Public Resources Code References
3013 This division shall be liberally construed to meet its purposes, and the director and the supervisor, acting with the approval of the director, shall have all powers, including the authority to adopt rules and regulations, which may be necessary to carry out the purposes of this division.
3106. (a) The supervisor shall so supervise the drilling, operation, maintenance, and abandonment of wells and the operation, maintenance, and removal or abandonment of tanks and facilitiesm attendant to oil and gas production, including pipelines not subject to regulation pursuant to Chapter 5.5 (commencing with Section 51010) of Part 1 of Division 1 of Title 5 of the Government Code that are within an oil and gas field, so as to prevent, as far as possible, damage to life, health, property, and natural resources; damage to underground oil and gas deposits from infiltrating water and other causes; loss of oil, gas, or reservoir energy, and damage to underground and surface waters suitable for irrigation or domestic purposes by the infiltration of, or the addition of, detrimental substances.
(b) The supervisor shall also supervise the drilling, operation, maintenance, and abandonment of wells so as to permit the owners or operators of the wells to utilize all methods and practices known to the oil industry for the purpose of increasing the ultimate recovery of underground hydrocarbons and which, in the opinion of the supervisor, are suitable for this purpose in each proposed case. To further the elimination of waste by increasing the recovery of underground hydrocarbons, it is hereby declared as a policy of this state that the grant in an oil and gas lease or contract to a lessee or operator of the right or power, in substance, to explore for and remove all hydrocarbons from any lands in the state, in the absence of an express provision to the contrary contained in the lease or contract, is deemed to allow the lessee or contractor, or the lessee's or contractor's successors or assigns, to do what a prudent operator using reasonable diligence would do, having in mind the best interests of the lessor, lessee, and the state in producing and removing hydrocarbons, including, but not limited to, the injection of air, gas, water, or other fluids into the productive strata, the application of pressure heat or other means for the reduction of viscosity of the hydrocarbons, the supplying of additional motive force, or the creating of enlarged or new channels for the underground movement of hydrocarbons into production wells, when these methods or processes employed have been approved by the supervisor, except that nothing contained in this section imposes a legal duty upon the lessee or contractor, or the lessee's or contractor's successors or assigns, to conduct these operations.
(c) The supervisor may require an operator to implement a monitoring program, designed to detect releases to the soil and water, including both groundwater and surface water, for aboveground oil production tanks and facilities.
(d) To best meet oil and gas needs in this state, the supervisor shall administer this division so as to encourage the wise development of oil and gas resources.
3234. (a) (1) Except as otherwise provided in this section, all the well records, including production reports, of any owner or operator which are filed pursuant to this chapter are public records for purposes of the California Public Records Act (Chapter 3.5 (commencing with Section 6250) of Division 7 of Title 1 of the Government Code).
(2) Those records are public records when filed with the division unless the owner or operator requests, in writing, that the division maintain the well records of onshore exploratory wells or offshore exploratory wells as confidential information. The records of other wells may be maintained as confidential information if, based upon information in a written request of the owner or operator, the supervisor determines there are extenuating circumstances. For onshore wells, the confidential period shall not exceed two years from the cessation of drilling operations as defined in subdivision (e).
For offshore wells, the confidential period shall not exceed five years from the cessation of drilling operations as specified in subdivision (e).
(3) Well records maintained as confidential information by the division shall be open to inspection by those persons who are authorized by the owner or operator in writing. Confidential status shall not apply to state officers charged with regulating well operations, the director, or as provided in subdivision (c).
(4) On receipt by the supervisor of a written request documenting extenuating circumstances relating to a particular well, including a well on an expired or terminated lease, the supervisor may extend the period of confidentiality for six months. For onshore wells, the total period of confidentiality, including all extensions, shall not exceed four years from the cessation of drilling operations as specified in subdivision (e), and for offshore wells the total period of confidentiality, including all extensions, shall not exceed seven years from the cessation of drilling operations as specified in subdivision (e), unless the director approves a longer period after a 30-day public notice and comment period. The director shall initiate and conduct a public hearing on receipt of a written complaint.
(b) Notwithstanding the provisions of subdivision (a) regarding the period of confidentiality, the well records for onshore and offshore wells shall become public records when the supervisor is notified that the lease has expired or terminated.
(c) Production reports filed pursuant to Section 3227 shall be open to inspection by the State Board of Equalization or its duly appointed representatives when making a survey pursuant to Section 1815 of the Revenue and Taxation Code or when valuing state-assessed property pursuant to Section 755 of the Revenue and Taxation Code, and by the assessor of the county in which a well referred to in Section 327 is located.
(d) For the purposes of this section, “well records” does not include either experimental logs and tests or interpretive data not generally available to all operators, as defined by the supervisor by regulation.
(e) The cessation of drilling operations occurs on the date of removal of drilling machinery from the well site.
3227. The owner of any well shall file with the supervisor, on or before the last day of each month, for the last preceding calendar month, a statement, in the form designated by the supervisor, showing all of the following:
(a) The amount of oil and gas produced from each well during the period indicated, together with the gravity of the oil, the amount of water produced from each well, estimated in accordance with methods approved by the supervisor, and the number of days during which fluid was produced from each well.
(b) The number of wells drilling, producing, injecting, or idle, that are owned or operated by the person.
(c) What disposition was made of the gas produced from each field, including the names of persons, if any, to whom the gas was delivered, and any other information regarding the gas and its disposition that the supervisor may require.
(d) What disposition was made of the water produced from each field, and the amount of fluid or gas injected into each well used for enhanced recovery, underground storage of hydrocarbons, or waste water disposal and any other information regarding those wells that the supervisor may require. Any operator that produces oil by the application of mining or other unconventional techniques shall file a report with the supervisor, on or before March 1 of each year, showing the amount of oil produced by those techniques in the preceding calendar year. Upon request and making a satisfactory showing therefore, a longer filing period may be established by the supervisor for any particular owner or operator.
California Code of Regulations Title 14 References
(a) All operations shall be conducted in accordance with good oilfield practice.
(b) The operator for a facility or group of related facilities shall develop a spill contingency plan. Spill contingency plans shall also be developed by the operator for those facilities within gas fields that produce condensate at an average rate of at least one barrel per day or where condensate storage volume exceeds 50 barrels. The plan(s) shall be fi led with the appropriate Division district office within six months of the effective date of Section 1722.9 or within three months after initial production or acquisition of a facility. Plans prepared pursuant to Federal Environmental Protection Agency regulations (SPCC Plans) may fulfill the provisions of this subsection if such plans are determined to be adequate by the appropriate Division district deputy. If, in the judgment of the Supervisor, a plan becomes outdated, the Supervisor may require that the plan be updated to ensure that it addresses and applies to current conditions and technology.
(c) For certain critical or high-pressure wells designated by the Supervisor, a blowout prevention and control plan, including provisions for the duties, training, supervision, and schedules for testing equipment and performing personnel drills, shall be submitted by the operator to the appropriate Division district deputy for approval.
(d) Notices of intention to drill, deepen, redrill, rework, or plug and abandon wells shall be completed on
current Division forms and submitted, in duplicate, to the appropriate Division district office for approval. Such notices shall include all information required on the forms, and such other pertinent data as the supervisor may require. Notices of intention and approvals will be canceled if the proposed operations have not commenced within one year of receipt of the notice. However, an approval for proposed operations may be extended for one year if the operator submits a supplementary notice prior to the expiration of the one-year period and can show good cause for such an extension. For the purpose of interpretation and enforcement of provisions of this section, operations, when commenced, must be completed in a timely and orderly manner.
(e) A copy of the operator’s notice of intention and any subsequent written approval of proposed operations by the Division shall be posted at the well site throughout the operations. inspections and tests requiring the presence of Division personnel.
(g) Operations approved by the Division shall not deviate from the approved program without prior Division approval, except in an emergency.
(h) Oil spills shall be promptly reported to the California Emergency Management Agency by calling the toll-free telephone number (800) 852-7550 and by contacting the agencies specified in the operator’s spill contingency plan.
(i) Blowouts, fires, serious accidents, and significant gas or water leaks resulting from or associated with an oil or gas drilling or producing operation, or related facility, shall be promptly reported to the appropriate Division district office.
(j) The use of radioactive materials in wells shall comply with the California Department of Health
Services regulations in Title 17, Division 1, Chapter 5, Subchapter 4 of the California Code of Regulations. With the exception of radioactive tracers used in injection surveys, the loss of radioactive materials in a well shall be promptly reported to the Department of Health Services pursuant to Section 30350.3 of the above referenced regulations and to the appropriate Division district office.
(k) When sufficient geologic and engineering information is available from previous drilling or producing operations, operators may make application to the Supervisor for the establishment of field rules, or the Supervisor may establish field rules or change established field rules for any oil or gas field. Before establishing or changing a field rule, the Supervisor shall distribute the proposed rule or change to affected persons and allow at least thirty (30) days for comments from the affected persons. The Supervisor shall notify affected persons in writing of the establishment or change of field rules.
NOTE: Authority cited: Sections 3013 and 3270, Public Resources Code. Reference: Sections 3106,
3203, 3208, 3219, 3222, 3223, 3224, 3226, 3229, 3230, 3270, and 3270.1 Public Resources Code.
1722.4. Cementing Casing.
Surface casing shall be cemented with suffi cient cement to fi ll the annular space from the shoe to the surface.Intermediate and production casings, if not cemented to the surface, shall be cemented with suffi cient cement to fill the annular space to at least 500 feet above oil and gas zones, and anomalous pressure intervals. Sufficient cement shall also be used to fi ll the annular space to at least 100 feet above the base of the freshwater zone, either by lifting cement around the casing shoe or cementing through perforations or a cementing device placed at or below the base of the freshwater zone. All casing shall be cemented in a manner that ensures proper distribution and bonding of cement in the annular spaces. The appropriate Division district deputy may require a cement bond log, temperature survey, or other survey to determine cement fi ll behind casing. If it is determined that the casing is not cemented adequately by the primary cementing operation, the operator shall recement in such a manner as to comply with the above requirements. If supported by known geologic conditions, an exception to the cement placement requirements of this section may be allowed by the appropriate Division district deputy.
NOTE: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106, 3220 and 3222-3224, Public Resources Code.
1722.9. Spill Contingency Plan Requirements.
A spill contingency plan shall be designed to prevent and respond to unauthorized releases and contain the following:
(a) A list of the operator’s 24-hour emergency contact telephone numbers. The operator’s emergency
contact shall be prepared to provide Division staff complete information about the production facility emergency shutdown procedures, including a list of safety shutdown devices including, but not limited to, kill switches, emergency shut-down devices, or master valves.
(b) A list of available personal safety equipment, including location and maintenance frequency.
(c) A one page quick-action checklist for use during initial stages of a spill response.
(d) A list of required local, state and federal agency notifications with telephone numbers, including, but not limited to, the phone number for the appropriate Division district office and the phone number for
reporting spills to the California Emergency Management Agency.
(e) A list of control and/or cleanup equipment available onsite or locally, with contact procedures.
(f) A map of the production facilities covered by the plan, including:
(1) Labeling of all permanent tanks, equipment, and pipelines. If locations are not known, the most probable location shall be shown and identified as a probable location.
(2) Identification of access roads for emergency response.
(3) Labeling of all out-of-service equipment.
(4) Labeling of all sumps and catch basins.
(5) Volume of all tanks and storage containers covered by the plan, listing the type of fluid stored.
(6) All designated waterways within one-quarter mile of the facility.
(7) Location of secondary containment with access routes.
(8) Topography or drainage flow direction.
(9) All storm drains within one-quarter mile of the site.
(10) A fluid flow schematic.
(g) A list of all chemicals for which a Material Safety Data Sheet is required, and the location of the Material Safety Data Sheets for those chemicals.
(h) Procedures for making regular facility inspections, and maintenance of related inspection records.
(i) Maximum and typical produced fluid processing rates.
(j) Typical volumes of liquids stored at the facility.
(k) A list of additional containment features for production facilities in drainages with direct access to waterways or urban areas as determined necessary by the Supervisor.
(l) A list of corrosion prevention or corrosion monitoring techniques utilized.
(m) A description of all installed sensor and alarm systems. The sensor and alarm systems to be described include, but are not limited to:
(1) Tank overfill.
(2) High and low pressure for pipelines and pressure vessels.
(3) Fire sensors.
(4) H2S detectors.
(5) Gas detectors.
(n) A description of the training provided to implement the plan.
NOTE: Authority cited: Section 3013, Public Resources Code. Reference: Sections 3106 and 3270.1, Public Resources Code.
1724.6. Approval of Underground Injection and Disposal Projects.
Approval must be obtained from this Division before any subsurface injection or disposal project can begin.This includes all EPA Class II wells and air- and gas-injection wells. The operator requesting approval for such a project must provide the appropriate Division district deputy with any data that, in the judgment of the Supervisor, are pertinent and necessary for the proper evaluation of the proposed project.
NOTE: Authority cited: Section 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
1724.7. Project Data Requirements.
(Note: See Section 1724.8 for special requirements for cyclic steam projects, and Section 1724.9 or supplementary requirements for gas storage projects.)
The data required to be filed with the district deputy include the following, where applicable:
(a) An engineering study, including but not limited to:
(1) Statement of primary purpose of the project.
(2) Reservoir characteristics of each injection zone, such as porosity, permeability, average thickness, areal extent, fracture gradient, original and present temperature and pressure, and original and residual oil, gas, and water saturations.
(3) Reservoir fluid data for each injection zone, such as oil gravity and viscosity, water quality, and specific gravity of gas.
(4) Casing diagrams, including cement plugs, and actual or calculated cement fill behind casing, of all idle, plugged and abandoned, or deeper-zone producing wells within the area affected by the project, and evidence that plugged and abandoned wells in the area will not have an adverse effect on the project or cause damage to life, health, property, or natural resources.
(5) The planned well-drilling and plugging and abandonment program to complete the project, including a flood-pattern map showing all injection, production, and plugged and abandoned wells, and unit boundaries.
(b) A geologic study, including but not limited to:
(1) Structural contour map drawn on a geologic marker at or near the top of each injection zone in the project area.
(2) Isopachous map of each injection zone or subzone in the project area.
(3) At least one geologic cross section through at least one injection well in the project area.
(4) Representative electric log to a depth below the deepest producing zone (if not already shown on the cross section), identifying all geologic units, formations, freshwater aquifers, and oil or gas zones.
(c) An injection plan, including but not limited to:
(1) A map showing injection facilities.
(2) Maximum anticipated surface injection pressure (pump pressure) and daily rate of injection, by well.
(3) Monitoring system or method to be utilized to ensure that no damage is occurring and that the injection fluid is confined to the intended zone or zones of injection.
(4) Method of injection.
(5) List of proposed cathodic protection measures for plant, lines, and wells, if such measures are warranted.
(6) Treatment of water to be injected.
(7) Source and analysis of the injection liquid.
(8) Location and depth of each water-source well that will be used in conjunction with the project.
(d) Copies of letters of notification sent to offset operators.
(e) Other data as required for large, unusual, or hazardous projects, for unusual or complex structures, or for critical wells. Examples of such data are: isogor maps, water-oil ratio maps, isobar maps, equipment
diagrams, and safety programs.
(f) All maps, diagrams and exhibits required in Section 1724.7(a) through (e) shall be clearly labeled as to scale and purpose and shall clearly identify wells, boundaries, zones, contacts, and other relevant data.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
1724.8. Data Required for Cyclic Steam Injection Project Approval.
The data required by the Division prior to approval of a cyclic steam (steam soak) project include, but are not limited to, the following:
(a) A letter from the operator notifying the Division of the intention to conduct cyclic steam injection operations on a specific lease, in a specific reservoir, or in a particular well.
(b) If cyclic steam injection is to be in wells adjacent to a lease boundary, a copy of a letter notifying each offset operator of the proposed project.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
1724.9. Gas Storage Projects.
The data required by the Division prior to approval of a gas storage project include all applicable items listed in Section 1724.7(a) through (e), and the following, where applicable:
(a) Characteristics of the cap rock, such as areal extent, average thickness, and threshold pressure.
(b) Oil and gas reserves of storage zones prior to start of injection, including calculations.
(c) List of proposed surface and subsurface safety devices, tests, and precautions to be taken to ensure safety of the project.
(d) Proposed waste water disposal method.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
1724.10. Filing, Notification, Operating, and Testing Requirements for Underground Injection Projects.
(a) The appropriate Division district deputy shall be notified of any anticipated changes in a project resulting in alteration of conditions originally approved, such as: increase in size, change of injection interval, or increase in injection pressure. Such changes shall not be carried out without Division approval.
(b) Notices of intention to drill, redrill, deepen, or rework, on current Division forms, shall be completed and submitted to the Division for approval whenever a new well is to be drilled for use as an injection well and whenever an existing well is converted to an injection well, even if no work is required on the well.
(c) An injection report on a current Division form or in a computerized format acceptable to the Division shall be filed with the Division on or before the 30th day of each month, for the preceding month.
(d) A chemical analysis of the liquid being injected shall be made and fi led with the Division whenever the source of injection liquid is changed, or as requested by the Supervisor.
(e) An accurate, operating pressure gauge or pressure recording device shall be available at all times, and all injection wells shall be equipped for installation and operation of such gauge or device. A gauge or device used for injection-pressure testing, which is permanently affi xed to the well or any part of the injection system, shall be calibrated at least every six months. Portable gauges shall be calibrated at least every two months. Evidence of such calibration shall be available to the Division upon request.
(f) All injection piping, valves, and facilities shall meet or exceed design standards for the maximum anticipated injection pressure, and shall be maintained in a safe and leak-free condition.
(g) All injection wells, except steam, air, and pipeline-quality gas injection wells, shall be equipped with tubing and packer set immediately above the approved zone of injection within one year after the effective date of this act. New or recompleted injection wells shall be equipped with tubing and packer upon completion or recompletion. Exceptions may be made when there is:
(1) No evidence of freshwater-bearing strata.
(2) More than one string of casing cemented below the base of fresh water.
(3) Other justification, as determined by the district deputy, based on documented evidence that freshwater and oil zones can be protected without the use of tubing and packer.
(h) Data shall be maintained to show performance of the project and to establish that no damage to life,
health, property, or natural resources is occurring by reason of the project. Injection shall be stopped if there is evidence of such damage, or loss of hydrocarbons, or upon written notice from the Division. Project data shall be available for periodic inspection by Division personnel.
(i) To determine the maximum allowable surface injection pressure, a step-rate test shall be conducted prior to sustained liquid injection. Test pressure shall be from hydrostatic to the pressure required to fracture the injection zone or the proposed injection pressure, whichever occurs first. Maximum allowable surface injection pressure shall be less than the fracture pressure. The appropriate district office shall be notified prior to conducting the test so that it may be witnessed by a Division inspector. The district deputy may waive or modify the requirement for a step-rate test if he or she determines that surface injection pressure for a particular well will be maintained considerably below the estimated pressure required to fracture the zone of injection.
(j) A mechanical integrity test (MIT) must be performed on all injection wells to ensure the injected fl uid
is confined to the approved zone or zones. An MIT shall consist of a two-part demonstration as provided in subsections (j)(1) and (2).
(1) Prior to commencing injection operations, each injection well must pass a pressure test of the casing tubing annulus to determine the absence of leaks. Thereafter, the annulus of each well must be tested at least once every five years; prior to recommencing injection operations following the repositioning or replacement of downhole equipment; or whenever requested by the appropriate Division district deputy.
(2) When required by subsection (j) above, injection wells shall pass a second demonstration of mechanical integrity. The second test of a two-part MIT shall demonstrate that there is no fluid migration behind the casing, tubing, or packer.
(3) The second part of the MIT must be performed within three (3) months after injection has commenced. Thereafter, water-disposal wells shall be tested at least once each year; waterflood wells shall be tested at least once every two years; and steamflood wells shall be tested at least once every fi ve years. Such testing for mechanical integrity shall also be performed following any significant anomalous rate or pressure change, or whenever requested by the appropriate Division district deputy. The MIT schedule may be modified by the district deputy if supported by evidence documenting good cause.
(4) The appropriate district office shall be notified before such tests/surveys are made, as a Division inspector may witness the operations. Copies of surveys and test results shall be submitted to the Division within 60 days.
(k) Additional requirements or modifications of the above requirements may be necessary to fi t specific circumstances and types of projects. Examples of such additional requirements or modifications are:
(1) Injectivity tests.
(2) Graphs of time vs. oil, water, and gas production rates, maintained for each pool in the project and available for periodic inspection by Division personnel.
(3) Graphs of time vs. tubing pressure, casing pressure, and injection rate maintained for each injection well and available for periodic inspection by Division personnel.
(4) List of all observation wells used to monitor the project, indicating what parameter each well is monitoring (i.e., pressure, temperature, etc.), submitted to the Division annually.
(5) List of all injection-withdrawal wells in a gas storage project, showing casing-integrity test methods and dates, the types of safety valves used, submitted to the Division annually.
(6) Isobaric maps of the injection zone, submitted to the Division annually.
(7) Notification of any change in waste disposal methods.
NOTE: Authority cited: Section 3013, Public Resources Code. References: Section 3106, Public Resources Code.
(j) “Operator” means any person drilling, maintaining, operating, pumping, or in control of any well.
1773.1. Production Facility Secondary Containment.
(a) All production facilities storing and/or processing fluids, except valves, headers, manifolds, pumps,
compressors, wellheads, pipelines, flowlines and gathering lines shall have secondary containment.
(b) Secondary containment shall be capable of containing the equivalent volume of liquids from the single
piece of equipment with the largest gross capacity within the secondary containment.
(c) Secondary containment shall be capable of confining liquid for a minimum of 72 hours.
(d) When not in use for rain water management, rain water valves on a secondary containment shall be
closed and secured to prevent unauthorized use.
(e) All damage to secondary containment shall be repaired immediately.
(f) The requirements of this section are not applicable until six months after the effective date of this
NOTE: Authority cited: Sections 3013 and 3270, Public Resources Code. Reference: Sections 3106 and
3270, Public Resources Code.
California Civil Code Reference
3426. This title may be cited as the Uniform Trade Secrets Act.
3426.1. As used in this title, unless the context requires otherwise:
(a) "Improper means" includes theft, bribery, misrepresentation,
(b) breach or inducement of a breach of a duty to maintain secrecy, orespionage through electronic or other means. Reverse engineering or independent derivation alone shall not be considered improper means.
(b) "Misappropriation" means:
(1) Acquisition of a trade secret of another by a person who knows or has reason to know that the trade secret was acquired by improper means; or
(2) Disclosure or use of a trade secret of another without express or implied consent by a person who:
(A) Used improper means to acquire knowledge of the trade secret; or
(B) At the time of disclosure or use, knew or had reason to know that his or her knowledge of the trade secret was:
(i) Derived from or through a person who had utilized improper means to acquire it;
(ii) Acquired under circumstances giving rise to a duty to maintain its secrecy or limit its use; or
(iii) Derived from or through a person who owed a duty to the person seeking relief to maintain its secrecy or limit its use; or
(C) Before a material change of his or her position, knew or had reason to know that it was a trade secret and that knowledge of it had been acquired by accident or mistake.
(c) "Person" means a natural person, corporation, business trust, estate, trust, partnership, limited liability company, association, joint venture, government, governmental subdivision or agency, or any
other legal or commercial entity.
(d) "Trade secret" means information, including a formula, pattern, compilation, program, device, method, technique, or process, that:
(1) Derives independent economic value, actual or potential, from not being generally known to the public or to other persons who can obtain economic value from its disclosure or use; and
(2) Is the subject of efforts that are reasonable under the circumstances to maintain its secrecy.
California Penal Code Reference
499c. (a) As used in this section:
(1) "Access" means to approach, a way or means of approaching, nearing, admittance to, including to instruct, communicate with, store information in, or retrieve information from a computer system or computer network.
(2) "Article" means any object, material, device, or substance or copy thereof, including any writing, record, recording, drawing, sample, specimen, prototype, model, photograph, micro-organism, blueprint, map, or tangible representation of a computer program or information, including both human and computer readable information and information while in transit.
(3) "Benefit" means gain or advantage, or anything regarded by the beneficiary as gain or advantage, including benefit to any other person or entity in whose welfare he or she is interested.
(4) "Computer system" means a machine or collection of machines, one or more of which contain computer programs and information, that performs functions, including, but not limited to, logic, arithmetic, information storage and retrieval, communications, and control.
(5) "Computer network" means an interconnection of two or more computer systems.
(6) "Computer program" means an ordered set of instructions or statements, and related information that, when automatically executed in actual or modified form in a computer system, causes it to perform specified functions.
(7) "Copy" means any facsimile, replica, photograph or other reproduction of an article, and any note, drawing or sketch made of or from an article.
(8) "Representing" means describing, depicting, containing, constituting, reflecting or recording.
(9) "Trade secret" means information, including a formula, pattern, compilation, program, device, method, technique, or process, that:
(A) Derives independent economic value, actual or potential, from not being generally known to the public or to other persons who can obtain economic value from its disclosure or use; and
(B) Is the subject of efforts that are reasonable under the circumstances to maintain its secrecy.
(b) Every person is guilty of theft who, with intent to deprive or withhold the control of a trade secret from its owner, or with an intent to appropriate a trade secret to his or her own use or to the use of another, does any of the following:
(1) Steals, takes, carries away, or uses without authorization, a trade secret.
(2) Fraudulently appropriates any article representing a trade secret entrusted to him or her.
(3) Having unlawfully obtained access to the article, without authority makes or causes to be made a copy of any article representing a trade secret.
(4) Having obtained access to the article through a relationship of trust and confidence, without authority and in breach of the obligations created by that relationship, makes or causes to be made,
directly from and in the presence of the article, a copy of any article representing a trade secret.
(c) Every person who promises, offers or gives, or conspires to promise or offer to give, to any present or former agent, employee or servant of another, a benefit as an inducement, bribe or reward for
conveying, delivering or otherwise making available an article representing a trade secret owned by his or her present or former principal, employer or master, to any person not authorized by the
owner to receive or acquire the trade secret and every present or former agent, employee, or servant, who solicits, accepts, receives or takes a benefit as an inducement, bribe or reward for conveying, delivering or otherwise making available an article representing a trade secret owned by his or her present or former principal, employer or master, to any person not authorized by the owner to receive or acquire the trade secret, shall be punished by imprisonment in a county jail not exceeding one year, or by imprisonment pursuant to subdivision (h) of Section 1170, or by a fine not exceeding five thousand dollars ($5,000), or by both that fine and imprisonment.
(d) In a prosecution for a violation of this section, it shall be no defense that the person returned or intended to return the article.
California Evidence Code Reference
1060. If he or his agent or employee claims the privilege, the owner of a trade secret has a privilege to refuse to disclose the secret, and to prevent another from disclosing it, if the allowance of the privilege will not tend to conceal fraud or otherwise work injustice.