a compliance handbook for sb 4 - california’s well ... · • well stimulation treatment radius...

A Compliance Handbook for SB 4 - California’s Well

Stimulation Permitting Law Third Edition

Prepared by:

Michael N. Mills

Thomas A. Henry

Eric R. Skanchy

July 2015

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SB 4: WELL STIMULATION TABLE OF CONTENTS

I. Key Components of SB 4 ..................................................................................................1 II. Well Stimulation Treatment Permit Applications .........................................................2

A. SB 4 Implementation Dates ................................................................................. 2 B. Permit Application ................................................................................................ 3

1. Well Stimulation Treatment Permit Application ........................................ 3 2. Notification Prior to Well Stimulation Activities ......................................... 4 3. Evaluation Prior to Well Stimulation Activities .......................................... 5 4. General Well Stimulation Treatment Requirements ................................. 5 5. After Well Stimulation Activities Have Occurred ....................................... 6

III. Neighbor Notification Scheme .........................................................................................9 A. Neighbor Notification ............................................................................................ 9 B. Availability of Water Testing ................................................................................. 9

IV. CEQA and Environmental Review Issues ....................................................................11 A. Permitting ........................................................................................................... 11 B. DOGGR’s EIR on Well Stimulation Activities ..................................................... 11

1. DOGGR’s EIR ........................................................................................ 12 V. Water Management and Groundwater Monitoring Considerations .........................13

A. Water Management Plan ................................................................................... 13 B. Groundwater Monitoring Plan ............................................................................ 13 C. SWRCB Model Groundwater Monitoring Criteria ............................................... 14 D. Reporting Requirements .................................................................................... 16

VI. Disclosures and Trade Secrets .......................................................................................17 A. Important Exemptions from SB 4’s Trade Secret Protection .............................. 18 B. Seeking Trade Secret Protection ....................................................................... 18 C. Working with DOGGR to Achieve Trade Secret Protection ............................... 19 D. Wells with Confidential Status ............................................................................ 19

VII. Reporting Website ..........................................................................................................21 VIII. Independent Study ..........................................................................................................22

A. Volume I ............................................................................................................. 23 B. Future Volumes .................................................................................................. 23

SB 4 Compliance Handbook 1 Third Edition (July 2015)

I. Key Components of SB 4 Senate Bill 4 (“SB 4”) increases regulatory oversight over all well stimulation activities,

including hydraulic fracturing. To understand the parameters of this evolving regulatory scheme, SB 4 can be broken up into these key components:

A. Operator Obligations 1) Evaluation Prior to a Well Stimulation Treatment 2) Well Stimulation Treatment Permitting 3) Notification to Neighboring Landowners 4) Well Integrity Testing, Monitoring, and Reporting Requirements 5) Groundwater Monitoring and Water Baseline Testing 6) Seismic Monitoring 7) Chemical Disclosures, Trade Secret Protection and Exemptions 8) Post-Well Stimulation Treatment Report

B. New Agency Obligations 1) Department of Conservation, Division of Oil, Gas and Geothermal Resources

(“DOGGR”):

i. Administer Permit Program ii. Create Environmental Impact Report iii. Finalize and Implement Regulations on Well Stimulation iv. Develop State-Run Reporting Website

2) California Natural Resources Agency (“CNRA”):

i. Commission Independent Study on Well Stimulation Treatments,

Conducted by California Council on Science and Technology (“CCST”) and the Lawrence Berkeley National Laboratory (“LBNL”)

3) State Water Resources Control Board (“SWRCB”):

i. Enter into a formal agreement with DOGGR regarding roles and responsibilities in the regulation of well stimulation treatments.

ii. Designate one or more third-party contractors that adhere to SWRCB-specified standards and protocols to perform water quality sampling and testing as requested by neighboring property owners.

iii. Audit and review sampling and testing conducted by the third-party contractor(s).

iv. By July 1, 2015, develop Groundwater Monitoring Model Criteria for Well Stimulation in consultation with DOGGR.

v. By January 1, 2016, implement regional groundwater monitoring program.


II. Well Stimulation Treatment Permit Applications

A. SB 4 Implementation Dates

While most of the operator obligations under SB 4 will be in effect as of the date of this updated primer, it is important for operators to calendar the following deadlines in DOGGR’s SB 4 Implementation Plan:

• July 1, 2015 – Final Well Stimulation Treatment Regulations Take Effect (see Appendix A).

• July 1, 2015 – SWRCB Promulgates Groundwater Monitoring Model Criteria.

• July 1, 2015 – CNRA Releases Independent Scientific Study Volumes II and III.

• January 1, 2016 – SWRCB Implements Regional Groundwater Monitoring Program.


B. Permit Application

SB 4 requires operators to apply for and obtain a permit from DOGGR prior to performing a well stimulation treatment. To complete a well stimulation permit application beginning July 1, 2015, the operator must comply with the following requirements.

1. Well Stimulation Treatment Permit Application

Operator Checklist: The following information must be included in all permit applications. (PRC § 3160(d)(1); Permanent Regulations § 1783.1 (“Regs”).)

• Operator’s name and telephone number. • Lease name and well identification number. • Location of the well and county. • Type of well. • Name of oilfield. • Time period during which well stimulation is planned to occur. • Vertical depth of the well and description of the wellbore path. • Estimated length, height, and direction of the induced fractures or other planned well

modification. • Formation name and depth of the productive horizon where well stimulation treatment

will occur. • Water management plan. • Groundwater monitoring plan. • List of all chemical constituents of the anticipated well stimulation treatment fluids. • Anticipated source, amount, and composition of the base fluids to be used in treatment • Quantity and disposal method of treatment-generated waste. • Number of stages in the treatment, and the anticipated volume, rate, and pressure of

fluid to be injected in each stage. • Axial dimensional stimulation area (“ADSA”) for each stage. • Plan for completion of the cement evaluation required under Regs § 1784.2(a). • Well stimulation treatment radius analysis required under Regs § 1784(a)(2), including

identification of all water within the area of the well stimulation treatment radius analysis, and the names and API numbers of all wells within the ADSA.

• Identification of all wells that have previously been hydraulically fractured in the same production horizon within twice the ADSA.

• Identification of where in the operator’s Spill Contingency Plan handling of well stimulation fluid and additives has been addressed.

• Procedures to comply with the Hazardous Waste Control Law. • Anticipated radiological components or tracers to be injected during treatment. • State Clearinghouse Number, or other identification, of all documents prepared under

the California Environmental Quality Act (“CEQA”) relating to the proposed treatment.


• In addition, PRC § 3160(d)(1)(G) requires disclosure of certain waste disposal methods to obtain a permit:

o Estimated amount of any treatment-generated waste materials that are not already identified pursuant to PRC § 3160(d)(1)(C) in the water management plan.

o Disposal method for the waste materials.

• Geological features should be identified if the treatment has the potential to limit or facilitate migrations of fluids outside the fracture zone. This information must be included in the well history that operators submit. (PRC § 3160(i)(1)-(2).)

• Upon receipt of a complete permit application, DOGGR will furnish a copy of the permit application to the Regional Water Quality Control Board (“Regional Water Board”), the Department of Toxic Substances Control (“DTSC”), the Air Resources Board, and the local air district. This permit application will include trade secret and confidential information. (Regs § 1783(c).)

o “The Division will provide the information that is not publicly disclosed to other state agencies as needed for regulatory purposes and in accordance with a written agreement with the other state agency regarding sharing of confidential information.” (Regs § 1788(c).)

• Even after DOGGR has approved the well stimulation treatment application, the operator

shall not commence treatment until receiving written approval from SWRCB or the Regional Water Board certifying that the treatment is covered under Water Code § 10783. (Regs § 1783(a).)

2. Notification Prior to Well Stimulation Activities

• The regulations have a notification scheme that requires notification to all neighbors within a specified distance from the wellhead and horizontal projection of the well 30 days prior to commencing well stimulation activity. See Section III for detailed requirements.

• Additionally, the operator must give DOGGR notice at least 72 hours prior to commencing well stimulation so that DOGGR staff have the opportunity to witness well stimulation activity. (Regs § 1783(d).) In addition, the operator must confirm with DOGGR that operations are going to commence within three to 15 hours prior to starting. (Regs § 1783(d).)

Stoel Rives Analysis: This well stimulation treatment permit application may be combined into a

single authorization for multiple applications for permits to perform well stimulation treatments and/or notices of intent to drill or rework wells. This single-project authorization must clearly delineate what permits are being requested. See Section IV for a deeper discussion of the CEQA implications of this combined authorization. (PRC § 3160(d)(2); Regs § 1751.)


3. Evaluation Prior to Well Stimulation Activities

• The operator is required to do all of the following prior to commencing or recommencing well stimulation treatment operations:

o Run a radial cement evaluation, allowing at least 48 hours to elapse after cement placement, pursuant to Regs § 1784.2(a).

o Conduct well stimulation treatment area analysis pursuant to Regs § 1784(a)(2). o Conduct pressure testing pursuant to Regs § 1784.1(a) not more than 30 days

before commencing well stimulation treatment operations.

• In addition, the operator should notify DOGGR at least 24 hours prior to conducting the pressure testing, and provide DOGGR with a charting of pressure testing at least 12 hours prior to commencing well stimulation treatment. (Regs § 1784.1(b).)

4. General Well Stimulation Treatment Requirements

The regulations also address the monitoring process and treatments during the actual well stimulation activities (a period of time the Legislature did not specifically address in SB 4).

Monitoring

• The operator is responsible for continuously monitoring specified parameters during the well stimulation treatment. These parameters include:

o Surface injection pressure. (Regs § 1785(a)(1).) o Slurry rate. (Regs § 1785(a)(2).) o Proppant concentration. (Regs § 1785(a)(3).) o Fluid rate. (Regs § 1785(a)(4).) o Specified levels of pressure changes. (Regs § 1785(a)(5)-(b).) o Potential breaches in the production casing. (Regs § 1785(b)(4).)

• If any of the events listed in § 1785(b) occur, the operator is required to perform

diagnostic testing to determine whether a well breach has occurred. The operator must notify DOGGR so that DOGGR staff have an opportunity to witness the testing, and the operator must immediately provide testing results to DOGGR. (Regs § 1785(c).)

• If a breach has occurred, the operator must immediately shut-in the well and make

certain disclosures to DOGGR and the Regional Water Board, including, but not limited to, a description of the activities, the exact description of chemical constituents of the well stimulation treatment, and an estimate of the volume of fluid lost during well failure. (Regs § 1785(d).)

(See Appendix A for the comprehensive regulations on monitoring.)

Fluid and Waste Storage

• Operators are required to store well stimulation fluids pursuant to the already existing storage requirements in the California Code of Regulations, title 14, § 1773.1. Operators must comply with all existing requirements for testing, inspection, and maintenance


requirements for production facilities containing well stimulation treatment fluids. (Regs § 1786(a)(1)-(2).)

o Those fluids must be accounted for in the operator’s Spill Contingency Plan. (Regs § 1786(a)(3).)

o Fluids must always be stored in containers, not in sumps or pits. (Regs § 1786(a)(4).)

• Should there be an unauthorized release of well stimulation fluids from the applicable

storage place, the operator is required to immediately notify response entities, and perform cleanup and remediation as required by all applicable federal, state, and local law. (Regs § 1786(a)(5).)

• Within five days of the occurrence, the operator must provide DOGGR with a written

report including, but not limited to, the description of the activities leading up to the release, and the type and volume of fluids released. (Regs § 1786(a)(6).)

• In addition to DOGGR’s requirements, operators must store and manage fluids in a manner consistent with the requirements of the Regional Water Board, the DTSC, the Air Resources Board and local air district, and the Certified Unified Program Agency. (Regs § 1786(a)(7).)

• An operator who generates waste must determine if the waste is hazardous by testing the waste according to the protocol in California Code of Regulations, title 22, § 66261.2. (Regs § 1786(a)(8).)

5. After Well Stimulation Activities Have Occurred

Monitoring

• Operators are required to monitor a producing well once an operator has stimulated or treated that well by engaging in specified monitoring techniques. For example:

o Monitoring the production pressure of the well at least once every two days over the first 30 days. (Regs § 1787(d)(1).)

o Monitoring the annular pressures of the well. (Regs § 1787(d)(2).)

• This information must be reported to DOGGR annually. (Regs § 1787(d)(2).)

• Beginning at the commencement of hydraulic fracturing until 10 days after the end of fracturing, the operator shall monitor the California Integrated Seismic Network for any earthquakes of magnitude 2.7 or greater occurring within a radius of five times the

Stoel Rives Analysis: Many of the regulations included in the Regs – such as the creation of a Spill

Contingency Plan, the monitoring of pressure changes during drilling operations, and the testing of casing – are activities that an operator already must comply with according to the current regulations presently required pursuant to the California Code of Regulations.


ADSA. If an earthquake is identified, the operator must notify DOGGR and conduct evaluations in accordance with Regs § 1785.1(b).

o During this time, no other fracking shall occur within the radius of five times the

ADSA until DOGGR has completed the evaluation and is satisfied that there is not a heightened risk of seismic activity. (Regs § 1785.1(b)(3).)

Reporting

• Within 60 days of the cessation of well stimulation treatments, operators must publicly disclose information as specified in Regs § 1788, including whether base fluid is suitable for irrigation or domestic purposes and the source, volume, and composition of all water used in the treatment. The Regs state that the disclosures shall be posted to the Chemical Disclosure Registry (FracFocus.org). (Regs § 1788(b).)

• In addition to posting disclosures pursuant to PRC § 3160(g)(1) within 60 days of the

well stimulation treatment, operators must also provide DOGGR with a report describing:

o Results of the well stimulation treatment. o Pressures encountered during the well stimulation treatment. o How the actual well stimulation treatment differed from the well stimulation

treatment design prepared pursuant to Regs § 1784(b). (Regs § 1789(a)(4).)

Penalties

• Penalties will be levied against a “person who violates this chapter [SB 4] or a regulation implementing this chapter.” (PRC § 3236.5(a).)

• For violations of Article 3 (PRC § 3150, et seq.), penalties cannot be less than $10,000 per day, but may not exceed $25,000 per day. (PRC § 3236.5(a).)

• The penalties “levied, assessed, and collected” will be used exclusively for the “support

and maintenance of [DOGGR].” (PRC § 3401(a).)

o However, other public entities (such as the Natural Resources Agency) may use the penalties collected for costs associated with “rulemaking and scientific studies required to evaluate the treatment, inspections, any air and water quality sampling, monitoring, and testing.” (PRC § 3401(b)(1).)

Stoel Rives Analysis: SB 4 does not define the “cessation” of well stimulation treatments. However, current regulations define the date of cessation of drilling operations as “the date on which any or all equipment or machinery necessary for carrying out a drilling operation is removed from the well site.” (Cal. Code Regs., tit. 14, § 1996.7.) Presumably, this definition can be applied to the cessation of well stimulation treatments, and its practical effect would remain the same: where a piece of equipment necessary to complete the work is removed from the job site, the operation is considered ceased.


Stoel Rives Analysis: Because this provision broadly applies to all of Article 3, it appears that

penalties could be assessed for any violation, from omissions in the permit application to unintentionally failing to notify a landowner.


III. Neighbor Notification Scheme A. Neighbor Notification

• After DOGGR approves the well stimulation treatment permit, the operator must hire an independent third party to identify and give notice to surface property owners and tenants within a specified radius. The operator must not commence well stimulation until 30 days after noticing all neighbors. (Regs § 1783.2(a).)

o For purposes of identifying those required to receive notice, a “tenant” is a person or an entity possessing the right to occupy a legally recognized parcel (or a portion of that parcel), by way of a valid written agreement. (Regs § 1781(r).)

o Notice to a tenant does not have to be addressed to a named individual. It can be addressed to “current resident” or “current occupant.” (Regs § 1783.2(g).)

• All surface property owners and tenants within the following distances must be given

notice. (Regs § 1783.2(a)(1).)

o 1500-foot radius of the wellhead. o 500-foot radius of the surface representation of the horizontal path of the

subsurface well. • Neighbor notification must consist of the following components. Additionally, the

operator must mail a declaration of notice to DOGGR pursuant to Regs § 1783.2(i).

o Approved well stimulation treatment permit. (Regs § 1783.2(a)(2)(A).) o Well Stimulation Treatment Neighbor Notification Form. (Regs §

1783.2(a)(2)(B).) The operator must use the DOGGR-issued form (7/15 Version, see Appendix B). The form is bilingual (in English and Spanish).

B. Availability of Water Testing

• Any surface property owner receiving neighbor notification pursuant to Regs § 1783.2 may request water quality testing on any existing well or surface water located on the property that is suitable for drinking or irrigation. (Regs § 1783.3(a).)

o The operator must pay for all reasonable costs of water quality testing. (Regs § 1783.3(b)(5).)

Stoel Rives Analysis: DOGGR added language to the Regs clarifying when there is no notification

requirement. If the independent third party determines that there are no neighbors within the specified radius, notification is not required and the 30-day waiting period is eliminated. The operator may commence operations 72 hours after the independent third party certifies its determination. (Regs §§ 1783.2(b), (c).)


• Water quality testing must be performed by a Designated Contractor for Water Sampling

in accordance with SWRCB’s standards. (Regs §§ 1783.3(b)(1), (2).)

o The surface property owner can elect to have the operator select and contract with the Designated Contractor, or the surface owner can select the Designated Contractor and communicate directly with the contractor. (Regs § 1783.3(b)(1).)

o If the surface property owner chooses for the operator to select and contract with the Designated Contractor, and the request is made in writing and postmarked within 20 days from the date notice is provided, the well stimulation treatment may not commence until the requested baseline sampling is completed. (Regs § 1783.3(b)(4)(A).)

• There are two phases of water quality testing: baseline testing occurs prior to

commencement of the well stimulation treatment, and follow-up testing is performed after the treatment is completed. (Regs § 1783.3(b)(3).)

o The Regional Water Board must be notified at least two working days in advance

of water testing so that staff may witness testing. (Regs § 1783.3(b)(7).)

o Water quality testing data must be submitted to DOGGR, the Regional Water Board, and the SWRCB. (Regs § 1783.3(c).)

• Any tenant receiving neighbor notification pursuant to Regs § 1783.2 may independently

contract for water quality testing. The operator does not pay for the cost of water quality testing for tenants. (Regs § 1783.3(d).)

Stoel Rives Analysis: DOGGR estimates that only about 30% of neighbors that are notified request

water testing. This is largely due to the fact that many of the neighboring property owners are related to agricultural interests or industries and they would prefer to not have their water tested.


IV. CEQA and Environmental Review Issues

A. Permitting

• “Where the supervisor determines that the activities proposed in the well stimulation treatment permit or the combined authorization have met all of the requirements of [CEQA], and have been fully described, analyzed, evaluated, and mitigated, no additional review or mitigation shall be required.” (PRC § 3160(d)(2)(B).)

• DOGGR has the authority to determine that this combined authorization or the well

stimulation permit has been evaluated under CEQA and, with that determination, decline to conduct additional environmental review.

B. DOGGR’s EIR on Well Stimulation Activities

• PRC § 3161(b)(4) requires DOGGR to conduct a statewide environmental impact report (“EIR”) on hydraulic fracturing in California and certify that EIR by July 1, 2015 (and it is required to act as the lead agency on this EIR). This EIR is not project- or location-specific.

• The Deputy Director of the Department of Conservation has publicly stated that DOGGR hopes to develop an EIR that local agencies can rely on during their environmental review, particularly as it pertains to mitigation measures that have already been certified in the DOGGR EIR.

Stoel Rives Analysis: There are several ways PRC § 3160(d)(2) can be interpreted. The first is that

this is simply a restatement of the current law (e.g., using an EIR adopted by a county in which DOGGR was a “responsible agency”). The second is that this provision allows DOGGR to avoid CEQA’s normal procedural requirements that would apply if the activity has been fully evaluated in another CEQA document (e.g., regardless of whether DOGGR was a responsible agency in the prior review). DOGGR may still be required to make appropriate findings, under CEQA, that the permit’s impacts have been evaluated and mitigated, and such mitigation measures have been incorporated in the permit approval. This provision caused several environmental groups to pull their support of SB 4, believing that this provision may result in curtailed environmental review of well stimulation permit applications/projects.


1. DOGGR’s EIR

• On July 1, 2015, DOGGR released the EIR.

• The “project” is defined as “all activities associated with a stimulation treatment that could occur either at an existing oil and gas well, or at an oil and gas well that is drilled in the future expressly for the purposes of a stimulation treatment.” (EIR, Executive Summary, at p. 3.)

• The potentially significant and unavoidable impacts of the project are identified as:

o Aesthetics (Visual Resources) o Air Quality o Biological Resources: Terrestrial Environment o Cultural Resources o Geology, Soils, and Mineral Resources o Greenhouse Gas Emissions o Land Use and Planning o Risk of Upset/Public and Worker Safety o Transportation and Traffic

Stoel Rives Analysis: This requirement is very unusual, as CEQA review is triggered by a “project,”

and the statute does not define the project subject to this EIR. It is not clear how a local agency could use the EIR as a part of its own CEQA process for a well, other than using the technical information in its own CEQA process, as CEQA contains strict procedural requirements as to when an agency may rely on a previously developed CEQA document. DOGGR has stated that well stimulation activities proposed in the future may be subject to additional environmental review.


V. Water Management and Groundwater Monitoring Considerations

• SB 4 added § 10783 to the Water Code to include groundwater monitoring criteria for

well stimulation activities.

• There are two types of water issues in SB 4: (1) water management, which focuses on the quantity of water used, the source of the water, and the disposal of the water; and (2) water quality, which focuses on testing the potential effects well stimulation might have on groundwater in California.

• In order to comply with SB 4, an operator must create a Water Management Plan and create or comply with a Groundwater Monitoring Plan.

A. Water Management Plan

• A Water Management Plan consists of the following components (Regs § 1783.1(a)(23)):

o Estimate of the amount of water to be used in the treatment. o Estimate of the amount of water to be recycled following the well stimulation

treatment and a description of how and where the water will be recycled. o Anticipated source of the water to be used in the treatment. o Disposal method for the recovered water in the flowback fluid from the treatment

that is not produced water included in the statement pursuant to PRC § 3227. o Anticipated source of the water to be used in the treatment, including the well

from which the water will be produced, the water supplier, and the point of diversion of surface water.

B. Groundwater Monitoring Plan

• An operator’s Groundwater Monitoring Plan may take one of three forms:

o A monitoring plan for a well located within the boundaries of an existing oil or gas field-specific or regional monitoring program developed pursuant to § 10783 of the Water Code.

o A monitoring plan for a well is located within the boundaries of an existing oil or gas field-specific or regional monitoring program developed and implemented by the owner/operator or operator meeting the model criteria established pursuant to § 10783 of the Water Code.

o A well-specific monitoring plan implemented by the owner or operator that meets the model criteria established pursuant to § 10783 of the Water Code, submitted to the appropriate Regional Water Board for review. This may occur in the absence of state implementation of a regional groundwater monitoring program.


Groundwater Monitoring Plan Requirements • In contrast to DOGGR’s Emergency Regulations (§ 1783.4), the Permanent Regulations

do not require an operator to create an individual groundwater monitoring plan. Instead, the operator can comply with a regional groundwater monitoring plan.

• An operator is required to either (Regs § 1783.1(a)(27)):

o Provide documentation from the SWRCB or the Regional Water Board certifying that the well is covered by a regional groundwater monitoring program pursuant to Water Code § 10783(h)(1); or

o Provide documentation proving that the operator is working with the SWRCB or the Regional Water Board to ensure that the well subject to well stimulation treatment is covered in accordance with Water Code § 10783.

C. SWRCB Model Groundwater Monitoring Criteria

• SB 4 amended the Water Code to require that, on or before July 1, 2015, the SWRCB will develop model groundwater monitoring criteria to be implemented either (i) on a well-by-well basis for a well subject to well stimulation; or (ii) on a regional scale.

o The criteria must address a range of spatial sampling scales, whether on a well-by-well basis or on a regional basis.

o The state must prioritize monitoring potentially affected groundwater that has the potential to be a source of drinking water, but must also protect all waters for beneficial use.

o In developing the model monitoring criteria, the SWRCB was required to consult with DOGGR and various experts on the design of the groundwater monitoring criteria. Perhaps more importantly, the state was required to seek the “advice of stakeholders representing the diverse interests of the oil- and gas-producing areas of the state.” (Water Code § 10783(e).)

• The scope and nature of the groundwater monitoring criteria includes the following

(Water Code § 10783(f)):

o List of the constituents tested to measure and assess water quality. o When a single aquifer containing protected water is penetrated by a stimulated

well, or group of stimulated wells, that aquifer must be monitored. o When multiple aquifers containing protected water are penetrated by a stimulated

well, or group of stimulated wells, a minimum of two aquifers must be monitored. The shallowest and deepest aquifer must be monitored.

o At a minimum, one upgradient and two downgradient monitoring wells for each aquifer to be monitored.

o Monitoring wells shall be located within 0.5 mile of the surface projection of the zone(s) of stimulation.

o For any drinking water supply well located within one mile and downgradient of the surface projection of the zone(s) of stimulation, a sentry monitoring well shall be located between the stimulated well(s) and the drinking water supply well.


o For area-specific groundwater monitoring, the operator must sample the groundwater monitoring wells as follows: Collection of samples before well stimulation. Following well stimulation,

area-specific groundwater monitoring wells shall be placed on a semi-annual monitoring schedule.

The quarter selected for semi-annual sampling shall alternate each year. For example, the first year, the operator will collect samples during the first and third quarter; the following year, samples will be collected during the second and fourth quarters.

o Threshold criteria indicating a transition from well-by-well monitoring to a regional monitoring program.

o All testing shall be performed by a laboratory certified by the State Water Board. o If test results indicate potential impacts from a stimulation treatment, the Water

Boards will require additional testing. o All groundwater monitoring data collected shall be compiled in a groundwater

monitoring report. Water Boards staff will evaluate the data and test results to determine

changes in water quality and whether additional monitoring requirements or corrective actions are necessary.

• In addition, when assessing the scope and nature of the groundwater monitoring criteria,

the SWRCB must consider the following factors:

o Existing quality and potential use of the groundwater. o Groundwater that is not an underground source of drinking water containing less

than 10,000 milligrams per liter total dissolved solids in groundwater. o Proximity to human population, public water service wells, and private

groundwater use, if known. o Presence of existing oil and gas production fields, including the distribution,

physical attributes, and operational status of oil and gas wells therein. o Monitoring for potential contamination events and, if contamination does occur,

monitoring to determine whether groundwater contamination can be attributable to a specific event or if changes are necessary.

• The SWRCB must implement the regulations setting forth the Groundwater Monitoring

Plan criteria no later than January 1, 2016. (Water Code §§ 10783(c), (h).)

• Implementation of the groundwater monitoring criteria developed by the SWRCB “is not required for oil and gas wells where the wells do not penetrate groundwater of beneficial use, as determined by a regional water quality control board.” (Water Code § 10783(j).)

Stoel Rives Analysis: Practically speaking, almost all sources of groundwater are amenable to

some beneficial use designation, so this exemption is likely to be of limited value, especially at deeper depths where aquifers are generally more protected.


D. Reporting Requirements

• In addition to reporting to FracFocus.org, and eventually the as-yet-to-be-implemented DOGGR-run state website, operators are required to report any water quality data obtained during the permitting and stimulation process to the SWRCB in an electronic format that is compatible with the SWRCB’s GeoTracker database. (PRC § 3160(g)(1); Water Code § 10783(l)(1).)

• The SWRCB is responsible for sending a copy of this data to a “public, nonprofit doctoral-degree-granting educational institution located in the San Joaquin Valley … in order to form the basis of a comprehensive groundwater quality data repository.” (Water Code § 10783(l)(2).)


VI. Disclosures and Trade Secrets • As discussed above in Section II, SB 4 requires the following public disclosures within

60 days of well stimulation:

o Date of the well stimulation treatment. o Complete list of the names, CAS numbers, and maximum concentration, in

percent by mass, of each and every chemical constituent of the well stimulation treatment fluids used.

o Trade name, supplier, concentration, and brief description of the intended purpose of each additive contained in the well stimulation treatment fluid.

o Total volume of base fluid used during the well stimulation treatment, and identification of whether the base fluid is water suitable for irrigation or domestic purposes, water not suitable for irrigation or domestic purposes, or a fluid other than water.

o Source, volume, and specific composition and disposition of all water, including all water used as base fluid during the well stimulation treatment and recovered from the well following the well stimulation treatment, that are not otherwise reported as produced water pursuant to PRC § 3227.

o Any repeated reuse of treated or untreated water for well stimulation treatments and well stimulation treatment-related activities.

o Specific composition and disposition of all well stimulation treatment fluids, including waste fluids, other than water.

o Any radiological components or tracers injected into the well as a part of, or in order to evaluate, the well stimulation treatment.

o Radioactivity of the recovered well stimulation fluids. o Description of the recovery method, if any, for those components or tracers, and

the recovery rate of the tracers, and specific disposal information for recovered tracers.

o Location of the portion of the well subject to the well stimulation treatment, and the extent of the fracturing surrounding the well induced by the treatment. (PRC § 3160(b)(2).)

• Suppliers – or drilling service providers – are required to disclose these aspects of well

stimulation activities, regardless of whether such activities or products are trade secrets. Once disclosed, DOGGR may choose to grant trade secret status and refuse to release the trade secret information to the public. (PRC § 3160(j).)

• Suppliers are required to provide operators with information sufficient for the operator to

comply with PRC § 3160(g)(1), which requires that the operator post information concerning well stimulation fluid composition and disposition within 60 days of cessation of well stimulation treatments, as discussed above in Section II. (PRC §§ 3160(f), (j)(4)(D).)

o The supplier must furnish the operator with this information as soon as possible,

but no later than 30 days following the conclusion of the treatment. (PRC § 3160(f).)


• DOGGR allows suppliers to seek trade secret protection surrounding hydraulic fracturing and other well stimulation activities. Trade secrets are protected in California pursuant to the Uniform Trade Secrets Act and the California Public Records Act.

A. Important Exemptions from SB 4’s Trade Secret Protection

• SB 4 explicitly exempts the following from any trade secret protections:

o Chemical constituency of additives, including CAS numbers. o Concentrations of the additives in well stimulation fluids. o Any air or other pollution monitoring data. o Health and safety data associated with the fluids. o Chemical composition of flowback fluid. (PRC §§ 3160(j)(2)(A)-(E) (emphasis

added).)

• As the concentration of fracking fluid constituents is the primary product for which suppliers seek trade secret protection, the exemptions make protecting that information difficult.

B. Seeking Trade Secret Protection

• SB 4 states that “[i]f a supplier believes that the information regarding a chemical constituent of a well stimulation fluid is a trade secret, the supplier shall nevertheless disclose the information to [DOGGR].” (PRC § 3160(j)(4)(A).) If some aspect of the information could be protected, the supplier has to substantiate the claim that such information is a trade secret.

• Regs § 1783.1(c) states that “[n]otwithstanding any claim of trade secret protection, [DOGGR] shall not approve as complete an application for a permit to perform a well stimulation treatment unless all of the information specified in this paragraph has been provided to [DOGGR].”

o To comply with public disclosure requirements, the supplier must indicate where

trade secret information has been redacted and provide substitute information, which shall be reviewed by DOGGR, prior to public disclosure. (PRC § 3160(j)(4)(C).)

Such substitute information shall be a list of any chemical constituents of

the additive, including CAS identification numbers.

Stoel Rives Analysis: The Deputy Director of the Department of Conservation has publicly stated

that SB 4’s exclusions from trade secret protections mean that drilling service providers are likely to refuse to bring trade secrets into California, in order to avoid abuse of their products nationally and even internationally.


• To substantiate a trade secret claim, the supplier must provide information to DOGGR that shows the following (PRC § 3160(j)(5)):

o Extent to which the trade secret information is known by the supplier’s employees or outside the supplier’s business.

o Measures taken by the supplier to guard the secret. o Value of the trade secret information to the supplier and its competitors. o Amount of effort or money the supplier has expended to guard the claim. o Ease or difficulty with which the trade secret information could be acquired by

others.

C. Working with DOGGR to Achieve Trade Secret Protection

• DOGGR may determine that the information provided in support of a trade secret designation is incomplete. If it does so, DOGGR will notify the supplier and allow the supplier 30 days to provide the complete information.

• If DOGGR determines that the information provided to support a trade secret

designation does not meet the substantive criteria for a trade secret designation, DOGGR will notify the supplier by certified mail.

o DOGGR will then release the trade secret information to the public 60 days after

the date of mailing the determination, unless prior to the expiration of the 60-day period the supplier obtains: Declaratory judgment that the information is subject to protection; or Preliminary injunction prohibiting disclosure of the information and notice

to DOGGR of the court order.

o Even if DOGGR designates information as a trade secret, DOGGR may still disclose it to officers or employees of state and local governments, health professionals, or contractors with the government if, in the opinion of DOGGR, that disclosure is necessary: To performance of a contract; To performance of work; or To protect health and safety.

D. Wells with Confidential Status

• An owner/operator of a well granted confidential status pursuant to PRC § 3234 is not required to disclose well stimulation treatment fluid information until the confidential status of the well ceases (though the fact that a well has been or will be the subject of well stimulation treatment is not itself confidential). (PRC § 3160(k).)

• An owner/operator can request that DOGGR make its well information confidential

pursuant to PRC § 3234 through a written request to DOGGR.


o Well records are public unless the owner or operator requests, in writing, that DOGGR maintain the records of onshore exploratory wells as confidential information.

o Well records are public unless the owner or operator requests, in writing, that DOGGR maintain the records of other wells as confidential information, and DOGGR believes that there are extenuating circumstances supporting this confidential status.

o The confidential period – including requests for extension – will not exceed four years from the cessation of drilling. (PRC § 3160(j).)


VII. Reporting Website • Presently, operators report their well stimulation activities through FracFocus.org, and up

until now this website has been sanctioned by DOGGR for this purpose.

• SB 4 requires that DOGGR create its own website, which will display the stimulated well’s identifying information and also any required chemical disclosures. This website must be up and running by January 1, 2016.

• The public must be able to easily search for the following information relating to well

stimulation treatments:

o Geographic area o Additive o Chemical constituent o CAS number o Time period o Operator

• From this data, DOGGR is required to develop a report for the Legislature on or before

January 1, 2016 (and annually thereafter), and the report must be made available on DOGGR’s website. The report must include:

o Aggregated data detailing the disposition of any produced water from wells that have undergone well stimulation treatments.

o Aggregated data describing the formations where wells have received well stimulation treatments, including the range of safety factors used and fracture zone lengths.

o Number of emergency responses to a spill or release associated with a well stimulation treatment.

o Aggregated data detailing the number of times trade secret information was not provided to the public, by county and by each company, in the preceding year.

o Data detailing the loss of well and well casing integrity in the preceding year for wells that have undergone well stimulation treatment.

o For comparative purposes, data detailing the loss of well and well casing integrity in the preceding year for all wells.

o Cause of each well and well casing failure, if known. o Number of spot check inspections conducted, including the number of

inspections where the composition of well stimulation fluids was verified, and the results of those inspections.

o Number of well stimulation treatments witnessed by DOGGR. o Number of enforcement actions associated with well stimulation treatments,

including, but not limited to, notices of deficiency, notices of violation, and civil or criminal enforcement actions, and any penalties assessed.


VIII. Independent Study • SB 4 calls for an independent scientific study (“study”) of well stimulation activities

commissioned by CNRA that will go beyond, and is separate from, the DOGGR EIR on well stimulation activities. The study is meant to evaluate the real and potential hazards and risks that well stimulation treatments pose to natural resources, public health, and safety. CNRA chose the California Council on Science and Technology and LBNL to conduct the independent scientific assessment.

• The study achieves the following:

o “Follow[s] the well-established standard protocols of the scientific profession,

including, but not limited to, the use of recognized experts, peer review, and publication.” (PRC § 3160(a)(1).)

o Identifies areas with existing and potential conventional and unconventional oil and gas reserves where well stimulation treatments are likely to spur or enable oil and gas exploration and production.

o Evaluates all aspects and effects of well stimulation treatments, including: Well stimulation treatment. Additive and water transportation to and from the well site. Mixing and handling of the well stimulation treatment fluids and additives

onsite. Use and potential for use of nontoxic additives, and the use or reuse of

treated or produced water in well stimulation treatment fluids, flowback fluids and handling, treatment, and disposal of flowback fluids and other materials generated by the treatment.

Potential for use of recycled water in well stimulation treatments, including appropriate water quality requirements and available treatment technologies.

o Reviews and evaluates acid matrix stimulation treatments, including: Range of acid volumes applied per treated foot and total acid volumes

used in treatments. Types of acids, acid concentration, and other chemicals used in the

treatments. o Considers environmental effects of the treatment, such as:

Atmospheric emissions. Potential degradation of air quality and potential impacts on wildlife,

native plants, and habitat (including habitat fragmentation). Potential water and surface contamination. Potential noise pollution. Induced seismicity. Ultimate disposition, transport, transformation, and toxicology of well

stimulation treatments. o Identifies and evaluates the geologic features present in the vicinity of a well,

including the well bore, that should be taken into consideration in the design of a proposed well stimulation treatment.

o Includes a hazard assessment and risk analysis addressing occupational and environmental exposures to well stimulation treatments, and the corresponding


impacts on public health and safety with the participation of the Office of Environmental Health Hazard Assessment.

A. Volume I

• Volume I of the study was released on January 14, 2015 and is titled “An Independent Scientific Assessment of Well Stimulation Technologies in California: Well Stimulation Technologies and their Past, Present, and Potential Future Use in California.”

• This volume provides an overview of well stimulation treatment in California. Broadly, the study concludes that “[a]lmost all hydraulic fracturing in California occurs in the San Joaquin Basin in wells that produce primarily oil. We expect this practice to continue as the main use of well stimulation in the state for the foreseeable future.” (Executive Summary, at p. iii.)

• The findings of Volume I are summarized as follows:

o Almost all stimulation activity is onshore fracking. o 96% of all fracking occurs in the San Joaquin Basin. o Since 2001, fracking has been used in 20% of all oil and gas production in

California.

B. Future Volumes

• Volumes II and III of the study will be released on July 1, 2015, pursuant to requirements

under SB 4.

• Volume II is titled “Generic and Potential Environmental Impacts of Well Stimulation Treatment.” It will evaluate the potential impacts of well stimulation treatment on water, air quality, greenhouse gas emissions, induced seismicity, ecology, traffic, and noise.

• Volume III is titled “Case Studies with Selected Evaluations of Environmental and Public Health Risk,” and will analyze certain regions of California in depth in case studies to assess environmental issues and qualitative hazards. Volume III will assess the issues of specific regions using the results of Volumes I and II.

o The case studies will analyze the following regions: Los Angeles, San Joaquin Valley, Monterey, and offshore production.

SB 4 Well Stimulation Treatment Regulations

Final Text of Regulations Page 1 of 28

SB 4 WELL STIMULATION TREATMENT REGULATIONS

FINAL TEXT OF REGULATIONS

Added text is shown in underline:

CHAPTER 4. DEVELOPMENT, REGULATION, AND CONSERVATION OF OIL AND GAS RESOURCES

Subchapter 2. Environmental Protection

Article 1. General.

1751. Single-Project Authorization. (a) For the purposes of this section, “single-project authorization” shall mean a single Division approval for multiple applications for permits to perform well stimulation treatments under Public Resources Code section 3160, subdivision (d), and/or notices of intent to drill or rework wells under Public Resources Code section 3203. (b) A request for a single-project authorization shall include: (1) Identification of each of the applications and notices that are part of the request; (2) The applications and notices that comprise the request for a single-project authorization. (c) The Division will review each application and notice submitted for single-project authorization in the same manner as it would had the application or notice been submitted individually. A single-project authorization shall specify which of the application or notices have been approved and the conditions of each approval. (d) Operations approved by a single-project authorization that have not commenced within one year shall not be commenced without first obtaining a new approval for those operations from the Division. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3160 and 3203, Public Resources Code.



Article 2. Definitions 1761. Well Stimulation and Underground Injection Projects. (a) The following definitions are applicable to this subchapter: (1) “Well stimulation treatment” means a treatment of a well designed to enhance oil and gas production or recovery by increasing the permeability of the formation. (A) Well stimulation is a short term and non-continual process for the purposes of opening and stimulating channels for the flow of hydrocarbons. Examples of well stimulation treatments include hydraulic fracturing, acid fracturing, and acid matrix stimulation. (i) Except for operations that meet the definition of “underground injection project” under Section 1761(a)(2), a treatment at pressure exceeding the formation fracture gradient shall be presumed to be a well stimulation treatment unless it is demonstrated to the Division’s satisfaction that the treatment, as designed, does not enhance oil and gas production or recovery by increasing the permeability of the formation. (ii) Except for operations that meet the definition of “underground injection project” under Section 1761(a)(2), a treatment that involves emplacing acid in a well and that uses a volume of fluid equal to or greater than the Acid Volume Threshold for the operation shall be presumed to be a well stimulation treatment unless it is demonstrated to the Division’s satisfaction that the treatment, as designed, does not enhance oil and gas production or recovery by increasing the permeability of the formation. For the purpose of determining whether a treatment is greater than the Acid Volume Threshold, the volume of fluid used in a treatment does not include the volume fluid used for a pre-flush that does not use acid or an overdisplacement that does not use acid. (iii) The searchable index maintained by the Division under Section 1777.4(e) will clearly indicate each submission for a treatment that exceeds the formation fracture gradient or emplaces acid in the well and exceeds the Acid Volume Threshold, and such submissions shall include the Division’s determination that the treatment is not a well stimulation treatment and the basis for the determination. (B) Well stimulation treatment does not include routine well cleanout work; routine well maintenance; routine treatment for the purpose of removal of formation damage due to drilling; bottom hole pressure surveys; routine activities that do not affect the integrity of the well or the formation; the removal of scale or precipitate from the perforations, casing, or tubing; a gravel pack treatment that does not exceed the formation fracture gradient; or a treatment that involves emplacing acid in a well and that uses a volume of fluid that is less than the Acid Volume Threshold for the operation and is below the formation fracture gradient.



(2) “Underground injection project” or “subsurface injection or disposal project” means sustained or continual injection into one or more wells over an extended period in order to add fluid to a zone for the purpose of enhanced oil recovery, disposal, or storage. Examples of underground injection projects include waterflood injection, steamflood injection, cyclic steam injection, injection disposal, and gas storage projects. (3) “Acid Volume Threshold” means a volume, in US gallons, per treated foot of well stimulation treatment, calculated as follows:

(((Size of the drill bit diameter in inches that was used in the treated zone / 2 + 36 inches)2 - (bit diameter in inches / 2)2) x 3.14159 x 12 inches x treated formation porosity) / 231 (inches3/gallon).

The lowest calculated or measured porosity in the zone of treated formation shall be the treated formation porosity used for calculating the Acid Volume Threshold. (b) Well stimulation treatments and underground injection projects are two distinct kinds of oil and gas production processes. Unless a regulation expressly addresses both well stimulation and underground injection projects, (1) Regulations regarding well stimulation treatments do not apply to underground injection projects; and (2) Regulations regarding underground injection projects do not apply to well stimulation. (3) If well stimulation treatment is done on a well that is part of an underground injection project, then regulations regarding well stimulation treatment apply to the well stimulation treatment and regulations regarding underground injection projects apply to the underground injection project operations. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3157 and 3160, Public Resources Code.

Article 3. Requirements 1777.4. Well Maintenance and Cleanout History. (a) Unless already addressed by an approved aggregation plan under subdivision (d), within 60 days of completing an operation on a well that involves emplacing fluid containing acid in the well, the operator shall submit the following information to the Division for inclusion in the well history: (1) A description of the nature and purpose of the operation;



(2) The volume of fluid emplaced in the well in the course of the operation, including specification of the gallons per treated foot; and (3) Calculation of the Acid Volume Threshold for the operation. (b) Within 60 days of completing an operation on a well that involves application of pressure to the formation that exceeds formation pore pressure, the operator shall submit the following information with the Division for inclusion in the well history: (1) A description of the nature and purpose of the operation; and (2) The bottom-hole pressure applied to the formation; and (3) Calculations used to determine bottom-hole pressure, if any. (c) This section does not apply to the following operations: (1) Well stimulation treatments regulated under Article 4 of this subchapter; (2) Underground injection project operations regulated under Sections 1724.6 through 1724.10 or Sections 1748 through 1748.3; (3) Drilling, redrilling, reworking, plugging, or abandonment operations permitted under Public Resources Code section 3203 or 3229; and (4) Replacement of equipment in the well, including but not limited to packers, pumps, and tubing. (d) Subject to approval by the Division, an operator may propose a plan for submitting aggregated information regarding a specific type of repeated operation that involves emplacing fluid containing acid in the well yet clearly does not meet the definition of a well stimulation treatment. An aggregation plan shall provide for annual submission of the aggregated volume of fluid containing acid used in an oilfield for the type of operation, a list of the wells subject to the operation during the year, and, if the operation is performed multiple times on the same well, the number of time the operation was performed on each well. An aggregation plan may be terminated at the Division’s sole discretion. (e) The Division will maintain a searchable index of submissions made under this section, and the index will be made available on the Division’s public internet website. The searchable index will clearly indicate each submission for a treatment that exceeds the formation fracture gradient or emplaces acid in the well and exceeds the Acid Volume Threshold, and such submissions shall include the Division’s determination that the treatment is not a well stimulation treatment and the basis for the determination. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3160 and 3213, Public Resources Code.



Article 4. Well Stimulation Treatments 1780. Purpose, Scope, and Applicability. (a) The purpose of this article is to set forth regulations governing well stimulation treatments, as defined in Section 1761(a)(1), for wells located both onshore and offshore. (b) Well stimulation treatments are not subsurface injection or disposal projects and are not subject to Sections 1724.6 through 1724.10 or Sections 1748 through 1748.3. This article does not apply to underground injection projects. If well stimulation treatment is done on a well that is part of an underground injection project, then regulations regarding well stimulation treatment apply to the well stimulation treatment and regulations regarding underground injection projects apply to the underground injection project operations. (c) For purposes of this article, a well stimulation treatment commences when well stimulation fluid is pumped into the well, and ends when the well stimulation treatment equipment is disconnected from the well. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1781. Definitions. The following definitions shall govern this article: (a) “Acid fracturing” means a well stimulation treatment that, in whole or in part, includes the pressurized injection of acid into an underground geologic formation in order to fracture the formation, thereby causing or enhancing, for the purposes of this division, the production of oil or gas from a well. (b) “Acid matrix stimulation treatment” means an acid treatment conducted at pressures lower than the applied pressure necessary to fracture the underground geologic formation. (c) “Acid well stimulation treatment” means a well stimulation treatment that uses, in whole or in part, the application of one or more acids to the well or underground geologic formation. The acid well stimulation treatment may be at any applied pressure and may be used in combination with hydraulic fracturing treatments or other well stimulation treatments. Acid well stimulation treatments include acid matrix stimulation treatments and acid fracturing treatments. (d) “Acid stimulation treatment fluid” means one or more base fluids mixed with physical and chemical additives for the purpose of performing an acid well stimulation treatment.



(e) “Additive” means a substance or combination of substances added to a base fluid for purposes of preparing well stimulation treatment fluid, including, but not limited to, acid stimulation treatment fluid and hydraulic fracturing fluid. An additive may serve additional purposes beyond the transmission of hydraulic pressure to the geologic formation. An additive may be of any phase and may include proppants. (f) “ADSA” or “axial dimensional stimulation area” means the estimated axial dimensions, expressed as maximum length, width, height, and azimuth, of the area(s) stimulated by a well stimulation treatment. (g) “Base fluid” means the continuous phase fluid used in the makeup of a well stimulation treatment fluid. The continuous phase fluid may include, but is not limited to, water, and may be a liquid or a hydrocarbon or nonhydrocarbon gas. A well stimulation treatment may use more than one base fluid. (h) "Chemical Disclosure Registry" means the chemical registry Internet Web site known as fracfocus.org developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. (i) “Designated Contractor for Water Sampling” means an independent third-party person or entity designated by the State Water Board to sample water well and surface water in accordance with Public Resources Code section 3160, subdivision (d)(7). (j) “Flowback fluid” means the fluid recovered from the treated well before the commencement of oil and gas production from that well following a well stimulation treatment. The flowback fluid may include materials of any phase. (k) “Hydraulic fracturing” means a well stimulation treatment that, in whole or in part, includes the pressurized injection of hydraulic fracturing fluid into an underground geologic formation in order to fracture the formation, thereby causing or enhancing, for the purposes of this division, the production of oil or gas from a well. (l) “Hydraulic fracturing fluid” means one or more base fluids mixed with physical and chemical additives for the purpose of hydraulic fracturing. (m) “Independent third party” means a person or entity responsible to an operator, but who is not an employee of the operator, is not under the ownership or direct control of the operator, and does not have a direct financial interest in the production activities of the operator. (n) “Proppants” means materials inserted or injected into the underground geologic formation that are intended to prevent fractures from closing. (o) “Regional Water Board” means the Regional Water Quality Control Board with jurisdiction over the location of a well subject to well stimulation treatment. (p) “State Water Board” means the State Water Resources Control Board. (q) “Surface property owner” means the owner of real property as shown on the latest equalized assessment roll or, if more recent information than the information



contained on the assessment roll is available, the owner of record according to the county assessor or tax collector. (r) “Tenant” means a person or entity with a possessory interest in and right to occupy a legally recognized parcel, or portion thereof. (s) “Well stimulation treatment fluid” means a base fluid mixed with physical and chemical additives, which may include acid, for the purpose of a well stimulation treatment. A well stimulation treatment may include more than one well stimulation treatment fluid. Well stimulation treatment fluids include, but are not limited to, hydraulic fracturing fluids and acid stimulation treatment fluids. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3150, 3151, 3152, 3153, 3154, 3156, 3158, 3159 and 3160, Public Resources Code. 1782. General Well Stimulation Treatment Requirements. (a) When a well stimulation treatment is performed, the operator shall ensure that all of the following conditions are continuously met: (1) Casing is sufficiently cemented or otherwise anchored in the hole in order to effectively control the well at all times; (2) Geologic and hydrologic isolation of the oil and gas formation are maintained during and following the well stimulation treatment; (3) All potentially productive zones, zones capable of over-pressurizing the surface casing annulus, or corrosive zones be isolated and sealed off to the extent that such isolation is necessary to prevent vertical migration of fluids or gases behind the casing; (4) All well stimulation treatment fluids are directed into the zone(s) of interest; (5) The wellbore’s mechanical integrity is tested and maintained; (6) The well stimulation treatment fluids used are of known quantity and description for reporting and disclosure as required pursuant to this article; and (7) The well stimulation treatment will not damage the well casing, tubing, cement, or other well equipment, or would not otherwise cause degradation of the well’s mechanical integrity during the treatment process; (8) Well breach occurring during well stimulation treatment will be reported as required in Section 1785, subdivision (d); and (9) Well stimulation treatment operations are conducted in compliance with all applicable requirements of the Regional Water Board, the Department of Toxic Substances Control, the Air Resources Board, the Air Quality Management District or Air Pollution Control District, the Certified Unified Program Agency, and any other local agencies with jurisdiction over the location of the well stimulation activities.



(b) In addition to specific methods set forth in these regulations, to achieve the objectives of this section, the operator shall follow all applicable well construction requirements, use good engineering practices, and employ best industry standards. (c) The operator shall terminate well stimulation treatment as soon as it is safe to do so after it determines, or is informed by the Division, that any of the conditions of subdivision (a) are not being met. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1783. Application for Permit to Perform Well Stimulation Treatment. (a) A well stimulation treatment or repeat well stimulation treatment shall not commence without a valid permit approved by the Division and shall be done in accordance with the conditions of the Division’s approval. All well stimulation treatment permits approved by the Division shall include the condition that the well stimulation treatment shall not commence until the State Water Board or the Regional Water Board has provided written approval that the well stimulation treatment is covered under Water Code section 10783. (b) An application for a permit to conduct well stimulation operations shall include all of the information listed in Section 1783.1 and shall be submitted electronically to the Division on a digital form specified by the Division and available on the Division’s public internet Web site at http://www.conservation.ca.gov/DOG/Pages/Index.aspx. (c) Upon receipt of a complete application for a permit to conduct well stimulation treatment, the Division will provide a copy of the permit application, including information in the application designated as trade secret or confidential, to the Regional Water Board, the Department of Toxic Substances Control, the Air Resources Board, and the local air district where the well stimulation treatment may occur, provided that the manner and timing of providing copies of permit applications has been specified in a written agreement between the Division and the receiving agency. (d) The operator shall notify the Division at least 72 hours prior to commencing well stimulation so that Division staff may witness. Between three and fifteen hours prior to commencing, the operator shall confirm with the Division that the well stimulation treatment is proceeding. Upon receipt of 72-hour notice from an operator, the Division will relay the notice to the Regional Water Board, the Department of Toxic Substances Control, the Air Resources Board, and the local air district where the well stimulation treatment may occur, provided that the manner and timing of relaying the notice has been specified in a written agreement between the Division and the receiving agency.



(e) If a well is drilled, redrilled, or reworked after the Division approves a permit for a well stimulation treatment on the well, then, when providing the 72-hour notice under subdivision (d), the operator shall indicate what, if any, variance there was from the original notice of intent to drill, redrill, or rework the well. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1783.1. Contents of Application for Permit to Perform Well Stimulation Treatment. (a) An application for a permit to perform a well stimulation treatment shall include the following: (1) Operator’s name; (2) Name and telephone number of person filing the form; (3) Name of person to contact with technical questions regarding operations; (4) Telephone number and email address of person to contact with technical questions regarding operations; (5) Lease name and number of the well; (6) Location of the well, submitted as a six-digit decimal degrees, non-projected, Latitude and Longitude, in the Geographic Coordinate System (GCS) NAD83. (7) API number assigned to the well by the Division; (8) Type of well; (9) Name of the oil field; (10) County in which the well is located; (11) The estimated two-week time period during which the well stimulation treatment is planned to occur; (12) Estimated measured and estimated true vertical depth of the well, and a description of the wellbore path that is specific enough to identify the location of the well stimulation treatment; (13) Formation name and vertical depth of the top and bottom of the productive horizon where well stimulation treatment will occur; (14) The maximum number of stages in the well stimulation treatment; (15) For each stage of the well stimulation treatment, the estimated measured and estimated true vertical depth of the planned interval of the well stimulation treatment on the well bore; (16) The ADSA for each stage; (17) For each stage of the well stimulation treatment, the anticipated volume, rate, and pressures of fluid to be injected;



(18) Identification of all wells that have previously been subject to well stimulation treatment in the same production horizon within the area of twice the ADSA; (19) Identification of where in the operator’s Spill Contingency Plan handling of well stimulation fluid and additives has been addressed; (20) The operator’s plan for completing the cement evaluation required under Section 1784.2(a), or a request for approval of an alternate cement evaluation plan under Section 1784.2(c); (21) The information required for the well stimulation treatment area analysis under Section 1784(a); (22) The well stimulation treatment design required under Section 1784(b); (23) A water management plan that includes all of the following: (A) An estimate of the amount of water to be used in the treatment; (B) An estimate of water to be recycled following the well stimulation treatment; (C) A description of how and where the water from a well stimulation treatment will be recycled, including a description of any treatment or reclamation activities to be conducted prior to recycling or reuse; (D) The anticipated source of the water to be used in the treatment, including any of the following: (i) The well or wells, if commingled, from which the water will be produced or extracted; (ii) The water supplier, if it will be purchased from a supplier; (iii) The point of diversion of surface water; and (E) The anticipated disposal method that will be used for the recovered water in the flowback fluid from the treatment that is not produced water that would be reported pursuant to Section 3227; (24) A description of anticipated procedures to comply with the Hazardous Waste Control Law (Health and Safety Code §§ 25100 et seq.) and implementing regulations pertaining to the activities and information provided under this article; (25) The anticipated source, amount, and composition of the base fluids to be used in the treatment, including pH, flash point, and any constituents listed in California Code of Regulations, title 22, section 66261.24, subdivision (a)(2)(A) and (B); (26) The estimated amount of treatment-generated waste materials that are not addressed by the water management plan, and the anticipated disposal method for the waste materials; (27) Documentation from either the State Water Board or the Regional Water Board that the well subject to the well stimulation treatment is covered by a regional groundwater monitoring program pursuant to Water Code section 10783, subdivision (h)(1), or indication that the operator is working with the State Water Board or the



Regional Water Board to ensure that the well subject to well stimulation treatment is covered in accordance with Water Code section 10783; (28) A complete list of the names, Chemical Abstract Service numbers, and estimated concentrations, in percent by mass, of each and every chemical constituent of the well stimulation fluids anticipated to be used in the treatment (if a Chemical Abstract Service number does not exist for a chemical constituent, another unique identifier may be used, if available); (29) Whether it is anticipated that radiological components or tracers will be injected during the well stimulation treatment; (30) The State Clearinghouse Number or other identification of all documents prepared under the California Environmental Quality Act that relate to the proposed well stimulation treatment; and (31) Other information as requested by the Division. (b) A claim of trade secret protection for the information required under this section shall be handled in the manner specified under Public Resources Code section 3160, subdivision (j). (c) Notwithstanding any claim of trade secret protection, the Division shall not approve as complete an application for a permit to perform a well stimulation treatment unless all of the information specified in this paragraph has been provided to the Division. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code; Section 10783, Water Code. 1783.2 Neighbor Notification, Duty to Hire Independent Third Party. (a) The operator of any oil or gas well receiving a permit to conduct well stimulation treatment from the Division shall hire an independent third party to perform the following actions: (1) Identify surface property owners and tenants, other than the operator of the well subject to well stimulation treatment, of legally recognized parcels of land situated within a 1500-foot radius of the wellhead receiving well stimulation treatment, or within 500 feet of the surface representation of the horizontal path of the subsurface parts of such well; (2) Provide all surface property owners and tenants so identified, or their duly authorized agents, with neighbor notification that shall include and must be limited to both of the following: (A) A copy of the approved well stimulation treatment permit; and (B) A completed Well Stimulation Treatment Neighbor Notification Form (7/15 version), hereby incorporated by reference; and



(3) Compile and mail to the Division a declaration of notice pursuant to subdivision (i). (b) Neighbor notification is not required if the independent third party determines that there are no surface property owners or tenants as described in subdivision (a)(1). (c) A well stimulation treatment subject to the neighbor notification requirements of this section shall not commence until 30 calendar days after all required notices are provided, as defined in subdivision (e). If the independent third party has made a determination under subdivision (b) that neighbor notification is not required, then the well stimulation treatment shall not commence until at least 72 hours after the operator provides the Division with a signed written statement from the independent third party certifying that determination. (d) The notice required under subdivision (a)(2) may be given by any of the following means: (1) Personal delivery; (2) Overnight delivery by an express service carrier; (3) Registered, certified, or express mail; (4) Electronic mail or facsimile, but only if the person to be notified has agreed in writing prior to the notice to accept notice by electronic mail or facsimile. The prior written agreement shall contain the email address or facsimile number of the person to be notified, which address or number shall be used until otherwise instructed by the person to be notified. (e) The notice required under this section is deemed to have been provided at the following times: (1) If given by personal delivery, when delivered; (2) If given by overnight delivery by an express service carrier, 2 calendar days after the notice is deposited with the carrier; (3) If given by registered, certified or express mail, 5 calendar days after the notice is deposited in the mail; (4) If given by electronic mail or facsimile, 2 calendar days after the notice is transmitted. (f) Any notice that is given to surface property owners by overnight delivery by an express service carrier or by registered, certified, or express mail shall be addressed to the address of record for that person, or his/her duly authorized agent, as shown on the latest equalized assessment roll, county assessor or tax collector records. In addition, if the owner’s address of record is different from the physical address of the property within the notification radius, and if that property is capable of receiving mail, a copy of the notice shall also be delivered or mailed to that property.



(g) Notice to a tenant shall not be considered deficient for lack of a named individual. Notice to any tenant can be addressed generally to “current resident,” “current occupant,” or such other non-specific addressee, as may be appropriate. (h) In addition to the means set forth in subdivision (d), tenants of a residential or commercial property that has 10 or more individual units for lease may be provided notice by leaving the copy of the permit and Well Stimulation Treatment Neighbor Notification Form at each individual residential or commercial unit within the residential or commercial property between the hours of eight in the morning and six in the evening, with some person not less than 18 years of age who provides a signature acknowledging receipt of the notice. Notice given in accordance with this subdivision shall be treated as a personal delivery for purposes of determining when such notice is deemed provided under subdivision (e). (i) The independent third party hired by the operator to provide notice under this section shall, within 5 calendar days of all required notices having been provided for a well stimulation treatment, submit to the Division in a text-searchable electronic format, directed to the email address “[email protected]” a declaration of notice that provides all of the following: (1) Identifying information for the well receiving well stimulation treatment and the operator of that well; (2) A list of all notices provided, itemized by the County Assessor’s Parcel Number for the property within the notification radius that corresponds to each notice provided; (3) The name of each surface property owner and tenant notified, or indication that the addressee was unspecified, as allowed under subdivision (g); (4) The specific method of providing each notice, including the physical or electronic address to which each notice was sent; (5) The date each notice was personally delivered, deposited with an express carrier or mail service, or transmitted electronically; (6) The date each notice is deemed to have been provided in accordance with subdivision (e); and (7) Representative copies of the completed Well Stimulation Treatment Neighbor Notification Form that were provided. (j) If any additional surface property owners or tenants are notified after the original declaration of notice is provided to the Division, then the independent third party shall within 5 calendar days submit to the Division a supplemental declaration of notice that contains the information listed in subdivision (i). (k) Each independent third party hired by the operator to provide notice under this section shall retain copies of all of the following:



(1) A representative copy of the well stimulation treatment permits provided to surface property owners and tenants; (2) Representative copies of the completed Well Stimulation Treatment Neighbor Notification Form provided to surface property owners and tenants; (3) Documentation demonstrating that the notices required under this section were provided, including documentation from the United States Postal Service or express service carrier such as proof of payment records, return receipts, delivery confirmations, and tracking records; and (4) Records relied upon to identify surface property owners and tenants who must receive notice under this section. (l) Records specified for retention under subdivision (k) shall be made available to the Division promptly upon request, and shall be maintained for at least 5 years from the date that the declaration of notice required under subdivision (h) is submitted to the Division. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1783.3 Availability of Water Testing, Request for Water Testing. (a) A surface property owner notified pursuant to Section 1783.2 may request water quality testing on any existing water well or surface water located on the parcel that is suitable for drinking or irrigation purposes. (b) When a surface property owner makes a request for water quality testing on any water well or surface water pursuant to subdivision (a), sampling and testing shall be in accordance with the following: (1) Water quality testing shall be performed by a Designated Contractor for Water Sampling. (2) Water quality testing shall be conducted in accordance with the standards and protocols specified by the State Water Board pursuant to Public Resources Code section 3160, subdivision (d)(7)(B). (3) Water quality testing shall include baseline measurements prior to the commencement of the well stimulation treatment, and follow-up measurements after the well stimulation treatment is completed. (4) Any written request for water testing shall specify whether the surface property owner elects to select the Designated Contractor for Water Sampling and communicate directly with the contractor to arrange for testing, or, alternatively, elects to have the operator select the Designated Contractor for Water Sampling and arrange for testing.



(A) If the surface property owner elects to have the operator select and contract with the Designated Contractor for Water Sampling, the well stimulation treatment may not commence until the requested baseline water sampling is completed, provided that the request is made in writing and postmarked to the operator within 20 calendar days from the date notice is provided under section 1783.2(e) and the surface property owner makes necessary accommodations to enable the collection of baseline measurements without undue delay. (B) If the surface property owner elects to select the Designated Contractor for Water Sampling and communicate directly with the contractor to arrange for testing, the surface property owner is responsible for scheduling baseline measurements to be taken prior to the commencement of the well stimulation treatment. The operator shall immediately inform the surface property owner when the well stimulation treatment is completed so that follow-up measurements can be collected. (5) The operator shall pay for all reasonable costs of water quality testing under this subdivision regardless of whether the surface property owner or the operator selects and coordinates with the Designated Contractor for Water Sampling. (6) The results of any water quality testing shall be provided to the Division, the appropriate Regional Water Board, the State Water Board, the surface property owner, and any tenant notified pursuant to Section 1783.2 to the extent authorized by the tenant’s lease. (7) The Regional Water Board shall be notified at least two working days prior to collecting a sample under this section so that Regional Water Board staff may witness the sampling. (c) Water quality data collected under subdivision (b) shall be submitted to the Regional Water Board in an electronic format that follows the guidelines detailed in California Code of Regulations, title 23, chapter 30. (d) A tenant notified pursuant to Section 1783.2 that has lawful use of any existing water well or surface water located on the parcel that is suitable for drinking or irrigation purposes may independently contract with a Designated Contractor for Water Sampling for water quality testing of such water. A tenant that contracts for such testing is responsible for scheduling baseline measurements to be taken prior to the commencement of the well stimulation treatment. A tenant that contracts for water testing pursuant to this section is not entitled to reimbursement from the operator for the costs of such testing. If the operator is made aware of the tenant’s contracting for water quality testing, then the operator shall immediately notify the tenant when the well stimulation treatment is completed so that follow-up measurements can be collected.



NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1784. Well Stimulation Treatment Area Analysis and Design. (a) As part of an application for a permit to conduct well stimulation, the operator shall conduct a well stimulation treatment area analysis to ensure the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation treatment. (1) The operator shall utilize modelling, or other analysis, approved by the Division that will effectively estimate the ADSA. The operator shall submit the ADSA and information supporting the modeling or analysis to the Division. (2) The well stimulation treatment area analysis shall include identification and review of all well bores located completely or partially within two times the ADSA to ensure the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation. The Division may allow modification of the review area based on modeling and analysis provided by the operator that demonstrates geologic and hydrologic isolation of the oil and gas formation during and following well stimulation treatment. For each well bore within the review area the well stimulation treatment area analysis shall include the following information: (A) Casing diagrams clearly indicating: (i) Sizes and weights of casing; (ii) Depths of shoes, stubs, and liner tops; (iii) Depths of perforation intervals, water shutoff holes, cement port, cavity shots, cuts, casing damage, and top of junk or fish left in well; (iv) Diameter and depth of hole; (v) Cement plugs inside casings, including top and bottom of cement plug, with indication of method of determining; (vi) Cement fill behind casings, including top and bottom of cement fill, with indication of method of determining; (vii) Type and weight (density) of fluid between cement plugs; (viii) Depths and names of the formations, zones, and sand markers penetrated by the well, including the top and bottom of the zone where well stimulation treatment will occur; (ix) All steps of cement yield and cement calculations performed; (x) All information used to calculate the cement slurry (volume, density, yield), including but not limited to, cement type and additives, for each cement job completed in each well; and (xi) All of the information listed in this paragraph for all previous redrilled or sidetracked well bores. (B) For directionally drilled wells, a wellbore path giving both inclination and azimuth measurements.



(3) The well stimulation treatment area analysis shall include a review of all geologic features, including known faults (active or inactive), within five times the ADSA to ensure the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation. For all such geologic features, the operator shall provide: (A) An evaluation of whether the geologic feature may act as a migration pathway for injected fluids or displaced formation fluids; and (B) An assessment of the risk that the well stimulation treatment will communicate with the geologic feature. (4) If five times the ADSA extends beyond the productive horizon being evaluated for possible well stimulation treatment, then the well stimulation treatment area analysis shall include a review of the geological formations adjacent to the productive horizon. The operator shall assess the mechanical rock properties, including permeability, relative hardness (using Young's Modulus), relative elasticity (using Poisson's Ratio), and other relevant characteristics of the geological formations to determine whether the geological formations will ensure the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation. (5) The well stimulation treatment area analysis shall include identification of all water within two times the ADSA. (b) Utilizing the well stimulation treatment area analysis conducted pursuant to subdivision (a), the operator shall design the well stimulation treatment so as to ensure that the well stimulation treatment fluids or hydrocarbons do not migrate and remain geologically and hydrologically isolated to the hydrocarbon formation. A well stimulation treatment shall not be designed to employ pressure exceeding 80% of the API rated minimum internal yield on any casing string in communication with the well stimulation treatment. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1784.1. Pressure Testing Prior to Well Stimulation Treatment. (a) The operator shall conduct pressure testing not more than 30 days before commencing well stimulation treatment, but after all operations that could affect well integrity or the integrity of the equipment are complete. Pressure testing shall include the following: (1) All cemented casing strings and all tubing strings to be utilized in the well stimulation treatment operations shall be pressure tested for at least 30 minutes at a pressure equal to at least 100% of the maximum surface pressure anticipated during the well stimulation treatment, but not greater than the API rated minimum internal yield



of the tested casing. The operator shall chart the pressure testing. If during testing, and after equilibrium has been reached, there is a pressure change of 10% or more from the original test pressure, then the operator shall immediately notify the Division, the operator shall provide the Division with copies of the charting of the pressure testing, and the tested casing or tubing shall not be used until the cause of the pressure drop is identified and corrected to the Division’s satisfaction. No casing or tubing shall be used unless it has been successfully tested pursuant to this section. (2) All surface equipment to be utilized for well stimulation treatment shall be rigged up as designed. The pump, and all equipment downstream from the pump, shall be pressure tested at a pressure equal to 125% of the maximum surface pressure anticipated during the well stimulation treatment, but not greater than the manufacturer’s pressure rating for the equipment being tested. If during testing there is a pressure change of 10% or more from the original test pressure, then the operator shall immediately notify the Division, and the tested equipment shall not be used until the cause of the pressure change is identified and corrected to the Division’s satisfaction. No equipment shall be used unless it has been successfully tested pursuant to this section. (b) The operator shall notify the Division at least 24 hours prior to conducting the pressure testing required under subdivision (a) so that Division staff may witness. The charting of pressure testing required under subdivision (a)(1) shall be provided to the Division not less than 12 hours before commencing well stimulation treatment. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1784.2. Cement Evaluation Prior to Well Stimulation Treatment. (a) In advance of conducting well stimulation treatment, but at least 48 hours after cement placement, the operator shall run a radial cement evaluation log or other cement evaluation method that is approved by the Division , and the cement evaluation shall demonstrate the following: (1) The well was and continues to be cemented in accordance with the requirements of Section 1722.4 if it is an onshore well, or Section 1744.3 if it is an offshore well; and (2) The quality of the cement is sufficient to ensure the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation treatment. (b) Documentation of the cement evaluation shall be provided to the Division not less than 72 hours before commencement of the well stimulation treatment. If the Division identifies a concern with the cement evaluation, the well stimulation treatment shall not commence until the concern has been addressed to the Division’s satisfaction.



(c) The Division may approve an alternate cement evaluation plan that waives the requirements of subdivisions (a) and (b) if the Division is satisfied that, based on geologic and engineering information available from previous drilling or producing operations in the area where the well stimulation treatment will occur, well construction and cementing methods have been established that ensure that there will be no voids in the annular space of the well. A request for approval of an alternate cement evaluation plan shall be submitted to the Division as part of the application for a permit to perform well stimulation treatment submitted under Section 1783. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1785. Monitoring During Well Stimulation Treatment Operations. (a) The operator shall continuously monitor and record all of the following parameters during the well stimulation treatment, if applicable: (1) Surface injection pressure; (2) Slurry rate; (3) Proppant concentration; (4) Fluid rate; and (5) All annuli pressures. (b) The operator shall terminate the well stimulation treatment and immediately provide the collected data to the Division if any of the following occurs: (1) A pressure change in the annulus between the tubing or casing through which well stimulation treatment fluid is conducted and the next larger tubular or casing more than 20% or greater than the calculated pressure increase due to pressure and/or temperature expansion; (2) Pressure exceeding 90% of the API rated minimum internal yield on any casing string in communication with the well stimulation treatment, if the pressure testing under Section 1784.1(a)(1) was done at a pressure equal to 100% of the API rated minimum internal yield of the tested casing; (3) Pressure exceeding 80% of the API rated minimum internal yield on any casing string in communication with the well stimulation treatment, if the pressure testing under Section 1784.1(a)(1) was done at a pressure equal to less than 100% of the API rated minimum internal yield of the tested casing; or (4) The operator has reason to suspect a potential breach in the cemented casing strings, the tubing strings utilized in the well stimulation treatment operations, or the geologic or hydrologic isolation of the formation.



(c) If any of the events listed in subdivision (b) occurs, then the operator shall perform diagnostic testing on the well to determine whether a breach has occurred. Diagnostic testing shall be done as soon as is reasonably practical. The Division shall be notified when diagnostic testing is being done so that Division staff may witness the testing. All diagnostic testing results shall be immediately provided to the Division. (d) If diagnostic testing reveals that a breach has occurred, then the operator shall immediately shut-in the well, isolate the perforated interval, and notify the Division and the Regional Water Board with all of the following information: (1) A description of the activities leading up to the well breach. (2) Depth interval of the well breach and methods used to determine the depth interval. (3) An exact description of the chemical constituents of the well stimulation treatment fluid, or of the fluid that is most representative of the fluid composition in the well at the time of the well breach. (e) The operator shall not resume operation of a well that has been shut-in under subdivision (d) without first obtaining approval from the Division. (f) Groundwater quality data submitted under subdivision (d) shall be in an electronic format that follows the guidelines detailed in California Code of Regulations, title 23, chapter 30. (g) If the surface casing annulus is not open to atmospheric pressure, then the surface casing pressures shall be monitored with a gauge and pressure relief device. The maximum set pressure on the relief device shall be the lowest of the following and well stimulation treatment shall be terminated if pressures in excess of the maximum set pressure are observed in the surface casing annulus: (1) A pressure equal to: 0.70 times 0.433 times the true vertical depth of the surface casing shoe (expressed in feet); (2) 70% of the API rated minimum internal yield for the surface casing; or (3) A pressure change that is 20% or greater than the calculated pressure increase due to pressure and/or temperature expansion. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code.



1785.1. Monitoring and Evaluation of Seismic Activity in the Vicinity of Hydraulic Fracturing. (a) From commencement of hydraulic fracturing until 10 days after the end of hydraulic fracturing, the operator shall monitor the California Integrated Seismic Network for indication of an earthquake of magnitude 2.7 or greater occurring within a radius of five times the ADSA. (b) If an earthquake of magnitude 2.7 or greater is identified under subdivision (a), then the following requirements shall apply: (1) The operator shall immediately notify the Division and inform the Division when the earthquake occurred relative to the hydraulic fracturing operations. (2) The Division, in consultation with the operator and the California Geological Survey, will conduct an evaluation of the following: (A) Whether there is indication of a causal connection between the hydraulic fracturing and the earthquake; (B) Whether there is a pattern of seismic activity in the area that correlates with nearby hydraulic fracturing; and (C) Whether the mechanical integrity of any active well within the radius specified in subdivision (a) has been compromised. (3) No further hydraulic fracturing shall be done within the radius specified in subdivision (a) until the Division has completed the evaluation under subdivision (b)(2) and is satisfied that hydraulic fracturing within that radius does not create a heightened risk of seismic activity. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1786. Storage and Handling of Well Stimulation Treatment Fluids and Wastes. (a) Operators shall adhere to the following requirements for the storage and handling of well stimulation treatment fluid, additives, and produced water from a well that has had a well stimulation treatment: (1) Fluids shall be stored in compliance with the secondary containment requirements of Section 1773.1, except that secondary containment is not required under this section for production facilities that are in one location for less than 30 days. The operator’s Spill Contingency Plan shall account for all production facilities outside of secondary containment and include specific steps to be taken and equipment available to address a spill outside of secondary containment.



(2) Operators shall be in compliance with all applicable testing, inspection, and maintenance requirements for production facilities containing well stimulation treatment fluids. (3) Fluids shall be accounted for in the operator’s Spill Contingency Plan. (4) Fluids shall be stored in containers and shall not be stored in sumps or pits. (5) In the event of an unauthorized release, the operator shall immediately implement the Spill Contingency Plan; notify the Regional Water Board and any other appropriate response entities for the location and the type of fluids involved, as required by all applicable federal, state, and local laws and regulations; and shall perform clean up and remediation of the area, and dispose of any cleanup or remediation waste, as required by all applicable federal, state, and local laws and regulations. (6) Within 5 days of the occurrence of an unauthorized release, the operator shall provide the Division a written report that includes: (A) A description of the activities leading up to the release; (B) The type and volumes of fluid released; (C) The cause(s) of release; (D) Action taken to stop, control, and respond to the release; and (E) Steps taken and any changes in operational procedures implemented by the operator to prevent future releases. (7) Operators shall conduct all activities that relate to storage and management of fluids in compliance with all applicable requirements of the Regional Water Board, the Department of Toxic Substances Control, the Air Resources Board, the Air Quality Management District or Air Pollution Control District, the Certified Unified Program Agency, and any other state or local agencies with jurisdiction over the location of the well stimulation activities. (8) An operator who generates a waste, as defined in Health and Safety Code section 25124 and California Code of Regulations, title 22, section 66261.2, in the course of conducting well stimulation activities, including but not limited to well stimulation treatment fluid, additives, produced water from a well, solids separated from well stimulation treatment fluid, remediation wastes, or any other wastes generated from the processing, treatment or management of these wastes, shall determine if the waste is a hazardous waste by sampling and testing the waste according to the methods set forth in California Code of Regulations, title 22, division 4.5, chapter 11, article 3 (section 66261.20 et seq.), or according to an equivalent method approved by the Department of Toxic Substances Control pursuant to California Code of Regulations, title 22, section 66260.21, except where the operator has determined that the waste is excluded from regulation under California Code of Regulations, title 22, section 66261.4 or Health and Safety Code section 25143.2. Notwithstanding any other section in this article, wastes



that are determined by the operator to be hazardous wastes shall be managed in compliance with all hazardous waste management requirements of the Department of Toxic Substances Control. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1787. Well Monitoring After Well Stimulation Treatment. (a) Operators shall monitor each well that has had a well stimulation treatment as specified in subdivision (d) to identify any indication of a well breach. If monitoring indicates that a well breach may have occurred, then the operator shall perform diagnostic testing on the well to determine whether a breach has occurred. Diagnostic testing shall be done as soon as is reasonably practical. The Division shall be notified when diagnostic testing is being done so that Division staff may witness the testing. All diagnostic testing results shall be immediately provided to the Division. (b) If diagnostic testing reveals that a breach has occurred, then the operator shall immediately shut-in the well, isolate the perforated interval, and notify the Division and the Regional Water Board with all of the following information: (1) A description of the activities leading up to the well breach. (2) Depth interval of the well breach and methods used to determine the depth interval. (3) An exact description of the chemical constituents of the fluid that is most representative of the fluid composition in the well at the time of the well breach. (c) The operator shall not resume operation of a well that has been shut-in under subdivision (b) without first obtaining approval from the Division. (d) Operators shall adhere to the following requirements for a well that has had a well stimulation treatment: (1) The production pressure of the well shall be monitored at least once every two days for the first thirty days after the well stimulation treatment and on a monthly basis thereafter. Information regarding production pressures shall be reported to the Division on a monthly basis. (2) The annular pressures of the well shall be reported to the Division annually, unless it has been demonstrated to the Division’s satisfaction that there are no voids in the annular space. It shall be immediately reported to the Division if annular pressure exceeds 70% of the API rated minimum internal yield or collapse strength of casing, or if surface casing pressures exceed a pressure equal to: 0.70 times 0.433 times the true vertical depth of the surface casing shoe (expressed in feet).



(3) The annular valve shall be kept accessible from the surface or left open and plumbed to the surface with a working pressure gauge unless it has been demonstrated to the Division’s satisfaction that there are no voids in the annular space. (4) A properly functioning pressure relief device shall be installed on the annulus between the surface casing and the production casing, or, if intermediate casing is set, on the annuli between the surface casing and the intermediate casing and the production casing. This requirement may be waived by the Division, if the operator demonstrates to the Division’s satisfaction that the installation of a pressure relief device is unnecessary based on technical analysis and/or operating experience in the area. (5) If a pressure relief device is installed, then all pressure releases from the device shall be immediately reported to the Division. The maximum set pressure of a surface casing pressure relief device shall be the lowest of the following: (A) A pressure equal to: 0.70 times 0.433 times the true vertical depth of the surface casing shoe (expressed in feet); (B) 70% of the API rated minimum internal yield for the surface casing; or (C) A pressure change that is 20% or greater than the calculated pressure increase due to pressure and/or temperature expansion NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106 and 3160, Public Resources Code. 1788. Required Public Disclosures. (a) Except as provided in subdivision (c), within 60 days after the cessation of a well stimulation treatment, the operator shall publicly disclose all of the following information: (1) Operator’s name; (2) API number assigned to the well by the Division; (3) Lease name and number of the well; (4) Location of the well, submitted as a six-digit decimal degrees, non-projected, Latitude and Longitude, in the Geographic Coordinate System (GCS) NAD83. (5) County in which the well is located; (6) Date that the well stimulation treatment occurred; (7) The measured and true vertical depth of the well; (8) Formation name and vertical depth of the top and bottom of the productive horizon where well stimulation treatment occurred; (9) The trade name, supplier, concentration, and a brief description of the intended purpose of each additive contained in the well stimulation fluids used; (10) The total volume of base fluid used during the well stimulation treatment;



(11) Identification of whether the base fluid is water suitable for irrigation or domestic purposes, water not suitable for irrigation or domestic purposes, or a fluid other than water; (12) The source, volume, and specific composition and disposition of all water associated with the well stimulation treatment, including all of the following: (A) The source of the water used as a base fluid for the well stimulation treatment, including any of the following: (i) The well or wells, if commingled, from which the water was produced or extracted; (ii) The water supplier, if purchased from a supplier; (iii) The point of diversion of surface water; (B) Composition of water used as base fluid, including all of the following: total dissolved solids; metals listed in California Code of Regulations, title 22, section 66261.24, subdivision (a)(2)(A); benzene, toluene, ethyl benzene, and xylenes; major and minor cations (including sodium, potassium, magnesium, and calcium); major and minor anions (including nitrate, chloride, sulfate, alkalinity, and bromide); and trace elements (including lithium, strontium, and boron); (C) Specific disposition of water recovered from the well following the well stimulation treatment, including method and location of disposal and, if the recovered water is injected into an injection well, identification of the operator, field, and project number of the injection project; (D) Composition of water recovered from the well following the well stimulation treatment, sampled after a calculated wellbore volume has been produced back but before three calculated wellbore volumes have been produced back, and then sampled a second time after 30 days of production after the first sample is taken, with both samples taken prior to being placed in a storage tank or being aggregated with fluid from other wells; (E) Composition of water recovered from the well following the well stimulation treatment shall be determined by testing the samples taken under paragraph (D) for all of the following: appropriate indicator compound(s) for the well stimulation treatment fluid; total dissolved solids; metals listed in California Code of Regulations, title 22, section 66261.24, subdivision (a)(2)(A); benzene, toluene, ethyl benzene, and xylenes; major and minor cations (including sodium, potassium, magnesium, and calcium); major and minor anions (including nitrate, chloride, sulfate, alkalinity, and bromide); and trace elements (including lithium, strontium, and boron); radium-226, gross alpha-beta, radon 222, fluoride, iron (redox), manganese (redox), H2S (redox), nitrate+nitrite (redox), strontium, thallium, mercury, and methane;



(F) All testing results shall have a cover page briefly describing when and where sampling was done and the results of the testing; (G) Sampling and testing conducted under subdivision (a)(12) is separate from and in addition to any sampling or testing that may be required to make hazardous waste determinations under the requirements of the Department of Toxic Substances Control; (13) Identification of any reuse of treated or untreated water for well stimulation treatments and well stimulation treatment-related activities; (14) The specific composition and disposition of all well stimulation treatment fluids, including waste fluids, other than water; (15) Any radiological components or tracers injected into the well as part of the well stimulation treatment, a description of the recovery method, if any, for those components or tracers, the recovery rate, and specific disposal information for recovered components or tracers; (16) The radioactivity of the recovered well stimulation fluids, and a brief description of the equipment and method used to determine the radioactivity; (17) For each stage of the well stimulation treatment, the measured and true vertical depth of the location of the portion of the well subject to the well stimulation treatment and the extent of the fracturing or other modification, if any, surrounding the well induced by the treatment; (18) The estimated volume of well stimulation treatment fluid that has been recovered; and (19) A complete list of the names, Chemical Abstract Service numbers, and maximum concentration, in percent by mass, of each and every chemical constituent of the well stimulation treatment fluids used. If a Chemical Abstract Service number does not exist for a chemical constituent, the operator may provide another unique identifier, if available. (b) For hydraulic fracturing well stimulation treatments, the operator shall post the information listed in subdivision (a) to the Chemical Disclosure Registry, to the extent that the website is able to receive the information. For all well stimulation treatments, the operator shall provide all of the information listed in subdivision (a) directly to the Division on the Well Stimulation Treatment Disclosure Reporting Form. The Well Stimulation Treatment Disclosure Reporting Form is available on the Division’s public internet website at ftp://ftp.consrv.ca.gov/pub/oil/forms/Oil%26Gas/OG110S.XLSX. The Well Stimulation Treatment Disclosure Reporting Form shall be submitted to the Division in an electronic format, directed to the email address “[email protected]”. The Division will organize the information provided on Well Stimulation Treatment Disclosure Forms in a format, such as a



spreadsheet, that allows the public to easily search and aggregate, to the extent practicable, each type of information disclosed. (c) Except for the information specified in subdivision (a)(1) through (6), operators are not required to publicly disclose information found in a well record that the Division has determined is not public record, pursuant to Public Resources Code section 3234. If information listed in subdivision (a) is not publicly disclosed on this basis, then the operator shall inform the Division in writing, and provide the Division the information that is not being publicly disclosed. The Division will provide the information that is not publicly disclosed to other state agencies as needed for regulatory purposes and in accordance with a written agreement with the other state agency regarding sharing of confidential information. It is the operator’s responsibility to publicly disclose the withheld information in the manner described in subdivision (b) as soon as the information becomes public record under Public Resources Code section 3234. (d) A claim of trade secret protection for the information required to be disclosed under this section shall be handled in the manner specified under Public Resources Code section 3160, subdivision (j). (e) Groundwater quality data reported under this section shall also be submitted to the Regional Water Board in an electronic format that follows the guidelines detailed in California Code of Regulations, title 23, chapter 30. (f) If for any reason information specified in subdivision (a) cannot be collected within 60 days after the cessation of a well stimulation treatment, then the information shall still be publicly disclosed as soon as possible in the manner described in subdivision (b). NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3160 and 3234, Public Resources Code. 1789. Post-Well Stimulation Treatment Report. (a) Within 60 days after the cessation of a well stimulation treatment, the operator shall submit a report to the Division describing: (1) The pressures recorded during monitoring required under Section 1785(a) during the well stimulation treatment; (2) The pressures recorded during the first 30 days of production pressure monitoring under Section 1787(d)(1); (3) The date and time that each stage of the well stimulation treatment was performed; (4) How the actual well stimulation treatment differs from what was anticipated in the well stimulation treatment design that was prepared under Section 1784(b);



(5) How the actual location of the well stimulation treatment differs from what was indicated in the permit application under Section 1783.1(a)(15); and (6) A description of hazardous wastes generated during the well stimulation activities and their disposition, including copies of all hazardous waste manifests used to transport the hazardous wastes offsite to an authorized facility. (b) If information found in a report submitted under this section is found in a well record that the Division has determined is not public record, pursuant to Public Resources Code section 3234, then the Division will provide the information to other state agencies as needed for regulatory purposes and in accordance with a written agreement with the other state agency regarding sharing of confidential information. NOTE: Authority cited: Sections 3013 and 3160, Public Resources Code. Reference: Sections 3106, 3160 and 3215, Public Resources Code.

OG500 Well Stimulation Treatment Neighbor Notification Form (7/15 version) Page 1 of 14

WELL STIMULATION TREATMENT NEIGHBOR NOTIFICATION

NOTICE AND INFORMATION THAT WELL STIMULATION TREATMENT ACTIVITIES

WILL OCCUR AND INFORMATION ON YOUR RIGHTS TO HAVE WATER ON YOUR

PROPERTY TESTED

Under California law, operators of oil and gas wells are required to inform certain neighboring

property owners or tenants before doing a hydraulic fracture treatment (commonly referred to

as “fracking”) or other forms of well stimulation treatment. (See Public Resources Code, §

3160, subd. (d).) This advanced notice may enable neighboring property owners or tenants to

obtain water quality testing – both before and after the well stimulation treatment – for certain

water wells or surface waters located on the property. Property owners may request that the

operator of the oil or gas well arrange and pay for water quality testing, while tenants may

arrange for such testing at their own expense. This Notice provides additional detail about the

well stimulation treatment planned to take place near your property or lease, and also provides

information about water quality testing. If you have questions about this notice please visit the

California Department of Conservation’s website for further information at

http://www.conservation.ca.gov.

Notice of Nearby Well Stimulation Treatment:

You are hereby notified that_____________________________________ [name of operator]

will conduct well stimulation treatment activities at the following well location:

Well: ____________________

API Number: ____________________

Field: ____________________

County: ____________________

Section _____. Township, _____ Range, _____

Any operator of an oil or gas well that intends to perform well stimulation activities at a well

must contract with an independent third party to identify and notify all surface property


owners and tenants within a 1500 foot radius of the wellhead and a 500 foot radius of the

surface representation of the horizontal path of the subsurface parts of such well. (See Public

Resources Code, § 3160, subd. (d)(6).) You are receiving this Notice because you have been

identified as a surface property owner or tenant of the following property:

______________________________________________________________________

[assessor’s parcel number], [county], which is located within or on this radius.

Well stimulation treatment refers to various methods used to enhance oil and gas production

by increasing the permeability of the subsurface oil or gas formation. Well stimulation

treatments may include, but are not limited to hydraulic fracturing treatments and acid well

stimulation treatments.

Timing of Well Stimulation Treatment:

The well operator may not commence well stimulation treatment until thirty (30) calendar days

after you are provided this Notice and a copy of the approved well stimulation permit.

The date this Notice is deemed to have been “provided” depends on the method by which it

was delivered, sent or transmitted to you. Specifically:

If this Notice was delivered to you personally, notice is deemed to have been provided

on the date of delivery.

If this Notice was sent to you by overnight delivery service, notice is deemed to have

been provided two (2) calendar days after this Notice was deposited with the carrier.

If this Notice was sent to you by registered, certified or express mail, notice is deemed

to have been provided five (5) calendar days after this Notice was deposited in the mail.

If this Notice was transmitted to you by electronic mail or facsimile, notice is deemed to

have been provided two (2) calendar days after transmission.

If this Notice was left on the premises with a person of 18 years or older, notice is

deemed to have been provided on the date it was left with such person.


This Notice was:

__ personally delivered

__deposited with an express carrier for overnight delivery

__ deposited in the mail by registered/certified/express mail

__ transmitted by electronic mail or facsimile

__ left on the premises with a person of 18 years or older

On the following date: _________________.

THIS NOTICE IS DEEMED TO HAVE BEEN PROVIDED ON:

_________________

[calculate date based on the schedule described above and in California Code of

Regulations, title 14, section 1783.2, subdivision (d)].

THE EARLIEST DATE WHEN WELL STIMULATION TREATMENT MAY COMMENCE IS:

_________________

[calculate date that is 30 calendar days after the date notice is deemed to have been

provided].


WATER TESTING

You may be entitled to request water quality testing for certain water wells or surface waters

located on the property. Different rules apply depending on whether you are a surface

property owner or a tenant of the property identified in this Notice.

FOR SURFACE PROPERTY OWNERS: If you are the surface property owner of the property

identified in this Notice, you may request water quality testing on any existing water well or

surface water located within your property line that is suitable for drinking or irrigation

purposes. (See Public Resources Code, § 3160, subd. (d)(7)(A).)

_____________________________________ [name of operator] will pay for the testing,

provided it is performed in accordance with standards and protocols of the State Water

Resources Control Board by a Designated Contractor for Water Sampling. The water quality

testing includes testing prior to the well stimulation treatment (“baseline testing”), as well as

testing after the well stimulation treatment has ceased (“follow‐up testing”).

If you are the surface property owner and you elect to request water quality testing, you must

make your request in writing, consistent with the additional directions below, and return it to:

[Operator Contact]

[Operator Street Address]

[City, State, Zip Code]

Or the following email address: __________________

A template form that can be used to make a request for water quality testing is available on the

website of the Division of Oil, Gas and Geothermal Resources

(http://www.conservation.ca.gov/dog).

If you request water quality testing, you must decide whether you would prefer to have

_____________________________________ [name of operator] select the Designated

Contractor for Water Sampling and arrange for that contractor to perform the water testing on

your property, or would rather select the Designated Contractor for Water Sampling and

arrange for such testing yourself. You must indicate your decision on your written request for

water quality testing.

If you decide to have _____________________________________ [name of operator] arrange

for the water testing, _____________________________________ [name of operator] will

contact you to arrange for baseline testing prior to the well stimulation treatment, and again

after the well stimulation treatment has ceased to arrange for follow‐up testing to be done. If


you decide to have _____________________________________ [name of operator] arrange

for the water testing, the well stimulation treatment may not commence until baseline testing

is complete, provided that you make the request within 20 days of receiving this notice and you

make necessary accommodations to enable the performance of baseline testing without undue

delay. You are responsible for providing copies of the results of the water testing to any

tenant(s) on your property, to the extent authorized by the tenant’s lease.

IF YOU WISH TO HAVE _____________________________________ [name of operator] BE

RESPONSIBLE FOR MAKING SURE BASELINE SAMPLING IS COMPLETE BEFORE WELL

STIMULATION TREATMENT BEGINS, YOUR REQUEST FOR WATER QUALITY TESTING MUST BE

POSTMARKED OR TRANSMITTED BY EMAIL NO LATER THAN _________________ [specify the

date that is 20 calendar days after the date identified above as the date this Notice is deemed to

have been provided].

If you decide to arrange for the water testing yourself, you are responsible for scheduling and

taking any other steps necessary to ensure that the Approved Water Quality Contractor

completes baseline testing prior to the commencement of the well stimulation treatment

described in this Notice. _____________________________________ [name of operator] is

not required to delay the well stimulation treatment beyond _________________ [specify the

date identified above as the earliest date upon which the well stimulation treatment may

commence] to allow for baseline testing prior to well stimulation treatment.

_____________________________________ [name of operator] will notify you when well

stimulation treatment has ceased so that you may arrange for follow‐up testing. If you decide

to arrange for the water testing yourself, you are still entitled to reimbursement from

_____________________________________ [name of operator] for the costs of such testing,

provided that the water testing is consistent with the standards and protocols specified by the

State Water Resources Control Board under California Public Resources Code section 3160,

subdivision (d)(7), and provided further that the results of such testing are distributed to all of

the following: (1) the California Department of Conservation, Division of Oil, Gas and

Geothermal Resources; (2) the appropriate Regional Water Quality Control Board having

jurisdiction over your property; and (3) any and all tenant(s) on your property to the extent

authorized by his or her lease. (See Public Resources Code, § 3160, subd. (d)(7)(C).)

IN ORDER FOR WATER QUALITY TESTING TO BE EFFECTIVE, BASELINE SAMPLING MUST BE

COMPLETED BEFORE THE WELL STIMULATION TREATMENT HAS COMMENCED.

FOR TENANTS: If you are the tenant of the property identified in this Notice, you may

independently contract for water quality testing on any existing water well or surface water

located on the property that is suitable for drinking or irrigation purposes, and of which you


have lawful use. (See Public Resources Code, § 3160, subd. (d)(7)(C).) You are not entitled to

reimbursement from _____________________________________ [name of operator] for the

costs of such testing. If you wish to independently contract for the testing of an existing water

well or surface water of which you have lawful use, you are encouraged to use a Designated

Contractor for Water Sampling approved by the State Water Resources Control Board. Please

be advised that you are responsible for scheduling and taking any other steps necessary to

ensure that the baseline testing is completed prior to the commencement of the well

stimulation treatment described in this Notice. _____________________________________

[name of operator] is not required to delay the well stimulation treatment beyond

_________________ [specify the date identified above as the earliest date upon which the well

stimulation treatment may commence] to allow for the baseline testing prior to well stimulation

treatment. Additionally, you are advised to inform

_____________________________________ [name of operator] that you are contracting for

water quality testing, as this will require _____________________________________ [name of

operator] to notify you when the well stimulation treatment has ceased so that you may

arrange for follow‐up testing.

In addition to your ability to independently contract for water quality testing you are also

entitled, to the extent provided in your lease, to receive the results of any water testing that

may be requested by the surface property owner in response to this Notice.

Additional Information:

A list of Designated Contractors for Water Sampling approved by the State Water Resources

Control Board for purposes of the water quality testing described in this Notice is available on

the websites of either the State Water Resources Control Board

(http://www.waterboards.ca.gov/water_issues/programs/groundwater/sb4.shtml) or the

California Department of Conservation, Division of Oil, Gas and Geothermal Resources


If you have any questions related to the matters described in this Notice, please contact

_____________________________________ [name of operator contact] at

_________________________ [direct phone] or _______________________________ [email

address].

You may also contact the California Department of Conservation, Division of Oil, Gas and

Geothermal Resources at (916) 445‐9686 with any questions related to the matters described in

this Notice.


Independent Third Party’s Signature and Contact:

By (signature): _________________________________________________________________

Printed Name: _________________________________________________________________

Address: ______________________________________________________________________

Telephone Number: _____________________________________________________________

Email Address: _________________________________________________________________


AVISO PARA VECINOS SOBRE EL TRATAMIENTO DE

ESTIMULACIÓN DE POZO

AVISO E INFORMACIÓN PARA INFORMAR A LOS VECINOS QUE SE LLEVARÁN A

CABO ACTIVIDADES PARA EL TRATAMIENTO DE ESTIMULACIÓN DE POZO, E

INFORMACIÓN ACERCA DE SU DERECHO A QUE SE SOMETA A PRUEBAS EL AGUA

DE SU PROPIEDAD

De acuerdo con la ley de California, los operadores de pozos de petróleo y gas están obligados a

informar a los dueños o inquilinos de ciertas propiedades vecinas previo a realizar un

tratamiento de fractura hidráulica (que se conoce comúnmente como "fracking") u otros tipos

de tratamiento de estimulación de pozo. (Ver Código de Recursos Públicos, § 3160, subd. (d).)

El presente aviso anticipado podrá permitir que los dueños o inquilinos de las propiedades

vecinas obtengan pruebas de calidad del agua (tanto antes como después del tratamiento de

estimulación de pozo) en ciertos pozos de agua o superficie de agua existente ubicada dentro

de los límites de la propiedad. Los dueños de la propiedad podrán solicitar que el operador del

pozo de petróleo o gas haga los arreglos necesarios y se encargue del pago de las pruebas de

calidad del agua, mientras que los inquilinos deberán enfrentar todos los gastos relacionados

con las pruebas. El presente aviso contiene detalles adicionales acerca del tratamiento de

estimulación de pozo que se llevará a cabo cerca de su propiedad o la propiedad que usted

alquila, y también contiene información acerca de las pruebas de calidad del agua. Si tiene

alguna pregunta acerca del presente Aviso, ingrese en el sitio web del Departamento de

Conservación de California para obtener más información, http://www.conservation.ca.gov.

Aviso de tratamiento de estimulación de pozo cercano:

Por la presente se le informa que _____________________________________ [name of

operator] llevará a cabo actividades de tratamiento de estimulación de pozo en los siguientes

lugares:

Pozo: ____________________

Número de API: ____________________

Campo: ____________________

Condado: ____________________

Sección_____. Barrio _____ Área _____


Cualquier operador de gas o petróleo que desea llevar a cabo actividades de estimulación de

pozo en un determinado pozo deberá contratar a un tercero independiente para identificar y

notificar este hecho a la totalidad de propietarios e inquilinos que habitan en la superficie

dentro de un radio de 1500 pies de la boca del pozo y un radio de 500 pies de la representación

de la superficie del tramo horizontal de las áreas ubicadas debajo de la superficie de dicho

pozo. (Ver Código de Recursos Públicos, § 3160, subd. (d)(6).) Usted está recibiendo el

presente Aviso porque ha sido identificado como inquilino o propietario del siguiente terreno:

______________________________________________________________________

[assessor’s parcel number], [county], ubicado dentro del radio o cerca de este.

El tratamiento de estimulación de pozo hace referencia a los diversos métodos utilizados para

mejorar la producción de petróleo y gas mediante el aumento de la permeabilidad de la

formación de gas o petróleo por debajo de la superficie. Los tratamientos de estimulación de

pozo pueden incluir, entre otros, tratamientos de fractura hidráulica y tratamientos ácidos de

estimulación de pozo.

Cronograma del tratamiento de estimulación de pozo:

El operador del pozo no podrá comenzar el tratamiento de estimulación hasta dentro de los

treinta (30) días calendario después de que usted reciba el presente Aviso y reciba una copia

aprobada del permiso de estimulación de pozo.

La fecha en la cual se considere que el presente Aviso fue entregado dependerá del método de

entrega, envío o transmisión. Específicamente:

Si el presente Aviso se le entregó personalmente, se considerará que se le dio aviso en la

fecha de la entrega.

Si el presente Aviso se le envió mediante un servicio de entrega en 24 horas, se

considerará que se le ha dado aviso dentro de los dos (2) días calendario posteriores a la

entrega del Aviso al transportista.

Si el presente Aviso se le envió mediante un servicio de correo registrado, certificado o

expreso, se considerará que se le ha dado aviso dentro de los cinco (5) días calendario

posteriores a la entrega del Aviso al correo.


Si el presente Aviso se transmitió por fax o correo electrónico, se considerará que se le

ha dado aviso dentro de los dos (2) días calendario posteriores a la transmisión.

Si el presente Aviso se dejó en las instalaciones a una persona mayor de 18 años, se

considerará que se le ha dado aviso en la fecha en que se entregó a dicha persona.

El presente Aviso:

__ se entregó personalmente

__ se depositó a un transportista expreso para entrega 24 horas

__ se depositó en el correo mediante correo registrado/certificado/expreso

__ se transmitió por fax o correo electrónico

__ se dejó en las instalaciones a una persona mayor de 18 años

En la siguiente fecha: _________________.

SE CONSIDERA QUE EL PRESENTE AVISO SE HA ENTREGADO EL:

_________________

[calculate date based on the schedule described above and in California Code of

Regulations, title 14, section 1783.2, subdivision (d)].

LA FECHA MÁS CERCANA EN QUE PUEDE COMENZAR EL TRATAMIENTO DE ESTIMULACIÓN

DE POZO ES:

_________________

[calculate date that is 30 calendar days after the date notice is deemed to have been

provided].


PRUEBA DE CALIDAD DEL AGUA

Usted podrá tener derecho a solicitar pruebas de calidad del agua en ciertos pozos o superficies

de agua ubicados dentro del límite de la propiedad. Podrán aplicarse normas diferentes según

usted sea dueño de la propiedad ubicada sobre la superficie o inquilino de la propiedad que se

identifica en el presente Aviso.

PARA LOS PROPIETARIOS DE TERRENOS SOBRE LA SUPERFICIE: Si usted es propietario de un

terreno sobre la superficie de los terrenos identificados en el presente Aviso, podrá solicitar

pruebas de calidad del agua sobre cualquier pozo o superficie de agua existente ubicada dentro

de los límites de su terreno y adecuada con fines de riego o consumo. (Ver Código de Recursos

Públicos, § 3160, subd. (d)(7)(A).) _____________________________________ [name of

operator] pagará las pruebas, en tanto y en cuanto se realicen conforme a las normas y los

protocolos establecidos por el Comité de Control de Recursos de Agua Estatal por parte de un

Contratista Designado para el Muestreo de Agua. La prueba de calidad de agua comprende

pruebas previas a las actividades de estimulación del pozo ("prueba de línea de base"), así

como también pruebas realizadas una vez finalizado el tratamiento de estimulación del pozo

("pruebas de seguimiento").

Si usted es el dueño del terreno y opta por solicitar una prueba de calidad de agua, deberá

realizar su solicitud por escrito, conforme a las siguientes instrucciones a continuación y deberá

entregarlo a:

[Operator Contact]

[Operator Street Address]

[City, State, Zip Code]

O la siguiente dirección de correo electrónico: __________________

Para realizar la prueba de calidad del agua, se podrá utilizar el formulario de plantilla disponible

en el sitio Web de la División de Petróleo, Gas y Recursos Geotérmicos


Si usted solicita una prueba de calidad del agua, deberá indicar si desea que

_____________________________________ [name of operator] elija al Contratista Designado

para el Muestreo de Agua y coordine con dicho contratista para que realice las pruebas de agua

en su terreno o si prefiere elegir al Contratista Designado para el Muestreo de Agua y usted

mismo coordinar la realización de dichas pruebas. Deberá indicar su decisión en su solicitud

escrita de prueba de calidad del agua.


Si decide que _____________________________________ [name of operator] coordine la

prueba de calidad del agua, _____________________________________ [name of operator]

se comunicará con usted para programar la prueba de línea de base previo al tratamiento de

estimulación del pozo, y una vez más luego de la finalización del tratamiento para programar la

prueba de seguimiento dentro del plazo de 30 a 60 días calendario tras finalizado el

tratamiento de estimulación del pozo. Si desea que

_____________________________________ [name of operator] coordine la prueba de calidad

del agua, es posible que el tratamiento de estimulación del pozo no comience hasta después de

finalizada la prueba de línea de base, en tanto y en cuanto usted realice las coordinaciones

adecuadas para permitir la prueba de línea de base sin demoras innecesarias. Usted es

responsable por la entrega de copias de los resultados de las pruebas del agua a los inquilinos

de su terreno, en la medida que dicha acción esté autorizada en el contrato del inquilino.

A FIN DE QUE SU SOLICITUD DE PRUEBA DE CALIDAD DEL AGUA SEA CONSIDERADA VÁLIDA Y

SEA COORDINADA POR _____________________________________ [name of operator], LA

MISMA DEBE SER ENVIADA POR CORREO Y LLEVAR EL SELLO POSTAL O BIEN SER ENVIADA

POR CORREO ELECTRÓNICO ANTES DEL _________________ [specify the date that is 20

calendar days after the date identified above as the date this Notice is deemed to have been

provided].

Si decide coordinar las pruebas de calidad del agua usted mismo, será responsable por

programar y hacer todo lo necesario para asegurarse de que el Contratista de Calidad del Agua

Aprobado concluya la prueba de línea de base previo al comienzo del tratamiento de

estimulación del pozo que se describe en el presente Aviso.

_____________________________________ [name of operator] no estará obligado a retrasar

el tratamiento de estimulación del pozo más allá del _________________ [specify the date

identified above as the earliest date upon which the well stimulation treatment may commence]

para permitir la realización de pruebas de líneade base previo al tratamiento de estimulación

del pozo. _____________________________________ [name of operator] se comunicará con

usted cuando finalice el tratamiento de estimulación del pozo para que pueda coordinar las

pruebas de seguimiento. Si desea coordinar usted mismo las pruebas de calidad del agua, aún

estará facultado a recibir un reembolso de _____________________________________ [name

of operator] por los gastos de dicha prueba, en tanto y en cuanto las pruebas de agua coincidan con las

normas y los protocolos especificados en el Comité Estatal de Control de Recursos de Agua conforme al

artículo 3160, inciso (d)(7) del Código de Recursos Públicos de California y en tanto y en cuanto los

resultados de dichas pruebas se distribuyan a las siguientes entidades y personas: (1) la División de

Petróleo, Gas y Recursos Geotérmicos del Departamento de Conservación de California; (2) el

Comité Regional de Control de Calidad del Agua que tenga jurisdicción sobre su terreno; y (3)


cualquiera y todos los inquilinos que se encuentren en su terreno, en la medida de lo que

autorice el contrato de alquiler. (Ver Código de Recursos Públicos, § 3160, subd. (d)(7)(C).)

PARA QUE LA PRUEBA DE CALIDAD DEL AGUA QUE USTED COORDINA SEA CONSIDERADA

VÁLIDA, TAL PRUEBA DEBE SER HECHA ANTES DEL COMIENZO DEL TRATAMIENTO DE

ESTIMULACIÓN DEL POZO.

PARA LOS INQUILINOS: Si usted fuera inquilino del terreno identificado en el presente Aviso,

podrá solicitar de manera independiente pruebas de calidad del agua sobre cualquier pozo de

agua o superficie de agua existente ubicada dentro de los límites del terreno adecuada con

fines de riego o consumo y respecto de los cuales tenga derecho de uso. (Ver Código de

Recursos Públicos, § 3160, subd. (d)(7)(C).) No estará facultado a recibir un reembolso de

_____________________________________ [name of operator] por los costos de dicha

prueba. Si desea contratar los servicios de prueba de calidad del agua en forma independiente

para un pozo o una superficie de agua existente respecto del cual tenga derecho de uso, se

recomienda contratar a un Contratista Designado para el Muestreo de Agua aprobado por el

Comité de Control de Recursos de Agua Estatal. Recuerde que usted es responsable de

programar y tomar las medidas necesarias para asegurarse de que se concluya la prueba de

línea de base previo al comienzo del tratamiento de estimulación del pozo que se describe en el

presente Aviso. _____________________________________ [name of operator] no estará

obligado a retrasar el tratamiento de estimulación del pozo más allá del _________________

[specify the date identified above as the earliest date upon which the well stimulation treatment

may commence] para permitir la realización de pruebas de línea de base previo al tratamiento

de estimulación del pozo. Además, se le recomienda informar a

_____________________________________ [name of operator] que piensa contratar un

servicio de prueba de calidad del agua; en consecuencia

_____________________________________ [name of operator] deberá notificarle cuando

finalice el tratamiento de estimulación del pozo para que usted coordine las pruebas de

seguimiento.

Además del derecho a contratar servicios de prueba de calidad del agua en forma

independiente, usted tendrá derecho, en la medida en que lo permita el contrato de alquiler, a

recibir los resultados de cualquier prueba de calidad del agua que pudiera ser solicitada por el

propietario del terreno de la superficie en respuesta al presente Aviso.


Información adicional:

Los sitios web del Comité de Control de Recursos de Agua Estatal

(http://www.waterboards.ca.gov/water_issues/programs/groundwater/sb4.shtml) o la División

de Petróleo, Gas y Recursos Geotérmicos del Departamento de Conservación de California

(http://www.conservation.ca.gov/dog) contienen una lista de Contratistas Designados para el

Muestreo de Agua aprobados por el Comité de Control de Recursos de Agua Estatal para llevar

a cabo prueba de calidad del agua según se describe en el presente Aviso.

Si tiene preguntas relacionadas con los asuntos que se describen en el presente Aviso,

comuníquese con _____________________________________ [name of operator contact] al

_________________________ [direct phone] o _______________________________ [email

address].

También puede llamar con sus preguntas relacionadas a los asuntos que se describen en el

presente Aviso a la División de Petróleo, Gas y Recursos Geotérmicos del Departamento de

Conservación de California al número (916) 445‐9686.

Firma y método de contacto de un tercero independiente:

Por (firma): __________________________________________________________________

Aclaración de firma: ___________________________________________________________

Dirección: ____________________________________________________________________

Número de teléfono: ___________________________________________________________

Dirección de correo electrónico: __________________________________________________

Lawrence BerkeleyNational Laboratory

An Independent Scienti�cAssessment of

Well Stimulation in California

Executive Summary

An Examination of Hydraulic Fracturingand Acid Stimulations

in the Oil and Gas Industry

July 2015

An Independent Scienti�cAssessment of

Well Stimulation in California

Executive Summary

An Examination of Hydraulic Fracturingand Acid Stimulations

in the Oil and Gas Industry

July 2015

An Independent Scientific Assessment of Well Stimulation

in CaliforniaExecutive Summary

An Examination of Hydraulic Fracturing and Acid Stimulations

in the Oil and Gas IndustryJane C. S. Long, PhD; California Council on Science and Technology

Steering Committee Chairman and Science Lead

Jens T. Birkholzer, PhD; Lawrence Berkeley National Laboratory Principal Investigator

Laura C. Feinstein, PhD; California Council on Science and Technology Project Manager

Members of the Steering CommitteeRoger Aines, PhD; Lawrence Livermore National LaboratoryBrian L. Cypher, PhD; California State University, StanislausJames Dieterich, PhD; University of California, RiversideDon Gautier, PhD; DonGautier L.L.C.Peter Gleick, PhD; Pacific InstituteDan Hill, PhD; Texas A&M UniversityAmy Myers Jaffe; University of California, DavisLarry Lake, PhD; University of Texas, AustinThomas E. McKone, PhD; Lawrence Berkeley National LaboratoryWilliam Minner, PE; Minner Engineering, Inc.Seth B.C. Shonkoff, PhD, MPH; PSE Healthy Energy Daniel Tormey, PhD; Ramboll Environ CorporationSamuel Traina, PhD; University of California, Merced

Report Lead AuthorsJens T. Birkholzer, Lawrence Berkeley National LaboratoryAdam Brandt , Stanford UniversityPatrick F. Dobson , Lawrence Berkeley National LaboratoryLaura C. Feinstein , California Council On Science And TechnologyWilliam Foxall , Lawrence Berkeley National LaboratoryDonald L. Gautier , DonGautier L.L.C.James E. Houseworth , Lawrence Berkeley National LaboratoryPreston D. Jordan , Lawrence Berkeley National LaboratoryJane C. S. Long, California Council On Science And TechnologyWilliam T. Stringfellow, Lawrence Berkeley National LaboratoryThomas E. McKone, Lawrence Berkeley National LaboratorySeth B. C. Shonkoff, PSE Healthy Energy

July 2015

Acknowledgments

This report has been prepared for the California Council on Science and Technology (CCST) with funding from the California Natural Resources Agency.

Copyright

Copyright 2015 by the California Council on Science and Technology ISBN Number: 978-1-930117-68-6 An Independent Scientific Assessment of Well Stimulation in California: Executive Summary. An Examination of Hydraulic Fracturing and Acid Stimulations in the Oil and Gas Industry.

About CCST

CCST is a non-profit organization established in 1988 at the request of the California State Government and sponsored by the major public and private postsecondary institutions of California and affiliate federal laboratories in conjunction with leading private-sector firms. CCST’s mission is to improve science and technology policy and application in California by proposing programs, conducting analyses, and recommending public policies and initiatives that will maintain California’s technological leadership and a vigorous economy.

Note

Any opinions, findings, conclusions, or recommendations expressed in this publication are those of the author(s) and do not necessarily reflect the views of the organizations or agencies that provided support for the project.

For questions or comments on this publication contact:

California Council on Science and Technology 1130 K Street, Suite 280 Sacramento, CA 95814 916-492-0996 [email protected] www.ccst.us

Layout by a Graphic Advantage! 3901 Carter Street #2, Riverside, CA 92501 www.agraphicadvantage.com

1

Executive Summary

In 2013, the California Legislature passed Senate Bill 4 (SB 4), setting the framework for regulation of hydraulic fracturing and acid stimulation technologies in California. SB 4 also requires the California Natural Resources Agency to conduct an independent scientific study to assess current and potential future well stimulation practices, including the likelihood that these technologies could enable extensive new petroleum production in the state; the impacts of well stimulation technologies (including hydraulic fracturing, acid fracturing and matrix acidizing) and the gaps in data that preclude this understanding; potential risks associated with current practices; and alternative practices that might limit these risks.

The California Council on Science and Technology (CCST) organized and led the study. Members of the CCST steering committee were appointed based on technical expertise and a balance of technical viewpoints. Lawrence Berkeley National Laboratory (LBNL) and subcontractors (the science team) developed the findings based on original technical data analyses and a review of the relevant literature. The science team studied each of the issues required by SB 4, and the science team and the steering committee collaborated to develop a series of conclusions and recommendations. Final responsibility for the conclusions and recommendations in this report lies with the steering committee. All steering committee members have agreed with these conclusions and recommendations. Any steering committee member could have written a dissenting opinion, but no one requested to do so.

This report has undergone extensive peer review; peer reviewers are listed in Appendix E of the Summary Report, “Expert Oversight and Review.” Eighteen reviewers were chosen for their relevant technical expertise. More than 1,500 anonymous review comments were provided to the authors. The authors revised the report in response to peer review comments. In cases where the authors disagreed with the reviewer, the response to review included their reasons for disagreement. Report monitors, appointed by CCST, then reviewed the response to the review comments and when satisfied, approved the report.

To create a hydraulic fracture, an operator increases the pressure of a mixture of water and chemicals in an isolated section of a well until the surrounding rock breaks, or “fractures.” Sand injected into these fractures props them open after the pressure is released. Acid fracturing, in which a high-pressure acidic fluid fractures the rock and etches the walls of the fractures, is hardly used in California and not discussed further. Matrix acidizing does not fracture the rock; instead, acid pumped into the well at relatively low pressure dissolves some of the rock and makes it more permeable. This study identified seven equally important major principles required for safe hydraulic fracturing and acid stimulation in California. Organized by principle, we draw conclusions and recommendations.

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Executive Summary

Principle 1. Maintain, expand and analyze data on the practice of hydraulic fracturing and acid stimulation in California.

Public records provide substantial information about the location, frequency of use, and water and chemical use for hydraulic fracturing and acid stimulation in California.

Conclusion 1.1. Most well stimulations in California are hydraulic fracturing and most hydraulic fracturing occurs in the San Joaquin Valley.

About 95% of reported hydraulic fracturing operations in California occur in the San Joaquin Basin, nearly all in four oil fields in Kern County. Over the last decade, about 20% of oil and gas production in California came from wells treated with hydraulic fracturing. Hydraulic fracturing accounts for about 90% of all well stimulations in California; matrix acidizing accounts for only 10%; and acid fracturing operations nearly none. Operators in California commonly use acid for well maintenance, but acid stimulation will not likely lead to major increases in oil and gas production due to the state’s geology. Operators of dry (non-associated) gas wells located in Northern California rarely use hydraulic fracturing (Volume I, Chapter 3).

Conclusion 1.2. The California experience with hydraulic fracturing differs from that in other states.

Present-day hydraulic fracturing practice and geologic conditions in California differ from those in other states, and as such, recent experiences with hydraulic fracturing in other states do not necessarily apply to current hydraulic fracturing in California (Volume I, Chapters 2 and 3).

Conclusion 1.3. Hydraulic fracturing in California does not use a lot of fresh water compared to other states and other human uses.

Operators in California use about 800 acre-feet (about a million cubic meters [m3]) of water per year for hydraulic fracturing. This does not represent a large amount of freshwater compared to other human water use, so recycling this water has only modest benefits. However, hydraulic fracturing takes place in relatively water-scarce regions. Where production was enabled by hydraulic fracturing, at least twice and possibly fourteen times as much fresh water was used for subsequent enhanced oil recovery using water or steam flooding than all the water used for hydraulic fracturing throughout the state. The state has recently begun requiring detailed reporting of water use and produced water disposal in California’s oil and gas fields under Senate Bill 1281 (SB 1281). In the future, these data could help optimize oil and gas water practices, including water use, production, reuse, and disposal.

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Executive Summary

Recommendation 1.1. Identify opportunities for water conservation and reuse in the oil and gas industry.

When roughly a year of water data becomes available from implementation of SB 1281, the state should begin an early assessment of these data to evaluate water sources, water production, reuse, and disposal for the entire oil and gas industry. Early assessment will shed light on the adequacy of the data reporting requirements and identify additional requirements that could include additional information about the quality of the water used and produced. When several years of data become available, a full assessment should identify opportunities to reduce freshwater consumption or increase the beneficial use of produced water, and regularly update opportunities for water efficiency and conservation (Volume I, Chapter 3).

Conclusion 1.4. A small number of offshore wells use hydraulic fracturing.

California operators currently use hydraulic fracturing in a small portion of offshore wells, and we expect hydraulic fracturing to remain incidental in the offshore environment. Policies currently restrict oil and gas production offshore, but if these were to change in the future, production could largely occur without well stimulation technology for the foreseeable future (Volume III, Chapter 2 [Offshore Case Study]).

Conclusion 1.5. Record keeping for hydraulic fracturing and acid stimulation in federal waters does not meet state standards.

Current record-keeping practice on stimulations in federal waters (from platforms more than three nautical miles offshore) does not meet the standards set by the pending SB 4 well treatment regulations and does not allow an assessment of the level of activity or composition of hydraulic fracturing chemicals being discharged in the ocean. The National Pollutant Discharge Elimination System permits that regulate discharge from offshore platforms do not effectively address hydraulic fracturing fluids. The limited publicly available records disclose only a few stimulations per year.

Recommendation 1.2. Improve reporting of hydraulic fracturing and acid stimulation data in federal waters.

The state of California should request that the federal government improve data collection and record keeping concerning well stimulation conducted in federal waters to at least match the requirements of SB 4. The U.S. Environmental Protection Agency should conduct an assessment of ocean discharge and, based on these results, consider if alternatives to ocean disposal for well stimulation fluid returns are necessary (Volume III, Chapter 2 [Offshore Case Study]).

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Executive Summary

Principle 2. Prepare for potential future changes in hydraulic fracturing and acid stimulation practice in California.

Conclusion 2.1. Future use of hydraulic fracturing in California will likely resemble current use.

Future use of hydraulic fracturing will most likely expand production in and near existing oil fields in the San Joaquin Basin that currently require hydraulic fracturing. Oil resource assessment and future use of hydraulic fracturing and acid stimulation in the Monterey Formation of California remain uncertain. In 2011, the U.S. Energy Information Administration (EIA) estimated that 15 billion barrels (2.4 billion m3) of recoverable shale-oil resources existed in Monterey source rock. This caused concern about the potential environmental impacts of widespread shale-oil development in California using hydraulic fracturing. In 2014 the EIA downgraded the 2011 estimate by 96%. This study reviewed both EIA estimates and concluded that neither one can be considered reliable. Any potential for production in the Monterey Formation would be confined to those parts of the formation in the “oil window,” that is, where Monterey Formation rocks have experienced the temperatures and pressures required to form oil. The surface footprint of this subset of the Monterey Formation expands existing regions of oil and gas production rather than opening up entirely new oil and gas producing regions.

Recommendation 2.1. Assess the oil resource potential of the Monterey Formation.

The state should request a comprehensive, science-based and peer-reviewed assessment of source-rock (“shale”) oil resources in California and the technologies that might be used to produce them. The state could request such an assessment from the U.S. Geological Survey, for example.

Recommendation 2.2. Keep track of exploration in the Monterey Formation.

As expansive production in the Monterey Formation remains possible, Division of Oil, Gas, and Geothermal Resources (DOGGR) should track well permits for future drilling in the “oil window” of the Monterey source rocks (and other extensive source rocks, such as the Kreyenhagen) and be able to report increased activity (Volume I, Chapter 4; Volume III, Chapter 3 [Monterey Formation Case Study]).

Principle 3. Account for and manage both direct and indirect impacts of hydraulic fracturing and acid stimulation.

Hydraulic fracturing or acid stimulation can cause direct impacts. Potential direct impacts might include a hydraulic fracture extending into protected groundwater, accidental spills of fluids containing hydraulic fracturing chemicals or acid, or inappropriate disposal or reuse of produced water containing hydraulic fracturing chemicals. These direct impacts

5

Executive Summary

do not occur in oil and gas production unless hydraulic fracturing or acid stimulation has occurred. This study covers potential direct impacts of hydraulic fracturing or acid stimulation.

Hydraulic fracturing or acid stimulation can also incur indirect impacts, i.e., those not directly attributable to the activity itself. Some reservoirs require hydraulic fracturing for economic production. All activities associated with oil and gas production enabled by hydraulic fracturing or acid stimulation can bring about indirect impacts. Indirect impacts of hydraulic-fracturing-enabled oil and gas development usually occur in all oil and gas development, whether or not the wells are stimulated.

Conclusion 3.1. Direct impacts of hydraulic fracturing appear small but have not been investigated.

Available evidence indicates that impacts caused directly by hydraulic fracturing or acid stimulation or by activities directly supporting these operations appear smaller than the indirect impacts associated with hydraulic-fracturing-enabled oil and gas development, or limited data precludes adequate assessment of these impacts. Good management and mitigation measures can address the vast majority of potential direct impacts of well stimulation.

Recommendation 3.1. Assess adequacy of regulations to control direct impacts of hydraulic fracturing and acid stimulations.

Over the next several years, relevant agencies should assess the adequacy and effectiveness of existing and pending regulations to mitigate direct impacts of hydraulic fracturing and acid stimulations.

Conclusion 3.2. Operators have unrestricted use of many hazardous and uncharacterized chemicals in hydraulic fracturing.

The California oil and gas industry uses a large number of hazardous chemicals during hydraulic fracturing and acid treatments. The use of these chemicals underlies all significant potential direct impacts of well stimulation in California. This assessment did not find recorded negative impacts from hydraulic fracturing chemical use in California, but no agency has systematically investigated possible impacts. A few classes of chemicals used in hydraulic fracturing (e.g. biocides, quaternary ammonium compounds, etc.) present larger hazards because of their relatively high toxicity, frequent use, or use in large amounts. The environmental characteristics of many chemicals remain unknown. We lack information to determine if these chemicals would present a threat to human health or the environment if released to groundwater or other environmental media. Application of green chemistry principles, including reduction of hazardous chemical use and substitution of less hazardous chemicals, would reduce potential risk to the environment or human health.

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Executive Summary

Recommendation 3.2. Limit the use of hazardous and poorly understood chemicals.

Operators should report the unique Chemical Abstracts Service Registry Number (CASRN) identification for all chemicals used in hydraulic fracturing and acid stimulation, and the use of chemicals with unknown environmental profiles should be disallowed. The overall number of different chemicals should be reduced, and the use of more hazardous chemicals and chemicals with poor environmental profiles should be reduced, avoided, or disallowed. The chemicals used in hydraulic fracturing could be limited to those on an approved list that would consist only of those chemicals with known and acceptable environmental hazard profiles. Operators should apply green chemistry principles to the formulation of hydraulic fracturing fluids, particularly for biocides, surfactants, and quaternary ammonium compounds, which have widely differing potential for environmental harm. Relevant state agencies, including DOGGR, should as soon as practical engage in discussion of technical issues involved in restricting chemical use with a group representing environmental and health scientists and industry practitioners, either through existing roundtable discussions or independently (Volume II, Chapters 2 and 6).

Conclusion 3.3. The majority of impacts associated with hydraulic fracturing are caused by the indirect impacts of oil and gas production enabled by the hydraulic fracturing.

Impacts caused by additional oil and gas development enabled by well stimulation (i.e. indirect impacts) account for the majority of environmental impacts associated with hydraulic fracturing. A corollary of this conclusion is that all oil and gas development causes similar impacts whether the oil is produced with well stimulation or not. As hydraulic fracturing enables only 20-25% of production in California, only about 20-25% of any given indirect impact is likely attributable to hydraulically fractured reservoirs.

Recommendation 3.3. Evaluate impacts of production for all oil and gas development, rather than just the portion of production enabled by well stimulation.

Concern about hydraulic fracturing might cause focus on impacts associated with production from fractured wells, but concern about these indirect impacts should lead to study of all types of oil and gas production, not just production enabled by hydraulic fracturing. Agencies with jurisdiction should evaluate impacts of concern for all oil and gas development, rather than just the portion of development enabled by well stimulation. As appropriate, many of the rules and regulations aimed at mitigating indirect impacts of hydraulic fracturing and acid stimulation should also be applied to all oil and gas wells (Volume II, Chapters 5 and 6).

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Executive Summary

Conclusion 3.4. Oil and gas development causes habitat loss and fragmentation.

Any oil and gas development, including that enabled by hydraulic fracturing, can cause habitat loss and fragmentation. The location of hydraulic-fracturing-enabled development coincides with ecologically sensitive areas in the Kern and Ventura Counties.

Recommendation 3.4. Minimize habitat loss and fragmentation in oil and gas producing regions.

Enact regional plans to conserve essential habitat and dispersal corridors for native species in Kern and Ventura Counties. The plans should identify top-priority habitat and restrict development in these regions. The plan should also define and require those practices, such as clustering multiple wells on a pad and using centralized networks of roads and pipes, which will minimize future surface disturbances. A program to set aside compensatory habitat in reserve areas when oil and gas development causes habitat loss and fragmentation should be developed and implemented (Volume II, Chapter 5; Volume III, Chapter 5 [San Joaquin Basin Case Study]).

Principle 4. Manage water produced from hydraulically fractured or acid stimulated wells appropriately.

Large volumes of water of various salinities and qualities get produced along with the oil. Oil reservoirs tend to yield increasing quantities of water over time, and most of California’s oil reservoirs have been in production for several decades to over a century. For 2013, more than 3 billion barrels (.48 billion m3) of water came along with some 0.2 billion barrels (.032 billion m3) of oil in California. Operators re-inject some produced water back into the oil and gas reservoirs to help recover more petroleum and mitigate land subsidence. In other cases, farmers use this water for irrigation; often blending treated produced water with higher-quality water to reduce salinity.

Conclusion 4.1. Produced water disposed of in percolation pits could contain hydraulic fracturing chemicals.

Based on publicly available data, operators disposed of some produced water from stimulated wells in Kern County in percolation pits. The effluent has not been tested to determine if there is a measureable concentration of hydraulic fracturing chemical constituents. If these chemicals were present, the potential impacts to groundwater, human health, wildlife, and vegetation would be extremely difficult to predict, because there are so many possible chemicals, and the environmental profiles of many of them are unmeasured.

8

Executive Summary

Recommendation 4.1. Ensure safe disposal of produced water in percolation pits with appropriate testing and treatment or phase out this practice.

Agencies with jurisdiction should promptly ensure through appropriate testing that the water discharged into percolation pits does not contain hazardous amounts of chemicals related to hydraulic fracturing as well as other phases of oil and gas development. If the presence of hazardous concentrations of chemicals cannot be ruled out, they should phase out the practice of discharging produced water into percolation pits. Agencies should investigate any legacy effects of discharging produced waters into percolation pits including the potential effects of stimulation fluids (Volume II, Chapter 2; Volume III, Chapters 4 and 5 [Los Angeles Basin and San Joaquin Basin Case Studies]).

Conclusion 4.2. The chemistry of produced water from hydraulically fractured or acid stimulated wells has not been measured.

Chemicals used in each hydraulic fracturing operation can react with each other and react with the rocks and fluids of the oil and gas reservoirs. When a well is stimulated with acid, the reaction of the acid with the rock minerals, petroleum, and other injected chemicals can release contaminants of concern in the oil reservoirs, such as metals or fluoride ions that have not been characterized or quantified. These contaminants may be present in recovered and produced water.

Recommendation 4.2. Evaluate and report produced water chemistry from hydraulically fractured or acid stimulated wells.

Evaluate the chemistry of produced water from hydraulically fractured and acid stimulated wells, and the potential consequences of that chemistry for the environment. Determine how this chemistry changes over time. Require reporting of all significant chemical use, including acids, for oil and gas development (Volume II, Chapters 2 and 6).

Conclusion 4.3. Required testing and treatment of produced water destined for reuse may not detect or remove chemicals associated with hydraulic fracturing and acid stimulation.

Produced water from oil and gas production has potential for beneficial reuse, such as for irrigation or for groundwater recharge. In fields that have applied hydraulic fracturing or acid stimulations, produced water may contain hazardous chemicals and chemical byproducts from well stimulation fluids. Practice in California does not always rule out the beneficial reuse of produced water from wells that have been hydraulically fractured or stimulated with acid. The required testing may not detect these chemicals, and the treatment required prior to reuse necessarily may not remove hydraulic fracturing chemicals.

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Executive Summary

Recommendation 4.3. Protect irrigation water from contamination by hydraulic fracturing chemicals and stimulation reaction products.

Agencies of jurisdiction should clarify that produced water from hydraulically fractured wells cannot be reused for purposes such as irrigation that could negatively impact the environment, human health, wildlife and vegetation. This ban should continue until or unless testing the produced water specifically for hydraulic fracturing chemicals and breakdown products shows non-hazardous concentrations, or required water treatment reduces concentrations to non-hazardous levels (Volume II, Chapter 2; Volume III, Chapter 5 [San Joaquin Basin Case Study]).

Conclusion 4.4. Injection wells currently under review for inappropriate disposal into protected aquifers may have received water that contains chemicals from hydraulic fracturing.

DOGGR is currently reviewing injection wells in the San Joaquin Valley for inappropriate disposal of oil and gas wastewaters into protected groundwater. The wastewaters injected into some of these wells likely included stimulation chemicals because hydraulic fracturing occurs nearby.

Recommendation 4.4. In the ongoing investigation of inappropriate disposal of wastewater into protected aquifers, recognize that hydraulic fracturing chemicals may have been present in the wastewater.

In the ongoing process of reviewing, analyzing, and remediating the potential impacts of wastewater injection into protected groundwater, agencies of jurisdiction should include the possibility that hydraulic fracturing chemicals may have been present in these wastewaters (Volume II, Chapter 2; Volume III, Chapter 5 [San Joaquin Basin Case Study]).

Conclusion 4.5. Disposal of produced water by underground injection has caused earthquakes elsewhere.

Fluid injected in the process of hydraulic fracturing will not likely cause earthquakes of concern. In contrast, disposal of produced water by underground injection could cause felt or damaging earthquakes. To date, there have been no reported cases of induced seismicity associated with produced water injection in California. However, it can be very difficult to distinguish California’s frequent natural earthquakes from those possibly caused by water injection into the subsurface.

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Executive Summary

Recommendation 4.5. Determine if there is a relationship between wastewater injection and earthquakes in California.

Conduct a comprehensive multi-year study to determine if there is a relationship between oil and gas-related fluid injection and any of California’s numerous earthquakes. In parallel, develop and apply protocols for monitoring, analyzing, and managing produced water injection operations to mitigate the risk of induced seismicity. Investigate whether future changes in disposal volumes or injection depth could affect potential for induced seismicity (Volume II, Chapter 4).

Conclusion 4.6. Changing the method of produced water disposal will incur tradeoffs in potential impacts.

Based on publicly available data, operators dispose of much of the produced water from stimulated wells in percolation pits (evaporation-percolation ponds), about a quarter by underground injection (in Class II wells), and less than one percent to surface bodies of water. Changing the method of produced water disposal could decrease some potential impacts while increasing others.

Recommendation 4.6. Evaluate tradeoffs in wastewater disposal practices.

As California moves to change disposal practices, for example by phasing out percolation pits or stopping injection into protected aquifers, agencies with jurisdiction should assess the consequences of modifying or increasing disposal via other methods (Volume II, Chapter 2; Volume II, Chapter 4).

Principle 5. Add protections to avoid groundwater contamination by hydraulic fracturing.

Conclusion 5.1. Shallow fracturing raises concerns about potential groundwater contamination.

In California, about three quarters of all hydraulic fracturing operations take place in shallow wells less than 2,000 feet (600 meters) deep. In a few places, protected aquifers exist above such shallow fracturing operations, and this presents an inherent risk that hydraulic fractures could accidentally connect to the drinking water aquifers and contaminate them or provide a pathway for water to enter the oil reservoir. Groundwater monitoring alone may not necessarily detect groundwater contamination from hydraulic fractures. Shallow hydraulic fracturing conducted near protected groundwater resources warrants special requirements and plans for design control, monitoring, reporting, and corrective action.

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Executive Summary

Recommendation 5.1. Protect groundwater from shallow hydraulic fracturing operations.

Agencies with jurisdiction should act promptly to locate and catalog the quality of groundwater throughout the oil-producing regions. Operators proposing to use hydraulic fracturing operation near protected groundwater resources should be required to provide adequate assurance that the expected fractures will not extend into these aquifers and cause contamination. If the operator cannot demonstrate the safety of the operation with reasonable assurance, agencies with jurisdiction should either deny the permit, or develop protocols for increased monitoring, operational control, reporting, and preparedness (Volume I, Chapter 3; Volume II, Chapter 2; Volume III, Chapter 5 [San Joaquin Basin Case Study]).

Conclusion 5.2. Leakage of hydraulic fracturing chemicals could occur through existing wells.

California operators use hydraulic fracturing mainly in reservoirs that have been in production for a long time. Consequently, these reservoirs have a high density of existing wells that could form leakage paths away from the fracture zone to protected groundwater or the ground surface. The pending SB 4 regulations going into effect July 2015 do address concerns about existing wells in the vicinity of well stimulation operations; however, it remains to demonstrate the effectiveness of these regulations in protecting groundwater.

Recommendation 5.2. Evaluate the effectiveness of hydraulic fracturing regulations designed to protect groundwater from leakage along existing wells.

Within a few years of the new regulations going into effect, DOGGR should conduct or commission an assessment of the regulatory requirements for existing wells near stimulation operations and their effectiveness in protecting groundwater with less than 10,000 TDS from well leakage. This assessment should include comparisons of field observations from hydraulic fracturing sites with the theoretical calculations for stimulation area or well pressure required in the regulations (Volume II, Chapter 2; Volume III, Chapters 4 and 5 [San Joaquin Basin and Los Angeles Basin Case Studies]).

Principle 6. Understand and control emissions and their impact on environmental and human health.

Gaseous emissions and particulates associated with hydraulic fracturing can arise from the use of fossil fuel in engines, outgassing from fluids, leaks, or proppant. Emissions can also result from all production processes. Such emissions have potential environmental or health impacts.

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Executive Summary

Conclusion 6.1. Oil and gas production from hydraulically fractured reservoirs emits less greenhouse gas per barrel of oil than other forms of oil production in California.

Burning fossil fuel to run vehicles, make electricity, and provide heat accounts for the vast majority of California’s greenhouse gas emissions. In comparison, publicly available California state emission inventories indicate that oil and gas production operations emit about 4% of California total greenhouse gas emissions. Oil and gas production from hydraulically fractured reservoirs emits less greenhouse gas per barrel of oil than production using steam injection. Oil produced in California using hydraulic fracturing also emits less greenhouse gas per barrel than the average barrel imported to California. If the oil and gas derived from stimulated reservoirs were no longer available, and demand for oil remained constant, the replacement fuel could have larger greenhouse gas emissions.

Recommendation 6.1. Assess and compare greenhouse gas signatures of different types of oil and gas production in California.

Conduct rigorous market-informed life-cycle analyses of emissions impacts of different oil and gas production to better understand GHG impacts of well stimulation (Volume II, Chapter 3).

Conclusion 6.2. Air pollutant and toxic air emissions from hydraulic fracturing are mostly a small part of total emissions, but pollutants can be concentrated near production wells.

According to publicly available California state emission inventories, oil and gas production in the San Joaquin Valley air district likely accounts for significant emissions of sulfur oxides (SOx), volatile organic compounds (VOC), and some air toxics, notably hydrogen sulfide (H2S). In other oil and gas production regions, production as a whole accounts for a small proportion of total emissions. Hydraulic fracturing facilitates about 20% of California production, and so emissions associated with this production also represent about 20% of all emissions from the oil and gas production in California. Even where the proportion of air pollutant and toxic emissions caused directly or indirectly by well simulation is small, atmospheric concentrations of pollutants near production sites can be much larger than basin or regional averages, and could potentially cause health impacts.

Recommendation 6.2. Control toxic air emissions from oil and gas production wells and measure their concentrations near productions wells.

Apply reduced-air-emission completion technologies to production wells, including stimulated wells, to limit direct emissions of air pollutants, as planned. Reassess opportunities for emission controls in general oil and gas operations to limit emissions. Improve specificity of inventories to allow better understanding of oil and gas emissions sources. Conduct studies to improve our understanding of toxics

13

Executive Summary

concentrations near stimulated and un-stimulated wells (Volume II, Chapter 3; Volume III, Chapter 4 [Los Angeles Basin Case Study]).

Conclusion 6.3. Emissions concentrated near all oil and gas production could present health hazards to nearby communities in California.

Many of the constituents used in and emitted by oil and gas development can damage health, and place disproportionate risks on sensitive populations, including children, pregnant women, the elderly, and those with pre-existing respiratory and cardiovascular conditions. Health risks near oil and gas wells may be independent of whether wells in production have undergone hydraulic fracturing or not. Consequently, a full understanding of health risks caused by proximity to production wells will require studying all types of productions wells, not just those that have undergone hydraulic fracturing. Oil and gas development poses more elevated health risks when conducted in areas of high population density, such as the Los Angeles Basin, because it results in larger population exposures to toxic air contaminants.

Recommendation 6.3. Assess public health near oil and gas production.

Conduct studies in California to assess public health as a function of proximity to all oil and gas development, not just stimulated wells, and develop policies such as science-based surface setbacks, to limit exposures (Volume II, Chapter 6; Volume III, Chapters 4 and 5 [San Joaquin Basin and Los Angeles Basin Case Studies]).

Conclusion 6.4. Hydraulic fracturing and acid stimulation operations add some occupational hazards to an already hazardous industry.

Studies done outside of California found workers in hydraulic fracturing operations were exposed to respirable silica and VOCs, especially benzene, above recommended occupational levels. The oil and gas industry commonly uses acid along with other toxic substances for both routine maintenance and well stimulation. Well-established procedures exist for safe handling of dangerous acids.

Recommendation 6.4. Assess occupational health hazards from proppant use and emission of volatile organic compounds.

Conduct California-based studies focused on silica and volatile organic compounds exposures to workers engaged in hydraulic-fracturing-enabled oil and gas development processes based on the National Institute for Occupational Safety and Health occupational health findings and protocols (Volume II, Chapter 6).

14

Executive Summary

Principle 7. Take an informed path forward.

Conclusion 7.1. Data reporting gaps and quality issues exist.

Significant gaps and inconsistencies exist in available voluntary and mandatory data sources, both in terms of duration and completeness of reporting. Because the hydrologic and geologic conditions and stimulation practices in California differ from other unconventional plays in this country, many data gaps are specific to California.

Recommendation 7.1. Improve and modernize public record keeping for oil and gas production.

DOGGR should digitize paper records and organize all datasets in databases that facilitate searches and quantitative analysis. DOGGR should also institute and publish data quality assurance practices, and institute enforcement measures to ensure accuracy of reporting. When a few years’ reporting data become available, a study should assess the value, completeness, and consistency of reporting requirements for hydraulic fracturing and acid treatment operations—and as necessary, revise or expand reporting requirements. The quality and completeness of the data collected by the South Coast Air Quality Management District provides a good example of the completeness and availability the state should seek to emulate. The Department of Conservation should reevaluate well stimulation data trends after 3–5 years of reporting.

Conclusion 7.2. Future research would fill knowledge gaps.

Questions remain at the end of this initial assessment of the impacts of well stimulation in California that can only be answered by new research and data collection. Volumes II and III of this report series provide many detailed recommendations for filling data gaps and additional research. Some examples of key questions include:

• Has any protected groundwater been contaminated with stimulation chemicals in the past, and what would protect against this occurrence in the future? No records of groundwater contamination due to hydraulic fracturing were found, but there were also few investigations designed to look for contamination.

• What environmental risks do stimulation chemicals pose, and are there practices that would limit these risks?

• Can water being produced from hydraulically fractured wells become a resource for California?

• How does oil and gas production as a whole (including that enabled by hydraulic fracturing) affect California’s water system?

15

Executive Summary

• Does California’s current or future practice of underground injection of wastewater present a significant risk of inducing earthquakes?

• How can the public best be protected from air pollution associated with oil and gas production?

• What are the ecological impacts of oil and gas development in California?

Recommendation 7.2. Conduct integrated research to close knowledge gaps.

Conduct integrated research studies in California to answer key questions about the environmental, health, and seismic impacts of oil and gas production enabled by well stimulation. Integrated research studies should include regional hydrologic characterization and field studies related to surface and groundwater protection, induced seismicity, ecological conditions, as well as air and health effects.

Conclusion 7.3. Ongoing scientific advice could inform policy.

As the state of California digests this assessment and as more data become available, continued interpretation of both the impacts of well stimulation and the potential meaning of scientific data and analysis would inform the policy framework for this complex topic.

Recommendation 7.3. Establish an advisory committee on oil and gas.

The state of California should establish a standing scientific advisory committee to support decisions on the regulation of oil and gas development.

California Council on Science and Technology

1130 K Street, Suite 280 Sacramento, CA 95814

(916) 492-0996 http://www.ccst.us

Lawrence Berkeley National Laboratory

Earth Sciences Division 1 Cyclotron Road,

Mail Stop 74R316C, Berkeley, CA 94720

(510) 486-6455 http://www.lbl.gov

Analysis of Oil and Gas Well Stimulation Treatments in California FINAL ENVIRONMENTAL IMPACT REPORT EXECUTIVE SUMMARY

June 2015 ES-1 Final EIR

Final Environmental Impact Report Executive Summary

This Final Environmental Impact Report (Final EIR) has been prepared to address the environmental effects of oil and gas well stimulation treatments in California, as mandated by Public Resources Code (PRC) Section 3161 (b)(3)(A) and (B) of Chapter 1, Division 3 (the State’s laws for the conservation of petroleum and gas). These provisions are part of Senate Bill 4 (SB 4) (Chapter 313), which was authored by State Senator Fran Pavley et al., and signed into law by Governor Edmund G. Brown Jr. on Septem-ber 20, 2013. SB 4 established a comprehensive regulatory program for oil and gas well stimulation treatments. SB 4 amended PRC Sections 3213, 3215, 3236.5 and 3401, added a new Article 3 (Sections 3150 through 3161) to Chapter 1, Division 3, of the PRC, and added a new Section 10783 to Part 2.76 (Groundwater Quality Monitoring) of the State’s Water Code.1

PRC Section 3157 (a) and (b) define oil and gas well stimulation treatments as follows:

(a) For purposes of this article, “well stimulation treatment” means any treatment of a well designed to enhance oil and gas production or recovery by increasing the permea-bility of the formation. Well stimulation treatments include, but are not limited to, hydraulic fracturing treatments and acid well stimulation treatments.

(b) Well stimulation treatments do not include steam flooding, water flooding, or cyclic steaming and do not include routine well cleanout work, routine well maintenance, routine removal of formation damage due to drilling, bottom hole pressure surveys, or routine activities that do not affect the integrity of the well or the formation.2

As presented in Final EIR Executive Summary Section ES.2 (Summary of the Project), the “project” involves either hydraulic fracturing, acid fracturing, or acid matrix stimulation of an oil and gas well within the State, where the well either (1) existed prior to January 1, 2014, or (2) could be drilled after January 1, 2014, specifically for the purpose of a well stimulation treatment (PRC Section 3161(b)(3)(B)(ii)).

This Final EIR Executive Summary contains the following Sections:

ES.1 Environmental Review Process and Use of the Final Environmental Impact Report

ES.2 Summary of the Project

ES.3 Summary of Project Alternatives

ES.4 Summary of Content and Conclusions of the Final Environmental Impact Report

ES.5 Environmentally Superior Alternative

ES.6 Use and Application of the Final Environmental Impact Report Mitigation Measures

ES.7 Areas of Known Controversy

ES.8 Issues to be Resolved

1 PRC Section 3161 was subsequently amended in 2014 by Senate Bill 861 (Statutes 2014, Chapter 35). 2 Please refer to Draft EIR Section 7.3.5 (Description of the Project, Testing and Production) (Final EIR Volume II)

for additional information on routine well cleanout work, routine well maintenance, routine removal of formation damage due to drilling, bottom hole pressure surveys, and routine activities that do not affect the integrity of a well or formation and are not considered to be well stimulation treatments.


Final EIR ES-2 June 2015

ES.1 Environmental Review Process and Use of the Final Environmental Impact Report

Consistent with Section 15082 of the State California Environmental Quality Act (CEQA) Guidelines, a Notice of Preparation (NOP) for the project was issued on November 15, 2013; the NOP requested com-ments on the Draft EIR’s scope and content from interested parties within a 60-day timeframe (November 15, 2013 through January 16, 2014). During this period, five public meetings on the scope and content of the Draft EIR were held in Oakland (December 10, 2013), Sacramento (December 11, 2013), Bakersfield (December 12, 2013), Ventura (January 8, 2014) and Long Beach (January 9, 2014), where comments by interested parties were also received.

The Draft EIR, a Notice of Completion, and a Notice of Availability for the project were released on Janu-ary 14, 2015. The Draft EIR was made available for review and comment for a 62-day period (January 14, 2015, through March 16, 2015), during which time six public meetings on the Draft EIR were held in Ventura (February 10, 2015), Los Angeles (February 1, 2015), Oakland (February 18, 2015), Sacramento (February 19, 2015), Bakersfield (February 23, 2015) and Salinas (February 25, 2015). An estimated 2,100 written and verbal comments on the Draft EIR were received. In this Final EIR the Department of Conservation (DOC), acting on behalf of its Division of Oil, Gas and Geothermal Resources (DOGGR), has prepared written responses to all significant environmental points contained in those comments, consis-tent with State CEQA Guidelines Section 15088.

This Final EIR represents the documentation necessary for the project’s full environmental review under CEQA. Section ES.4 of this Executive Summary provides a summation of the Final EIR’s content and con-clusions. Consistent with PRC Section 3161 (b)(3)(B)(i), this Final EIR will be considered for certification by the decision maker for the project on or before July 1, 2015. For the purposes of this Final EIR, the “decision maker” is the State Oil and Gas Supervisor.

ES.2 Summary of the Project

Description of the Project

For the purposes of this Final EIR, well stimulation treatments include hydraulic fracturing, acid fracturing and acid matrix stimulation. Well stimulation treatments do not include steam flooding, water flooding, or cyclic steaming. Additionally, such treatments do not include routine well cleanout work, routine well maintenance, routine removal of formation damage due to drilling, bottom hole pressure surveys, or routine activities that do not affect the integrity of a well or formation. Further, high rate gravel packing is not considered a well stimulation treatment when it is used to control sand within a well;3 however, gravel (i.e., sand) packing treatments that are performed for well stimulation with the intent of fracturing a geologic formation are considered.

As directed by PRC Section 3161(b)(3)(A), this document focuses on the physical acts associated with hydraulic fracturing, acid fracturing, and acid matrix stimulation as they apply to both existing and future oil and gas wells in the State. This Final EIR analyzes the impacts of these well stimulation treatments with implementation of DOGGR’s permanent regulations for well stimulation treatments, which were

3 High rate gravel packing is a technique where the annulus (the space between the casing and the drilled hole or

wellbore) of a well is packed, at a high pumping rate, with gravel, water, and additives to limit the entry of fines and sand from a geologic formation into the wellbore. The size of the gravel is similar to the size of the proppant (sand) used for hydraulic fracturing.



adopted on December 30, 2014, and have amended California Code of Regulations Title 14, Division 2, Chapter 4, Subchapter 2. These regulations will go into effect on July 1, 2015, as required by PRC Section 3161(a). This Final EIR’s analysis assumes that well stimulation treatments, with application of DOGGR’s permanent regulations, could occur either within or outside of existing oil and gas field boundaries. For the purposes of this Final EIR the “project” is defined as all activities associated with a stimulation treat-ment that could occur either at an existing oil and gas well, or at an oil and gas well that is drilled in the future expressly for the purposes of stimulation treatment.

The project also assumes implementation of the mitigation measures recommended in this Final EIR, as applicable at a site-specific level of analysis, to avoid or minimize potential impacts to certain categories of environmental resources. Please refer to Final EIR Executive Summary Section ES.6 (Use and Applica-tion of the Final Environmental Impact Report Mitigation Measures) for a discussion of the project’s mit-igation measures. Draft EIR Chapter 7 (Description of the Project), as revised for this Final EIR and con-tained in Volume II details the activities associated with the well stimulation treatments analyzed.

Objectives of the Project

Section 15124(b) of the State CEQA Guidelines requires that an EIR’s “Project Description” include a clearly written statement of a proposed project’s objectives to help a Lead Agency develop a reasonable range of alternatives, and aid its decision making body when preparing Findings of Fact and a Statement of Overriding Considerations, if necessary. Unlike most EIRs, which are typically prepared in response to a specific project proposal such as a permit application or proposed legislative action, this EIR has been prepared in response to the mandate set forth in PRC Section 3161(b)(3). Accordingly, this EIR has not been prepared in response to a specific project proposal, but rather is an informational document regarding the potential impacts of well stimulation which may serve to inform other CEQA documents. The statute adds that the mandate to prepare a statewide EIR does not prohibit a local lead agency from conducting its own EIR.

SB 4 also directs other State, regional and local agencies, in collaboration with DOGGR, to establish their respective authority, responsibility, notification and reporting requirements as related to various aspects of well stimulation treatments. Although the execution of some of the requirements of SB 4 are independent and exclusive of each other, they are all inter-related in the sense that they all serve the overall objective of SB 4 to rigorously evaluate well stimulation treatments and determine whether they can be conducted safely and with minimal impacts to the environment. To this end, the over-arching objectives of this EIR are not limited to oil and gas well stimulation treatments alone, but also include the objectives of the regulatory processes prescribed by SB 4, as follows:

1. Objectives of Oil and Gas Well Stimulation Treatments

a. To increase the recovery of oil and gas resources by increasing the reservoir permeability to create an economically feasible production rate from presently unusable formations.

b. To minimize the number of new wells required for the recovery of hydrocarbon resources.

c. To maximize the efficiency and production capacity of existing and planned oil and gas wells.

d. To allow continued development of the State’s hydrocarbon resources.

e. To conduct well stimulation treatments safely to minimize impacts to the environment and nat-ural resources.

f. To reduce the State’s and nation’s reliance on foreign oil and gas resources.



2. Objectives of the Environmental Impact Report

a. To comply with PRC Section 3161, Subdivisions (b)(3)(A) and (B) by providing the public with detailed information regarding the practice of well stimulation.

b. To provide DOGGR and other applicable regulatory agencies with information which may be necessary to efficiently and effectively evaluate future permit applications for proposed oil and gas well stimulation practices, during or following well completion, in order to ensure a consis-tent approach to CEQA compliance.

c. To identify and develop impact avoidance and mitigation strategies to address any significant environmental effects directly, indirectly or cumulatively resulting from well stimulation practices that are not already sufficiently addressed by the permanent regulations addressing well stimulation treatments adopted by DOGGR on December 30, 2014, pursuant to PRC Section 3160, Subdivision (b)(1).

d. To facilitate on-going coordination between DOGGR and other federal, State, regional and local agencies having regulatory authority over well stimulation practices.

3. Objectives of the Regulatory Process Mandated by SB 4

a. To ensure cooperation and communication among regulatory agencies to expressly regulate the practice of well stimulation through the imposition of certain standards, to require the collec-tion of data regarding well stimulation in California, and to require notification to those poten-tially affected by well stimulation practices.

b. To prevent, as far as possible, damage to life, health, property, and natural resources resulting directly or indirectly from well stimulation, consistent with State statutes authorizing the effi-cient recovery of hydrocarbon resources, and consistent with impact avoidance and mitigation concepts of CEQA.

c. To prevent damage to underground and surface waters suitable for irrigation or domestic pur-poses by the infiltration of, or the addition of, detrimental substances resulting directly or indi-rectly from well stimulation, consistent with State statutes authorizing the efficient recovery of hydrocarbon resources, and consistent with impact avoidance and mitigation concepts of CEQA.

ES.3 Summary of Project Alternatives

The statutory requirements for an EIR’s evaluation of alternatives are detailed in Draft EIR Chapter 8 (Description of the Alternatives) and Chapter 14 (Comparison of the Alternatives), as revised for this Final EIR (Volumes II and III). Draft EIR Chapter 12 Environmental Analysis of the Alternatives), as also revised for this Final EIR (Volume III), provides the subject-specific assessment of the project’s alterna-tives. Alternatives to the project include the:

No Future Well Simulation Treatments Alternative (Alternative 1);

No Future Well Stimulation Treatments Outside of Existing Oil and Gas Field Boundaries (Alternative 2);

Well Pad Consolidation Alternative (Alternative 3);

Urbanized Area Protection Alternative (Alternative 4);

Active Fault Zone Restrictions Alternative (Alternative 5); and

No Project Alternative (Alternative 6).



Additional detail regarding the alternatives can also be found in Draft EIR Section 1.2 (Summary of Project Alternatives), as revised for this Final EIR and contained in Volume II.

ES.4 Summary of Content and Conclusions of the Final Environmental Impact Report

Final Environmental Impact Report Content

Consistent with State CEQA Guidelines Sections 15088 and 15132, this Final EIR provides all comments received on, and written responses to, all significant environmental issues raised on the Draft EIR, as well as all revisions to the text of the Draft EIR. All changes to the text of the Draft EIR are contained in Volumes II and III of this Final EIR, and are indicated in strikethrough (strikethrough) text for deletions and underline (underline) text for additions.

Volume I of this Final EIR contains this Executive Summary, four chapters and one technical appendix, as follows:

Executive Summary Summary of the Final EIR’s content and conclusions, including narratives of how its mitigation measures will be applied in the future, and new “areas of known controversy” and “issues to be resolved” that have been identified since publication of the Draft EIR

Chapter A Introduction

Chapter B Draft Environmental Impact Report Review Comments

Chapter C Responses to Review Comments on the Draft Environmental Impact Report

Chapter D Revisions to the Draft Environmental Impact Report Map Book

Appendix 1 Draft Environmental Impact Report Comment Correspondence and Public Meeting Transcripts

The Draft EIR, as revised and contained in Volumes II and III of this Final EIR addresses the project and its six alternatives at a programmatic level of analysis per the assumptions detailed in revised Draft EIR Chapter 9 (Overall Approach to the Environmental Analysis) (Final EIR Volume II). The Final EIR analyzes 23 subjects including:

Aesthetics Agriculture and Forestry Resources Air Quality Biological Resources (Terrestrial Environment) Biological Resources (Coastal and Marine Environment) Coastal Processes and Marine Water Quality Commercial and Recreational Fishing Cultural Resources Paleontological Resources Environmental Justice Geology, Soils and Mineral Resources Greenhouse Gas Emissions

Hazards and Hazardous Materials Groundwater Resources Surface Water Resources Land Use and Planning Noise and Vibration Population and Housing Public Services Recreation Risk of Upset/Public and Worker Safety Transportation and Traffic Utilities and Service Systems



For the purposes of these evaluations, the State was divided into six study regions, which follow the boundaries of DOGGR’s six administrative Districts. Further refinement of these study regions was applied to reflect where oil and gas development can either be reasonably predicted to occur in the future, or has occurred. The study regions are described in revised Draft EIR Chapter 5 (Location and Regional Setting for the Project and Alternatives), and revised Draft EIR Section 5.8 details those areas of the State that the analysis concentrates on (Study Region Areas of Focus) (Final EIR Volume II).

For each subject programmatically evaluated, the Draft EIR, as revised for this Final EIR, assesses direct and reasonably foreseeable indirect impacts of the project, as well as three specific oil and gas fields, including the: Wilmington Oil and Gas Field (Study Region 1); Inglewood Oil and Gas Field (Study Region 1); and Sespe Oil and Gas Field (Study Region 2). The Draft EIR, as revised for this Final EIR, addi-tionally analyzes the project’s incremental contribution to cumulative impacts (revised Draft EIR Chapter 13), as well as its effects related to “other CEQA considerations” (revised Draft EIR Chapter 15).

In total, the Draft EIR, as revised for this Final EIR and contained in Volumes II and III, is made up of an Executive Summary, 19 chapters and 11 technical appendices, as follows:

Executive Summary

Summary of the Draft EIR, including a narrative of areas of known controversy and issues to be resolved

Chapter 1 Introduction

Chapter 2 Regulatory Framework for the Division of Oil, Gas and Geothermal Resources

Chapter 3 Other Relevant Regulatory Schemes

Chapter 4 Scope and Intent of the Environmental Impact Report

Chapter 5 Location and Regional Setting for the Project and Alternatives

Chapter 6 Overview of California’s Oil and Gas Resources

Chapter 7 Description of the Project

Chapter 8 Description of the Alternatives

Chapter 9 Overall Approach to the Environmental Analysis

Chapter 10 Programmatic Level Analysis of the Project

Chapter 11 Programmatic Level Analysis of Specific Oil and Gas Fields

Chapter 12 Environmental Analysis of the Alternatives

Chapter 13 Cumulative Impact Analysis

Chapter 14 Comparison of Alternatives

Chapter 15 Other CEQA Considerations

Chapter 16 Public Participation and Noticing

Chapter 17 References and Organizations/Persons Consulted

Chapter 18 List of Acronyms

Chapter 19 List of Preparers and Reviewers

Appendix A Oil and Gas Glossary of Terms

Appendix B Text of Senate Bill No. 4 (as modified in 2014)

Appendix C Well Stimulation Treatment Neighborhood Notification Form

Appendix D Guidelines and Environmental Checklist for Future Environmental Reviews and Clearances

Appendix E Emission Calculation Examples – Well Stimulation Treatments

Appendix F California History, Prehistory, and Cultural Resources Types

Appendix G Descriptions of Native American Tribes and Reservations



Appendix H Paleontological Resources Assessments for the Wilmington and Sespe Oil and Gas Fields

Appendix I Chemicals Used in Hydraulic Fracturing

Appendix J Groundwater Basin Data for Study Regions 1 through 6

Appendix K Summary of National Train Accident Data for Class I Railroads (excluding Amtrak)

In addition, the Draft EIR includes a companion Map Book, which contains the maps associated with the Draft EIR’s content and subject-specific analyses, as revised for this Final EIR. For the purposes of this Final EIR, the Draft EIR Map Book has not been re-published. Revisions to its content can be found in Final EIR Volume I, Chapter D (Revisions to the Draft Environmental Impact Report Map Book). The entire Draft EIR and its Map Book can be accessed at:

http://www.conservation.ca.gov/dog/SB 4DEIR/Pages/SB 4_DEIR_TOC.aspx

The Draft EIR and Map Book can also be viewed in published form at all six DOGGR District offices, as follows:

DOC Headquarters/DOGGR District 6 801 K Street, MS 24-01 Sacramento, CA 95814

DOGGR District 3 195 South Broadway, Suite 101 Orcutt, CA 93455-4655

DOGGR District 1 5816 Corporate Avenue, Suite 200 Cypress, CA 90630-4731

DOGGR District 4 4800 Stockdale Highway, Suite 417 Bakersfield, CA 93309-0279

DOGGR District 2 1000 South Hill Road, Suite 116 Ventura, CA 93003-4458

DOGGR District 5 466 North Fifth Street Coalinga, CA 93210-1793

Conclusions of the Final Environmental Impact Report

For the purposes of calibrating potential impacts and their significance, for each subject-specific impact evaluated in this Final EIR, the following impact classification system is applied:

Class I: Significant and Unavoidable Impact. Class I impacts are significant adverse environmental effects that cannot be mitigated to a level of less than significant through the application of feasible mitigation measures.

Class II: Less Than Significant Impact With Mitigation Incorporated. Class II Impacts are significant adverse environmental effects that can be reduced to a level of less than significant with the applica-tion of feasible mitigation measures.

Class III: Less Than Significant Impact. Class III impacts are adverse environmental effects that have been determined to be comparatively minor in the sense that they do not meet or exceed the sub-ject-specific criteria established to gauge significance.

Class IV: No Impact. Class IV impacts do not have any adverse or beneficial environmental effects.

At a programmatic level of analysis, the Final EIR concludes that the project has the potential to cause significant and unavoidable (Class I) impacts to aesthetics, air quality, biological resources (terrestrial environment), cultural resources, geology, soils and mineral resources, greenhouse gas emissions, land use and planning, risk of upset/public and worker safety, and transportation and traffic, as summarized in Table ES-1 (Summary of Significant and Unavoidable (Class I) Impacts of the Project). As the table

http://www.conservation.ca.gov/dog/SB4DEIR/Pages/SB4_DEIR_TOC.aspx



notes, the occurrence of Class I impacts is dependent on the site-specific conditions in particular areas in which well stimulation treatments may occur. In some instances, less than significant impacts with miti-gation incorporated (Class II), less than significant impacts (Class III), or no impact (Class IV) could occur.

At a programmatic level of analysis, the Final EIR concludes that the project has the potential to cause Class II through Class IV impacts, as summarized in Table ES-2 (Summary of Impacts and Mitigation Mea-sures for the Project), starting on page ES-30.

At a programmatic level of analysis for specific oil and gas fields, the Final EIR concludes that significant and unavoidable impacts (Class I) for air quality, biological resources (terrestrial environment), cultural resources, greenhouse gas emissions, land use and planning, risk of upset/public and worker safety, and transportation and traffic could occur. These impacts, as well as the less than significant impacts with mitigation incorporated (Class II), less than significant impacts (Class III), and no impact (Class IV) that could occur at a field-specific level, are summarized in Table ES-3 (Summary of Impacts and Mitigation Measures for the Project: Analysis of Specific Oil and Gas Fields), starting on page ES-46.

Table ES-1. Summary of Significant and Unavoidable (Class I) Impacts of the Project*

Subject / Impact Criteria Mitigation Measures Significance after Mitigation

Aesthetics

Impact AES-1: Substantially adversely affect scenic vistas

AES-1a: Prepare and Implement a Site Plan to Reduce Visual Impacts to Sensitive Receptors AES-1b: Minimize Lighting Visibility Offsite

Class I or II in new areas depending on site-specific conditions

Impact AES-2: Substantially alter or damage scenic resources



Impact AES-3: Substantially degrade the existing visual character or quality of a site and its surroundings



Impact AES-4: Create new sources of substantial light and glare



Air Quality

Impact AQ-1: Conflict with or obstruct implementation of an applicable air quality plan

AQ-1a: Improve Air Quality Planning Inventories and Local Control Measures AQ-1b: Improve Methodologies and Emission Factors Used in Inventory Development

Class I (Statewide) Class III (in SCAQMD)

Impact AQ-2: Increase criteria pollutants or precursor pollutants to levels that violate an air quality standard or contribute substantially to an existing or projected air quality violation

AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources AQ-2c: Reduce Emissions from Dust-Causing Activities

Class I

Impact AQ-3: Expose sensitive receptors to substantial pollutant concentrations

AQ-3a: Comply with Local Air District Protocols Relating to the Preparation of a Health Risk Assessment and Implement Emission Controls AQ-3b: Avoid Unnecessary Exposure to Air Pollutants by Improving Local Land Use Compatibility

Class I





Impact AQ-4: Create objectionable odors affecting a substantial number of people

AQ-4a: Prepare and Implement an Odor Minimization Plan AQ-4b: Avoid Unnecessary Exposure to Odors by Improving Local Land Use Compatibility

Class I

Biological Resources: Terrestrial Environment

Impact BIOT-1: Substantially reduce the habitat of a fish or wildlife species

BIOT-1a: Evaluate Impacts to Native Vegetation and Fish and Wildlife Habitat BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat AQ-2c: Reduce Emissions from Dust-Causing Activities GW-1a: Use Alternative Water Sources to the Extent Feasible GW-1b: Minimize Groundwater Impacts HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials SWR-1a: Require Stormwater Pollution Prevention Plan SWR-2a: Implement Erosion Control Plan SWR-3a: Ensure Adequate Water Availability

Class I through III depending on site-specific conditions

Impact BIOT-2: Cause a fish or wildlife population to drop below self-sustaining levels

BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat BIOT-2a: Prevent Hazards to Fish and Wildlife BIOT-2b: California Condor Protection Measures BIOT-2c: Nelson’s Bighorn Sheep Protection Measures BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife BIOT-4b: Minimize Impacts to Protected Birds BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials SWR-1a: Require Stormwater Pollution Prevention Plan SWR-2a: Implement Erosion Control Plan






Impact BIOT-3: Substantially reduce the number or restrict the range of an endangered, rare, or threatened species

BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat BIOT-2a: Prevent Hazards to Fish and Wildlife BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife BIOT-3b: Minimize and Mitigate Impacts to Special-status Plants BIOT-4b: Minimize Impacts to Protected Birds BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement AQ-2c: Reduce Emissions from Dust-Causing Activities SWR-1a: Require Stormwater Pollution Prevention Plan


Impact BIOT-4: Have a substantial adverse effect, either directly or through habitat modifications, on any species identified as a candidate, sensitive, or special-status species in local or regional plans, policies, or regulations, or by CDFW or USFWS

BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat BIOT-2a: Prevent Hazards to Fish and Wildlife BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife BIOT-3b: Minimize and Mitigate Impacts to Special-status Plants BIOT-4a Minimize and Mitigate Impacts to All Species Identified as a Candidate, Sensitive, or Special-status Species in Local or Regional Plans, Policies, or Regulations, or by CDFW or USFWS BIOT-4b: Minimize Impacts to Protected Birds BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement


Impact BIOT-5: Have a substantial adverse effect on any riparian habitat or other sensitive natural community identified in local or regional plans, policies, regulations, or by CDFW or USFWS

BIOT-1a: Evaluate Impacts to Native Vegetation and Fish and Wildlife Habitat BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat AQ-2c: Reduce Emissions from Dust-Causing Activities GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection SWR-2a: Implement Erosion Control Plan SWR-3a: Ensure Adequate Water Availability






Impact BIOT-6: Have a substantial adverse effect on federally protected wetlands as defined by Section 404, of the Clean Water Act (including, but not limited to, marsh, vernal pool, coastal, etc.) through direct removal, filling, hydrological interruption, or other means

BIOT-1a: Evaluate Impacts to Native Vegetation and Fish and Wildlife Habitat BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat BIOT-2a: Prevent Hazards to Fish and Wildlife BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife BIOT-6a: Protect Jurisdictional Waters GW-1a: Use Alternative Water Sources to the Extent Feasible GW-1b: Minimize Groundwater Impacts GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection SWR-2a: Implement Erosion Control Plan SWR-3a: Ensure Adequate Water Availability


Impact BIOT-7: Interfere substantially with the movement of any native resident or migratory fish or wildlife species or with established native resident or migratory wildlife corridors, or impede the use of native wildlife nursery sites

BIOT-7a: Prevent Habitat Fragmentation and Impacts to Fish and Wildlife Movement


Impact BIOT-8: Conflict with any local policies or ordinances protecting biological resources, such as a tree preservation policy or ordinance

BIOT-8a: Coordinate with Local Agencies and Jurisdictions Regarding Local Policies and Conservation Plans


Impact BIOT-9: Conflict with the provisions of an adopted Habitat Conservation Plan, Natural Community Conservation Plan, or other approved local, regional, or state habitat conservation plan

BIOT-9a: Coordinate with CDFW, USFWS, and Permittees Regarding NCCPs, HCPs, and Other Conservation Plans


Impact BIOT-10: Contribute to global climate change and consequent impacts to biodiversity

AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources GHG-1a: Prevent Methane Emissions from Associated Gas and Casinghead gas GHG-1b: Reduce Emissions by Implementing Clean Development Mechanism (CDM) Strategies GHG-2a: Require Applicant to Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program

Class I





Cultural Resources

Impact CUL-1: Affect historic-era archaeological and built-environment resources

CUL-1a: Require Information and Evaluate Cultural Resources CUL-1b: Complete Native American Coordination CUL-1c: Prepare and Implement Cultural Resources Management and Treatment Plan CUL-1d: Prepare Plan for the Inadvertent Discovery of Human Remains CUL-1e: Provide Cultural Resources Specialist with the Authority to Halt Earth Disturbing Activities CUL-1f: Conduct a Cultural Resources Worker Environmental Awareness Program CUL-1g: Monitor Earth Disturbing Activities for Cultural Resources CUL-1h: Provide Native American Monitors during Earth Disturbing Activities CUL-1i: Prepare Cultural Resources Documents for the Monitoring of Earth Disturbing Activities CUL-1j: Curate all Discovered Cultural Resources Associated with Earth Disturbing Activities

Class I through IV depending on site-specific conditions

Impact CUL-2: Affect prehistoric resources







Impact CUL-3: Disturb human remains or cultural items, including funerary objects, sacred objects, and objects of cultural patrimony



Impact CUL-4: Affect cultural landscapes



Geology, Soils and Mineral Resources

Impact GEO-6: Result in the loss of availability of known mineral resource, or loss of a locally important mineral resource recovery site delineated on a local general plan, specific plan or other land use plan

No mitigation proposed Class III in most instances; Class I in some cases when local governments, with proper findings, approve land uses that preclude further access to important mineral resources





Greenhouse Gas Emissions

Impact GHG-1: Generate greenhouse gas emissions that may have a significant impact on the environment

AQ-2a: Reduce Emissions from Well Stimulation Treatments AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources GHG-1a: Prevent Methane Emissions from Associated Gas and Casinghead Gas GHG-1b: Reduce Emissions by Implementing Clean Development Mechanism (CDM) Strategies GHG-1c: Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide

Class I

Impact GHG-2: Conflict with an applicable plan, policy or regulation adopted for the purpose of reducing the emissions of greenhouse gases

AQ-2a: Reduce Emissions from Well Stimulation Treatments AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources GHG-1c: Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide GHG-2a: Require Applicant Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program

Class I

Land Use and Planning

Impact LU-1: Preclude existing or permitted land uses, or create a disturbance that would diminish the function of land uses

(None available for significant and unavoidable impacts associated with Risk of Upset/Public and Worker Safety)

Class I

Risk of Upset/Public and Worker Safety

Impact RSK-1: Create a hazard to the public or environment through crude oil transport and reasonably foreseeable accidents and releases

RSK-1a: Increase the Number of CPUC Rail Inspectors RSK-1b: Expedite the Phase-out of Older Tank Cars RSK-1c: Implement New Accident Prevention Technology RSK-1d: Monitor and Enforce New Speed Limits RSK-1e: Monitor the Implementation of Trackside Safety Technology RSK-1f: Improve Emergency Preparedness and Response Programs RSK-1g: Provide Real-Time Shipment Information to Emergency Responders RSK-1h: Provide Additional Accident and Injury Data to the State

Class I

Impact RSK-6: Increase risks to public safety by exposing the public to accidental hazardous materials releases from pipelines

RSK-6a: Increase Inspection of Mechanical Integrity RSK-6b: Improve Leak Detection Capability RSK-6c: Reduce Mainline Valve Spacing

Class I

Transportation and Traffic

Impact TR-4: Transport hazardous materials

TR-4a: Know Spill Prevention Measures Class I

*Note: The occurrence of Class I Impacts is contingent on site-specific conditions of where a well stimulation treatment may occur. In some instances less than significant impacts with mitigation incorporated (Class II), less than significant impacts (Class III), or no impacts (Class IV) could occur.



In addition to the project’s direct and indirect effects, the Final EIR concludes that the project would have the potential to incrementally contribute to significant and unavoidable impacts related to aesthetics, air quality, agricultural and forestry resources, biological resources (terrestrial environment), cultural resources, environmental justice, greenhouse gas emissions, geology, soils and mineral resources, groundwater resources, land use and planning, risk of upset/public and worker safety, surface water resources, and transportation and traffic. These impacts are summarized in Table ES-4 (Summary of the Project’s Incremental Contribution to Cumulative Impacts).

Table ES-4. Summary of the Project’s Incremental Contribution to Cumulative Impacts

Subject / Impact Criteria1 Impact Significance and Mitigation Measures2,3

Aesthetics

Impact AES-1. Substantially adversely affect scenic vistas Class III in existing fields; Class I or II in new areas; for Class I and II impacts the mitigation measures as identified in Table ES-2 apply

Impact AES-2: Substantially alter or damage scenic resources Class III in existing fields; Class I or II in new areas for Class I and II impacts the mitigation measures as identified in Table ES-2 apply


Class III in existing fields; Class I or II in new areas; for Class I and II impacts the mitigation measures as identified in Table ES-2 apply

Impact AES-4: Create new sources of substantial light and glare Class III in existing fields; Class I or II in new areas for Class I and II impacts the mitigation measures as identified in Table ES-2 apply

Agricultural and Forestry Resources

Impact AGF-1: Convert Prime Farmland, Unique Farmland, or Farmland of statewide Importance (Important Farmland), as designated by the Farmland Mapping and Monitoring Program, to non-agricultural use

Class I on or adjacent to Important Farmland; for Class I impacts the same mitigation measures as identified in Table ES-2 apply

Impact AGF-2: Conflict with existing zoning for agricultural use or with Williamson Act contracts

Class II on land zoned for agricultural use or enrolled in Williamson Act contracts; for Class II impacts the same mitigation measures as identified in Table ES-2 apply

Impact AGF-3: Conflict with existing zoning for, or cause rezoning of, forest land, timberland, or timberland zoned Timberland Production

Class II on land zoned as forestland, timberland, or Timberland Production; for Class II impacts the same mitigation measures as identified in Table ES-2 apply

Impact AGF-4: Result in the loss of forest land or conversion of forest land to non-forest use

Class I on forest land; for Class I impacts the same mitigation measures as identified in Table ES-2 apply

Impact AGF-5: Directly or indirectly impair the use of agricultural land or forest land

Class II for well stimulation activities on or within 1,500 feet of agricultural or forest land; for Class II impacts the same mitigation measures as identified in Table ES-2 apply

Air Quality


Class I (Statewide); Class III (in SCAQMD). For Class I impacts the same mitigation measures as identified in Table ES-2 apply


Class I; the same mitigation measures as identified in Table ES-2 apply

























Class II; the same mitigation measures as identified in Table ES-2 apply





Biological Resources: Coastal and Marine Environment

Impact BIOCM-1: Substantially affect any species identified as a candidate, sensitive, or special status species or their habitat

Class III; no mitigation required

Impact BIOCM-2: Interfere substantially with the movement of any native resident or migratory fish or wildlife species or with established native resident or migratory wildlife corridors, or impede the use of native wildlife nursery sites






Impact BIOCM-3: Have a substantial adverse effect on federally protected wetlands as defined by Section 404 of the Clean Water Act (including, but not limited to, marsh, vernal pool, coastal, etc.) through direct removal, filling, hydrological interruption, or other means


Coastal Processes and Marine Water Quality

Impact CPMWQ-1: Change marine water chemical composition with respect to known hazardous substances; or the measured water temperature, salinity, conductivity, or turbidity


Impact CPMWQ-2: Change the velocity or direction of ocean currents

Class IV; no mitigation required

Impact CPMWQ-3: Change the velocity or direction of coastal and ocean winds


Impact CPMWQ-4: Change the direction, size, or period of ocean waves


Impact CPMWQ-5: Increase the risk of a tsunami Class III; no mitigation required

Commercial and Recreational Fishing

Impact CRF-1: Cause long-term exclusion of important commercial and recreational fishing areas


Impact CRF-2: Result in substantial loss of total catch to commercial and recreational fishing industries


Cultural Resources


Class I or Class II if historic or built-environment resources are present (mitigation measures identified in Table ES-2 apply); Class III or Class IV if historic or built-environment resources are not considered significant or are not present (no mitigation required)

Impact CUL-2: Affect prehistoric resources Class I or Class II if historic or built-environment resources are present (mitigation measures identified in Table ES-2 apply); Class III or Class IV if historic or built-environment resources are not considered significant or are not present (no mitigation required)


Class I or Class II if historic or built-environment resources are present (mitigation measures identified in Table ES-2 apply); Class III or Class IV if historic or built-environment resources are not considered significant or are not present (no mitigation required)

Impact CUL-4: Affect cultural landscapes Class I or Class II if historic or built-environment resources are present (mitigation measures identified in Table ES-2 apply); Class III or Class IV if historic or built-environment resources are not considered significant or are not present (no mitigation required)





Environmental Justice

Impact EJ-1: Disproportionately affect minority or low-income populations

Class I through Class IV depending on site-specific demographics; the same mitigation measure as identified in Table ES-2 applies to Class I and II impacts


Impact GEO-1: Expose people or structures to potential substantial adverse effects as a result of rupture of a known fault, seismically induced groundshaking, and/or ground failure


Impact GEO-2: Result in substantial soil erosion or the loss of topsoil


Impact GEO-3: Be located on a geologic unit or soil that is unstable and result in on- or off-site landslide, lateral spreading, subsidence or collapse

Class II; the same mitigation measure as identified in Table ES-2 applies

Impact GEO-4: Be located on expansive soil creating substantial risks to life or property


Impact GEO-5: Have soils incapable of adequately supporting the use of septic tanks or alternative wastewater disposal systems


Impact GEO-6: Result in the loss of availability of known mineral resource loss of a locally important mineral resource recovery site delineated on a local general plan, specific plan or other land use plan

Class III in most instances; Class I in some cases when local governments, with proper findings, approve land uses that preclude further access to important mineral resources; no mitigation measures proposed

Impact GEO-7: Cause an induced seismic event including ground shaking and ground failure







Hazards and Hazardous Materials

Impact HAZ-1: Release hazardous materials into the environment from a spill or leak


Groundwater Resources

Impact GW-1: Cause or contribute to overdraft conditions Class I; the same mitigation measures as identified in Table ES-2 apply

Impact GW-2: Lower groundwater levels through pumping, resulting in inelastic land subsidence or interconnected surface water


Impact GW-3: Adversely impact groundwater quality through surface spills or leaks during well stimulation






Impact GW-4: Migration of well stimulation fluids or formation fluids including gas to protected groundwater through non-existent or ineffective annular well seals


Impact GW-5: Migration of well stimulation fluids or formation fluids including gas into protected groundwater through damaged or improperly abandoned wells


Impact GW-6: Improper disposal of flowback in injection wells could potentially impact groundwater quality


Impact GW-7: Inability to identify specific impacts to groundwater quality from well stimulation activities





Impact LU-2: Physically divide an established community Class IV; no mitigation required

Impact LU-3: Conflict with applicable land use plans, policies, programs, ordinances or other land use regulations of agencies with jurisdiction over a project adopted for the purpose of avoiding or mitigating an environmental effect


Noise and Vibration

Impact NOI-1: Cause exposure of persons to or generation of excessive noise levels or a substantial increase in ambient noise levels


Impact NOI-2: Cause exposure of persons to or generation of excessive groundborne vibration


Paleontological Resources

Impact PALEO-1: Destroy or disturb surface or near-surface significant paleontological resources

Class II if fossil bearing geologic units are present (the same mitigation measures as identified in Table ES-2 apply); Class IV if no fossil bearing units are present (no mitigation required)

Population and Housing

Impact POP-1: Induce substantial population growth Class III; no mitigation required

Impact POP-2: Displace substantial numbers of people or existing housing, necessitating the construction of replacement housing elsewhere


Public Services

Impact PUB-1: Require new or physically altered governmental facilities in order to maintain acceptable service ratios, response times, or to other performance objectives for fire, police, or schools


Recreation

Impact REC-1: Result in the physical deterioration of recreational resources

Class III; not mitigation required





Impact REC-2: Cause disruptions in designated recreation areas Class II; the same mitigation measures as identified in Table ES-2 apply




Impact RSK-2: Create a hazard to the public, workers, or environment through a reasonably foreseeable accidental release of hazardous materials due to a hose leak or connection leak while pumping well stimulation treatment fluids


Impact RSK-3: Substantially increase the potential for major oil spills due to ship groundings and collisions


Impact RSK-4: Create a hazard to the public, workers, or environment through a reasonably foreseeable accidental pressure changes during flowback activity caused by blocked pump discharge, sudden change in downhole condition, or human error


Impact RSK-5: Generate risks to public safety by causing a flammable atmosphere in the flowback tank




Impact RSK-7: Expose workers and public to hazardous levels of airborne silica during the use of proppant


Surface Water Resources

Impact SWR-1: Violate water quality standards or waste discharge requirements, provide substantial additional sources of polluted runoff, or otherwise substantially degrade or diminish surface water quality


Impact SWR-2: Substantially alter the existing drainage pattern of the site or area, including through the alteration of the course of a stream or river, in a manner which would result in substantial erosion or siltation on- or off-site

Class I in Study Regions 2,4 and 5 (the same mitigation measure as identified in Table ES-2 applies); Class III in Study Region 1 and Class IV in Study Regions 3 and 6 (no mitigation required)

Impact SWR-3: Substantially diminish surface water quantity Class I; the same mitigation measures as identified in Table ES-2 apply

Impact SWR-4: Create flood hazard by substantially altering existing drainage patterns, substantially increasing the rate or amount of surface runoff, impeding or redirecting flood flows, or exposing people or structures to flooding



Impact TR-1: Generate additional truck traffic and disrupt traffic operations

Class III for project activities in Study Region 6 and for existing fields (no mitigation required); Class II outside of existing oil and gas fields in Study Regions 1 through 5 where 10 or more wells are drilled by a single applicant within one square mile (the same mitigation measures as identified in Table ES-2 apply)





Impact TR-2: Inadvertently damage road rights-of-way Class III for project activities in Study Region 6 and for existing fields (no mitigation required); Class II outside of existing oil and gas fields in Study Regions 1 through 5 where 10 or more wells are drilled by a single applicant within one square mile (the same mitigation measures as identified in Table ES-2 apply)

Impact TR-3: Cause traffic safety hazards for vehicles, bicyclists, and pedestrians

Class III for project activities in Study Region 6 and for existing fields (no mitigation required); Class II outside of existing oil and gas fields in Study Regions 1 through 5 where 10 or more wells are drilled by a single applicant within one square mile (the same mitigation measures as identified in Table ES-2 apply)

Impact TR-4: Transport hazardous materials Class I; the same mitigation measures as identified in Table ES-2 apply

Impact TR-5: Change air traffic patterns Class IV if no airports are nearby (no mitigation required); Class III if FAA notification under 14 CFR 77 is required (no mitigation required)

Impact TR-6: Temporarily interfere with emergency response Class III for project activities in Study Region 6 and for existing fields (no mitigation required); Class II outside of existing oil and gas fields in Study Regions 1 through 5 where 10 or more wells are drilled by a single applicant within one square mile (the same mitigation measures as identified in Table ES-2 apply)

Utilities and Service Systems

Impact UTL-1: Adversely affect utilities and service systems due to population growth from Project-related development


Impact UTL-2: Require new or expanded electrical or natural gas infrastructure


Impact UTL-3: Exceed existing municipal wastewater treatment provider capacities


Impact UTL-4: Exceed permitted solid waste capacity of landfills Class II; the same mitigation measures as identified in Table ES-2 apply

Energy Conservation (Other CEQA Considerations)

Impact EN-1: Result in substantial new energy requirements or energy use inefficiencies


Impact EN-2: Cause an adverse effect on local and regional energy supplies and requirements for additional capacity because of inefficient, wasteful, or unnecessary energy use


Impact EN-3: Cause an adverse effect on peak and base period demands for electricity and other forms of energy because of inefficient, wasteful, or unnecessary energy use


Impact EN-4: Disrupt compliance with existing energy standards Class III; no mitigation required

Impact EN-5: Cause an adverse effect on energy resources because of inefficient, wasteful, or unnecessary energy use


Impact EN-6: Result in inefficient, wasteful, or unnecessary transportation energy use




1 - The occurrence of significant and unavoidable impacts (Class I) for some subject areas is contingent on site-specific conditions of where a proposed well stimulation treatment may occur. As example, if a proposed well stimulation site’s future environmental review demonstrates that no cultural resources are present, no impacts would occur and no mitigation would be required. However, if the site does contain such resources, potential impacts could be either significant and unavoidable (Class I), less than significant with mitigation incorporated (Class II), less than significant (Class III) or no impact (Class IV).

2 - Class I = Significant and Unavoidable Impact; Class II = Less Than Significant Impact With Mitigation Incorporated; Class III = Less Than Significant Impact; Class IV = No Impact.

3 - For the purposes of the EIR’s cumulative analysis, the Wilmington and Inglewood Oil and Gas Fields are considered to be part of Study Region 1 as a whole and thus are not addressed individually. Similarly, the Sespe Oil and Gas Field is considered to be part of Study Region 2 as a whole and thus is not addressed individually.

The Final EIR concludes that the direct and indirect impacts associated with the project’s six alternatives could also range from significant and unavoidable (Class I) to no impact (Class IV). Collectively, significant and unavoidable impacts (Class I) were identified for aesthetics, agriculture and forestry resources, air quality, biological resources (terrestrial environment), cultural resources, coastal processes and marine water quality, geology, soils and mineral resources, greenhouse gas emissions, hazards and hazardous materials, groundwater resources, land use and planning, noise and vibration, paleontological resources, public services, recreation, risk of upset/public and worker safety, surface water resources, and trans-portation and traffic. Many of the significant and unavoidable impacts identified are related to Alterna-tive 6 (No Project Alternative) because its implementation would not include application of the mitiga-tion measures applied to the project and its alternatives (e.g., only implementation of DOGGR’s perma-nent regulations for well stimulation treatments would occur). All impacts associated with each project alternative are identified in Table ES-5 (Summary of Impacts for the Alternatives), starting on page ES-64.

ES.5 Environmentally Superior Alternative

As noted in the Draft EIR, the determination of an “environmentally superior alternative,” as required by State CEQA Guidelines Section 15126.6, is often somewhat subjective, as it requires a balancing of dif-ferent kinds of impacts against one another. Thus, it is possible that an alternative can be superior to others in certain impact categories and yet not be considered the overall environmentally superior alter-native. As such, in addition to identifying an overall environmentally superior alternative, this Final EIR also identifies the preferred alternative(s) for each resource area evaluated. An alternative identified as “preferred” for one resource topic may still have significant environmental effects, but when compared with the other alternatives, its environmental effects would be less than, or the same as, those of the other alternatives. Significant and unavoidable (Class I) impacts of the project are noted in Final EIR Executive Summary Table ES-1. Highlighting these impacts identifies whether any alternative would be capable of eliminating one or more significant and adverse environmental effects of the project, as well as which alternatives would create significant and adverse impacts.

Draft EIR Chapter 14 (Comparison of Alternatives), as revised for this Final EIR (Volume III) presents a preference ranking by alternative for each resource/issue-area analyzed, which allows consideration of all subjects equally. However, in the overall comparison of the project and its alternatives, the choice of the environmentally superior alternative during the decision making process may place more weight on certain issue areas than on others. For example, it is common for lead agencies to give greater weight to alternatives that reduce impacts to human health and biological resources than to alternatives that reduce impacts that are primarily sources of irritation to humans (such as noise impacts or impacts on aesthetics or transportation facilities). Here, reflecting what DOGGR considers to be among California’s current top regulatory concerns, DOGGR is particularly concerned with greenhouse gas emissions and water consumption, and has given greater weight to those categories of impact than to others. As such,



although this Final EIR identifies an environmentally superior alternative, it is possible that the decision maker may balance the importance of each impact area differently and reach different conclusions.

The Draft EIR identified the project as the environmentally superior alternative. The basis for this conclu-sion was that with implementation of the project standards for resource protection as related to water recycling, habitat, surface water and groundwater, and all recommended mitigation measures contained in that document, the project would have the fewest direct and indirect impacts. Numerous parties commented the Draft EIR’s alternatives analysis and the selection of the project as the environmentally superior alternative; these comments ranged from agreement with DOGGR’s determination to strong condemnation of the selection of any alternative other than the No Future Well Stimulation Treatments Alternative (Alternative 1) as the environmentally superior alternative. As a consequence of these com-ments, and similar comments on the project’s standards, great care was placed on consideration of the alternatives, as demonstrated in Final EIR Chapter C (Responses to Review Comments on the Draft Envi-ronmental Impact Report), and most notably Global Responses GR-15 and GR-16.

With implementation of all of the mitigation measures contained in this Final EIR, the project is still con-sidered to be the environmentally superior alternative. Alternatives 3 through 5 were designed to consolidate impacts and reduce overall ground disturbance, reduce impacts to urbanized areas, and reduce seismic impacts. Based upon the revised analysis contained in this Final EIR, the project would be largely similar to Alternatives 3 through 5, although somewhat less area might be affected under these alternatives. These alternatives, however, have been developed primarily for consideration by local agencies and would not be implemented by DOGGR by itself; thus they are largely outside of DOGGR’s control. It is also possible that these alternatives would not be implemented, as the local agencies at issue may choose not to take the actions recommended by these alternatives. Therefore, their imple-mentation is uncertain. Given that the impacts of the project and these three alternatives would be largely similar, DOGGR gave preference to the project because it could be solely implemented by DOGGR, and its implementation was not uncertain. Therefore, in contrast to Alternatives 3 through 5, the actions necessary to mitigate or avoid the environmental effects of the project would be under the control of DOGGR and reasonably expected to occur as described in this Final EIR.

Under Alternative 6 (the No Project Alternative), the project’s mitigation measures as identified in this EIR would not be implemented. Therefore, due to much greater environmental impacts associated with all issue areas except population and housing, where impacts would remain less than significant (Class III), Alternative 6 was not found to be environmentally preferable to the project.

Because Alternative 1 (the No Future Well Stimulation Alternative) would prohibit all well stimulation treatments within and outside of existing oil and gas fields, Alternative 1 would be environmentally superior for the programmatic level analysis at the Wilmington, Inglewood, and Sespe Oil and Gas Fields, because it would eliminate all direct environmental impacts, including all surface and subsurface distur-bances, associated with well stimulation activities. Although additional conventional wells would likely be drilled to make up for lost production, some wells may also be abandoned within the fields, which would partially offset this indirect impact. However, viewed on a larger programmatic level, the indirect impacts outside of those fields would create much greater impacts to greenhouse gas emissions from the importation of oil and gas from out of the State that would result if Alternative 1 were implemented. Given the importance in California law of efforts to address climate change (e.g., Assembly Bill 32, the California Global Warming Solutions Act), DOGGR has given considerable weight to this negative attribute of Alternative 1, and finds that, for this reason, Alternative 1 cannot be the environmentally superior alternative.



Similarly, Alternative 2 (the Not Future Well Stimulation Treatments Outside of Existing Oil and Gas Field Boundaries Alternative) is better than the project in some ways, because it would eliminate all direct impacts related to well stimulation outside of existing oil and gas fields. Additional wells may still be developed and stimulated within existing fields, which would reduce the need to drill new conventional wells or import oil and gas from out of State compared to Alternative 1. Therefore, indirect environmen-tal impacts would be reduced compared to those described under Alternative 1. However, because many of the mature oil and gas fields in California are in decline and Alternative 2 would prohibit devel-oping new fields that require well stimulation, there would be some loss of oil and gas reserves and pro-duction due to implementation of this alternative, which would result in similar indirect impacts as associated with Alternative 1. Among these indirect effects would be those associated with increased oil imports, most notably, an increase in greenhouse gas emissions. As with Alternative 1, DOGGR has concluded that, in light of the centrality of climate change policy under California law, Alternative 2 cannot be the environmentally superior alternative.

ES.6 Use and Application of the Final Environmental Impact Report Mitigation Measures

As addressed in Final EIR Volume I, Section A.8.2 (Revised Treatment of Project Standards for Resources Protection), DOGGR no longer proposes to implement any of the Project Standards for Resources Pro-tection (“standards”) as part of the project, as presented in Draft EIR Section 7.5 (Project Standards for Resource Protection), starting on Draft EIR page 7-48. Two of the Draft EIR standards, the Water Recycling Standard and the Surface Water Protection Standard, have been converted into mitigation measure (MM) GW-1a (Use Alternative Water Sources to the Extent Feasible) and MM SWR-1b (Surface Water Protection), respectively.

DOGGR has also determined that the intent of the Groundwater Protection Standard will be adequately addressed by a combination of existing laws and regulations and other mitigation measures, as revised and presented in Final EIR Volume II, Sections 10.4 (Biological Resources–Terrestrial Environment) and 10.14 (Groundwater Resources) (e.g., MMs GW-1a, GW-1b, GW-4a, GW-5a, GW-6a, and GW-7a and MMs BIOT-1a through BIOT-9a).

The Habitat Protection Standard has been eliminated, and has not been replaced. DOGGR has deter-mined that, taken together, the package of mitigation measures addressing impacts to terrestrial biolog-ical resources (MMs BIOT-1a through BIOT-9a) will be sufficient to protect the specific habitat types mentioned in the former proposed standard. The requirements in the Habitat Protection Standard as related to coastal and marine biological resources were always considered redundant because of exist-ing State and federal regulations that protect sensitive habitat. As a consequence, removal of this stand-ard did not require the creation of a new mitigation measure.

In addition to the above, DOGGR has comprehensively reviewed all of the Draft EIR mitigation measures in light of concerns expressed by various commenters (see Final EIR Chapter C (Responses to Review Comments on the Draft Environmental Impact Report)), and has revised a number of the mitigation measures that were presented in the Draft EIR. DOGGR has also eliminated some previously proposed mitigation measures entirely, added others, and, in some instances, has combined mitigation measures to avoid redundancy. Throughout this process, DOGGR’s primary objective was to stringently protect public health and the environment while avoiding the prospect of imposing generally applicable permit conditions on particular permit applicants whose well stimulation projects simply do not require such generally applicable conditions. For example, many well stimulation treatment projects, particularly those in highly developed existing oil and gas fields, will likely cause very minimal, if any, effects on



aesthetics, agricultural and forestry resources, cultural resources, paleontological resources, or habitat for special-status species. DOGGR has modified the original mitigation measures for these categories of impacts to ensure that conditions of approval will be imposed only where the resources at issue are likely actually present and in danger of being impacted. DOGGR’s expert engineers and other knowledgeable professionals also participated in this process with respect to certain mitigation mea-sures presented in the Draft EIR that, after much deliberation, were determined to be either unworkable or counterproductive from a practical standpoint.

The above-referenced revisions to the Draft EIR’s mitigation measures are detailed in Final EIR Volume I, Section A.8.3 (Revisions to Mitigation Measures in Response to Comments on the Draft EIR and Further Consideration of Their Applicability and Feasibility). These mitigation measures, as well as those that have not been modified since publication of the Draft EIR, are all listed in Final EIR Executive Summary Table ES-2.

Seven of the project’s final mitigation measures will be converted into proposed regulations and sub-jected to a formal rulemaking process under the Administrative Procedure Act. When the final regula-tions are in place, they will appear in DOGGR’s regulations in Title 14 of the California Code of Regula-tions. These mitigation measures include:

New Mitigation Measure GW-1a, which is based on the former proposed Resource Protection Stand-ard for Water Recycling;

Mitigation Measure GW-4b, as modified in this Final EIR, which requires, for a new well drilled for a stimulation treatment, that the well contain an annular 500-foot cement seal extending across the base of protected water and that the integrity of the seal will prevent unintended migration of fluids;

New Mitigation Measure SWR-1b, which is based on the former proposed Resource Protection Stand-ard for Surface Water as found in Draft EIR Section 7.5.3;

Mitigation Measures GEO-1a and GEO-1b, which require that the Spill Contingency Plan already required for each oil and gas well by Section 1722.9 of Title 14 of the California Code of Regulations include as additional contents well control and well shut-in procedures that adequately address the consequences of the rupture of a known fault, seismically induced ground shaking, and/or ground failure that could occur during the well stimulation process;

Mitigation Measure GEO-1e, which requires that the Spill Contingency Plan also include elements of an earthquake response plan; and

Mitigation Measure HAZ-1a, which requires that the Spill Contingency Plan be sufficient to prevent any leaks, spills, or other discharges of well stimulation fluids, flowback fluids, produced water, haz-ardous chemicals, contaminated surface water runoff, oil, or other potentially dangerous materials that might occur before, during, and after the well stimulation process from reaching the soil at all site pads.

The remaining mitigation measures contained in this EIR will be included in a Mitigation Policy Manual that DOGGR will use for determining the exact mitigation measures that might be necessary for a partic-ular proposed well stimulation treatment permit or groups of permits, depending on circumstances and the potential severity of impacts that might occur. The measures in the Mitigation Policy Manual will represent DOGGR’s starting point for determining what level of site-specific mitigation will be required for individual well stimulation treatment permits or groups of permits. Particular mitigation measures will not be required absent the kinds of significant impacts to which they are addressed. Further, even where there are significant impacts of the kind at which DOGGR’s mitigation measures are aimed,



DOGGR may not impose the measures exactly as they are written. Before imposing any measures with-out change, however, DOGGR will first ascertain whether site-specific revisions might be appropriate, and whether there might already be similar alternative mitigation strategies in place based on past local government regulatory actions governing the oil and/or gas field in question. In determining whether any revisions are required, DOGGR will also consult, through environmental review, with permit appli-cants, affected or interested State and local agencies, and/or interested members of the public regard-ing how, if at all, the Final EIR mitigation measures may be modified to address the specific conditions applicable to individual permits.

The mitigation measures in the Mitigation Policy Manual, as used in support of site-specific Mitigated Negative Declarations and EIRs, will “set a floor,” albeit a somewhat flexible one, for future mitigation that DOGGR will impose as permit conditions. In their final form after input from various stakeholders, the mitigation measures for individual permits or groups of permits will have to be substantially consis-tent with the measures found in the Mitigation Policy Manual. In determining whether a particular mea-sure is substantially consistent with DOGGR’s own recommended mitigation, DOGGR will take full account of the following: (1) any local lead agency’s analysis as to whether a particular impact is signifi-cant and thus requires feasible mitigation, if any is available; and (2) the extent to which the level of any impact reduction that would be achieved by the locally imposed measure would be reasonably compar-able to the level of mitigation that would have been achieved by the DOGGR-recommended measures.

The above-referenced seven mitigation measures (MMs GW-1a, GW-4b, SWR-1b, GEO-1a, GEO-1b, GEO-1e and HAZ-1a) will be temporarily included within the Mitigation Policy Manual with the understanding that they will simultaneously be converted into proposed regulations and subjected to a formal rulemaking process. When the final regulations are in place, they will be deleted from the Mitigation Policy Manual. Similarly, other mitigation measures in the Mitigation Policy Manual might also be included only temporarily. Using its authority under PRC Section 3106(a), DOGGR has developed mitiga-tion measures that it hopes, and in some cases anticipates, will be superseded by new regulation or other enforceable requirements imposed in the future by sister agencies, such as the Air Resources Board and the State Water Resources Control Board. DOGGR’s measures will function as placeholders, ensuring stringent mitigation, until such time as the sister agencies’ requirements are in place. Examples of this kind include MM AQ-2a (Reduce Hydrocarbon Emissions from Well Stimulation Treatments), MM GHG-1a (Prevent Methane Emissions from Associated Gas and Casinghead Gas), MM GHG-1b (Reduce Emissions by Implementing Clean Development Mechanism (CDM) Strategies), MM GHG-1c (Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide), and MM GW-7a (Add a Tracer to Well Stim-ulation Fluids or Develop a Reasonable Method to Distinguish Well Stimulation Fluids in the Environment).

ES.7 Areas of Known Controversy

Draft EIR Executive Summary Section ES.8 (Areas of Known Controversy) (Final EIR Volume II) outlines the national and State areas of known controversy related to well stimulation treatments; no substantive changes to, or resolution of, these issues has occurred since the Draft EIR’s publication, and they are incorporated herein by reference.

As demonstrated in Final EIR Chapter B (Draft Environmental Impact Report Review Comments) and its corresponding Appendix 1 (Draft Environmental Impact Report Comment Correspondence and Public Meeting Transcripts), public opinion regarding well stimulation treatments is highly varied, including full support, neutrality and acute opposition. Numerous parties that have participated in the EIR’s environ-mental review process assert that the analyses and mitigation measures contained in the document are



not rigorous enough to avoid or minimize the potential impacts of well stimulation treatments, while others contend that the document’s analysis and recommended mitigation measures exceed what is proportionate to identified impacts and thus should not be required. It is noted that the EIR’s analysis is programmatic in nature and that it expressly states, and frequently reiterates, that the potential for impacts, their significance, and required mitigation measures at a project level of analysis in the future will be contingent on site-specific conditions. It is also noted that the EIR, without bias, considers the potential impacts of well stimulation treatments and the potentially feasible mitigation measures that can be applied to minimize them, and that, to date, impartial technical and scientific assessment of well stimulation treatments both in California and nationally remains a relatively new field of study, and that a large percentage of the materials on well stimulation treatments that are publicly available have a predisposition either in favor of, or against, these practices. To this end, it is concluded that the public remains severely divided on the subject of whether well stimulation treatments should be entirely pro-hibited at a statewide level, or if they should remain legal practices, with or without implementation of DOGGR’s permanent regulations and the mitigation measures recommended in this EIR.

ES.8 Issues to be Resolved

The issues to be resolved regarding well stimulation treatments remain the same as those that were provided in Draft EIR Executive Summary Section ES.9 (Final EIR Volume II), and they are incorporated herein by reference.

As noted in Final EIR Executive Summary Section ES.7 (Areas of Known Controversy), the controversy regarding well stimulation treatments is not expected to be resolved as a consequence of this EIR; the effectiveness of DOGGR’s permanent regulations and the mitigation measures recommended herein remains to be realized in the future. Once their effectiveness is established, decision makers will then need to make a determination as to whether further regulation and/or study is warranted.

Current Review and Future Regulatory Amendment to DOGGR’s Underground Injection Control Pro-gram: Background and Discussion. As related to oil and gas exploration and development as a whole, within which well stimulation treatments are included, Class II injection wells are defined by the U.S. Environmental Protection Agency (EPA) as wells “that inject brines and other fluids associated with oil and gas production, or storage of hydrocarbons. Class II well types include salt water disposal wells, enhanced recovery wells, and hydrocarbon storage wells.” There are three types of Class II injection wells: (1) Enhanced Recovery Wells (or Enhanced Oil Recovery [EOR] Wells), which inject brine, water, steam, polymers, or carbon dioxide into oil-bearing formations to recover residual oil and, in some lim-ited applications, natural gas; (2) Disposal Wells, which inject brines and other fluids associated with the production of oil and natural gas or natural gas storage operations; and (3) Hydrocarbon Storage Wells, which inject liquid hydrocarbons in underground formations where they are stored, generally, as part of the U.S. Strategic Petroleum Reserve.

States may request that the EPA provide them with direct “primacy,” or regulatory authority, to imple-ment and enforce the requirements of the federal Safe Drinking Water Act (SDWA) for Class II injection wells if it can be demonstrated to the EPA’s satisfaction that that state’s Underground Injection Control (UIC) program is fully compliant with either SDWA Section 1422 or Section 1425, as follows:

Section 1422 requires states to meet the EPA’s minimum requirements for UIC programs. Programs authorized under section 1422 must include the construction, operation, monitoring and testing, reporting, and closure requirements for well owners or operators. EOR wells may either be issued permits or be authorized by rule (e.g., regulation). Disposal wells are issued permits. The owners or



operators of the wells must meet all applicable requirements, including strict construction and con-version standards and regular testing and inspection.

Section 1425 allows states to demonstrate that their existing standards and regulations are effective in preventing endangerment of Underground Source[s] of Drinking Water (USDWs). These programs must include permitting, inspection, monitoring, and record-keeping and reporting that demonstrates the effectiveness of their requirements.

In regard to SDWA Section 1425, an USDW is defined as an “aquifer or portion of an aquifer that supplies any public water system or that contains a sufficient quantity of ground water to supply a public water system, and currently supplies drinking water for human consumption, or that contains fewer than 10,000 milligrams per liter (mg/l) of total dissolved solids (TDS) and is not an exempted aquifer [40 Code of Federal Regulations Section 144.3].” An exempted aquifer is defined as an “aquifer, or a portion of an aquifer, that meets the criteria for a USDW, for which protection under the SDWA has been waived by the UIC Program. [A]n aquifer may be exempted if it is either not currently being used, and will not be used in the future, as a drinking water source, or it is not reasonably expected to supply a public water system due to a high total dissolved solids content. Without an aquifer exemption, certain types of energy production, mining, or waste disposal into USDWs would be prohibited.” The EPA makes the final determination on granting or denying all aquifer exemptions.

In 1983, DOGGR obtained primacy from the EPA to implement and enforce the requirements of the SDWA for the protection of USDWs pursuant to the State’s Class II UIC program. In 2011, an audit was completed, on behalf of the EPA, to review DOGGR’s practices and regulations to ensure compliance with its obligations to properly administer its Class II UIC program pursuant to the federal SDWA and applicable California law. The audit identified several areas of concern for which the EPA requested that DOGGR and the State Water Resources Control Board (State Water Board), which assists DOGGR with the UIC Program’s implementation, prepare a corrective plan.

In addition, DOGGR and the EPA have established that some existing Class II wells were injecting into 11 aquifers that had been treated historically as exempted may not actually qualify for exemption. These wells are associated with one oil and gas field located in EIR Study Region 2, six oil and gas fields located in EIR Study Region 4, and two gas fields located in EIR Study Region 6.

In a letter to the EPA dated February 6, 2015, DOGGR and the State Water Board outlined a corrective plan to bring DOGGR into compliance with all aspects regarding the SDWA, noting that several items in need of correction could be implemented either through existing regulations or with further amend-ment to existing regulations, but that the development and adoption of these new or amended regula-tions would be require time. The letter also outlined a schedule for addressing injection into USDWs, either by obtaining EPA aquifer exemptions or by prohibiting injection into these aquifers. The Class II injection compliance schedule currently includes the following:

October 15, 2015: Well shut-in completion date for injection into non-hydrocarbon-bearing aquifers with less than 3,000 mg/L TDS that do not have an aquifer exemption.

December 31, 2016: Well shut-in completion date for the 11 specific aquifers historically treated as exempted by the EPA unless the EPA takes further action to affirm exemption of the pertinent aquifer(s) before that date.

February 15, 2017: Well shut-in completion date for injection into aquifers with less than 10,000 mg/L TDS that do not have an aquifer exemption.



On April 20, 2015, emergency regulations for DOGGR’s UIC program were put into effect for the above-referenced compliance schedule, as approved by the Office of Administrative Law (OAL), adopting Sec-tions 1760.1 and 1779.1 into Title 14 of the California Code of Regulations. While these regulations are in effect, DOGGR will continue its development, finalization, and adoption of both amended and new regulations for compliance with the SWDA. DOGGR anticipates consideration of new or amended regula-tions for the following:

Well construction and cementing requirements

Plugging and abandoning requirements

Evaluation of the zone of endangering influence (ZEI)

Requirements for fluid disposal

Requirements for monitoring of zone pressure

Annual project reviews

Well monitoring requirements

Inspections and compliance/enforcement practices and tools

Idle-well planning and testing program

Cyclic steam injection wells

Production from diatomite

These regulations are anticipated to be extensive and will require a considerable amount of time to develop. They will also require extensive coordination and input from the EPA, State Water Board, Regional Water Quality Control Boards, other State agencies, oil and gas operators, local agencies, non-government organizations and the public.

As of the time of this Final EIR’s publication, a schedule for completion and adoption of the above-refer-enced new and amended regulations had not been established. While it is important to recognize that SB 4, through its amendment to the State’s Water Code, specifically Sections 10783(g)(2) and (k)(2), requires consideration of the EPA’s definition of USDWs and exempted aquifers as related to well stimu-lation treatments, it must also be understood that DOGGR’s forthcoming new and amended regulations may further govern such practices in the future.



Table ES-2. Summary of Impacts and Mitigation Measures for the Project

Subject / Impact Criteria1 Impact Significance

with Mitigation Incoporated2 Mitigation Measures

Aesthetics


Class III in existing fields;

Class I or II in new areas

AES-1a: Prepare and Implement a Site Plan to Reduce Visual Impacts to Sensitive Receptors

AES-1b: Minimize Lighting Visibility Offsite


















Class II on or adjacent to Important Farmland

AGF-1a: Minimize Impacts to Important Farmland

AGF-1b: Develop an Agricultural Resources Protection Plan

AGF-1c: Compensate for Loss of Important Farmland


Class II on land zoned for agricultural use or enrolled in Williamson Act contracts

AGF-2a: Ensure Compatibility with Agricultural Zoning

AGF-2b: Ensure Compatibility with Williamson Act Contracts or Terminate Williamson Act Contracts


Class II on land zoned as forestland, timberland, or Timberland Production

AGF-3a: Ensure Compatibility with Forest and Timberland Zoning


Class II on forest land AGF-4a: Minimize Impacts to Forest Land

AGF-4b: Develop a Forest Land Protection Plan

AGF-4c: Compensate for Loss of Forest Land







Class II for well stimulation activities on or within 1,500 feet of agricultural or forest land


AGF-1b: Develop an Agricultural Resources Protection Plan MM

AGF-4a: Minimize Impacts to Forest Land


AQ-2c: Reduce Emissions from Dust-Causing Activities

BIOT-2a: Prevent Hazards to Fish and Wildlife

HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials

GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments

SWR-1a: Require Stormwater Pollution Prevention Plan

SWR-2a: Implement Erosion Control Plan

SWR-3a: Ensure Adequate Water Availability

TR-1a: Prepare Traffic Plan

Air Quality


Class I (Statewide)

Class III (in SCAQMD)

AQ-1a: Improve Air Quality Planning Inventories and Local Control Measures

AQ-1b: Improve the Methodologies and Emission Factors Used in Inventory Development


Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments

AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources



Class I AQ-3a: Comply with Local Air District Protocols Relating to the Preparation of a Health Risk Assessment and Implement Emission Controls

AQ-3b: Avoid Unnecessary Exposure to Air Pollutants by Improving Local Land Use Compatibility


Class I AQ-4a: Prepare and Implement an Odor Minimization Plan

AQ-4b: Avoid Unnecessary Exposure to Odors by Improving Local Land Use Compatibility








Class I, II, or III BIOT-1a: Evaluate Impacts to Native Vegetation and Fish and Wildlife Habitat

BIOT-1b: Minimize Impacts to Native Vegetation and Habitat

BIOT-1c: Replace or Offset Loss of Sensitive Habitat GW-1a: Use Alternative Water Sources to the Extent Feasible GW-1b: Minimize Groundwater Impacts







Class I, II, or III BIOT-1b: Minimize Impacts to Native Vegetation and Habitat

BIOT-1c: Replace or Offset Loss of Sensitive Habitat


BIOT-2b: California Condor Protection Measures

BIOT-2c: Nelson’s Bighorn Sheep Protection Measures

BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife

BIOT-4b: Minimize Impacts to Protected Birds

BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials SWR-1a: Require Stormwater Pollution Prevention Plan












BIOT-3b: Minimize and Mitigate Impacts to Special-status Plants


BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement AQ-2c: Reduce Emissions from Dust-Causing Activities








BIOT-4a Minimize and Mitigate Impacts to all species identified as a candidate, sensitive, or special-status species in local or regional plans, policies, or regulations, or by CDFW or USFWS


BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement





AQ-2c: Reduce Emissions from Dust-Causing Activities GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments

SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection














BIOT-6a: Protect Jurisdictional Waters GW-1a: Use Alternative Water Sources to the Extent Feasible GW-1b: Minimize Groundwater Impacts GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation






Class I, II, or III BIOT-7a: Prevent Habitat Fragmentation and Impacts to Fish and Wildlife Movement


Class I, II, or III BIOT-8a: Coordinate with Local Agencies and Jurisdictions Regarding Local Policies and Conservation Plans


Class I, II, or III BIOT-9a: Coordinate with CDFW, USFWS, and Permittees Regarding NCCPs, HCPs, and Other Conservation Plans







Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments


GHG-1a: Prevent Methane Emissions from Associated Gas and Casinghead Gas

GHG-1b: Reduce Emissions by Implementing Clean Development Mechanism (CDM) Strategies

GHG-2a: Require Applicant to Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program



Class III No mitigation required







Class II CPMWQ-1a: Protect Marine Water Quality


Class II CPMWQ-2a: Prepare and Implement Marine Current Plan









Class IV No mitigation required

Impact CPMWQ-5: Increase the risk of a tsunami







Cultural Resources


Class I or Class II if historic or built-environment resources are present

Class III or Class IV if historic or built-environment resources are not considered significant or are not present

CUL-1a: Require Information and Evaluate Cultural Resources

CUL-1b: Complete Native American Coordination

CUL-1c: Prepare and Implement Cultural Resources Management and Treatment Plan

CUL-1d: Prepare Plan for the Inadvertent Discovery of Human Remains

CUL-1e: Provide Cultural Resources Specialist with the Authority to Halt Earth Disturbing Activities

CUL-1f: Conduct a Cultural Resources Worker Environmental Awareness Program

CUL-1g: Monitor Earth Disturbing Activities for Cultural Resources

CUL-1h: Provide Native American Monitors during Earth Disturbing Activities

CUL-1i: Prepare Cultural Resources Documents for the Monitoring of Earth Disturbing Activities

CUL-1j: Curate all Discovered Cultural Resources Associated with Earth Disturbing Activities






Impact CUL-2: Affect prehistoric resources Class I or II if prehistoric resources are present

Class III or Class IV if prehistoric resources are not considered significant or are not present












Class I or II if human remains or cultural items are present

Class III or Class IV if cultural items are not considered significant or are not present

Class IV if human remains are not present
















Impact CUL-4: Affect cultural landscapes Class I or II if cultural landscapes are present

Class III or Class IV if cultural landscapes are not considered significant or are not present













Unknown EJ-1a: Track Characteristics of Affected Populations in the Vicinity of Well Stimulation Treatments

Geology, Soils, and Mineral Resources


Class II GEO-1a: Avoid Active Faults if Necessary

GEO-1b: Implement an Appropriate Setback if Necessary

GEO-1c: Implement Industry Accepted Practices

GEO-1d: Conduct Ground Monitoring

GEO-1e: Include an Earthquake Response Plan within the Spill Response Plan


Class II SWR-1a: Require Stormwater Pollution Prevention Plan



Class II GEO-3a: Prepare Geotechnical Report if Necessary









Class IV No mitigation required

Impact GEO-6: Result in the loss of availability of known mineral resource loss of a locally important mineral resource recovery site delineated on a local general plan, specific plan or other land use plan

Class III in most instances; Class I in some instances

No mitigation proposed





Class I AQ-2a: Reduce Emissions from Well Stimulation Treatments




GHG-1c: Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide


Class I AQ-2a: Reduce Emissions from Well stimulation Treatments



GHG-2a: Require Applicant Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program



Class II HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials


Impact GW-1: Cause or contribute to overdraft conditions

Class II GW-1a: Use Alternative Water Sources to the Extent Feasible

GW-1b: Minimize Groundwater Impacts







Class II GW-1a: Use Alternative Water Sources to the Extent Feasible GW-1b: Minimize Groundwater Impacts


Class II HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials


Class II GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation Treatment

GW-4b: Install a Well Seal across Protected Groundwater for New Wells Subject to Well Stimulation Treatments

GW-4c: Install Methane Sensors on Wells Subject to Well Stimulation Treatments


Class II GW-5a: Conduct Surface Geophysical Surveys or Apply Other Field Methods to Locate Improperly Abandoned Wells and Mitigate


Class II GW-6a: Require Wastewater Disposal Wells to Inject Only into Exempted Aquifers to Protect Groundwater


Class II GW-7a: Add a Tracer to Well Stimulation Fluids or Develop a Reasonable Method to Distinguish Well Stimulation Fluids in the Environment



Class I None available for unavoidable and significant impacts associated with Risk of Upset/Public and Worker Safety

Impact LU-2: Physically divide an established community



Class II PRC Section 1783.2 requiring “Neighbor Notification”

All mitigation measures prescribed in this EIR






Noise and Vibration


Class II NOI-1a: Control Noise Levels near Sensitive Land Uses





Class II if fossil bearing geologic units are present

Class IV if no fossil bearing units are present

PALEO-1a: Require Information and Evaluate Paleontological Resources

PALEO-1b: Develop Paleontological Resource Mitigation Plan

PALEO-1c: Retain Qualified Paleontological Resources Staff

PALEO-1d: Conduct a Paleontological Resources Worker Environmental Awareness Program

PALEO-1e: Monitor Earth Disturbing Activities for Paleontological Resources

PALEO-1f: Provide Qualified Paleontological Resources Monitor with Authority to Halt Earth Disturbing Activities

PALEO-1g: Prepare Paleontological Resources Report for the Monitoring of Earth Disturbing Activities

PALEO-1h: Curate all Discovered Paleontological Resources Associated with Earth Disturbing Activities


Impact POP-1: Induce substantial population growth









Public Services


Class II (Fire or Police Services); Class III (Population Growth)

PUB-1a: Assess Public Service Ratios and Ensure Adequate Compensation

HAZ-1: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials


Recreation



Impact REC-2: Cause disruptions in designated recreation areas

Class II REC-2a: Coordinate Well Stimulation Treatment Schedule with Managing Officer(s) for Affected Recreation Areas

REC-2b: Provide Noticing of Closures and Identify Alternative Recreation Areas

Risk of Upset / Public and Worker Safety


Class I RSK-1a: Increase the Number of CPUC Rail Inspectors

RSK-1b: Expedite the Phase-out of Older Tank Cars

RSK-1c: Implement New Accident Prevention Technology

RSK-1d: Monitor and Enforce New Speed Limits

RSK-1e: Monitor the Implementation of Trackside Safety Technology

RSK-1f: Improve Emergency Preparedness and Response Programs

RSK-1g: Provide Real-Time Shipment Information to Emergency Responders

RSK-1h: Provide Additional Accident and Injury Data to the State


Class II RSK-2a: Reduce the Inventory/Volumes Handled with the Hazardous Chemicals

RSK-2b: Conduct a Facility Siting Study or a Quantitative Risk Assessment

RSK-2c: Ensure Mechanical Integrity Program Through Compliance with Permanent Regulation

Impact RSK-3: Increase the potential for major oil spills due to ship groundings and collisions








Class II RSK-4a: Conduct a Process Hazard Analysis (PHA) followed by a Layer of Protection Analysis (LOPA) to Ensure Installation of Proper Safety Interlocks


Class II RSK-5a: Prepare and Implement the Procedures to Avoid Pump Cavitation during all Well Stimulation Activities

RSK-5b: Verify the Need of Installation of Flame Arresters on the Tank Vents

RSK-5c: Prepare and Implement a Control of Ignition Sources Plan


Class I RSK-6a: Increase Inspection of Mechanical Integrity RSK-6b: Improve Leak Detection Capability RSK-6c: Reduce Mainline Valve Spacing


Class II RSK-7a: Use Alternative Proppant (e.g., Sintered Bauxite, Ceramics, Resins) or Use Alternative Proppant Delivery System

RSK-7b: Reduce Emissions from Dust-Causing Activities



Class II SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection

SWR-1c: Provide Adequate Flood Protection

SWR-1d: Protect Surface Water Reservoirs



Class II SWR-2a: Implement Erosion Control Plan

Impact SWR-3: Substantially diminish surface water quantity

Class II SWR-3a: Ensure Adequate Water Availability







Class II SWR-1c: Provide Adequate Flood Protection



Class III for project activities in Study Region 6 and for existing fields

Class II outside of existing oil and gas fields in Study Regions 1-5 where 10 or more wells are drilled by a single applicant within one square mile


Impact TR-2: Inadvertently damage road rights-of-way

Class III for project activities in Study Region 6 and in existing oil and gas fields


TR-2a: Repair Roadway Damage





Impact TR-4: Transport hazardous materials Class I TR-4a: Know Spill Prevention Measures

Impact TR-5: Change air traffic patterns Class IV if no airports are nearby

Class III if FAA notification under 14 CFR 77 is required

No mitigation required

Impact TR-6: Temporarily interfere with emergency response


Class II in Study Regions 1-5 outside of existing oil and gas fields













Class II UTL-3a: Assess Wastewater Quality and Ensure Adequate Capacity to Process Wastewater at Municipal and Private Wastewater Treatment Plants

Impact UTL-4: Exceed permitted solid waste capacity of landfills

Class II UTL-4a: Assess Non-Hazardous Solid Waste Generation and Ensure Adequate Capacity to Accept Solid Waste at Municipal and Private Solid Waste Facilities






Impact EN-3: Cause an adverse effect on peak and base period demands for electricity and other forms of energy because of ineffi-cient, wasteful, or unnecessary energy use


Impact EN-4: Disrupt compliance with existing energy standards










Table ES-3. Summary of Impacts and Mitigation Measures for the Project: Analysis of Specific Oil and Gas Fields

Impact Significance with Mitigation Incorporated,

by Oil & Gas Field2

Subject / Impact Criteria1 Wilmington Inglewood Sespe Mitigation Measures

Aesthetics


Class III Class III Class III No mitigation required









Class IV Class IV Class II Wilmington and Inglewood: No mitigation required Sespe: AGF-2b: Ensure Compatibility with Williamson Act Contracts or Terminate Williamson Act Contracts


Class IV Class IV Class II Wilmington and Inglewood: No mitigation required Sespe: Same as for the project (see Table ES-2)


Class IV Class IV Class IV No mitigation required


Class IV Class IV Class II Wilmington and Inglewood: No mitigation required Sespe: Same as for the project (see Table ES-2)





by Oil & Gas Field2



Class IV Class II Class II Wilmington: No mitigation required Inglewood and Sespe: Same as for the project (see Table ES-2)

Air Quality


Class III Class III Class III Wilmington and Inglewood: No mitigation required Sespe: AQ-1a: Improve Air Quality Planning Inventories and Local Control Measures AQ-1b: Improve the Methodologies and Emission Factors Used in Inventory Development


Class I Class I Class I Same as for the project (see Table ES-2)







Class I, II, or III Class I, II, or III Class I, II, or III Class III Impacts: No mitigation required Class I and II Impacts: Same as for the project (see Table ES-2)





by Oil & Gas Field2



Class I, II, or III Class I, II, or III Class I, II, or III Class III Impacts: No mitigation required Class I and II Impacts: Wilmington and Inglewood: BIOT-1b: Minimize Impacts to Native Vegetation and Habitat BIOT-1c: Replace or Offset Loss of Sensitive Habitat BIOT-2a: Prevent Hazards to Fish and Wildlife BIOT-3a: Minimize and Mitigate Impacts to Special-status Fish and Wildlife BIOT-4b: Minimize Impacts to Protected Birds BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials SWR-1a: Require Stormwater Pollution Prevention Plan SWR-2a: Implement Erosion Control Plan Sespe: Same as above and BIOT-2b: California Condor Protection Measures BIOT-2c: Nelson’s Bighorn Sheep Protection Measures


Class I, II, or III Class I, II, or III Class I, II, or III Class III Impacts: No mitigation required Class I and II Impacts: Wilmington and Inglewood: Same as for the project (see Table ES-2) Sespe: Same as for the project (see Table ES-2) and BIOT-2b: California Condor Protection Measures BIOT-2c: Nelson’s Bighorn Sheep Protection Measures





by Oil & Gas Field2



Class I, II, or III Class I, II, or III Class I, II, or III Class III Impacts: No mitigation required Class I and II Impacts: Wilmington and Inglewood: Same as for the project (see Table ES-2) Sespe: Same as for the project (see Table ES-2) and BIOT-2b: California Condor Protection Measures BIOT-2c: Nelson’s Bighorn Sheep Protection Measures






Class III Class III Class I, II, or III Class III Impacts: No mitigation required Class I and II Impacts: Same as for the project (see Table ES-2)





by Oil & Gas Field2



Class II or III Class III Class II or III Class III Impacts: No mitigation required Class II Impacts: Same as for the project (see Table ES-2)


Class II or III

Class II or III

Class II or III Class III Impacts: No mitigation required Class II Impacts: Same as for the project (see Table ES-2)





Class III N/A N/A No mitigation required







by Oil & Gas Field2






Class II N/A N/A Wilmington: Same as for the project (see Table ES-2) Inglewood and Sespe: No mitigation required


Class II N/A N/A Wilmington: Same as for the project (see Table ES-2) Inglewood and Sespe: No mitigation required




Class IV N/A N/A No mitigation required







by Oil & Gas Field2







Cultural Resources


Class I or Class II if historic or built-environment resources are present; Class III or Class IV if historic or built-environment resources are not considered significant or are not present



Class I and II Impacts: Same as for the project (see Table ES-2) Class III and IV Impacts: No mitigation required


Class I or II if pre-historic resources are present; Class III or Class IV if prehistoric resources are not considered significant or are not present








by Oil & Gas Field2



Class I or II if human remains or cultural items are present; Class III or Class IV if cultural items are not considered significant or are not present Class IV if human remains are not present




Impact CUL-4: Affect cultural landscapes

Class I or II if cultural landscapes are present; Class III or Class IV if cultural landscapes are not considered significant or are not present






Unknown Unknown Unknown Wilmington: Same as for the project (see Table ES-2), except GEO-1a would not be required (see Table ES-2) Inglewood and Sespe: Same as for the project (see Table ES-2)





by Oil & Gas Field2




Class II Class II Class II Same as for the project (see Table ES-2)









Impact GEO-6: Result in the loss of availability of known mineral resource or loss of a locally important mineral resource recovery site delineated on a local general plan, specific plan or other land use plan








by Oil & Gas Field2




Class I to Class III Class I Class I to Class III Class I and II Impacts: Same as for the project (see Table ES-2) Class III Impacts: No mitigation required


Class III Class I Class III Inglewood: Same as for the project (see Table ES-2) Wilmington and Sespe: No mitigation required



Class II Class II Class II Same as for the project (see Table ES-2) and HAZ-1b: Require the Operator to Conduct an Annual Inventory of Its Well Stim-ulation Equipment and Report of the Aged Infrastructure and Its Likelihood of Failure Leading to Spills or Leaks to DOGGR


Impact GW-1: Cause or contribute to overdraft conditions

Class II Class II Class III Wilmington and Inglewood: Same as for the project (see Table ES-2) Sespe: No mitigation required


Class II Class II Class III Wilmington and Inglewood: GW-1b: Minimize Groundwater Impacts Sespe: No mitigation required









by Oil & Gas Field2










Class II Class I Class III Wilmington: HAZ-1a: Provide a Physical Barrier on the Ground Surface at the Site Pad for All Production Facilities, Regardless of the Amount of Time They Are in Place, Prior to Moving in Hazardous Materials and Manage Surface Water Runoff and Drainage on the Barrier Using Best Management Practices HAZ-1b: Require the Operator to Conduct an Annual Inventory of its Well Stimulation Equipment and Report of the Aged Infrastructure and its Likelihood of Failure Leading to Spills or Leaks to DOGGR RSK-2a: Conduct a Reactive Hazard Assessment (RHA) RSK-2b: Reduce the Inventory/Volumes Handled with the Hazardous Chemicals RSK-2c: Install an Upgraded SCADA System RSK-2d: Conduct a Facility Siting Study or a Quantitative Risk Assessment RSK-2e: Use Totes or Hazardous Materials Storage Containers Provided with a Protective Outer Shell or a Double Containment Storage System RSK-2f: Ensure Mechanical Integrity Program Complies with Regulation





by Oil & Gas Field2


Impact LU-1, continued RSK-4a: Conduct a Process Hazard Analysis (PHA) Followed by a Layer of Protection Analysis (LOPA) to Ensure Installation of Proper Safety Interlocks RSK-5a: Prepare and Implement the Procedures to Avoid Pump Cavitation during all Well Stimulation Activities RSK-5b: Verify the Need of Installation of Flame Arresters on the Tank Vents RSK-5c: Prepare and Implement a Control of Ignition Sources Plan RSK-7a: Use Alternative Proppant (e.g., Sintered Bauxite, Ceramics, Resins) RSK-7b: Reduce Emissions from Dust-Causing Activities REC-2a: Coordinate Well Stimulation Treatment Schedule with Managing Officer(s) for Affected Recreation Areas REC-2b: Provide Noticing of Closures and Identify Alternative Recreation Areas Inglewood: Same as for the project (see Table ES-2) Sespe: No mitigation required




Class II Class II Class II Wilmington and Sespe: HAZ-1a: Provide a Physical Barrier on the Ground Surface at the Site Pad for All Production Facilities, Regardless of the Amount of Time They Are in Place, Prior to Moving in Hazardous Materials and Manage Surface Water Runoff and Drainage on the Barrier Using Best Management Practices HAZ-1b: Require the Operator to Conduct an Annual Inventory of its Well Stimulation Equipment and Report of the Aged Infrastructure and its Likelihood of Failure Leading to Spills or Leaks to DOGGR RSK-2a: Reduce the Inventory/Volumes Handled with the Hazardous Chemicals RSK-2b: Conduct a Facility Siting Study or Quantitative Risk Assessment RSK-2c: Ensure Mechanical Integrity Through Compliance with Permanent Regulation





by Oil & Gas Field2


Impact LU-3. continued RSK-4a: Conduct a Process Hazard Analysis (PHA) Followed by a Layer of Protection Analysis (LOPA) to Ensure Installation of Proper Safety Interlocks RSK-5a: Prepare and Implement the Procedures to Avoid Pump Cavitation during all Well Stimulation Activities RSK-5b: Verify the Need of Installation of Flame Arresters on the Tank Vents RSK-5c: Prepare and Implement a Control of Ignition Sources Plan RSK-7a: Use Alternative Proppant (e.g., Sintered Bauxite, Ceramics, Resins) RSK-7b: Reduce Emissions from Dust-Causing Activities REC-2a: Coordinate Well Stimulation Treatment Schedule with Managing Officer(s) for Affected Recreation Areas REC-2b: Provide Noticing of Closures and Identify Alternative Recreation Areas Inglewood: Same as for the project (see Table ES-2)

Noise and Vibration







Class II if fossil bearing geologic units are present; Class IV if no fossil bearing units are present



Class II Impacts: Same as for the project (see Table ES-2) Class IV Impacts: No mitigation required





by Oil & Gas Field2






Class IV Class III Class III No mitigation required

Public Services


Class II Class II Class II Same as for the project (see Table ES-2) and HAZ-1b: Require the Operator to Conduct an Annual Inventory of Its Well Stimulation Equipment and Report of the Aged Infrastructure and Its Likelihood of Failure Leading to Spills or Leaks to DOGGR

Recreation




Class II Class II Class II Sespe: No mitigation required Wilmington an Inglewood: Same as for the project (see Table ES-2)



Class I Class IV Class I Class I Impacts: Same as for the project (see Table ES-2) Class IV Impacts: No mitigation required





by Oil & Gas Field2




Impact RSK-3: Increase the potential for major oil spills due to ship groundings and collisions

Class III Class IV Class IV No mitigation required







RSK-7: Expose workers and public to hazardous levels of airborne silica during the use of proppant






by Oil & Gas Field2




Class II Class II Class II Wilmington, Inglewood, and Sespe: SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection SWR-1c: Provide Adequate Flood Protection


Class II Class II Class II Wilmington: Same as for the project (see Table ES-2) Inglewood: Same as for the project (see Table ES-2) and mitigation measures in the Baldwin Hills CSD Final EIR (LA County, 2008) Sespe: Same as for the project (see Table ES-2) and SWR-1d: Protect Surface Water


Class II Class II Class II Wilmington and Sespe: Same as for the project (see Table ES-2) Inglewood: Same as for the project (see Table ES-2) and mitigation measures in the Baldwin Hills CSD Final EIR (LA County, 2008)


Class II Class II Class II Wilmington and Sespe: Same as for the project (see Table ES-2) Inglewood: Same as for the project (see Table ES-2) and mitigation measures in the Baldwin Hills CSD Final EIR (LA County, 2008)





Class III Class III Class II Wilmington and Inglewood: No mitigation required Sespe: Same as for the project in the City of Fillmore (see Table ES-2)





by Oil & Gas Field2






Impact TR-5: Change air traffic patterns

Class III Class III Class IV No mitigation required



















by Oil & Gas Field2




Impact EN-3: Cause an adverse effect on peak and base period demands for electricity and other forms of energy because of inefficient, wasteful, or unnecessary energy use


Impact EN-4: Disrupt compliance with existing energy standards








N/A - Not applicable to the resource because the Inglewood and Sespe Oil and Gas Fields are located inland.



Table ES-5. Summary of Impacts for the Alternatives

Subject / Impact Criteria1 Alternative2 Impact Significance with Mitigation Incorporated3 Mitigation Measures

Aesthetics


1 Class IV and V (Direct)

Class I, II, III and IV (Indirect)

Class I, II, III for new or expanded terminals

None available for new or expanded areas

2 Class III or IV (Direct)

Class IIII (Indirect)

None available for new or expanded areas

3 New well pad: Class I or Class II;

Existing well pad: Class III



4 Class III in existing fields


Existing Fields: No mitigation required

New Areas:

Same mitigations as applied to Alternative 3 (AES-1a and AES-1b for new areas)




6 Class III in existing fields Class I in new areas

No mitigation applied



Class I, II, III, and IV (Indirect)

No mitigation available for new or expanded areas

2 Class I, II, III, or IV (Direct)

Class III (Indirect)

Class I or II for new or expanded terminals









Impact AES-2, continued 4 Class III in existing fields



New Areas:


AES-1b: Minimize Offsite Lighting Visibility.












Class I, II, III for new or expanded terminals




New areas:






New Areas:

















Class II for new or expanded terminals









New Areas:










1 Class IV (Direct)

Class V and II (Indirect)



AGF-1c: Compensate for Loss of Important Farmland

2 Class IV (Direct)

Class II or V (Indirect)

Same mitigations as applied to Alternative 1 (AGF-1a through AGF-1c)

3 Class II Same mitigations as applied to Alternative 1 (AGF-1a through AGF-1c)

4 Class II on or adjacent to Important Farmland Same mitigations as applied to Alternative 1 (AGF-1a through AGF-1c)

5 Class II on or adjacent to Important Farmland Same mitigations as applied to Alternative 1 (AGF-1a through AGF-1c)

6 Class I on or adjacent to Important Farmland No mitigation applied






1 Class IV (Direct)


AGF-2a: Ensure Compatibility with Agricultural Zoning

AGF-2b: Ensure Compatibility with Williamson Act Contracts or Terminate Williamson Act Contracts

2 Class IV (Direct)


Same mitigations as applied to Alternative 1 (AGF-2a and AGF-2b)

3 Class II Same mitigations as applied to Alternative 1 (AGF-2a and AGF-2b)

4 Class II on land zoned for agricultural use or enrolled in Williamson Act contracts


5 Class II on land zoned for agricultural use or enrolled in Williamson Act contracts


6 Class I on land zoned for agricultural use or enrolled in Williamson Act contracts



1 Class IV (Direct)


AGF-3a: Ensure Compatibility with Forest and Timberland Zoning

2 Class IV (Direct)


Same mitigation as applied to Alternative 1 (AGF-3a)

3 Class II Same mitigation as applied to Alternative 1 (AGF-3a)

4 Class II on land zoned as forestland, timberland, or Timberland Production


5 Class II on land zoned as forestland, timberland, or Timberland Production


6 Class I on land zoned as forestland, timberland, or Timberland Production



1 Class IV (Direct)




AGF-4c: Compensate for Loss of Forest Land

2 Class IV (Direct)


Same mitigations as applied to Alternative 1 (AGF-4a through AGF-4c)





Impact AGF-4, continued 3 Class II on forest land Same mitigations as applied to Alternative 1 (AGF-4a through AGF-4c)

4 Class II on forest land Same mitigations as applied to Alternative 1 (AGF-4a through AGF-4c)

5 Class II on forest land Same mitigations as applied to Alternative 1 (AGF-4a through AGF-4c)

6 Class I on forest land No mitigation applied


1 Class IV (Direct)














2 Class IV (Direct)


Same mitigations as applied to Alternative 1 (AGF-1a, AGF-1b, AGF-4a, AGF-4b, AQ-2c, BIOT-2a, HAZ-1a, GW-4b, SWR-1a, SWR-2a, SWR-3a, TR-1a)

3 Class II for well stimulation activities on or within 1,500 feet of agricultural or forest land


4 Class II for well stimulation activities on or within 1,500 feet of agricultural or forest land






Impact AGF-5, continued 5 Class II for well stimulation activities on or within 1,500 feet of agricultural or forest land


6 Class I for well stimulation activities on or within 1,500 feet of agricultural or forest land


Air Quality


1 Class I (Indirect) AQ-1a: Improve Air Quality Planning Inventories and Local Control Measures

2 Class I (Indirect) AQ-1a: Improve Air Quality Planning Inventories and Local Control Measures

AQ-1b: Improve the Methodologies and Emission Factors Used in Inventory Development

3 Class I (Statewide)


Same mitigation as applied to Alternative 2 (AQ-1a and AQ-1b)



Same mitigations as applied to Alternative 2 (AQ-1a and AQ-1b)



Same mitigations as applied to Alternative 2 (AQ-1a and AQ-1b)





1 Class I (Indirect) AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources


2 Class I (Indirect) AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments



3 Class I Same mitigations as applied to Alternative 2 (AQ-2a through AQ-2c)





Impact AQ-2, continued 4 Class I (Indirect) Same mitigations as applied to Alternative 2 ( AQ-2a through AQ-2c)

5 Class I (Indirect) Same mitigations as applied to Alternative 1 ( AQ-2a through AQ-2c)

6 Class I No mitigation applied


1 Class I (Indirect) AQ-3a: Comply with Local Air District Protocols Relating to the Preparation of a Health Risk Assessment and Implement Emission Controls

AQ-3b: Avoid Unnecessary Exposure to Air Pollutants by Improving Local Land Use Compatibility.

2 Class I (Indirect) Same mitigation as applied to Alternative 1 (AQ-3a and AQ-3b)

3 Class I Same mitigation as applied to Alternative 1 (AQ-3a and AQ-3b)

4 Class I Same mitigation as applied to Alternative 1 (AQ-3a and AQ-3b)

5 Class II (Indirect) Same mitigation as applied to Alternative 1 (AQ-3a and AQ-3b)



1 Class I (Indirect) AQ-4a: Prepare and Implement an Odor Minimization Plan

AQ-4b: Avoid Unnecessary Exposure to Odors by Improving Local Land Use Compatibility.

2 Class I Same mitigations as applied to Alternative 1 (AQ-4a and AQ-4b)

3 Class I (Indirect) Same mitigation as applied to Alternative 1 (AQ-4a)

4 Class I Same mitigations as applied to Alternative 1 (AQ-4a and AQ-4b)

5 Class I (Indirect) Same mitigation as applied to Alternative 1 (AQ-4a and AQ-4b)








1 Class IV (Direct)

Class I (Indirect)

BIOT-1a: Evaluate Impacts to Native Vegetation and Fish and Wildlife Habitat


BIOT-1c: Replace of Offset Loss of Sensitive Habitat



SWR-2a: Implement Erosion Control


2 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, SWR-1a, SWR-2a, SWR-3a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, SWR-1a, SWR-2a, SWR-3a)

4 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, SWR-1a, SWR-2a, SWR-3a)

5 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, SWR-1a, SWR-2a, SWR-3a)







1 Class IV (Direct)

Class I (Indirect)






BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials SWR-1a: Require Stormwater Pollution Prevention Plan


2 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, GW-4a, GW-4b, HAZ-1a, SWR-1a, SWR-2a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, GW-4a, GW-4b, HAZ-1a, SWR-1a, SWR-2a)

4 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, GW-4a, GW-4b, HAZ-1a, SWR-1a, SWR-2a)

5 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, GW-4a, GW-4b, HAZ-1a, SWR-1a, SWR-2a)

6 Class I or III No mitigation applied






1 Class IV (Direct)

Class I (Indirect)







BIOT-7a: Prevent or Mitigate Habitat Fragmentation and Impacts to Fish and Wildlife Movement AQ-2c: Reduce Emissions from Dust-Causing Activities


2 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, AQ-2c, SWR-1a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, AQ-2c, SWR-1a)

4 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-3b, BIOT-4b, BIOT-7a, AQ-2c, SWR-1a)

5 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIOT-4b, BIOT-7a, AQ-2c, SWR-1a)



1 Class IV (Direct)

Class I (Indirect)






BIOT-4a Minimize and Mitigate Impacts to all Species Identified as a Candidate, Sensitive, or Special-Status Species in Local or Regional Plans, Policies, or Regulations, or by CDFW or USFWS







Impact BIOT-4, continued 2 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIO-3b, BIOT-4a, BIOT-4b, BIOT-7a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIO-3b, BIOT-4a, BIOT-4b, BIOT-7a)

4 Class I Same mitigations as applied to Alternative 1(BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIO-3b, BIOT-4a, BIOT-4b, BIOT-7a)

5 Class I Same mitigations as applied to Alternative 1 (BIOT-1b, BIOT-1c, BIOT-2a, BIOT-3a, BIO-3b, BIOT-4a, BIOT-4b, BIOT-7a)



1 Class IV (Direct)

Class I (Indirect)




AQ-2c: Reduce Emissions from Dust-Causing Activities GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation GW-4b: Install a Well Seal Across Protected Groundwater for New Wells Subject to Well Stimulation Treatments




2 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)

4 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)





Impact BIOT-5, continued 5 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, AQ-2c, GW-4a, GW-4b, SWR-1a, SWR-1b. SWR-2a, SWR-3a)



1 Class IV (Direct)

Class I (Indirect)






BIOT-6a: Protect Jurisdictional Waters

GW-1a: Use Alternative Water Sources to the Extent Feasible


GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation



SWR-1b: Surface Water Protection



2 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, BIOT-2a, BIO-3a, BIOT-6a, GW-1a, GW-1b, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)

3 Class I, II or III Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, BIOT-2a, BIO-3a, BIOT-6a, GW-1a, GW-1b, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)

4 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, BIOT-2a, BIO-3a, BIOT-6a, GW-1a, GW-1b, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)





Impact BIOT-6, continued 5 Class I Same mitigations as applied to Alternative 1 (BIOT-1a, BIOT-1b, BIOT-1c, BIOT-2a, BIO-3a, BIOT-6a, GW-1a, GW-1b, GW-4a, GW-4b, SWR-1a, SWR-1b, SWR-2a, SWR-3a)



1 Class IV (Direct)

Class I (Indirect)


2 Class I Same mitigation as applied to Alternative 1 (BIOT-7a)

3 Class II or III Same mitigation as applied to Alternative 1 (BIOT-7a)





1 Class IV (Direct)

Class I (Indirect)

BIOT-8a: Coordinate with Local Agencies and Jurisdictions Regarding Local Policies and Conservation Plans

2 Class II Same mitigation as applied to Alternative 1 (BIOT-8a)






1 Class IV (Direct)

Class I (Indirect)

BIOT-9a: Coordinate with CDFW, USFWS, and Permittees Regarding NCCPs, HCPs, and Other Conservation Plans











1 Class IV (Direct)

Class I (Indirect)

AQ-2a: Reduce Emissions from Well Stimulation Treatments





2 Class I Same mitigations as applied to Alternative 1 (AQ-2a, AQ-2b, GHG-1a, GHG-1b, GHG-2a)






Impact BIOCM-1: Substantially affect rare, threatened, or endangered coastal/marine species or their habitat

1 Class IV (Direct)



2 Class III No mitigation required



Impact BIOCM-2: Interfere with migration or movement of coastal/marine fish or wildlife

1 Class IV (Direct)










Impact BIOCM-3: Result in substantial loss or alteration of coastal/marine habitat

1 Class IV (Direct)






Impact BIOCM-4: Substantially disrupt or affect local coastal/marine biological communities or habitats

1 Class IV (Direct)








1 Class II CPMWQ-1a: Protect Marine Water Quality

2 Class II Same mitigation as applied to Alternative 1 (CPMWQ-1a)




1 Class II CPMWQ-2a: Prepare and Implement Marine Current Plan








6 Class III No mitigation applied






1 Class IV No mitigation required





1 Class IV (Direct)

Class III (Indirect) No mitigation required






1 Class IV (Direct)






Impact CRF-2: Result in substantial economic losses to local commercial and recreational fishing industries

1 Class IV (Direct)










Cultural Resources


1 Class IV (Direct)

Class I (Indirect)

CUL-1a: Require Information and Evaluate Cultural Resources.

CUL-1b: Complete Native American Coordination.

CUL-1c: Prepare and Implement Cultural Resources Management and Treatment Plan.

CUL-1d: Prepare Plan for the Inadvertent Discovery of Human Remains.

CUL-1e: Provide Cultural Resources Specialist with the Authority to Halt Earth Disturbing Activities.

CUL-1f: Conduct a Cultural Resources Worker Environmental Awareness Program.

CUL-1g: Monitor Earth Disturbing Activities for Cultural Resources.

CUL-1h: Provide Native American Monitors during Earth Disturbing Activities.

CUL-1i: Prepare Cultural Resources Documents for the Monitoring of Earth Disturbing Activities.


2 Class I Same mitigations as applied to Alternative 1 (CUL-1a through CUL-1j)

3 Class I or II if cultural landscapes are present;


Same mitigations as applied to Alternative 1 (CUL-1a through CUL-1j)

4 Class I or Class II if historic or built-environment resources are present;










Impact CUL-1, continued 6 Class I if historic or built-environment resources are present




1 Class IV (Direct)

Class I (Indirect) Same mitigations as applied to Impact CUL-1 (CUL-1a through CUL-1j)




Same mitigations as applied to Alternative 1 (CUL-1 (CUL-1a through CUL-1j)







6 Class I if prehistoric resources are present

Class III or Class IV if prehistoric resources are not considered significant or are not present



1 Class IV (Direct)

Class I (Indirect)

Same mitigations as applied to Impact CUL-1 (CUL-1a through CUL-1j)






Impact CUL-3, continued 3 Class I or II if human remains or cultural items are present




4 Class I or II if human remains or cultural items are present



Same mitigations as applied to Alternative 1(CUL-1a through CUL-1j)




6 Class I if human remains or cultural items are present




Impact CUL-4: Affect cultural landscapes 1 Class IV (Direct)

Class I (Indirect)

Same mitigations as applied to Impact CUL-1 (CUL-1a through CUL-1j)





4 Class I if cultural landscapes are present







Impact CUL-4, continued 5 Class I if cultural landscapes are present



6 Class I if cultural landscapes are present




Impact EJ-1: Significant impacts would disproportionately affect minority or low-income populations

1 Unknown, possibly Class I (Indirect) EJ-1a: Track Characteristics of Affected Populations in the Vicinity of Well Stimulation Treatments

2 Unknown, possibly Class I (Indirect) Same mitigation as applied to Alternative 1 (EJ-1a)

3 Unknown, possibly Class I (Indirect) Same mitigation as applied to Alternative 1 (EJ-1a)

4 Unknown, possibly Class I Same mitigation as applied to Alternative 1 (EJ-1a)

5 Unknown, possibly Class I Same mitigation as applied to Alternative 1 (EJ-1a)




1 Class IV (Direct)

Class II (Indirect)

GEO-1a: Avoid Active Faults if Necessary


GEO-1e: Include an Earthquake Response Plan within the Spill Contingency Plan

2 Class IV (Direct)

Class II

Same mitigations as applied to Alternative 1 (GEO-1a, GEO-1b, GEO-1e)

3 Class II GEO-1a: Avoid Active Faults if Necessary



GEO-1e: Include an Earthquake Response Plan with the Spill Contingency Plan





Impact GEO-1, continued 4 Class II GEO-1a: Avoid Active Faults if Necessary




GEO-1e: Include an Earthquake Response Plan within the Spill Contingency Plan

5 Class II GEO-1b: Implement Appropriate Setback



GEO-1e: Include an Earthquake Response Plan with the Spill Contingency Plan



1 Class IV (Direct)

Class II (Indirect)


2 Class IV outside of existing fields (Direct)

Class II within existing fields (Indirect)


Same mitigation as applied to Alternative 1 (SWR-1a)

3 Class II No mitigation required

4 Class III SWR 1a: Require Stormwater Pollution Prevention Plan

SWR 2a: Implement Erosion Control Plan

5 Class III Same mitigation as applied to Alternative 4 (SWR-1a and SWR-2a)



1 Class IV (Direct)

Class II (Indirect)

GEO-3a: Prepare Geotechnical Report if Necessary


Class II within existing fields (Direct)


Same mitigation as applied to Alternative 1 (GEO-3a)

3 Class II Same mitigation as applied to Alternative 1 (GEO-3a)





Impact GEO-3, continued 4 Class II Same mitigation as applied to Alternative 1 (GEO-3a)

5 Class II Same mitigation as applied to Alternative 1 (GEO-3a)



1 Class IV (Direct)




Class III within existing fields (Indirect)














Impact GEO-6: Result in the loss of availability of known mineral resource, loss of a locally important mineral resource recovery site delineated on a local general plan, specific plan or other land use plan

1 Class IV (Direct)

Class I (loss of fossil fuels) Indirect)

Class III (loss of non-fuel resources) (Indirect)


2 Class IV (loss of non-fuel resources) (Direct)

Class I (loss of fossil fuels) (Direct)



3 Class III in most instances; Class I in some instances






Impact GEO-6, continued 4 Class III in most instances; Class I in some instances


5 Class III in most instances; Class I in some instances


6 Class I or III No mitigation proposed


1 Class IV (Direct)



2 Class IV (Direct)









1 Class IV (Direct)

Class I (Indirect)



2 Class I GHG-1a: Prevent Methane Emissions from Associated Gas and Casinghead Gas







Impact GHG-1, continued 3 Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments




GHG 1c: Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide

4 Class I Same mitigations as applied to Alternative 3 (AQ-2a, AQ-2b, GHG-1a, GHG-1b, GHG-1c)

5 Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments



GHG-1b: Reduce Emissions by Implementing Clean Development Mechanism (CDM) Strategies.




1 Class I AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources






Impact GHG-2, continued 2 Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments










GHG-1c: Detect and Quantify Fugitive and Vented Methane and Carbon Dioxide GHG-2a: Require Applicant Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program





Impact GHG-2, continued 5 Class I AQ-2a: Reduce Hydrocarbon Emissions from Well Stimulation Treatments.

AQ-2b: Reduce Emissions from Portable Equipment and Mobile Sources.


GHG 2a: Require Applicant Enter into Mitigation Programs or Agreements for GHG Emissions not Covered by or Exempt from ARB’s Cap and Trade Program



Impact HAZ-1: Hazardous materials associated with well stimulation fluids could be released to the environment from a spill or leak


Class I and III (Indirect)

No mitigation available

2 Class II HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials

3 Class II Same mitigation as applied to Alternative 2 (HAZ-1a)





Impact GW-1: Cause or contribute to overdraft conditions in critically impacted groundwater basins

1 Class II (federal lands), III, and IV GW-1a: Use Alternative Water Sources to the Extent Feasible

2 Class II (Direct)

Class IV (Indirect)

GW-1a: Use Alternative Water Sources to the Extent Feasible


3 Class II Same mitigations as applied to Alternative 2 (GW-1a, GW-1b)








Impact GW-2: Lower groundwater levels through pumping, resulting in subsidence or impacts to nearby water wells

1 Class II (federal lands), III, and IV GW-1b: Minimize Groundwater Impacts

2 Class II (Direct)

Class IV (Indirect)

Same mitigation as applied to Alternative 1 (GW-1b)

3 Class II Same mitigation as applied to Alternative 1 (GW-1b)

4 Class II Same mitigation as applied to Alternative 1 (GW-2a)



Impact GW-3: Water quality in the Protected Water zone is adversely affected through surface spill or leak during well stimulation treatment

1 Class II (federal lands) HAZ-1a: Ensure that Spill Contingency Plan Provides Adequate Protection Against Leaks or Discharges of Dangerous Fluids and Other Potentially Dangerous Materials

2 Class II (Direct)

Class IV (Indirect)

Same mitigation as applied to Alternative 1 (HAZ-1a)





Impact GW-4: Non-existent or ineffective well seals in annular space resulting in migration of fluids

1 Class II (federal lands) and IV GW-4a: Demonstrate that Wells within the ADSA Have Effective Cement Well Seals and Monitor Wells during Well Stimulation Treatment


GW-4c: Install Methane Sensors on Wells Subject to Well Stimulation Treatments.

2 Class II (Direct)

Class IV (Indirect)

Same mitigations as applied to Alternative 1 (GW-4a through GW-4c)

3 Class II Same mitigations as applied to Alternative 1 (GW-4a through GW-4c)





Impact GW-4, continued 4 Class II Same mitigations as applied to Alternative 1 (GW-4a through GW-4c)

5 Class II Same mitigations as applied to Alternative 1 (GW-4a through GW-4c)


Impact GW-5: Fluids introduced to Protected Water through damaged or improperly abandoned wells within area of influence of new well.

1 Class II (federal lands) and IV GW-5a: Conduct Surface Geophysical Surveys or Apply Other Field Methods to Locate Improperly Abandoned Wells and Mitigate

2 Class II (Direct)

Class IV (Indirect)

Same mitigation as applied to Alternative 1 (GW-5a)






1 Class II (federal lands) and IV GW-6a: Require Wastewater Disposal Wells to Inject Only into Exempted Aquifers to Protect Groundwater

2 Class II (Direct)

Class IV (Indirect)







1 Class II (federal lands) and IV GW-7a: Add a Tracer to Well Stimulation Fluids or Develop a Reasonable Method to Distinguish These Fluids in the Environment

2 Class II (Direct)

Class IV (Indirect)








Impact GW-7, continued 5 Class II Same mitigation as applied to Alternative 1 (GW-7a)



LU-1: Preclude existing or permitted land uses, or create a disturbance that would diminish the function of land uses

1 Class IV (Direct)

Class I or III(Indirect)

(No mitigation available for impacts associated with Risk of Upset/Public and Worker Safety)

2 Class I (No mitigation for impacts associated with Risk of Upset/Public and Worker Safety)

3 Class I (No mitigation available for impacts associated with Risk of Upset/Public and Worker Safety)













2 Class II (PRC Section 1783.2 requiring “Neighbor Notification”) (All mitigation measures prescribed in this EIR)







Impact LU-3, continued 5 Class II (PRC Section 1783.2 requiring “Neighbor Notification”) (All mitigation measures prescribed in this EIR)


Noise and Vibration



Class II (federal lands) and V (Indirect)

NOI-1a: Control Noise Levels near Sensitive Land Uses

NOI-1b: Control Noise Levels from Well Drilling Near Noise Sensitive Land Uses

2 Class II (Direct)

Class II to Class IV (Indirect)

Same mitigation as applied to Alternative 1 ( NOI-1a)

3 Class II Same mitigation as applied to Alternative 1 ( NOI-1a)






Class II and V (Indirect)

Mitigation may be required if new infrastructure is closer to noise sensitive receivers

2 Class IV (Direct)

Class I to IV (Indirect)

Mitigation may be required if new infrastructure is closer to noise sensitive receivers










Impact PALEO-1: Well stimulation treatments would destroy or disturb surface or near-surface significant paleontological resources

1 Class IV (Direct)

Class II (Indirect)

PALEO-1a: Require Information and Evaluate Paleontological Resources

PALEO-1b: Develop Paleontological Resource Mitigation Plan

PALEO-1c: Retain Qualified Paleontological Resources Staff

PALEO-1d: Conduct a Paleontological Resources Worker Environmental Awareness Program

PALEO-1e: Monitor Earth Disturbing Activities for Paleontological Resources

PALEO-1f: Provide Qualified Paleontological Resources Monitor with Authority to Halt Earth Disturbing Activities

PALEO-1g: Prepare Paleontological Resources Report for the Monitoring of Earth Disturbing Activities

PALEO-1h: Curate all Discovered Paleontological Resources Associated with Earth Disturbing Activities

2 Class II Same mitigations as applied to Alternative 1 (PALEO-1a through PALEO-1h)

3 Class II if fossil bearing geologic units are present


Same mitigations as applied to Alternative 1 (PALEO-1a through PALEO-1h)



Same mitigation as applied to Alternative 1 (PALEO-1a through PALEO-1h)



Same mitigations as applied to Alternative 1 (PALEO-1a through PALEO-1h)

6 Class I if fossil bearing geologic units are present No mitigation applied










Impact POP-1, continued 4 Class III No mitigation required










Public Services


1 Class IV (Direct)

Class II (Indirect)

PUB-1a: Assess Public Service Ratios and Ensure Adequate Compensation

2 Class II Same mitigation as applied to Alternative 1 (PUB-1a)

3 Class II outside of existing oil and gas fields where 10 or more wells are drilled by a single applicant within 1 square mile;

Otherwise, Class III

Same mitigation as applied to Alternative 1 (PUB-1a)




6 Class I for Increased Need for Fire or Police Services Due to Project Activities

Class III for Increased Need for Public Services Due to Population Growth






Recreation

REC-1: Result in the physical deterioration of recreational resources









2 Class II REC-2a: Coordinate Well Stimulation Treatment Schedule with Managing Officer(s) for Affected Recreation Areas

REC-2b: Provide Noticing of Closures and Identify Alternative Recreation Areas

3 Class II Same mitigations as applied to Alternative 2 (REC-2a and REC-2b)






1 Class I RSK-1a: Increase the Number of CPUC Rail Inspectors

RSK-1b: Expedite the Phase-out of Older Tank Cars

RSK-1c: Implement New Accident Prevention Technology

RSK-1d: Monitor and Enforce New Speed Limits

RSK-1e: Monitor the Implementation of Trackside Safety Technology

RSK-1f: Improve Emergency Preparedness and Response Programs

RSK-1g: Provide Real-Time Shipment Information to Emergency Responders

RSK-1h: Provide Additional Accident and Injury Data to the State





Impact RSK-1, continued 2 Class I Same mitigations as applied to Alternative 1 (RSK-1a through RSK-1h)

3 Class I Same mitigations as applied to Alternative 1 (RSK-1a through RSK-1h)





1 Class II RSK-2a: Reduce the Inventory/Volumes Handled with the Hazardous Chemicals

RSK-2b: Conduct a Facility Siting Study or a Quantitative Risk Assessment

RSK-2c: Ensure Mechanical Integrity Through Compliance with Regulation

2 Class II Same mitigations as applied to Alternative 1 (RSK-2a through RSK-2c)





Impact RSK-3: Substantially increase the potential for major oil spills due to ship groundings and collisions











Impact RSK-4: Create a hazard to the public, workers, or environment through reasonably foreseeable accidental pressure changes during flowback activity caused by blocked pump discharge, sudden change in downhole condition, or human error

1 Class II RSK-4a: Conduct a Process Hazard Analysis (PHA) Followed by a Layer of Protection Analysis (LOPA) to Ensure Installation of Proper Safety Interlocks

2 Class II Same mitigation as applied to Alternative 1 (RSK-4a)






1 Class II RSK-5a: Prepare and Implement the Procedures to Avoid Pump Cavitation during all Well Stimulation Activities

RSK-5b: Verify the Need of Installation of Flame Arresters on the Tank Vents

RSK-5c: Prepare and Implement a Control of Ignition Sources Plan






Impact RSK-6: Increase risks to public safety by exposing the public to accidental crude oil or produced gas releases from pipelines

1 Class I RSK-6a: Increase Inspection of Mechanical Integrity RSK-6b: Improve Leak Detection Capability RSK-6c: Reduce Mainline Valve Spacing

2 Class I Same mitigations as applied to Alternative 1 (RSK-6a through RSK-6c)






Impact RSK-6, continued 4 Class I Same mitigations as applied to Alternative 1 (RSK-6a through RSK-6c)




1 Class II RSK-7a: Use Alternative Proppant (e.g., Sintered Bauxite, Ceramics, Resins) or Use Alternative Proppant Delivery System

RSK-7b: Reduce Emissions from Dust-Causing Activities

2 Class II Same mitigations as applied to Alternative 1 (RSK-7a and RSK-7b)







1 Class IV (Direct)

Class III (federal lands) and III (Indirect)





2 Class II SWR-1a: Require Stormwater Pollution Prevention Plan SWR-1b: Surface Water Protection



3 Class II Same mitigations as applied to Alternative 2 (SWR-1a through SWR-1d)





Impact SWR-1, continued 4 Class II Same mitigations as applied to Alternative 1 (SWR-1a through SWR-1d, BIOT-2a)

5 Class II Same mitigations as applied to Alternative 2 (SWR-1a through SWR-1d, BIOT-2a)



1 Class IV (Direct)

Class II (federal lands) and IV (Indirect)


2 Class II Same mitigation as applied to Alternative 1 (SWR-2a)






1 Class IV (Direct)


SWR-3a: Ensure Adequate Water







1 Class IV (Direct)



2 Class II Same mitigation as applied to Alternative 1 (SWR-1c)











1 Class V (Direct)



2 Class I (transport of hazardous materials) or V No mitigation available

3 Class III for Project activities in Study Region 6 and for existing fields;

Class II outside of existing oil and gas fields in Study Regions 1-5 where 10 or more wells are drilled by a single applicant within 1 square mile




Same mitigation as applied to Alternative 3 (TR-1a)




6 Class I outside of existing fields in Study Regions 1-5 where 10 or more wells are drilled by a single applicant within one square mile

Class III in existing fields and Study Region 6



1 Class V (Direct)

Class II (Indirect)


2 Class II Same mitigation as applied to Alternative 1 (TR-2a)








Impact TR-2, continued 4 Class III for Project activities in Study Region 6 and for existing fields;






6 Class I (as above for TR-1)

Class III (as above for TR-1)



1 Class V (Direct)













6 Class I outside of existing fields in Study Regions 1-55 where 10 or more wells are drilled by a single applicant within one square mile

Class III in existing fields and Study Region 6







1 Class I No mitigation available

2 Class I TR-4a: Know Spill Prevention Measures

3 Class I Same mitigation as applied to Alternative 2 (TR-4a)




Impact TR-5: Change air traffic patterns 1 Class V (Direct)




3 Class IV if no airports are nearby









6 Class IV if no airports are nearby No mitigation applied


1 Class V (Direct)




3 Class II PUB-1a: Assess Public Service Ratios and Ensure Adequate Compensation


Class II in Study Regions 1-5 outside of existing oil and gas fields where 10 or more wells are drilled by a single applicant within 1 square mile



TR-4a: Know Spill Prevention Measures





Impact TR-6, continued 5 Class III for Project activities in Study Region 6 and for existing fields;


Same mitigation as applied to Alternative 4 (TR-1a, TR-2a, TR-4a)

6 Class I (as above for TR-1)

Class III





2 Class IV (Direct)



3 Class II PUB-1a: Assess Public Service Ratios and Ensure Adequate Compensation






2 Class IV (Direct)









2 Class IV (Direct)

Class II (Indirect)

UTL-3a: Assess Wastewater Quality and Ensure Adequate Capacity to Process Wastewater at Municipal and Private Wastewater Treatment Plants






Impact UTL-3, continued 4 Class II Same mitigation as applied to Alternative 2 (UTL-3a)

5 Class II Same mitigation as applied to Alternative 2 (UTL-3a)




2 Class IV (Direct)

Class II (Indirect)

UTL-4a: Assess Non-Hazardous Solid Waste Generation and Ensure Adequate Capacity to Accept Solid Waste at Municipal and Private Solid Waste Facilities





1 - The occurrence of significant and unavoidable impacts (Class I) for some subject areas is contingent on site-specific conditions of where a proposed well stimulation treatment may occur. As example, if a proposed well stimulation site’s future environmental review demonstrates that no cultural resources are present, no impacts would occur and no mitigation would be required. However, if the site does contain such resources, potential impacts could be either significant and unavoidable (Class I), less than significant with mitigation incorporated (Class II), less than sig-nificant (Class III), no impact (Class IV), or beneficial impact (Class V).

2 - Alternatives: 1 No Future Well Stimulation Treatments Alternative 2 No Future Well Stimulation Treatments Outside of Existing Oil and Gas Field Boundaries Alternative 3 Well Pad Consolidation Alternative 4 Urbanized Area Protection Alternative 5 Active Fault Zone Restrictions Alternative 6 No Project Alternative


M i c h a e l N . M i l l s

Experience

Michael Mills is an environmental and oil and gas lawyer in the firm's Sacramento office with a practice emphasizing federal and state environmental litigation and

regulatory counseling. He is the Chair of the firm's Oil & Gas, Pipelines and Mining Industries Team, a partner in the Environment, Land Use and Natural Resources

practice group and a member of the firm’s property tax practice. Mike's practice

involves a wide spectrum of natural resources matters, including oil & gas, mining, natural resources development permitting, and eminent domain. Mike has a great deal

of experience in federal and state hazardous waste litigation, California Environmental Quality Act (CEQA) litigation, and California water rights litigation. His

oil and gas experience extends to land, title and permitting issues unique to California's oil and gas industry, including compliance with SB 4, California's well

stimulation treatment permitting law. In addition to being an experienced California

oil and gas attorney, Mike also has experience in the areas of property tax assessment appeals, as well as land use, valuation and condemnation issues arising from the

California High Speed Rail project.

Representative Work and Engagements Oil and Gas

• Representation of major and independent oil and gas companies in negotiating, reviewing and drafting oil and gas exploration and production agreements, including joint operating agreements, farmout agreements, pooling/unit agreements, leases and surface use agreements, easements, and purchase and

sale agreements.

• Conducting due diligence for acquisition of oil and gas leases and fee interests, including advice on compliance with terms of affected joint operating agreements, farmout agreements and leases.

• Preparation of acquisition, division order and drilling title opinions.

• Due diligence for regulatory, permitting, title and environmental issues in connection with the acquisition of an underground natural gas storage facility in

Northern California.

• Counsel and legal advice to oil and gas exploration and production companies

seeking to develop California's Monterey Shale formation.

• Counseling and advice on subsurface trespass, pass-through rights and well

setback requirements.

Partner

(916) 319-4642 direct

(916) 447-4781 fax

[email protected]

Education

• University of California, Davis, School of Law, J.D., 1997

Order of the Coif

Senior Notes and Comments Editor,

U.C. Davis Law Review

• University of California, Davis, B.S., Environmental Toxicology (minor in

English), 1994, summa cum laude

• Dana Curtis Mediation, Appellate

Mediation Training Program,

Certificate of Completion, 2010

Admissions

• California

• U.S. District Courts for the Eastern, Southern, Northern and Central

Districts of California

• U.S. Court of Appeals for the Ninth

Circuit

• U.S. Bankruptcy Court for the Eastern

District of California


• Counseling and advice to investment firm on oil and gas exploration and production issues in connection with financing the

purchase of interests in South Belridge Oil Field, Kern County, California.

• Counseling and advice for operators and mineral lessees on forced entry procedures.

• Counseling and advice in connection with permitting applications and related CEQA review for oil and gas wells throughout

California.

• Lead counsel in defense of Fortune 500 oil and gas company in claim of breach of Joint Development Agreement for California's

Monterey Shale formation.

• Representation of oil and gas operator in collection action against non-operators for unpaid charges under joint operating

agreements in Colusa and Sutter Counties.

• Counseling and advice to Canadian oil and gas drilling machinery supplier on entry into California market.

• Lead counsel for Fortune 500 oil and gas company in CEQA litigation to challenge residential development for lack of analysis of

impacts to mineral resources.

• Representation of national oil and gas company in dispute over surface access rights in connection with residential development

in Contra Costa County, California.

• Representation of development company in dispute over surface access rights in connection with commercial development in

San Joaquin County, California.

• Representation of oil and gas company in lawsuit by property owners challenging company's use of road right-of-way for natural

gas pipeline.

• Counseling and advice in connection with leases for underground gas storage project.

• Representation of oil and gas company in contract litigation involving joint operating agreement for natural gas field in Sutter

County, California.

• Representation of oil and gas company in contract litigation involving terms of farmout agreement for natural gas field in San

Joaquin County, California.

Mining

• Represented mining company as seller in the negotiation of a purchase and sale agreement for a sand mine in Southern California.

• Lead counsel for mining company in litigation brought against the Department of Conservation challenging procedures relating to a mine's removal from the AB 3098 List.

• Lead counsel for mining company in complex environmental enforcement action brought by the California Attorney General's Office to require remediation of abandoned mine in Tuolumne County, California.

• Lead counsel for mining industry plaintiffs challenging validity of certain financial assurance regulations under the Surface

Mining and Reclamation Act.


• Lead counsel for mining company subsidiary in complex enforcement action brought by the Alaska Department of Environmental

Conservation to require the cleanup of an abandoned fuel bunker in Juneau, Alaska.

• Lead counsel for trustee of trust established under court-ordered settlement to oversee funds dedicated to, and management

of, remediation of abandoned gold mine.

• Advise and counsel mining clients on CEQA compliance and related permitting matters.

• Lead counsel in defense of aggregate mining company in CEQA lawsuit challenging approval of mine expansion in Merced

County, California.

• Lead counsel in defense of national aggregate mining company in CEQA lawsuit challenging approval of mine expansion in Butte

County, California.

• Representation of national aggregate mining company in CEQA lawsuit challenging approval of mine expansion in Fresno County,

California.

• Representation of national aggregate mining company in CEQA challenge to municipal ordinance requiring conditional use

permit for federally approved mitigation bank.

• Representation of mining company in assessment appeal proceeding in Amador County, California.

Environmental Litigation and Administrative Enforcement Proceedings

• Lead counsel for Fortune 500 oil and gas company in connection with compliance efforts under the federal Clean Water Act and

General Industrial Storm Water Permit for oil and gas fields in Southern California.

• Representation of Fortune 500 oil and gas company in defense of Clean Water Act citizen suit arising from concerns over hydraulic fracturing and enhanced oil recovery techniques resulting in alleged storm water discharges in violation of the General

Industrial Storm Water Permit.

• Representation of Fortune 500 oil and gas company in connection with application of, and compliance with, Prevention of

Significant Deterioration Regulation under the federal Clean Air Act in California's San Joaquin Valley.

• Lead counsel for property owner defendant in complex CERCLA action filed in the U.S. District Court for the Central District of California seeking contribution resulting from contamination within the EI Monte Operable Unit of the San Gabriel Valley

Superfund Site.

• Lead counsel for property owner defendant in complex CERCLA action filed in the U.S. District Court for the Eastern District of

California seeking contribution for soil and groundwater contamination.

• Lead counsel for property owner in negotiation of Corrective Action Consent Agreement with California Department of Toxic

Substances Control.

• Defended public water agency in complex environmental action brought in the U.S. District Court for the District of Arizona

asserting claims under CERCLA, RCRA and Clean Water Act, as well as other claims.

• Defended second largest generator and coordinated representation of joint defense group in municipality's CERCLA cost-

recovery action brought in the U.S. District Court for the Northern District of California.


• Common counsel to group of cooperating parties in cleanup of multiparty Superfund site under supervision of the U.S.

Environmental Protection Agency.

• Representation of trust established under court-ordered settlement to oversee funds dedicated to, and management of,

remediation of solvent contamination to soil and groundwater in San Joaquin County, California.

• Representation and advice on legal and regulatory issues concerning contaminated lands and groundwater cleanup projects

throughout Northern and Central California, including matters involving leaking or abandoned underground storage tanks.

California Environmental Quality Act (CEQA) Compliance and Litigation

• Advise clients with respect to CEQA compliance and related requirements.

• Evaluate projects for compliance with CEQA in preparation for litigation.

• Lead counsel for plaintiffs in CEQA lawsuit challenging the City of Oakland, California's proposed ordinance to ban plastic carry-

out bags.

• Lead counsel in defense of Fortune 500 oil company in CEQA challenge to drilling permits issued by the Department of

Conservation, Division of Oil, Gas, and Geothermal Resources.

• Lead counsel for Fortune 500 oil and gas company in CEQA litigation to challenge residential development for lack of analysis of

impacts to mineral resources.

• Lead counsel in defense of residential developer in CEQA lawsuit challenging approval of residential subdivision in San

Bernardino County, California.

• Lead counsel in defense of hunting club in CEQA lawsuit challenging approval of shooting range facility.

• Defense of public agency in CEQA challenge arising from proposed residential development project.

Property Tax

• Lead counsel for county in dispute with special district over property tax administration fees (successfully argued case before the California Court of Appeal, Third Appellate District).

• Lead counsel for hydroelectric facility in assessment appeals in Lassen County, California and Shasta County, California.

• Lead counsel for multiple public entities in unjust enrichment action seeking portion of previously refunded property taxes following successful assessment challenge.

• Representation of public agencies in both litigation and administrative proceedings involving Proposition 218 challenges to governmental assessments of property.

• Counsel for municipal utility district for property tax issues relating to real property acquisitions.

Land Use, Real Estate and Eminent Domain

• Lead counsel for Fortune 500 telecommunications company in land use dispute concerning zoning and site placement of cell

phone tower.


• Advice and counseling to affected landowners in connection with California High Speed Rail Authority's anticipated

condemnation proceedings.

• Lead counsel for major oil and gas exploration and production company for condemnation issues affecting mineral rights.

• Defense of property rights of major oil and gas exploration company in numerous eminent domain actions brought by the State

of California.

• Lead counsel for property owner in real estate purchase dispute involving contaminated property.

• Representation of landowner in connection with negotiations over municipal public improvements to avoid flooding of private

property.

• Representation of commercial real estate leasing firm in various litigation matters.

• Defense of public agency landowners in eminent domain proceedings.

Water Rights Litigation

• Lead counsel for hydroelectric project operator in complex RICO action brought in the U.S. District Court for the Eastern District

of California involving claims over disputed water rights.

• Representation of water right holders in Judicial Council Coordination Proceeding JC 4118: the Bay-Delta Decision 1641

Litigation.

• Representation of county water agency in complex lease dispute with lessee over construction of flood control and water quality

project.

Civil Writs and Other Engagements

• Lead counsel in defense of county in writ of mandate proceeding challenging selected site for water pumping facility.

• Representation of corporate defendant in complex litigation relating to closure of landfill in Amador County, California.

Published Opinions

• 138 Cal.App.4th 574 (2006).

• 105 Cal.App.4th 1155 (2003).

• 308 F.Supp.2d 1137 (2003).

• 213 F.Supp.2d 1208 (2002).

Professional Honors and Activities

• Listed in Northern California Super Lawyers® (Environmental Law), 2013-2014

• Member, State Bar of California, Environmental Law Section

• Panel Mediator, California Court of Appeal, Third Appellate District, Appellate Mediation Program


• Member and former President, former First Vice President, former Second Vice President, former Secretary/Treasurer and former Director-at-Large, Bar Council; Chair, Nominating Committee; member, Environmental Law Section, Sacramento County

Bar Association

• Member and former President, Vice President, Programs Director and Secretary, Sacramento Chapter, Federal Bar Association

• Member, Natural Resources Section, American Bar Association

• Member and former Treasurer, Asian/Pacific Bar Association of Sacramento

• Member, Rocky Mountain Mineral Law Foundation

• Member, California Independent Petroleum Association

• Member, Sacramento Petroleum Association

• Member, Western States Petroleum Association

Presentations

• Co-Presenter, "Fracking-The Latest on Environmental and Real Property Law Issues," Sacramento County Bar Association, Real Property and Environmental Law Sections, Sacramento, California, March 12, 2015

• "Here Today & Fracked Tomorrow: A Rollercoaster Year for SB 4 Implementation," AEG Sacramento Section and Groundwater Resources Association of California Joint Meeting, Sacramento, California, Dec. 17, 2014

• Co-Presenter, "Legal Considerations for Implementing California's New Industrial Stormwater Permit," California League of Food

Processors Stormwater Compliance Workshop, Sacramento, California, Dec. 4, 2014

• Co-Presenter, “Title Issues in Mine Leasing and Acquisitions and Their Potential Impacts on Permitting and Operations,” CalCIMA

Education Conference, San Diego, California, Nov. 4, 2014

• Co-Presenter, “Review of the ‘Typical’ California Oil & Gas Lease,” 32nd Annual West Coast Landmen’s Institute, Las Vegas,

Nevada, Oct. 23, 2014

• Panelist, “California’s NEW Industrial Storm Water Permit: Strategy, Preparation, Compliance,” Stoel Rives LLP Webinar, Sept.

24, 2014

• Co-Presenter, "California SB 4 Compliance Update: Practical and Legal Implications of the DOGGR Interim Regulations for

Operators in 2014," Stoel Rives Webinar, March 13, 2014

• "Getting Ready for SB 4: California's New Well Stimulation Permitting Law," Stoel Rives Seminar, Bakersfield, California, Dec. 11

2013

• "Environmental Regulation and Hydraulic Fracturing in California," Program Co-Chair, Law Seminars International, Santa Monica,

California, Jul. 29-30, 2013

• "Oil and Gas Drilling Law 101: The Nature and Scope of California's Regulation of Oil and Gas Production," Law Seminars

International's Environmental Regulation and Hydraulic Fracturing in California Seminar, Santa Monica, California, Jul. 29, 2013


• "Strategies for Complying with California's Cap & Trade Program," Kern County Bar Association, Bakersfield, California, Dec. 12,

2012

• "How to Use A Title Opinion," 30th Annual West Coast Landmen's Institute, Dana Point, California, Sep. 27, 2012

• "Resolving Conflicts Between Solar Energy and Oil and Gas Development," PV America West, San Jose, California, Mar. 19-21,

2012

• "Getting the Most from the Consultant/Attorney Team," Stoel Rives LLP, Sacramento, California, Feb. 2, 2012

• "More Fracking Regulations? The Public's Sudden Interest in Hydraulic Fracturing," Bakersfield Association of Professional

Landmen, Bakersfield, California, Jan. 10, 2012

• "Off or On? Examining OMR's AB 3098 Listing Procedures," California Construction and Industrial Materials Association Annual

Education Conference, Monterey, California, Oct. 12, 2011

• "Are Your Taxes Too High?," California Construction and Industrial Materials Association Annual Education Conference, Monterey,

California, Oct. 11, 2011

• "CEQA -- Its Role In and Effect On the Permitting Process," 29th Annual West Coast Landmen's Institute, Santa Barbara,

California, Sept. 29, 2011

• "Onshore Oil Production and Regulation in California," Environmental Law Symposium, University of California, Davis, School of

Law, Apr. 1, 2011

• "Resolving Conflicts Between Oil and Gas and Renewable Energy Development," Bakersfield Association of Professional Landmen,

Jan. 18, 2011

• "AB 32 and SB 97: California's Laws Regulating Greenhouse Gas Emissions and Climate Change and Their Related Impacts on

Project Timelines and Permitting," 28th Annual West Coast Landmen's Institute, Shell Beach, California, Sept. 23, 2010

• "The Resurgence of Biomass Facilities – What You Need to Know to Develop, Permit and Finance Your Project," Tulare,

California, Feb. 9, 2010

• "PITFALL – Landman Harry's Adventure in California's Land Use Jungle," Bakersfield Association of Professional Landmen, Nov. 17,

2009

• "Do's and Don'ts for Expert Witnesses," Groundwater Resources Association, 2005

• "Applying Environmental Toxicology to Environmental Problems – The Interconnection of Law and Science," U.C. Davis,

Department of Environmental Toxicology, 2000

Publications

• Frequent contributor to Stoel Rives Blogs including www.californiaenvironmentallawblog.com and www.minerallawblog.com

• "Another Front in War on Fracking," (co-author), Daily Journal, March 2015

• "Inside Calif.'s De Facto Moratorium On Well Stimulation," (co-author), Law360, April 2014


• "What Is Fracking Wastewater and How Should We Manage It?" (co-author), ABA Section of Environment, Energy and Resources,

Winter 2014

• "A Compliance Handbook for SB 4 - California's Well Stimulation Permitting Law" and "SB 4 Compliance Flowchart," (co-author),

Stoel Rives LLP, Dec. 2013

• "California's Cap and Trade Program under AB32 – a Primer" (co-author), Stoel Rives LLP, December 2012

• "Will California's 33% Renewable Portfolio Standard Survive a Commerce Clause Challenge by Other States? A Recently Filed

Colorado Case May Provide the Answer," The Override, Los Angeles Association of Professional Landmen, May 2011

• News Alert, "California High-Speed Rail: It's Coming Fast! The Central Valley is the Early Winner of Stimulus Funds," Nov. 22,

2010

• Comment, "Inequality Creates Exceptions: Limiting United States v. Mendoza to Its Policy Rationale," U.C. Davis Law Review,

1997

Civic Activities

• Board Member, U.C. Davis School of Law, King Hall Alumni Association Board of Directors

• President, Spinning Rod Way Neighborhood Watch, 2003-2009

• Moot Court Judge, U.C. Davis School of Law, 2002, 2004-2007

• Alumni Representative, Distinguished Teaching Award Selection Committee, U.C. Davis School of Law, 2009

• Member, CEB Award for Excellence in Legal Research and Writing Selection Committee, U.C. Davis School of Law, 2009-2010

T h o m a s A . H e n r y

Experience Tom Henry is a partner in the Environment, Land Use and Natural Resources group

specializing in mining and oil and gas matters. As a California mining attorney, Tom's practice involves permitting, environmental review under the California Environmental

Quality Act (CEQA), as well as resolving other land use, title and regulatory

compliance issues. Tom's oil and gas experience involves title review, as well as land use, permitting and CEQA issues related to oil and gas development and production.

Tom also advises clients as to California's AB 32 emissions reporting and Cap and Trade Program. Before practicing law, Tom served as a U.S. Army officer on active duty from

1982-1987.

Before joining Stoel Rives, Tom was a partner with Downey Brand LLP in Sacramento.

Representative Work

• Represents mining, development and oil companies and other commercial and industrial project proponents on issues of CEQA compliance.

• Represents oil and gas companies in CEQA litigation, local agency oil and gas ordinances, title opinions, permitting issues and leases.

• Represents mining companies regarding environmental due diligence for mine

acquisitions.

• Represents mining companies regarding California's pit backfill requirements.

• Represents mining companies in complying with the California Surface Mining and Reclamation Act and federal mining laws, including obtaining approval of mining

permits and reclamation plans.

• Represents developers, vineyards and mining companies in complying with California lake and streambed alteration requirements under Section 1602,

including negotiating streambed alteration agreements.

• Represents developers and mining companies in obtaining Clean Water Act

Section 404 permits for fill activities.

• Represents developers and vineyards in obtaining Clean Water Act Section 401 water quality certifications from State and Regional Water Quality Control

Boards, including drafting appeals of water quality certification determinations.

• Represents mining companies in determining vested rights status.

• Represents private project proponents in litigation regarding CEQA compliance

and design review.

Partner

(916) 319-4667 direct

(916) 447-4781 fax

[email protected]

Education

• University of California, Davis, School

of Law, J.D., 1998

• University of Texas, Austin, B.B.A.,

1982

Admissions

• California



• Listed in Best Lawyers in America® (currently: Oil & Gas Law), 2012-2015

• Member, California Independent Petroleum Association

• Member, Sacramento Petroleum Association

• Member, California Construction and Industrial Materials Association

• Member, Environmental Law Section, Sacramento County Bar Association

• Member, Environmental Law Section, State Bar of California


Presentations

• Co-Presenter, “Compliance Strategies for Surface Water Diversions Under New Section 1602 Requirements,” Stoel Rives Water

Law Webinar, July 28, 2015

• Presenter, “Challenges Associated with California’s Pit Backfill Requirements,” State Mining and Geology Board meeting,

Sacramento, California, June 11, 2015

• Co-Presenter, “Title Issues in Mine Leasing and Acquisitions and Their Potential Impacts on Permitting and Operations,” CalCIMA

Education Conference, San Diego, California, Nov. 4, 2014

• Co-Presenter, “Review of the ‘Typical’ California Oil & Gas Lease,” 32nd Annual West Coast Landmen’s Institute, Las Vegas,

Nevada, Oct. 23, 2014

• Co-Presenter, “California SB 4 Compliance Update: Practical and Legal Implications of the DOGGR Interim Regulations for

Operators in 2014,” Stoel Rives Webinar, Mar. 13, 2014

• "Getting Ready for SB 4: California's New Well Stimulation Permitting Law," Stoel Rives Seminar, Bakersfield, California, Dec. 11,

2013

• "The Not So Good, the Bad and the Ugly - What Every Landman Needs to Know About Community Leases" (presenter), 31st

Annual West Coast Landmen's Institute, Sept. 2013

• "Strategies for Complying with California's Cap & Trade Program," Kern County Bar Association, Bakersfield, California, Dec.

2012

• "Oil and Gas Exploration and Production of Private Lands in California," Infocast California Oil Summit, Long Beach, California,

Dec. 2012

• "How to Use a Title Opinion," 30th Annual West Coast Landmen's Institute, Dana Point, California, Sept. 2012

• "Off or On? Examining OMR's AB 3098 Listing Procedures," California Construction and Industrial Materials Association Annual

Education Conference, Monterey, California, Oct. 2011

• "CEQA -- Its Role In and Effect On the Permitting Process," 29th Annual West Coast Landmen's Institute, Santa Barbara,

California, Sept. 2011


• "Regulatory Trends in California," Industrial Mineral Association-North America Annual Meeting & National Industrial Sand

Association 75th Anniversary Celebration, The Lodge at Sonoma Renaissance Resort and Spa, Sonoma, California, Sept. 2011

• "Resolving Conflicts Between Oil and Gas and Renewable Energy Development," Bakersfield Association of Petroleum Landmen,

Jan. 18, 2011

• "AB 32 and SB 97: California's Laws Regulating Greenhouse Gas Emissions and Climate Change and Their Related Impacts on

Project Timelines and Permitting," 28th Annual West Coast Land Institute, Shell Beach, California, Sept. 23, 2010

• PITFALL - "Landman Harry's Adventure in California's Land Use Jungle," Bakersfield Association of Petroleum Landmen, Nov. 17,

2009

• "National Environmental Policy Act" and "Wetlands Regulations," Lorman Education Services, Zoning and Land Use in California,

2005

• "2004 Mining Law Update," American Association of Professional Landmen, 2005



• "Streambed Alteration Agreements and Notifications," Construction Materials Association Conference, 2003

• "How to Avoid a Prop. 65 Lawsuit," Construction Materials Association of California Operators Conference for the Construction

Materials Industry, 1999

Publications

• "Calif. Seems Set To Solve Split On Oil Rail Shipments," Law360, Feb. 4, 2015

• "A Compliance Handbook for SB 4 - California's Well Stimulation Permitting Law" and "SB 4 Compliance Flowchart," (co-author),

Stoel Rives LLP, Dec. 2013

• "California's Cap and Trade Program under AB 32 – a Primer" (co-author), Stoel Rives LLP December 2012

• "State Supreme Court Sets Environmental Baseline" (coauthor), The Daily Journal, Apr. 1, 2010

• "2000 Year in Review" (coauthor), Public Lands Section, American Bar Association

• "1999 Year in Review" (coauthor), Public Lands Section, American Bar Association

E r i c R . S k a n c h y

Experience Eric Skanchy is an attorney in the firm’s Environment, Land Use and Natural Resources

group, where he focuses his practice on the California oil and gas industry. Eric works with clients to acquire and lease mineral rights and he prepares drilling, division order

and acquisition title opinions.

Prior to joining Stoel Rives, Eric worked as a District Landman where he analyzed oil and gas leases and assisted with due diligence for several multimillion dollar purchases

of oil and gas assets. During law school Eric served as a legal intern at the U.S. EPA where he participated in pending litigation regarding the enforcement of the Clean

Water Act and other regulatory acts before Federal and Administrative judges.


• Registered Landman, American Association of Professional Landmen


Attorney

(916) 319-4746 direct

(916) 447-4781 fax

[email protected]

Education

• University of Colorado Law School, J.D., 2013

Production Editor, Colorado Natural

Resources, Energy & Environmental

Law Review

• Utah State University, B.S., Economics

& Political Science, 2008

Admissions

• California

• Colorado

• Utah

• Wyoming