Section 8670.28 of the Government Code is amended to read:
Earlier text of § 8670.28 is not compiled in this navigator, so changes are not marked.
The administrator, taking into consideration the facility or vessel contingency plan requirements of the State Lands Commission, the Office of the State Fire Marshal, the California Coastal Commission, and other state and federal agencies, shall adopt and implement regulations governing the adequacy of oil spill contingency plans to be prepared and implemented under this article. All regulations shall be developed in consultation with the Oil Spill Technical Advisory Committee, and shall be consistent with the California oil spill contingency plan and not in conflict with the National Contingency Plan. The regulations shall provide for the best achievable protection of the waters and natural resources of the state. The regulations shall permit the development, application, and use of an oil spill contingency plan for similar vessels, pipelines, terminals, and facilities within a single company or organization, and across companies and organizations. The regulations shall, at a minimum, ensure all of the following:
All areas of state waters are at all times protected by prevention, response, containment, and cleanup equipment and operations.
Standards set for response, containment, and cleanup equipment and operations are maintained and regularly improved to protect the resources of the state.
All appropriate personnel employed by operators required to have a contingency plan receive training in oil spill response and cleanup equipment usage and operations.
Each oil spill contingency plan provides for appropriate financial or contractual arrangements for all necessary equipment and services for the response, containment, and cleanup of a reasonable worst case oil spill scenario for each area the plan addresses.
Each oil spill contingency plan demonstrates that all protection measures are being taken to reduce the possibility of an oil spill occurring as a result of the operation of the facility or vessel. The protection measures shall include, but not be limited to, response to disabled vessels and identification of those measures taken to comply with requirements of Division 7.8 (commencing with Section 8750) of the Public Resources Code.
Each oil spill contingency plan identifies the types of equipment that can be used, the location of the equipment, and the time taken to deliver the equipment.
Each facility, as determined by the administrator, conducts a hazard and operability study to identify the hazards associated with the operation of the facility, including the use of the facility by vessels, due to operating error, equipment failure, and external events. For the hazards identified in the hazard and operability studies, the facility shall conduct an offsite consequence analysis that, for the most likely hazards, assumes pessimistic water and air dispersion and other adverse environmental conditions.
Each oil spill contingency plan contains a list of contacts to call in the event of a drill, threatened discharge of oil, or discharge of oil.
Each oil spill contingency plan identifies the measures to be taken to protect the recreational and environmentally sensitive areas that would be threatened by a reasonable worst case oil spill scenario.
Standards for determining a reasonable worst case oil spill.
Commencing January 15, 2027, and at least once every 10 years thereafter, in order to increase public participation, the administrator shall solicit public input regarding the appropriateness of the reasonable worst case spill volumes for facilities. Based on this feedback, the administrator shall review and, as appropriate, revise the criteria and formulas for calculating reasonable worst case spill volumes to reflect the best available information. If revisions are appropriate, the administrator shall initiate a rulemaking action pursuant to the Administrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3), which includes a public notice and comment process.
Notwithstanding subparagraphs (A) and (B), for a nontank vessel, the reasonable worst case is a spill of the total volume of the largest fuel tank on the nontank vessel.
Each oil spill contingency plan specifies an agent for service of process. The agent shall be located in this state.
The review and potential subsequent rulemaking action pursuant to paragraph (10) shall be combined with and be used to inform the review and potential subsequent rulemaking action pursuant to paragraph (3) of subdivision (d) of Section 8670.37.51, related to financial responsibility.
The regulations and guidelines adopted pursuant to this section shall also include provisions to provide for public review and comment on submitted oil spill contingency plans.
The regulations adopted pursuant to this section shall specifically address the types of equipment that will be necessary, the maximum time that will be allowed for deployment, the maximum distance to cooperating response entities, the amounts of dispersant, and the maximum time required for application should the use of dispersants be approved. Upon a determination by the administrator that booming is appropriate at the site and necessary to provide best achievable protection, the regulations shall require that vessels engaged in lightering operations be boomed prior to the commencement of operations.
The administrator shall adopt regulations and guidelines for oil spill contingency plans with regard to mobile transfer units, small marine fueling facilities, and vessels carrying oil as secondary cargo that acknowledge the reduced risk of damage from oil spills from those units, facilities, and vessels while maintaining the best achievable protection for the public health and safety and the environment.
Section 8670.37.51 of the Government Code is amended to read:
Earlier text of § 8670.37.51 is not compiled in this navigator, so changes are not marked.
A tank vessel or vessel carrying oil as a secondary cargo shall not be used to transport oil across waters of the state unless the owner or operator has applied for and obtained a certificate of financial responsibility issued by the administrator for that vessel or for the owner of all of the oil contained in and to be transferred to or from that vessel.
An operator of a marine terminal within the state shall not transfer oil to or from a tank vessel or vessel carrying oil as a secondary cargo unless the operator of the marine terminal has received a copy of a certificate of financial responsibility issued by the administrator for the operator of that vessel or for all of the oil contained in and to be transferred to or from that vessel.
An operator of a marine terminal within the state shall not transfer oil to or from any vessel that is or is intended to be used for transporting oil as cargo to or from a second vessel unless the operator of the marine terminal has first received a copy of a certificate of financial responsibility issued by the administrator for the person responsible for both the first and second vessels or all of the oil contained in both vessels, as well as all the oil to be transferred to or from both vessels.
An owner or operator of a facility where a spill could impact waters of the state shall apply for and obtain a certificate of financial responsibility issued by the administrator for the facility or the oil to be handled, stored, or transported by the facility.
The administrator shall publicly post on the Office of Spill Prevention and Response internet website a list of all applications for certificates of financial responsibility submitted by facility owners and operators. The posting shall include the legal name of the applicant, the name and reasonable worst case spill volume of the facility to be covered by the certificate, the amount of financial responsibility demonstrated, and the type of evidence furnished to demonstrate the financial responsibility. The administrator shall post this information within seven business days of receiving an application.
Commencing January 15, 2027, and at least once every 10 years thereafter, in order to increase public participation, the administrator shall solicit public input regarding the appropriateness of the financial responsibility requirements for facilities. Based on this feedback, the administrator shall review and, as appropriate, revise the criteria and formulas for calculating the financial assurances and setting the maximum amount of a certificate of financial responsibility necessary to respond to an oil spill to reflect the best available information, pursuant to the rulemaking requirements of the Administrative Procedure Act (Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3), which includes a public notice and comment process.
Pursuant to Section 8670.37.58, nontank vessels shall obtain a certificate of financial responsibility.
Section 51014.1 is added to the Government Code, to read:
(a) Any existing oil pipeline that is six inches or larger that has been idle, inactive, or out of service for five years or more, shall not be restarted without passing a spike hydrostatic testing program.
(b) (1) (A) The hydrostatic spike test shall be at least 139 percent of the maximum operating pressure of the pipeline and shall not exceed 80 percent of the specific minimum yield strength, as determined appropriate by the State Fire Marshal.
(B) Notwithstanding subparagraph (A), at the operator’s request, the minimum hydrostatic spike test pressure may be lower than 100 percent of the specified minimum yield strength if the maximum operating pressure of the pipeline is correspondingly reduced.
(i) Pursuant to this subparagraph the hydrostatic spike test shall be at least 139 percent of the reduced maximum operating pressure of the pipeline, as determined appropriate by the State Fire Marshal.
(ii) The hydrostatic spike test shall be performed in segments to ensure every elevation point is tested.
(2) If the specified minimum yield strength is unknown, the specified minimum yield strength shall be determined pursuant to Section 195.106(b) of Title 49 of the Code of Federal Regulations before performing the hydrostatic spike test.
(c) The hydrostatic spike test shall be no more than 15 minutes, and be immediately followed by a hydrostatic test, which shall be held for a minimum of eight hours and meet the requirements of the State Fire Marshal.
(d) The hydrostatic and hydrostatic spike test shall be performed in segments to ensure every elevation point is tested.
(e) All tests shall be performed by a qualified testing company that is compliant with this chapter, as determined by the State Fire Marshal.
(f) The Office of the State Fire Marshal shall promulgate regulations as necessary to implement this section.
(g) The requirements of this section shall become operative upon the effective date of this statute.
(h) The State Fire Marshal shall post on its public internet website information fully characterizing the parameters and results of each hydrostatic spike test performed, subject to any such information deemed confidential and proprietary, no less than 30 calendar days after each hydrostatic spike test is conducted pursuant to this section.
Section 43830.5 is added to the Health and Safety Code, to read:
Notwithstanding any other law, the Governor shall suspend the regulatory control periods under Section 2262.4 of Title 13 of the California Code of Regulations, during which gasoline exceeding the Reid vapor pressure limits in Title 13, Section 2262 of the California Code of Regulations may not be sold or supplied for use in the state, if the Governor, in consultation with the State Energy Resources Conservation and Development Commission and the state board, determines the average retail gasoline price increased substantially or is projected to increase substantially within any 30-day period and a suspension is necessary to protect consumers in the state from extraordinary gasoline price increases and determines, in the Governor’s discretion, that suspension is prudent and unlikely to yield unintended consequences. In considering whether to suspend the regulatory control periods, as described in this section, the Governor shall consider the air quality effects and options to mitigate those effects, if necessary and subject to available resources.
Section 21080.81 is added to the Public Resources Code, to read:
(a) The Legislature finds and declares all of the following:
(1) The Legislature recognizes the significance of oil and gas production in the County of Kern, while also affirming the state’s commitment to protecting public health, safety, and environmental quality, particularly for communities located near oil and gas operations.
(2) The County of Kern has adopted an oil and gas permitting ordinance, and in connection with that ordinance, has certified a Second Supplemental Environmental Impact Report (SSREIR) pursuant to this division. The County of Kern’s SSREIR and oil and gas permitting ordinance impose comprehensive mitigations to address potential environmental impacts associated with oil and gas production.
(3) Article 4.6 (commencing with Section 3280) of Chapter 1 of Division 3 establishes health protection zones to safeguard residents from the health risks associated with oil and gas extraction activities. The Geologic Energy Management Division’s approval of a notice of intention under Section 3203 is required before drilling a new oil and gas well. Section 3281 prohibits approval of a notice of intention within a health protection zone absent certain limited exceptions. The Kern County SSREIR does not cover activities within a health protection zone.
(4) Because the County of Kern’s SSREIR does not cover activities within a health protection zone, the Geologic Energy Management Division is the lead agency under this division for projects that include permits to drill or rework an oil and gas well within a health protection zone in the County of Kern, to the extent that those activities might be allowed under Section 3281.
(b) The Kern County Second Supplemental Recirculated Environmental Impact Report (SCH2013081079), including all appendices (SSREIR March 2025), is hereby deemed sufficient for full compliance with this division for purposes of consideration and adoption of amended Revisions to Title 19 - Kern County Zoning Ordinance Code 2025 (A), Focused on Oil and Gas Local Permitting by the County of Kern. No further environmental review is required under this division for the consideration and adoption of the Revisions to Title 19 - Kern County Zoning Ordinance Code - 2025 (A), Focused on Oil and Gas Local Permitting (SSREIR March 2025), as enacted as of January 1, 2026. Corrections of minor typographical errors and formatting changes to the zoning ordinance version shall not require further environmental review. Any other modification to or readoption of the zoning ordinance, however, shall not be covered by this section but rather by the other provisions of this division.
(c) Projects that satisfy the requirements of Revisions to Title 19 - Kern County Zoning Ordinance Code - 2025 (A), Focused on Oil and Gas Local Permitting, and that are approved by the County of Kern under that ordinance as enacted as of the effective date of this section, or as reenacted to incorporate corrections of minor typographical errors or formatting changes, are deemed sufficient for full compliance with this division and no further environmental review is required under this division, so long as the projects comply with Article 4.6 (commencing with Section 3280) of Chapter 1 of Division 3, as that article read on January 1, 2025.
(d) This section applies prospectively to any approvals by the County of Kern with respect to the permitting of oil and gas production operations under any adopted local ordinance and associated development and also applies prospectively and retroactively to any causes of action and claims that are pending as of the effective date of this section, and for which no final nonappealable judgment has been entered before that date.
(e) Notwithstanding Section 21166, the Legislature’s determination in this section that the Kern County Second Supplemental Recirculated Environmental Impact Report (SCH2013081079), including all appendices (SSREIR March 2025), is sufficient for full compliance with this division and shall be final and conclusive for purposes of reliance on that report for its use by any responsible agencies. Reliance on use of that report by any responsible agency shall fully satisfy the responsible agency’s obligations under this division and shall not be subject to challenge pursuant to Section 21166.
(f) No approval may be granted by the County of Kern or the Geologic Energy Management Division in reliance on the Kern County Second Supplemental Recirculated Environmental Impact Report (SCH2013081079), including all appendices (SSREIR March 2025), with respect to any operation located in a health protection zone as defined in Section 3280, regardless of whether Section 3281 is enforceable or independently prohibits that approval.
(g) The Geologic Energy Management Division shall be the lead agency under this division for projects in the County of Kern that include approval of a notice of intention under Section 3203 to drill or rework an oil gas well within 3,200 feet of a residence, educational facility, youth center, health care facility, live-in housing, or any building housing a business that is open to the public, to the extent those projects may be authorized by law. The measurement shall be made from the property line unless the building is more than 50 feet set back from the property line, in which case the measurement shall be made from the outline of the building footprint to 3,200 feet in all directions.
(h) The Geologic Energy Management Division shall not approve more than 2,000 notices of intention per calendar year to drill new wells in reliance on the Second Supplemental Recirculated Environmental Impact Report (SCH2013081079) as a responsible agency under this section, unless the State Energy Resources Conservation and Development Commission makes a formal finding that additional permit issuance is necessary for in-state crude oil production to supply 25 percent of in-state refinery feedstock demand, and that the production would likely help reduce costs for retail consumers of gasoline in the state.
(i) Because the Kern County Second Supplemental Recirculated Environmental Impact Report (SCH2013081079), including all appendices (SSREIR March 2025), analyzes activities only through the end of 2035, further environmental review is required to satisfy the lead agency’s obligations under this division for any County of Kern ordinance on oil and gas permitting enacted on or after January 1, 2026, unless that ordinance only corrects minor typographical errors and formatting to the zoning ordinance referenced in subdivision (b).
(j) This section shall remain in effect only until January 1, 2036, and as of that date is repealed, unless a later enacted statute that is enacted before January 1, 2036, deletes or extends that date.
Section 25371 of the Public Resources Code is amended to read:
Earlier text of § 25371 is not compiled in this navigator, so changes are not marked.
Notwithstanding Section 10231.5 of the Government Code, on or before January 1, 2024, and every three years thereafter, the commission shall submit an assessment to the Legislature, in accordance with Section 9795 of the Government Code, and to the Governor that does all of the following:
Identifies methods to ensure a reliable supply of affordable and safe transportation fuels in California. The assessment shall include estimates for the level of transportation fuels at the state level, and, to the extent feasible, at regional and local levels, and individual refineries if relevant, that should be held in reserve by refiners to prevent gasoline price spikes. The assessment shall consider all factors causing price fluctuations in retail gasoline prices when recommending adequate reserve levels. The commission shall consider all relevant evidence from any reasonably available source, including, but not limited to, information about imports, by amount, source, if known, and data received by the commission pursuant to existing laws, economic and business experts, and information from any local, state, and federal agencies. The commission shall transmit to the Legislature, in accordance with Section 9795 of the Government Code, any proposals it deems appropriate for mandatory reserve levels and the terms of a program to implement reserve levels.
Evaluates the price of transportation fuels, including branded and unbranded retail prices, alternate formulations of gasoline with lower carbon impact, and other products suitable for production from refineries in California. This evaluation shall consider the market demand for these products at 3-, 7-, 10-, and 20-year intervals from the date of the assessment and shall rely on the most recent transportation forecasting and assessment activities conducted pursuant to Section 25304. This evaluation shall include both of the following:
An examination of whether branded fuel additives have any impact, and, if so, how much, on fuel efficiency and vehicle emissions.
An assessment of the presence and availability of retail outlets, including monitoring changes in availability of retail outlets that contribute to increasing retail prices in local and regional areas.
Considers different levels of supply conditions and assesses the impact of potential refinery closures in California.
Includes an analysis of the impacts on production of refinery planned maintenance, unplanned maintenance, and turnaround. The assessment shall evaluate ways to manage necessary maintenance among the various facilities that would protect the health and safety of employees and the public, and minimize the impact of maintenance-related production losses. Notwithstanding any other law, the Department of Industrial Relations and Division of Occupational Safety and Health shall disclose to the commission, upon request, any information the department and division have received under Section 7872 of the Labor Code to ensure all aspects of refinery safety are incorporated into the assessment. All information designated confidential shall be treated as confidential by the commission.
Evaluates the utility and feasibility of alternative methods to maintain adequate supplies of transportation fuels, including delivery alternatives for fuel and components of refined fuel, such as delivery by rail, a publicly maintained strategic fuel reserve, and other solutions beyond the activities of refineries and petroleum market participants.
Proposes solutions to mitigate any impacts described in the assessment. The solutions shall include an assessment of the employment impacts and the cost and cost-effectiveness of any proposal, including cost impacts to all impacted sectors, both public and private. The assessment shall include recommendations and alternatives.
Beginning with the first assessment submitted after the effective date of this subparagraph, evaluates California’s future petroleum product and crude oil import needs and identifies steps that can be taken to ensure that marine infrastructure and port facilities will be adequate to accommodate the efficient movement of petroleum products to meet those needs. In preparing the evaluation pursuant to this subparagraph, the commission shall consult with the ports in California at which petroleum and refined transportation fuels are imported, tanker terminal operators at California ports, the State Lands Commission, the California Coastal Commission, and the San Francisco Bay Conservation and Development Commission and evaluate ways to maximize the use of existing infrastructure and minimize cumulative pollution burdens.
Beginning with the first assessment submitted after the effective date of this subparagraph, evaluates the effects of state regulations on supplies of transportation fuels that the commission identifies may be causing supply constraints, or for which the commission believes alternative compliance pathways should be considered by state agencies to mitigate potential impacts on supply.
In the first assessment submitted after the effective date of this subparagraph, evaluate the cost and supply impacts of allowing the sale of gasoline with alternative specifications from those in Subarticle 2 (commencing with Section 2260) of Article 1 of Chapter 5 of Division 3 of Title 13 of the California Code of Regulations to support a reliable and affordable supply of transportation fuels in California. If the evaluation finds that allowing the sale of gasoline with alternative specifications is likely to support a reliable and affordable supply of transportation fuels in California, the commission, in coordination with the State Air Resources Board, shall recommend a strategy to facilitate the sale of gasoline with those alternative specifications that, at a minimum, considers (i) a trigger mechanism for when the gasoline with those alternative specifications may be sold based on the conditions of the transportation fuels market, (ii) the existing variance process in Section 43013.2 of the Health and Safety code, and (iii) the use of a fee established pursuant to Section 43013.2 of the Health and Safety Code associated with the sale of gasoline with those alternative specifications to mitigate for any increase in emissions.
In the first assessment submitted after the effective date of this subparagraph, evaluate the development of a westwide gasoline specification that could be used in a western region to include California and areas outside of the state as an alternative to the California-specific specification established under Subarticle 2 (commencing with Section 2260) of Article 1 of Chapter 5 of Division 3 of Title 13 of the California Code of Regulations to stabilize the petroleum market and petroleum prices in the western region, including California. The commission, in coordination with the State Air Resources Board, shall conduct outreach to the western states, including the States of Arizona, Nevada, Oregon, and Washington, in furtherance of this evaluation.
The evaluation pursuant to this subparagraph shall assess the costs and benefits of each alternative specification, including economic impacts to the state and to consumers, labor impacts, public health impacts, and environmental impacts. In making this evaluation, the commission shall take into consideration the impacts of the state’s electrification efforts and the requirements of the federal Clean Air Act (42 U.S.C. Sec. 7661 et seq.). The evaluation shall identify and recommend the alternative specification that would minimize the costs and maximize the benefits to the state.
The first assessment shall include the evaluation of oil and gas extraction and refining that the State Air Resources Board outlined in the most recent update to the scoping plan prepared pursuant to Section 38561 of the Health and Safety Code.
The assessment shall be separate from the report submitted pursuant to Section 25302 and shall be developed in a public process. The assessment shall be available to the public within the proceeding docket and shall be approved by a vote of the commission at its business meeting.
The commission may enter into contracts to perform the assessment required by subdivision (a) and the contracts shall not require the review, consent, or approval of the Department of General Services or any other state department or agency and do not need to comply with requirements under the State Contracting Manual or the Public Contract Code.
The Division of Petroleum Market Oversight shall provide input to and otherwise support other divisions of the commission in preparation of the assessment required by subdivision (a).
The Independent Consumer Fuels Advisory Committee established pursuant to Section 25373 shall provide input to the commission in preparation of the assessment required by subdivision (a).
Section 25371.4 is added to the Public Resources Code, immediately following Section 25371.3, to read:
The commission shall, on or before March 31, 2026, submit an assessment to the Legislature, in accordance with Section 9795 of the Government Code, and to the Governor that evaluates the recommendations and strategies put forward by the vice chair of the commission in the June 27, 2025, letter to Governor Newsom in order to, as described in that letter, “ensure that Californians have access to safe, affordable, and reliable transportation fuels and that petroleum refiners continue to see value in serving the California market...” The assessment shall also offer recommendations to the Legislature and the Governor on potential changes to working group authorities or structures, including on permitting changes and reforms, which may include one-stop-shop permitting, to support the state’s reliable, equitable, safe, and affordable transition away from petroleum fuels.
Section 30262 of the Public Resources Code is amended to read:
Earlier text of § 30262 is not compiled in this navigator, so changes are not marked.
New or expanded oil and gas development shall not be considered a coastal-dependent industrial facility for the purposes of Section 30260, and may be permitted only if found to be consistent with all applicable provisions of this division and if all of the following conditions are met:
The development is performed safely and consistent with the geologic conditions of the well site.
Activities related to that development are consolidated, to the maximum extent feasible and legally permissible, unless consolidation will have adverse environmental consequences and will not significantly reduce the number of producing wells, support facilities, or sites required to produce the reservoir economically and with minimal environmental impacts.
The development will not cause or contribute to subsidence hazards unless it is determined that adequate measures will be undertaken to prevent damage from that subsidence.
All oilfield brines are reinjected into oil-producing zones unless the Geologic Energy Management Division of the Department of Conservation determines to do so would adversely affect production of the reservoirs and unless injection into other subsurface zones will reduce environmental risks. Exceptions to reinjections will be granted consistent with the California Ocean Plan of the State Water Resources Control Board and where adequate provision is made for the elimination of petroleum odors and water quality problems.
All oil produced offshore California shall be transported onshore by pipeline only. The pipelines used to transport this oil shall utilize the best achievable technology to ensure maximum protection of public health and safety and of the integrity and productivity of terrestrial and marine ecosystems.
Once oil produced offshore California is onshore, it shall be transported to processing and refining facilities by pipeline that uses the best available technology pursuant to Section 51013.1 of the Government Code.
The following guidelines shall be used when applying subparagraphs (A) and (B):
“Best achievable technology,” means the technology that provides the greatest degree of protection taking into consideration both of the following:
Processes that are being developed, or could feasibly be developed, anywhere in the world, given overall reasonable expenditures on research and development.
Processes that are currently in use anywhere in the world. This clause is not intended to create any conflicting or duplicative regulation of pipelines, including those governing the transportation of oil produced from onshore reserves.
“Oil” refers to crude oil before it is refined into products, including gasoline, bunker fuel, lubricants, and asphalt. Crude oil that is upgraded in quality through residue reduction or other means shall be transported as provided in subparagraphs (A) and (B).
Subparagraphs (A) and (B) shall apply only to new or expanded oil extraction operations. “New extraction operations” means production of offshore oil from leases that did not exist or had never produced oil, as of January 1, 2003, or from platforms, drilling islands, subsea completions, or onshore drilling sites, that did not exist as of January 1, 2003. “Expanded oil extraction” means an increase in the geographic extent of existing leases or units, including lease boundary adjustments, an increase in the number of well heads, reactivation of a facility idled, inactive, or out of service for more than five years, or an increase in oil extraction from the use of hydraulic fracturing, extended reach drilling, acidization, or other unconventional technologies, on or after January 1, 2003.
If a state of emergency is declared by the Governor for an emergency that disrupts the transportation of oil by pipeline, oil may be transported by a waterborne vessel, if authorized by permit, in the same manner as required by emergency permits that are issued pursuant to Section 30624.
In addition to all other measures that will maximize the protection of marine habitat and environmental quality, when an offshore well is abandoned, the best achievable technology shall be used.
Repair and maintenance of an existing oil and gas facility may be permitted in accordance with Section 30260 only if it does not result in expansion of capacity of the oil and gas facility, and if all applicable conditions of subdivision (a) are met.
Repair, reactivation, and maintenance of an oil and gas facility, including an oil pipeline, that has been idled, inactive, or out of service for five years or more shall be considered a new or expanded development requiring a new coastal development permit consistent with this section.
Development associated with the repair, reactivation, or maintenance of an oil pipeline that has been idled, inactive, or out of service for five years or more requires a new coastal development permit consistent with this section.
The commission or local government with a certified local coastal program shall review and approve, modify, condition, or deny the permit based on the requirements of this section.
Where appropriate, monitoring programs to record land surface and near-shore ocean floor movements shall be initiated in locations of new large-scale fluid extraction on land or near shore before operations begin and shall continue until surface conditions have stabilized. Costs of monitoring and mitigation programs shall be borne by liquid and gas extraction operators.
This section does not affect the activities of any state agency that is responsible for regulating the extraction, production, or transport of oil and gas.
Bill text is the chaptered version from LegiScan (California Legislature); spacing is normalized. Code section text in a bill is the text that bill chaptered, not necessarily the law in effect today. Not legal advice.