruction Replacement or reconstruction of deteriorated or damaged structures on State Lands. (c) Class 3: New Construction of Small Structures (1) A pier, floating dock, or boathouse, that will occupy no more than 3,000 square feet of State land. (2) A pier, floating dock, or boathouse, for non-commercial use by more than applicant, applying jointly, where all the applicants are littoral (next to the shore) landowners, such as homeowner's associations, and the littoral parcels are next to one another, that will occupy the following areas of State lands: Number of Adjacent and Littoral Landowners Area of Use 2 4,000 sq. ft. or less 3 4,750 sq. ft. or less 4 5,250 sq. ft. or less 5 or more 6,000 sq. ft. or less (3) Small boat mooring buoys. (4) A floating platform used solely for swimming. (5) Buoys for delineating a safety area or designated speed zones, provided that public navigational and fishing rights are not affected. (d) Class 4: Minor Alteration to Land (1) Grazing of livestock where disturbance of soil does not occur. (2) Rebuilding or repair of levees or other protective structure. Minor dredging of material for above purposes. (3) Removal of derelict or hazardous structures on State waterways or school lands. (4) Minor periodic maintenance dredging for existing docks and marinas. (5) Replanting of timber on previously harvested, burned, or barren areas of school lands where extensive site preparation is not permitted. (e) Class 6: Information Collection (1) Core hole drilling, operations to obtain foundation design data, to gather data and information for environmental documentation where minimal or no disturbance of the land surface results. (2) Core hole drilling for the purposes of mineral evaluation pursuant to Public Resources Code Section 6401(b) where minimal or no disturbance of the land surface results. (3) Surface or underwater biological, geological, geophysical, cultural (archeological/historical), and geochemical surveys where minimal or no disturbance of the land surface results. (4) Temperature survey holes where minimal disturbance of the surface results. (5) Wind or water current, temperature, or other monitoring devices. (6) Salvage exploration where no disturbance of the environment is contemplated. (f) Class 7: Actions by Regulatory Agencies for Protection of Natural Resources (1) Lease or permits to public agencies or conservation organizations for wildlife preservation activities, or to the State Department of Parks and Recreation for historical or other cultural activities. Construction activities are not included in this exemption. (2) Timber harvesting of burned or diseased timber on school lands in accordance with the Forest Practices Act (Public Resources Code, Sections 4511, et seq.). (g) Class 16: Transfer of Ownership of Land in Order to Create Parks Lease and permits to person and public agencies for the development of public parks including alterations to the land for such purposes. Note: Authority cited: Section 21084, Public Resources Code; and Sections 15100 et seq., Title 14, California Administrative Code. Reference: Sections 15100, 15100.2(c), 15100.4, 15101 (Class 1), 15102 (Class 2), 15103 (Class 3), 15104 (Class 4), 15106 (Class 6), 15107 (Class 7), and 15116 (Class 16), Title 14, California Administrative Code. s 2906. Adequate Time for Review and Comment. The review period for the final EIR shall be 15 days. Note: Authority cited: Section 21104, Public Resources Code; and Section 15160(a), Title 14, California Administrative Code. Reference: Section 15160(a), Title 14, California Administrative Code. s 2951. Authority and Purpose. These regulations are adopted pursuant to Public Resources Code Section 6370 in order to provide for the permanent protection of lands within Commission jurisdiction which possess significant environmental values. Note: Authority cited: Sections 6370 and 6370.1, Public Resources Code. Reference: Sections 6370 and 6370.1, Public Resources Code. s 2952. Significant Lands Inventory. Pursuant to Public Resources Code Section 6370.2, the Commission prepared a report entitled "Inventory of Unconveyed State School Lands and Tide and Submerged Lands Possessing Significant Environmental Values," approved December 1, 1975. This report shall be available to the public and shall herein be referred to as the "Significant Lands Inventory." Note: Authority cited: Section 6370 and 6370.2, Public Resources Code. Reference: Sections 6370 and 6370.2, Public Resources Code. s 2953. Definitions. (a) Environmentally significant lands: Lands within the jurisdiction of the Commission within which environmentally significant values have been identified pursuant to Public Resources Code Section 6370.1. (b) Significant environmental values: Those features or characteristics which have been identified pursuant to Public Resources Code Section 6370.1, the criteria for which are set forth in the Significant Lands Inventory. (c) Use Classification: A classification system designed to provide permanent protection to identify significant environmental values, more particularly described in the Significant Lands Inventory. Note: Authority cited: Sections 6370 and 6370.1, Public Resources Code. Reference: Sections 6370 and 6370.1, Public Resources Code. s 2954. Permanent Protection of Environmentally Significant Lands Through CEQA. Projects which will affect environmentally significant lands will be subject to review by the use of the CEQA process under the California Environmental Quality Act (Public Resources Code Sections 21000, et seq.); the State EIR Guidelines (14 California Administrative Code Sections 15000, et seq.); and the Commission's Regulations for the Implementation of the California Environmental Quality Act (Article 10 of this Chapter). In order to provide permanent protection to environmentally significant values, projects must be designed to be consistent with the use classifications assigned under the Significant Lands Inventory or pursuant to Public Resources Code Section 6219. If such consistency cannot be accomplished through mitigation or alteration of the project, the project must be denied. The Commission may not apply Section 15089 of the State EIR Guidelines, regarding a Statement of Overriding Considerations, to approve a project which cannot be made consistent with the use classification assigned to the subject parcel. Note: Authority cited: Sections 6219 and 6370, Public Resources Code. Reference: Sections 6219 and 6370, Public Resources Code. NOTE: Pursuant to a regulation of the Fair Political Practices Commission (Title 2, CCR, section 18750(k)(2)), an agency adopting a conflict of interest code has the options of requesting that the code either be (1) printed in the CCR in its entirety or (2) incorporated by reference into the CCR. Here, the adopting agency has requested incorporation by reference. However, the full text of the regulations is available to the public for review or purchase at cost at the following locations: STATE LANDS COMMISSION 1807 13TH STREET, ROOM 101 SACRAMENTO, CALIFORNIA 95814 FAIR POLITICAL PRACTICES COMMISSION 1100 K STREET SACRAMENTO, CALIFORNIA 95814 ARCHIVES SECRETARY OF STATE 1020 "O" STREET SACRAMENTO, CALIFORNIA 95814 The Conflict of Interest Code is designated as Article 12 of Chapter 1 of Division 3, Title 2, California Code of Regulations, and consists of sections numbered and titled as follows: Article 12. Conflict of Interest Code Section 2970. General Provisions Appendix Note: Authority cited: Sections 87300 and 87304, Government Code. Reference: Sections 87300, et seq., Government Code. s 2980. Purpose and Scope. The purpose of this article is to establish, as authorized and required by Government Code Sections 4525 et seq. , procedures for securing architectural, landscape architecture, engineering, environmental, land surveying, and construction project management services. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Sections 4525-4529.5, Government Code. s 2980.1. Definitions. As used in these regulations, the following terms have the following meaning: (a) "Firm" means any individual, firm, partnership, corporation, association, or other legal entity permitted by law to practice the profession of architecture, landscape architecture, engineering, environmental services, land surveying, or construction project management. (b) "Small business" firm is one that meets the definition of small business firm set forth in Title 2, California Code of Regulations, Section 1896(n). (c) "Commission" is the State Lands Commission. (d) "Executive Officer" is the Executive Officer of the State Lands Commission or any person designated by the Executive Officer to act on behalf of the Executive Officer. (e) "Architectural, landscape architectural, engineering, environmental, and land surveying services" includes those professional services of an architectural, landscape architectural, engineering, environmental, or land surveying nature as well as incidental services that members of these professions and those in their employ may logically and justifiably perform. (f) "Construction project management" means those services provided by a licensed architect, registered engineer, or licensed general contractor which meet the requirements of Government Code Section 4529.5 for management and supervision of work performed on state construction projects. (g) "Environmental services" means those services performed in connection with project development and permit processing in order to comply with federal and state environmental laws. "Environmental services" also includes the processing and awarding of claims pursuant to Chapter 6.75 (commencing with Section 25299.10) of Division 20 of the Health and Safety Code. (h) "Publish" shall mean publication of notices describing projects for which architectural, landscape architecture, engineering, environmental, land surveying, or construction project management services will be required in the publications of the respective professional societies and in the State Contracts Register. "Publish" shall also include publication of such notices in electronic form through the Internet. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4525, Government Code. s 2980.2. Conflict of Interest/Unlawful Activity Prohibited. Any practice which might result in unlawful activity, including, but not limited to, rebates, kickbacks, or other unlawful consideration, is strictly prohibited, and each Commission employee is specifically prohibited from participating in the negotiation or selection process when that employee has an interest in, or has a personal or business relationship with a person affiliated with, any person or business entity seeking a contract with the Commission or solicited by the Commission for such a contract which would subject that employee to the prohibition of Section 87100 of the Government Code. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Sections 4526 and 87100, Government Code. s 2980.3. Establishment of General Criteria and Establishment of List of Pre-Qualified Contractors. (a) The Executive Officer shall publish at least annually a notice that solicits statements of qualification and performance data from firms that provide the services defined in Section 2980.1. (b) The Executive Officer shall establish and publish a list of relevant general criteria which will form the basis for adding such firms to a list of pre-qualified contractors maintained by the Commission. The general criteria shall include such factors as professional excellence, demonstrated competence, specialized experience of the firm, education and experience of key personnel to be assigned, staff capability, workload, ability to meet schedules, nature and quality of completed work, reliability and continuity of the firm, location, familiarity with pertinent regulatory processes, familiarity with project locale, previous experience with a specific type of project, and other considerations deemed relevant. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4527, Government Code. s 2980.4. Construction Project Management Expertise. Any individual or firm proposing to provide construction project management services pursuant to these regulations shall provide evidence that the individual or firm and its personnel carrying out onsite responsibilities have expertise and experience in construction project design review and evaluation, construction mobilization and supervision, bid evaluation, project scheduling, cost-benefit analysis, claims review and negotiation, and general management and administration of a construction project. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4529.5, Government Code. s 2980.5. Notice and Publication for Specific Projects (a) The Executive Officer shall publish a statewide announcement of any project or projects requiring architectural, landscape architectural, engineering, environmental, land surveying, or construction management services. Such announcement shall contain, at a minimum, the type of services required, a description of the project, a projected schedule for the project, a description of responsive material that must be submitted by firms not on the Commission's list of pre-qualified firms, and a date before which that responsive material must be submitted to the Commission. (b) The Executive Officer may, prior to engaging a firm for a specific project, develop and include in the published statewide announcement for the project a list of relevant factors, if any, that may be considered in selecting a contractor for that particular project. Such factors may be considered by the Executive Officer according to the nature of the project, the needs of the State and the complexity and special requirements of that specific project. (c) The Executive Officer shall endeavor to provide to all small business firms which have indicated an interest in receiving such announcements a copy of each project announcement. Failure of the Executive Officer to send a copy of an announcement to any firm or failure of such firm or firms to receive an announcement sent by the Executive Officer shall not operate to preclude any contract. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Sections 4527 and 4528, Government Code. s 2980.6. Estimate of Value of Services. Before any discussion with any firm concerning fees for services provided in connection with a particular project, the Executive Officer shall cause an estimate of the value of such services to be prepared. This estimate shall serve as a guide in determining fair and reasonable compensation for the services rendered. Such estimate shall be, and remain, confidential until award of contract or abandonment of any further procedure for the services to which it relates. At any time the Executive Officer determines the State's estimates to be unrealistic due to rising costs, special conditions, or for other relevant considerations, the estimate shall be reevaluated and modified if necessary. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4528, Government Code. s 2980.7. Negotiation of Contract. (a) After expiration of the notice/compliance period stated in an announcement, the Executive Officer shall evaluate current statements of qualifications and performance data on file with the Commission, together with those that may be submitted by other firms regarding the proposed project, and shall conduct discussions with no less than three firms regarding the Commission's need for services, and the ability of each firm to provide those services to the Commission for the proposed project in a timely manner. The Executive Officer shall then select therefrom, in order of preference, based upon criteria established pursuant to section 2980.3, no less than three of the firms deemed to be the most highly qualified to provide the services required. (b) The Executive Officer shall, in accordance with section 6106 of the Public Contracts Code, negotiate a contract with the best-qualified firm for services at compensation that the Executive Officer determines is fair and reasonable to the State of California. Should the Executive Officer be unable to negotiate a satisfactory contract with the firm considered to be the best-qualified at a price the Executive Officer determines to be fair and reasonable to the State of California, negotiations with that firm shall be formally terminated. The Executive Officer shall then undertake negotiations with the second best-qualified firm. Failing accord with the second most qualified firm, the Executive Officer shall terminate negotiations. The Executive Officer shall then undertake negotiations with the third most qualified firm. (c) Should the Executive Officer be unable to negotiate a satisfactory contract with any of the selected firms, the Executive Officer shall select additional firms in order of their competence and qualifications and continue negotiations in the same manner until a satisfactory agreement is reached. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Sections 4527 and 4528, Government Code. s 2980.8. Contracting in Phases. Should the Commission determine that it is necessary or desirable to have a given project performed in phases, it will not be necessary to negotiate the total contract price or compensation provisions at the time the initial phase is negotiated, provided that the Executive Officer shall have determined that the firm is the best qualified to perform the whole project at a fair and reasonable cost and that the contract contains provisions that the State, at its option, may utilize the firm for other phases and that the firm will accept a fair and reasonable price for subsequent phases to be later negotiated and reflected in a subsequent written instrument. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4528, Government Code. s 2980.9. Amendments. In instances where the Commission or the Executive Officer orders a necessary change in the character or scope of work to be performed in the course of performance of the contract, the firm's compensation may, by written agreement between the Commission and the firm, be adjusted in an amount which reasonably reflects the value of the change from that character and scope of work which existed prior to the change. Note: Authority cited: Section 4526, Government Code; and Section 6108, Public Resources Code. Reference: Section 4528, Government Code. Note: Authority cited: Section 8750, Government Code. Reference: Sections 8750-8756 and 81000, Government Code. s 3600. Statement of Purposes. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3604. Eligibility. (a) To be eligible for funding, an applicant shall meet the following eligibility requirements. (1) Organizations shall be required to meet the following: (A) have proof of non-profit status under section 501(c)(3) of the Internal Revenue Code, or under section 23701(d) of the California Revenue and Taxation Code, or be a unit of government. (B) be consistently engaged in arts programming for a specific number of years prior to time of application; (C) must comply with the Civil Rights Act of 1964, section 504 of the Rehabilitation Act of 1973 (as amended), the Age Discrimination Act of 1975, observe provision of the Drug Free Workplace Act, and Government Code sections 11135-11139.5; (D) must comply with Fair Labor Standards Act; as defined by the Secretary of Labor in part 505 of title 29 of the Code of Federal Regulations. (E) must have principal place of business in California; (F) must have completed prior contract evaluations, if applicable; (G) must have approval of the applicant organization's board of directors or other governing body. (2) Individuals shall be required to meet the following: (A) must be a working artist/and show professional competence in an artistic discipline; (B) must be a resident of California, except for artist applying in the Arts in Public Building Program. (C) must comply with the Personal Responsibility and Work Opportunity Act of 1996. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code; and 8 U.S.C. Sections 1621, 1641 and 1642. s 3608. Grants. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3612. Grant Categories. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3616. Funding Criteria. (a) The California Arts Council shall predetermine which program categories shall be awarded contracts for services and which shall be awarded grants. Grants and/or contracts shall be awarded only to those individuals and/or organizations which demonstrate high artistic merit, high standards of performance and administration, promote cross-cultural exchange, serve unique needs created by geographic or other special factors, encourage the development and assimilation of new art forms, and/or demonstrate the problem solving capacities of arts and artists for the general public and the various agencies and institutions that serve them. The California Arts Council shall also consider the effect of the program or project on the artist and/or the organization as well as the community, the capacity to carry out the project, and the need that is demonstrated for the support requested. (b) The California Arts Council shall not fund with local assistance monies for profit organizations, capital investments, out-of-state travel or expenditures for equipment, except as recommended by the Executive Director, with the approval of the Council and relevant Control agencies. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3620. Matching Grants, or Contracts. The California Arts Council may require grants or contracts to be matched. A match is constituted in dollars or in goods or services (in-kind match) from the local organization, school or agency. (a) The following criteria shall guide the California Arts Council in determining which program, grants or contracts will be matched and the amount of the match: (1) The ability of the applicants to raise matching dollars. (2) The extent to which matching dollars addresses program goals and objectives. (3) The need for the California Arts Council to provide a match for federal dollars awarded to the state and re-granted to local organizations or individuals. (b) The following match designs shall be considered in Arts Council programs: (1) Cash match: the applicant must provide for some of the cost of the project and match the California Arts Council dollars. The ratio of the match will vary from program to program for the reasons described in (a) above. (2) Progressive match: this is a multi-year commitment requiring different match responsibilities each year. (3) No match: grants or contracts are awarded with no matching requirements. (4) No-cash match: goods and/or services can be provided in place of cash. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3624. Program Development Procedures. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3628. Application Review and Awards Process. (a) Applicants shall apply under a specific funding category and are required to complete the application forms contained in the relevant publications when applying for a specific grant. The California Arts Council hereby incorporates by reference the specific applications and specific instructions contained within these publications for each program. (1) Art in Public Buildings Program Instructions and Application 1990-91 (2) Artist Fellowship Program Instructions and Application 1990-91 (3) Artists in Residence Individual Artist Instructions and Application 1991-92 Multi-Residency Instructions and Application 1990-91 (4) California Challenge Program Instructions and Application 1990-91 (5) Multi-Cultural Advancement Grant Application and Instructions 1990-91 Entry Grant Instructions and Application 1990-93 (6) Organizational Support Program Mid-Size and Large Organizations Instructions and Application 1990-91 Small Organizations Instructions and Application 1990-91 Large Budget Organizations Instructions and Application 1990-91 (7) State-Local Partnership Instructions and Application 1990-91 (8) Touring Artist Directory 1990-91 (9) Touring/Presenting Program Instructions and Application 1991-92 and 1992-93 (10) Traditional Folk Arts Program Instructions and Applications 1990-91 (b) The application forms are intended to provide the California Arts Council with information and shall include, but not necessarily be limited to: (1) Name, mailing address, telephone and social security number. (2) A description of the project, including a budget, if applicable. (3) A brief statement of the applicant's objectives and how the proposed project will achieve the objective. (4) An annual income and expenditure report and if applicable, source of match (Applicants for fellowships, apprenticeships, and commissions are exempted from reporting this information.) (5) Documentation and support materials. Some examples are videotapes, audio cassettes, slides, catalogs, publicity photos, books and manuscripts. (c) Upon receipt of an application each application, shall be reviewed by the California Arts Council or its designee for compliance with instructions and completeness and then forward to the peer review panel. Incomplete applications or those not in compliance will not be reviewed by the peer review panel. (1) Members of the peer review panels shall be approved by the Council. These members shall be from the arts community and provide their expertise in evaluating all aspects of applications. Panels shall be selected by the California Arts Council to represent the diversity of California in terms of geography, gender, ethnicity and arts discipline. (2) One or more Council Members may be present at peer review panels which meet and discuss each application. After discussion and evaluation of applications according to criteria outlined in each program's instructions, (section 3628(a) above) the panel shall rank each application in accordance with the highest priority for funding. The list of recommendations shall then be presented to the full Council which shall make the final decisions on funding and awards at a public meeting. (d) Notification of applicant status. (1) All applicants, those receiving and those denied grant awards, shall be notified by the California Arts Council staff of the Council's decision by mail within ten working days after the public meeting. (2) Applicants approved for funding shall receive information from the California Arts Council outlining the award agreement, mutual responsibilities and safeguards for the agency and the recipient. (3) Grant award letters or contract for services agreements shall be signed by the grantee and returned to the agency within 60 days of the date postmarked. (e) Payment on direct grants. Grant award payments shall be allocated by either a lump sum award or a partial advance payment with the final payment of the grant award, to be made after evaluation of the project. (f) Payment on contracts for services. (1) The California Arts Council shall make payment in arrears on contracts for services, meaning that grantees shall be reimbursed for expenses already incurred. Payment will be made within thirty days after receipt of invoices. (2) The California Arts Council shall determine when advance payments may be made to recipients of contracts for services. These advance payments shall not exceed 25% of the contract amount at any one time. Those applicants that receive advance payments shall submit invoices for actual expenditures prior to the receipt of any additional funds. (3) The final 10% of a contract will be withheld until the recipient has submitted the final evaluation report. (g) The California Arts Council shall not claim ownership, copyright rights, royalties or any other claims to artwork produced as a result of a California Arts Council grant or contract. The California Arts Council may request documentation or copies of artwork for purposes of the California Arts Council record. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3629. Limitations on Individual Contract Grants for Aliens. (a) All eligibility requirements contained herein shall be applied without regard to the race, creed, color, gender, religion, or national origin of the individual applying for the public benefit. (b) Pursuant to Section 411 of the Personal Responsibility and Work Opportunity Reconciliation Act of 1996 (Pub. L. No. 104-193 (PRWORA)), (8 U.S.C. s 1621), and notwithstanding any other provision of this division, aliens who are not qualified aliens, nonimmigrant aliens under the Immigration and Nationality Act (INA) (8 U.S.C. s 1101 et seq.), or aliens paroled into the United States under Section 212(d)(5) of the INA (8 U.S.C. s 1182(d)(5)) for lessthan one year, are not eligible to receive individual contract grants as set forth in Section 8753, Government Code, except as provided in 8 U.S.C. s 1621(c)(2). (c) A qualified alien is an alien who, at the time he or she applies for, receives, or attempts to receive a public benefit, is, under Section 431(b) and (c) of the PRWORA (8 U.S.C. s 1641(b) and (c)), any of the following: (1) An alien who is lawfully admitted for permanent residence under the INA (8 U.S.C. s 1101 et seq.). (2) An alien who is granted asylum under Section 208 of the INA (8 U.S.C. s 1158). (3) A refugee who is admitted to the United States under Section 207 of the INA (8 U.S.C. s 1157). (4) An alien who is paroled into the United States under Section 212(d)(5) of the INA (8 U.S.C. s 1182(d)(5)) for a period of at least one year. (5) An alien whose deportation is being withheld under Section 243(h) of the INA (8 U.S.C. s 1253(h)) (as in effect immediately before the effective date of Section 307 of division C of Public Law 104-208) or Section 241(b)(3) of such Act (8 U.S.C. s 1251(b)(3)) (as amended by Section 305(a) of division C of Public Law 104-208). (6) An alien who is granted conditional entry pursuant to Section 203(a)(7) of the INA as in effect prior to April 1, 1980. (8 U.S.C. s 1153(a)(7)) (See editorial note under 8 U.S.C. s 1101, "Effective Date of 1980 Amendment.") (7) An alien who is a Cuban or Haitian entrant (as defined in Section 501(e) of the Refugee Education Assistance Act of 1980 (8 U.S.C. s 1522 note)). (8) An alien who meets all of the conditions of subparagraphs (A), (B), (C), and (D) below: (A) The alien has been battered or subjected to extreme cruelty in the United States by a spouse or a parent, or by a member of the spouse's or parent's family residing in the same household as the alien, and the spouse or parent of the alien consented to, or acquiesced in, such battery or cruelty. For purposes of this subsection, the term "battered or subjected to extreme cruelty" includes, but is not limited to being the victim of any act or threatened act of violence including any forceful detention, which results or threatens to result in physical or mental injury. Rape, molestation, incest (if the victim is a minor), or forced prostitution shall be considered acts of violence. (B) There is a substantial connection between such battery or cruelty and the need for the benefits to be provided in the opinion of the California Arts Council. For purposes of this subsection, the following circumstances demonstrate a substantial connection between the battery or cruelty and the need for the benefits to be provided: 1. The benefits are needed to enable the alien to become self-sufficient following separation from the abuser. 2. The benefits are needed to enable the alien to escape the abuser and/or the community in which the abuser lives, or to ensure the safety of the alien from the abuser. 3. The benefits are needed due to a loss of financial support resulting from the alien's separation from the abuser. 4. The benefits are needed because the battery or cruelty, separation from the abuser, or work absences or lower job performance resulting from the battery or extreme cruelty or from legal proceedings relating thereto (including resulting child support, child custody, and divorce actions) cause the alien to lose his or her job or to earn less or to require the alien to leave his or her job for safety reasons. 5. The benefits are needed because the alien requires medical attention or mental health counseling, or has become disabled, as a result of the battery or extreme cruelty. 6. The benefits are needed because the loss of a dwelling or source of income or fear of the abuser following separation from the abuser jeopardizes the alien's ability to care for his or her children (e.g., inability to house, feed, or clothe children or to put children into a day care for fear of being found by the abuser). 7. The benefits are needed to alleviate nutritional risk or need resulting from the abuse or following separation from the abuser. 8. The benefits are needed to provide medical care during a pregnancy resulting from the abuser's sexual assault or abuse of, or relationship with, the alien and/or to care for any resulting children. 9. Where medical coverage and/or health care services are needed to replace medical coverage or health care services the alien had when living with the abuser. (C) The alien has a petition that has been approved or has a petition pending which sets forth a prima facie case for: 1. status as a spouse or child of a United States citizen pursuant to clause (ii), (iii), or (iv) of Section 204(a)(1)(A) of the INA (8 U.S.C. s 1154(a)(1)(A)(ii), (iii) or (iv)), 2. classification pursuant to clause (ii) or (iii) of Section 204(a)(1)(B) of the INA (8 U.S.C. s 1154(a)(1)(B)(ii) or (iii)), 3. suspension of deportation and adjustment of status pursuant to section 244(a)(3) of the INA (8 U.S.C. s 1254) as in effect prior to April 1, 1997 [Pub. L. 104-208. s 501 (effective September 30, 1996, pursuant to sec. 591); Pub. L. 104-208. Sec. 304 (effective April 1, 1997, pursuant to sec. 309); Pub. L. 105-33, sec. 5581 (effective pursuant to sec. 5582)] (incorrectly codified as "cancellation of removal under section 240A of such Act [8 U.S.C.S. sec. 1229b] (as in effect prior to April 1, 1997)", 4. status as a spouse or child of a United States citizen pursuant to clause (i) of Section 204(a)(1)(A) of the INA (8 U.S.C. s 1154(a)(1)(A)(i)) or classification pursuant to clause (i) of Section 204(a)(1)(B) of the INA (8 U.S.C. s 1154(a)(1)(B)(i)), or 5. cancellation of removal pursuant to section 240A(b)(2) of the INA (8 U.S.C. s 1229b(b)(2)). (D) For the period for which benefits are sought, the individual responsible for the battery or cruelty does not reside in the same household or family eligibility unit as the individual subjected to the battery or cruelty. (9) An alien who meets all of the conditions of subparagraphs (A), (B), (C), (D) and (E) below: (A) The alien has a child who has been battered or subjected to extreme cruelty in the United States by a spouse or a parent of the alien (without the active participation of the alien in the batteryor cruelty), or by a member of the spouse's or parent's family residing in the same household as the alien, and the spouse or parent consented or acquiesced to such battery or cruelty. For purposes of this subsection, the term "battered or subjected to extreme cruelty" includes, but is not limited to being the victim of any act or threatened act of violence including any forceful detention, which results or threatens to result in physical or mental injury. Rape, molestation, incest (if the victim is a minor), or forced prostitution shall be considered acts of violence. (B) The alien did not actively participate in such battery or cruelty. (C) There is a substantial connection between such battery or cruelty and the need for the benefits to be provided in the opinion of the California Arts Council. For purposes of this subsection, the following circumstances demonstrate a substantial connection between the battery or cruelty and the need for the benefits to be provided: 1. The benefits are needed to enable the alien's child to become self-sufficient following separation from the abuser. 2. The benefits are needed to enable the alien's child to escape the abuser and/or the community in which the abuser lives, or to ensure the safety of the alien's child from the abuser. 3. The benefits are needed due to a loss of financial support resulting from the alien's child's separation from the abuser. 4. The benefits are needed because the battery or cruelty, separation from the abuser, or work absences or lower job performance resulting from the battery or extreme cruelty or from legal proceedings relating thereto (including resulting child support, child custody, and divorce actions) cause the alien's child to lose his or her job or to earn less or to require the alien's child to leave his or her job for safety reasons. 5. The benefits are needed because the alien's child requires medical attention or mental health counseling, or has become disabled, as a result of the battery or extreme cruelty. 6. The benefits are needed because the loss of a dwelling or source of income or fear of the abuser following separation from the abuser jeopardizes the alien's child's ability to care for his or her children (e.g., inability to house, feed, or clothe children or to put children into day care for fear of being found by the abuser). 7. The benefits are needed to alleviate nutritional risk or need resulting from the abuse or following separation from the abuser. 8. The benefits are needed to provide medical care during a pregnancy resulting from the abuser's sexual assault or abuse of, or relationship with, the alien's child and/or to care for any resulting children. 9. Where medical coverage and/or health care services are needed to replace medical coverage or health care services the alien's child had when living with the abuser. (D) The alien meets the requirements of subsection (c)(8)(C) above. (E) For the period for which benefits are sought, the individual responsible for the battery or cruelty does not reside in the same household or family eligibility unit as the individual subjected to the battery or cruelty. (10) An alien child who meets all of the conditions of subparagraphs (A), (B), and (C) below: (A) The alien child resides in the same household as a parent who has been battered or subjected to extreme cruelty in the United States by that parent's spouse or by a member of the spouse's family residing in the same household as the parent and the spouse consented or acquiesced to such battery or cruelty. For purposes of this subsection, the term "battered or subjected to extreme cruelty" includes, but is not limited to being the victim of any act or threatened act of violence including any forceful detention, which results or threatens to result in physical or mental injury. Rape, molestation, incest (if the victim is a minor), or forced prostitution shall be considered acts of violence. (B) There is a substantial connection between such battery or cruelty and the need for the benefits to be provided in the opinion of the California Arts Council. For purposes of this subsection, the following circumstances demonstrate a substantial connection between the battery or cruelty and the need for the benefits to be provided: 1. The benefits are needed to enable the alien child's parent to become self-sufficient following separation from the abuser. 2. The benefits are needed to enable the alien child's parent to escape the abuser and/or the community in which the abuser lives, or to ensure the safety of the alien child's parent from the abuser. 3. The benefits are needed due to a loss of financial support resulting from the alien child's parent's separation from the abuser. 4. The benefits are needed because the battery or cruelty, separation from the abuser, or work absences or lower job performance resulting from the battery or extreme cruelty or from legal proceedings relating thereto (including resulting child support, child custody, and divorce actions) cause the alien child's parent to lose his or her job or to earn less or to require the alien child's parent to leave his or her job for safety reasons. 5. The benefits are needed because the alien child's parent requires medical attention or mental health counseling, or has become disabled, as a result of the battery or extreme cruelty. 6. The benefits are needed because the loss of a dwelling or source of income or fear of the abuser following separation from the abuser jeopardizes the alien child's parent's ability to care for his or her children (e.g., inability to house, feed, or clothe children or to put children into day care for fear of being found by the abuser). 7. The benefits are needed to alleviate nutritional risk or need resulting from the abuse or following separation from the abuser. 8. The benefits are needed to provide medical care during a pregnancy resulting from the abuser's sexual assault or abuse of, or relationship with, the alien child's parent and/or to care for any resulting children. 9. Where medical coverage and/or health care services are needed to replace medical coverage or health care services the alien child's parent had when living with the abuser. (C) The alien child meets the requirements of subsection (c)(8)(C) above. (d) For purposes of this section, "nonimmigrant" is defined the same as in Section 101(a)(15) of the INA (8 U.S.C. s 1101(a)(15)). (e) For purposes of establishing eligibility for individual contract grants pursuant to Section 8753, Government Code, all of the following must be met: (1) The applicant must declare himself or herself to be a citizen of the United States, a qualified alien under subsection (c), a nonimmigrant alien under subsection (d), or an alien paroled into the United States for less than one year under Section 212(d)(5) of the INA (8 U.S.C. s 1182(d)(5)). The applicant shall declare that status through use of the "Statement of Citizenship, Alienage, and Immigration Status for State Public Benefits," Form CAC 272 (Edition 3/98), which is hereby incorporated by reference. (2) The applicant must present documents of a type acceptable to the Immigration and Naturalization Services (INS) which serve as reasonable evidence of the applicant's declared status. (3) The applicant must complete and sign Form CAC 272 (Edition 3/98). (4) Where authorized by the INS, the documentation presented by an alien as reasonable evidence of the alien's declared immigration status must be submitted to the INS for verification through the Systematic Alien Verification for Entitlements (SAVE) system procedures as follows: (A) Unless the primary SAVE system is unavailable for use, the primary SAVE system verification must be used to access the biographical/immigration status computer record contained in the Alien Status Verification Index maintained by the INS. Subject to subparagraph (B), this procedure must be used to verify the status of all aliens who claim to be qualified aliens and who present an INS-issued document that contains an alien registration or alien admission number. (B) In any of the following cases, the secondary SAVE system verification procedure may be used to forward copies of original INS documents evidencing an alien's status as a qualified alien, as a nonimmigrant alien under the INA, or as an alien paroled into the United States under Section 212(d)(5) of the INA (8 U.S.C. s 1182(d)(5)) for less than one year: 1. The primary SAVE system is unavailable for verification. 2. A primary check of the Alien Status Verification Index instructs the California Arts Council to "institute secondary verification." 3. The document presented indicates immigration status but does not include an alien registration or alien admission number. 4. The Alien Status Verification Index record includes the alien registration or admission number on the document presented by the alien but does not match other information contained in the document. 5. The document is suspected to be counterfeit or to have been altered. 6. The document includes an alien registration number in the A60 000 000 (not yet issued) or A80 000 000 (illegal border crossing) series. 7. The document is a fee receipt from INS for replacement of a lost, stolen, or unreadable INS document. 8. The document is one of the following: an INS Form I-181b notification letter issued in connection with an INS Form I-181 Memorandum of Creation of Record of Permanent Residence, an Arrival-Departure Record (INS Form I-94) or a foreign passport stamped "PROCESSED FOR I-551, TEMPORARY EVIDENCE OF LAWFUL PERMANENT RESIDENCE" that INS issued more than one year before the date of application for individual contract grants. (5) Where verification through the SAVE system is not available, if the documents presented do not on their face reasonably appear to be genuine or to relate to the individual presenting them, the government entity that originally issued the document shall be contacted for verification. With regard to naturalized citizens and derivative citizens presenting certificates of citizenship and aliens, the INS is the appropriate government entity to contact for verification. The California Arts Council shall request verification by the INS by filing INS Form G-845 with copies of the pertinent documents provided by the applicant with the local INS office. If the applicant has lost his or her original documents, or presents expired documents or is unable to present any documentation evidencing his or her immigration status, the applicant shall be referred to the local INS office to obtain documentation. (6) If the INS advises that the applicant has citizenship status or immigration status which makes him or her a qualified alien, a nonimmigrant or alien paroled for less than one year under section 212(d)(5) of the INA, the INS verification shall be accepted. If the INS advises that it cannot verify that the applicant has citizenship status or an immigration status that makes him or her a qualified alien, a nonimmigrant or an alien paroled for less than one year under section 212(d)(5) of the INA, benefits shall be denied and the applicant notified pursuant to the individual contract grants regular procedures of his or her rights to appeal the denial of benefits. (7) Provided that the alien has completed and signed Form CAC 272 (Edition 3/98) under penalty of perjury, eligibility for individual contract grants shall not be delayed, denied, reduced or terminated while the status of the alien is verified. (f) Pursuant to Section 432(d) of the PRWORA (8 U.S.C. s 1642(d)), a nonprofit charitable organization that provides federal, state, or local public benefits shall not be required to determine, verify, or otherwise require proof of eligibility of any applicant or beneficiary with respect to his or her immigration status or alienage. (g) Nothing in this section shall be construed to withdraw eligibility for any applicable exception, under section 411(b) of the PRWORA, 8 U.S.C. s 1621(b). (h) Pursuant to Section 434 of the PRWORA (8 U.S.C. s 1644), where the California Arts Council reasonably believes that an alien is unlawfully in the State based on the failure of the alien to provide reasonable evidence of the alien's declared status, after an opportunity to do so, said alien shall be reported to the Immigration and Naturalization Service. (i) Any applicant who is determined to be ineligible pursuant to subsection (b) and (e) or who was made eligible for individual contract grants whose services are terminated, suspended, or reduced pursuant to subsections (b) and (e), is entitled to a hearing, pursuant to appropriate authority for administrative review of decision on eligibility for state public benefit. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code; 8 U.S.C. Sections 1621, 1641 and 1642. s 3632. Funding Amounts. For those organizations or individual artists whose grant or contract has been approved, the California Arts Council shall notify the applicant of the funding amount recommended by the peer review panel or allowed within the program instructions. (Section 3628(a)). Applicants may or may not receive the full amount requested. The California Arts Council shall set funding amounts for grants or contracts based on the following factors. (1) Annual state budget. (2) Total dollars requested by recommended fundable applications. (3) Number of fundable projects. Note: Authority cited: Section 8753, Government Code. Reference: Sections 8753 and 8753.5, Government Code. s 3636. California Arts Council Goals. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3640. General State Requirements. (a) The following requirements, in addition to any special conditions incorporated in the California Arts Council Funding Criteria shall be applicable to and binding upon recipients of awards from the California Arts Council. (1) Those awards which consist in whole or in part of Federal funds shall be made only to organizations which do not use Federal funds as part of their match. (2) Applicants shall not use Federal funds to match Federal funds. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 3644. Project Defined. Note: Authority cited: Section 8753, Government Code. Reference: Section 8753, Government Code. s 4000. Definitions. For the purpose of these regulations, the following words and phrases are defined and shall be construed as hereinafter set out unless it shall be apparent from the context that they have a different meaning. (a) "Directors of board" shall name the Board of Directors of the California Museum of Science and Industry. (b) "Association" means the Sixth District Agricultural Association, a state institution, now known as the California Museum of Science and Industry. (c) "Park" shall include all driveways, paths or any of the grounds of the California Museum of Science and Industry; including that area leased to the Coliseum Commission, the City of Los Angeles, the County of Los Angeles or any department or part of the government of the State of California. (d) "Park" is synonymous with Exposition Park and includes area owned by the California Museum of Science and Industry bounded on the north by Exposition Boulevard, on the east by Figueroa, on the south by Santa Barbara and on the west by Vermont Avenue and excepting therefrom any areas not owned by the California Museum of Science and Industry. (e) "Police officer" shall mean every officer of the California State Police and the Museum Security Officers of the California Museum of Science and Industry. (f) "Shall" is mandatory and "may" is permissive. Note: Authority cited for Article 1 (Sections 4000 through 4012): Section 3965, Food and Agricultural Code. s 4001. Soliciting. s 4002. Lingering or Loitering. s 4003. Lingering or Loitering After Ordered to Leave. s 4004. Obstructions. s 4005. Dogs. s 4006. Games. s 4007. Bicycles. The riding of bicycles in the park is prohibited except in and upon that portion of the park used by vehicular traffic. s 4008. Flower Beds, Lawns, Terraces and Other Structures. s 4009. Handbills and Circulars. s 4010. Fountains and Ponds. s 4011. Landing of Helicopter. s 4012. Deposit of Offensive Matter, Rocks or Dirt. s 5000. Definitions. Note: Authority cited: Section 3965, Food and Agricultural Code. Reference: Sections 21113 and 22659, Vehicle Code. s 5001. Driving and Parking Vehicles in the Park -General. s 5002. Boulevard Stops in the Park. s 5003. Speed of Vehicles in the Park. s 5004. Standing or Parking of Vehicles in the Park. s 5005. Crosswalks in the Park. s 5006. Parking Area. s 5007. Driving in the Parking Area. s 5008. U-Turn. s 5009. Driving over a Double Line. s 5010. Driving Under the Influence of Liquor or Narcotics. s 5011. Driver's License. s 5012. Removal of Debris from Accidents. The driver of any vehicle which is involved in any collision shall remove or cause to be removed all glass and other debris which may have fallen on any roadway as a result of such collision from such roadway or parking area before leaving the place of the collision, and every person hired or employed to move or remove any such vehicle shall remove all glass and other debris which may have fallen upon the roadway or parking area as a result of the collision in which the vehicle was involved before removing the vehicle. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5013. Authorized Emergency Vehicles. s 5014. Citations and Arrests. s 5015. Presumption of Validity of Signs, Devices, Signals and Markings. s 5016. Driving on the Right. s 5017. Passing a Stopped Car at a Crosswalk. s 5018. Driving in a Parking Area. No person shall enter any parking area except at places marked "entrance" nor leave such area except at the places marked "exit," unless the contrary shall be established by competent evidence. The Museum may, when it is necessary, determine if the movement of traffic will be expedited and thereby designate: (a) Places where vehicles may or may not be parked. (b) Period of time for which vehicles may be parked at any place and display appropriate signs giving notice thereof. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5019. Parking Time Limitations. (a) Stopping or Standing Prohibited. (1) Whenever authorized signs are in place giving notice that stopping or standing is prohibited during such hours or on such days as are indicated on such signs, it shall be unlawful for any person to stop or stand or park any vehicle at any time and during such hours or such days. (b) Parking Prohibited. (1) Whenever authorized signs are in place giving notice that parking is prohibited at any time or during certain hours, it shall be unlawful for any person to park any vehicle during such prohibited times. (c) Parking Time Limits. (1) Whenever authorized signs are in place giving notice thereof, it shall be unlawful for any person to stop or stand or park any vehicle for a period of time in excess of the parking time limit indicated by such signs. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5020. All Night Parking Prohibited. No persons shall stop, stand or park a vehicle overnight on any driveway, path, road, or any grounds of the Museum. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5021. Unlawful Parking, Peddlers, Vendors. (a) No persons shall stop, stand or park any vehicle, wagon, or push cart for the purpose of peddling, hocking, displaying or offering for sale therefrom any goods, wares, merchandise, or any fruit, vegetables, drinks or food stuffs on any path, driveway, roadway or any grounds of the park without the express written permission of the board. Said permit must designate the specific location at which such vehicle, wagon or push cart may stand and shall be conspicuously displayed at all times. (b) No person shall park or stand any vehicle or wagon used for any or intended to be used in the transportation of property for hire on any street, path, driveway, roadway or on any grounds in the park while awaiting patronage for such vehicle or wagon without first obtaining a written permit to do so from the board, which permit shall designate the specific location where such vehicle may stand. (c) No person shall stand or park a vehicle upon any pass or roadway or public parking area for the purpose of displaying such vehicle for sale by sign or otherwise. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5022. Temporary Signs. s 5023. Authorization to Place Curb Marks for Signs, No Stopping, Standing or Parking. s 5024. Establishment of Passenger, Commercial, Short Time Limit and No Stopping Curb Zone. s 5025. Marking and Parking for Zones. (a) No stopping zones when designated by painted curbs and signs shall be red and stenciled bus zones. No person shall park any vehicle at any time adjacent to a curb marked in red Bus zones shall be red and stenciled bus zones. (b) Short time parking zones when designated by painted curbs shall be green and stenciled with the time limit allowed for parking. No person shall park any vehicle adjacent to a curb marked in green for any period in excess of the posted time limit. (c) Commercial loading zones when designated by painted curbs shall be yellow and stenciled loading only. No persons shall park any vehicle other than a commercial vehicle adjacent to any yellow curb nor any commercial vehicle adjacent to such curb for any greater length of time than is actually necessary for the loading or unloading of materials. A curb marked in yellow should indicate a loading zone for commercial vehicles only. (d) Passenger loading zones when designated by painted curb shall be white and stenciled passenger loading zone only. No person shall park any vehicle other than a private passenger automobile adjacent to any white curb and shall not park any vehicle for any greater period of time than is actually necessary for the loading or unloading of passengers and personal baggage. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5026. Parking in the Parking Area. No persons shall park any vehicle in the public parking area except between the painted lines indicating where such vehicle shall be parked. No persons shall so park a vehicle as to occupy or use more than one such marked parking space. No person shall remove a vehicle from any public parking area without first paying all fees or charges due for the use of such parking space. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5027. Parallel and/or Angle Parking. s 5028. Designated Parking Area. Unless otherwise directed by the Museum or the California State Police, no person shall stop, park or leave standing any vehicle on any road, path or driveway or any parking area unless this vehicle is parked, stopped, or left standing in areas designated for parking and in conformance with such signs as may be posted on said grounds from time to time. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5029. Parking Permits. Parking permits shall be issued by the Museum under such conditions as may be described by the board. Said parking permits shall be subject to revocation or suspension at any time. No persons hall stop, park or leave standing any vehicle on the authority of said parking permit unless such vehicle is parked, stopped or left standing in the area designated for such parking by permit and in conformance with such signs as may be posted on said parking area from time to time. Said parking permits shall expire as indicated on said permit. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5030. Installation of Parking Meters Authorized. s 5031. Parking Meter Spaces to Be Indicated and Maintained. s 5032. Time of Parking in Parking Meter Zones. s 5033. Parking Meters, Times for Operations. s 5034. Operation of the Parking Meter. s 5035. Parking Meters, Deposit of Coins. When the operator of a vehicle parks this vehicle within a parking meter space on path, roadways or grounds of the park, the operator shall immediately deposit or cause to be deposited in the parking meter adjacent to such space lawful money of the United States of the rates determined by the Museum from time to time and indicated by signs around the parking meter. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5036. Parking Meters and Parking Meter Standards Not to Be Used for Certain Purposes. s 5037. Improper Use or Misuse of Meters. s 5038. Extending Parking Time. It shall be unlawful for any person to deposit or cause to be deposited in a parking meter any coins for the purpose of increasing or extending the parking time of any vehicle beyond the legal parking time which has been established by the board for the parking space adjacent to which the meter is placed. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5039. Failure to Deposit Coins. It shall be unlawful for any person to park or to cause, allow, permit or suffer to be parked a vehicle in any parking meter space without immediately depositing or causing to be deposited a coin or coins in the parking meter as hereinbefore provided. It shall be unlawful for any person to cause, allow, permit or suffer any vehicle to remain in any parking meter space for more than the time indicated by proper signs placed on such parking meters indicating the maximum parking time allowed in such parking meter space or during any time the parking meter is indicating that time has elapsed for which coins of the United States of America may have been deposited in said parking meter provided, however, that the provisions of this section shall not apply to any vehicle described in Section 21055, emergency vehicles exempt herefrom. Note: Authority cited: Section 3965(c), Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5040. Installation of Off-Street Parking Meters. s 5041. Off-Street Parking Meter Spaces to Be Indicated and Maintained. s 5042. Time of Parking in Off-Street Parking Meter Zones. s 5043. Off-Street Parking Meters. Times for Operation. s 5044. Operation of Off-Street Parking Meters. s 5045. Off-Street Parking Meters, Deposit of Coins. s 5046. Off-Street Parking Meters and Off-Street Parking Meter Standards Not to Be Used for Certain Purposes. s 5047. Improper Use of Off-Street Parking Meters. s 5048. Extending Parking Time. s 5049. Failure to Deposit Coins. s 5050. Manner of Direction of Traffic. Police officers are authorized to direct all traffic by voice, hand or signal in conformance with traffic laws of the City of Los Angeles and the State of California provided that in the event of a fire or other emergency they may direct traffic as conditions may require notwithstanding the provisions of these regulations. No persons shall willfully fail or refuse to comply with any lawful order, direction or signal of a police officer. s 5051. Application to Public Employees. s 5052. Exemption to Certain Vehicles. Provisions of these regulations governing the operation, parking or standing of vehicles in the park and the adjacent parking facilities shall not apply to any vehicle of the police or fire department, any public ambulance, or any public utility vehicle, or any private ambulance which public utility vehicle or ambulance has qualified as an authorized emergency, when any vehicle mentioned in this section is operated in the manner specified in the Vehicle Code in response to an emergency call. The foregoing exemptions shall not, however, protect the driver of any vehicle of the consequences of his willful disregard of the safety of others. The provisions of these regulations governing the parking or standing of vehicles shall not apply to any vehicles of the city, county, state or federal government or public utility while necessary and used for construction or repair work or while engaged in the collection of garbage or noncombustible rubbish where compliance therewith would obstruct such operation or any vehicle owned by United States while in use for the collection, transportation or delivery of United States mail or to any vehicle owned or operated by the Department of Army, Department of Navy or Department of Air Force during periods of proclaimed national emergency. s 5053. Barriers, Fences or Posts. s 5054. Driving in Unauthorized Areas. No vehicle shall be driven or parked in any area which has been landscaped or designated for landscaping or any cement walk or unpaved pathway for pedestrian use except for maintenance by an appropriate Museum employee or in an emergency. s 5055. Sound Vehicles and Advertising Vehicles Prohibited. No persons shall drive, operate or propel any sound or advertising vehicle with a soundmaking device or loud speaker thereof in use or operation upon any path, street, roadway or any grounds of the park without the express written permission issued by the Museum. s 5056. Installation of Automatic Parking Equipment. s 5057. Automatic Parking Gates, Times for Operation. s 5058. Operation of the Automatic Parking Gates. s 5059. Automatic Parking Gates Not to Be Used for Certain Purposes. s 5060. Improper Use or Misuse of the Automatic Parking Gate. s 5061. Failure to Deposit Coins in the Automatic Parking Gates. It shall be unlawful for any person to park or to cause, permit or suffer to be parked a vehicle in any parking lot where ingress to said parking lot is governed by the operation of automatic parking gates without immediately depositing or causing to be deposited a coin or coins in the automatic parking gates. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 5062. Emergency Rules and Signs. s 5063. Penalties. s 5064. "21113" Vehicles on Certain Property. s 5065. Removal of Vehicles at Owner's Expense. s 5066. One-Way Traffic. No person shall operate or move a vehicle upon the driveways, paths or grounds of the park designated and sign posted for one-way traffic in a direction opposed to that indicated by the designation or signpost. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 21113, Vehicle Code. s 6000. Definitions. For the purpose of these regulations, the following words and phrases are defined and shall be construed as hereinafter set forth unless it shall be apparent from the context that they have a different meaning: (a) "Museum" means the California Museum of Science and Industry, a State institution. (b) "Directors or Board" means the Board of Directors of the California Museum of Science and Industry. (c) "Park" shall include all driveways, paths, parking lots or any of the grounds owned by the California Museum of Science and Industry, bounded on the north by Exposition Boulevard, on the east by Figueroa Street, on the south by Santa Barbara Avenue and on the west by Vermont Avenue, City and County of Los Angeles, State of California, excepting therefrom any area not owned by the California Museum of Science and Industry, but including that area leased to the Los Angeles Memorial Coliseum Commission, the City of Los Angeles, the County of Los Angeles or any department or part of the government of the State of California. (d) "Police Officer" shall mean every officer of the California State Police, as defined in Section 14613 of the Government Code, or the Los Angeles Police Department or any other peace officer, as defined in Section 830 et seq., of the Penal Code; and the Museum Security Officers of the California Museum of Science and Industry. (e) "Agent" shall mean a representative of the Intelligence Division, Internal Revenue Service, United States Treasury Department. (f) "Ticket Speculator" shall mean any person who engages in, manages, conducts, or carries on in or upon the grounds of the Park the sale of tickets of admission or other evidence of the right of entry to designated activities as defined in Section 4301 of the Food and Agricultural Code. (g) "Ticket Scalping" shall mean the sale of tickets to designated activities as defined in Section 4301 of the Agricultural Code, at any premium or price in excess of the maximum price printed or endorsed on said tickets, plus lawful taxes. (h) "Permit" shall mean a permit issued by the Board under Sections 3965 and 4301 of the Food and Agricultural Code. (i) "Permittee" shall mean any person licensed by the Board under Sections 3965 and 4301 of the Food and Agricultural Code. (j) "Person" shall mean a natural person, firm, corporation, association or partnership. (k) "Identification Card" shall mean a card issued by the Board containing, but not limited to, name of permittee, address of permittee, age, height, weight, permit number, effective date of permit, expiration date of permit, photograph of permittee, signatures of permittee and authorized representative of the Museum. (l) The provisions of this Article shall not be deemed to apply to a person, firm, corporation, association or partnership engaged in the business of selling tickets at a fixed and duly authorized ticket office and/or booth in the Park under jurisdiction and management of the Los Angeles Memorial Coliseum Commission, the City of Los Angeles, the County of Los Angeles or any department or part of the government of the State of California. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 4301, Food and Agricultural Code. s 6001. Matters of Public Interest. s 6002. Permit Required. s 6003. Requirements for Permit. (a) Applicant must file written application with Museum setting forth such information as Board may require in order to enable Museum to carry into effect the provisions of Section 4301 of the Food and Agricultural Code and regulations promulgated thereunder. (b) Said application shall be accompanied by evidence and proof satisfactory to Museum of the moral character of the applicant. (c) Applicant must secure, at his own expense, and file within 30 days after issuance of said permit, a bond in due form, approved by the Museum, payable to the people of the State of California and to the Museum, in the penal sum of $2,500.00, with two or more sufficient sureties or a duly authorized surety company. Said bond shall be conditioned that the obligor will not be guilty of any fraud or extortion, will not violate directly or indirectly any of the provisions of Section 4301 of the Food and Agricultural Code or regulations promulgated thereunder, will comply with said statute and regulations and will pay any and all damages occasioned to any person by reason of any misstatement, misrepresentation, fraud or deceit, or any unlawful act or omission of such obligor, his agents or employees, while acting within the scope of their employment in carrying on the sale of tickets for which such permit is granted. Failure to file said bond, as approved, within 30 day period, shall nullify, void, revoke and invalidate any permit issued under these regulations. (d) Applicant must secure, at his own expense, and file with the application therefor, evidence and proof satisfactory to the Museum, that applicant obtained from District Director of Internal Revenue, any and all necessary permits required under the provisions of Section 4234 of the United States Internal Revenue Code. Any such violator of said Code is subject to criminal prosecution in the United States District Court. (e) Each application for a permit shall be accompanied by two copies of the applicant's fingerprints made on forms provided by Museum. Fingerprints may be obtained through the Office of the California State Police, 1525 S. Broadway, Room 413, Los Angeles, CA 90015, or through any other law enforcement agency upon payment of prevailing cost therefor. Permit will not be issued until State Bureau of Criminal Identification and Investigation, Department of Justice, has reviewed said fingerprints and the findings thereof are satisfactory to the Museum. (f) Permit Fees. Each application must be accompanied by a fee of $150.00 and shall be renewed upon the payment of a fee of $75.00 annually. Payment must be made by cash, cashier's check, certified check or money order made payable to the Museum. No personal checks accepted. Since fee has been established to cover administrative costs and expenses including, but not limited to, character investigation, fingerprint check, inspection service, printing costs, material and supplies, labor costs, etc., refunds will not be made, in the event permit is not issued or permit is suspended, revoked or otherwise declared void. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 4301, Food and Agricultural Code. s 6004. Conditions of Permit. (a) Each permittee while acting as a "ticket speculator" engaged in "ticket scalping" shall have in his possession at all times an Identification Card. Said Card shall be made available, upon request, to any Police Officer, Agent, authorized representative of the Museum or to any person purchasing a ticket from said permittee. (b) Each permittee while acting as a "ticket speculator" engaged in "ticket scalping" or at any other reasonable time, shall maintain and keep a book of record and account containing the name, address, and telephone number, if any, of each person, firm, corporation, association, or partnership from whom any ticket is purchased, with respect to each ticket purchased, together with the full purchase price of each ticket, names and dates for performance of designated activities, seat location, date of purchase, and shall, upon request, make such book of record and account available to any Police Officer, Agent, authorized representative of the Museum or to the person purchasing such a ticket. (c) Each permittee while acting as a "ticket speculator" engaged in "ticket scalping" or at any other reasonable time, shall maintain and keep a book of record and account with respect to the sale of any ticket containing the name, address and telephone number, if any, of such person, firm, corporation, association or partnership purchasing said ticket, together with the price paid by said purchaser. Said book of record and account shall also include name and dates for performances of designated activities, seat location, date of sale and shall, upon request, make such book of record and account available to any Police Officer, Agent, authorized representative of the Museum for inspection and audit. (d) Each permittee shall furnish each purchaser of a ticket with a receipt showing, but not limited to, name and address of permittee, date of sale, description, location and quantity of tickets sold, price paid, name of purchaser, permit number and duly signed by permittee. A copy of each receipt issued shall be retained by permittee and upon request or a reasonable time thereafter, not to exceed 24 hours after request made, shall be made available for inspection and audit by authorized representatives of the Museum, Agents and Police Officers. (e) No permittee shall engage in "ticket scalping" nor permit any person in his employ to engage in "ticket scalping" in or upon the grounds of the Park other than the premises approved and permitted to be used for such purpose by such permittee and subject to the following further restrictions: (1) At no time shall permittee or any person in his employ engage in "ticket scalping" in or upon any grounds of the Park where a person may drive, stop, park or leave standing any vehicle so as to hinder or obstruct free and orderly flow of traffic. (2) At no time shall permittee or any person in his employ engage in "ticket scalping" within five hundred (500) feet of the nearest fixed and duly authorized ticket office and/or booth in the Park under jurisdiction and management of the Los Angeles Memorial Coliseum Commission, the City of Los Angeles, the County of Los Angeles or any department or part of the government of the State of California. (3) No permittee shall stand or sit in or upon the grounds of the Park in any manner so as to hinder or obstruct the free passage of pedestrians thereon, or to annoy or molest such pedestrians. (f) No permittee shall employ any person to engage in "ticket scalping" unless such person has been properly permitted to engage in such "ticket scalping" in accordance with the provisions of Section 4301 of the Food and Agricultural Code and these regulations. (g) Notwithstanding anything herein contained to the contrary, no permittee shall engage in the practice of directing, guiding, influencing or engage others to direct, guide, influence or solicit prospective patrons of said sports stadia, arena, pavilion, places of public exhibitions and other designated activities, or induce or solicit or attempt to induce or solicit the purchase of tickets from them by said prospective patrons in or upon the grounds within the Park. (h) Each permittee while engaged in "ticket scalping" shall comply with any order or resolution as may be adopted from time to time by the Board of the Museum or any other public agency or commission that may have jurisdiction over location where said "ticket scalping" is requested to take place. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 4301, Food and Agricultural Code. s 6005. Misstatement in Application. No person shall make any false, misleading or fraudulent statement or misrepresent any fact in any application for a permit or in any notice of record required to be filed with the Museum, City, County, State or Federal Government; such conduct shall be grounds for suspension or revocation of any permit issued to such person. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 4301, Food and Agricultural Code. s 6006. Suspension and Revocation. In the event that any permittee shall be guilty of any fraud or misrepresentation or otherwise violate any of the provisions of these rules and regulations, such violations shall be deemed sufficient cause for suspension or revocation of the offender's permit on giving five (5) days' notice by mail to such permittee. This Section shall not be deemed or construed as prohibiting such permittee from answering the charges made against him. Note: Authority cited: Sections 3965(c) and 4051, Food and Agricultural Code. Reference: Section 4301, Food and Agricultural Code.