Renewable + Law : Renewable Energy Lawyer & Attorneys : Stoel Rives Law Firm : Climate Change, Emissions, Carbon Markets, Wind, Solar, Biofuels : Western United States

1. The renewable energy project is proposed to be located on land identified by the REAT and/or BLM as suitable for renewable energy development.
2. The project will use air‐cooling technologies for thermal power plant cooling.
3. The appropriate biological resource surveys are completed during the appropriate season using the proper protocols.
4. A draft biological assessment (BA), draft application for Incidental Take Permits, and draft Lake or Streambed Alteration Agreement notification form, if applicable to the project, are as complete as possible and filed with applications to the appropriate lead agencies. The draft BA must include a complete draft project description, full description and assessment of project impacts and species affected, and project impact mitigation measures.
5. Cultural resource surveys required by lead agencies, and lead agency approved archaeological reports, tribal consultations, assessments, and project impact mitigation measures are completed following the proper protocols and standards.
6. BLM requirements and Resource Management Plans are addressed and incorporated in the project design, for projects located on BLM managed lands. Projects are consistent with guidance in the BLM programmatic wind and geothermal Environmental Impact Statements (EISs), and after publication, the BLM programmatic solar EIS.
7. Local agency requirements, including but not limited to local zoning, general plan policies, land use, water, hydrology, safety, aesthetics, noise, traffic, and height restrictions, are incorporated into the applications to lead agencies. The project is consistent with Williamson Act requirements, zoning ordinances, and general plan designations. If termination of a Williamson Act contract is required for locating a project on contracted lands, contract termination is in the final stages.
8. DOD and nearby military installation requirements are addressed and incorporated into a project’s design, ensuring that the project will not conflict with military operations.
9. Interconnecting the proposed project to the existing electric transmission system is shown to not negatively impact electric transmission system reliability. A transmission system interconnection study (California Independent System Operator [California ISO] Phase I, for example) is reviewed and completed by the California ISO or other control area operator. Measures for eliminating unacceptable degradation to the transmission system reliability beyond the first point of interconnection are identified and agreed upon.
10. For projects requiring local air quality management district or air pollution control district permits, include the proposed project Determination of Compliance or Authority to Construct application with applications to lead agencies.

Key Findings (see pages 3-4 of Findings and Recommendations by the California Carbon Capture and Storage Review Panel, December 2010):

1.     There is a public benefit from long-term geologic storage of CO2 as a strategy for reducing GHG emissions to the atmosphere as required by California laws and policies.

2.     Technology currently exists for the safe and effective capture, transport, and geological storage of CO2 from power plants and other large industrial facilities.

3.     High costs, inadequate economic drivers, remaining uncertainties in the regulatory and legal frameworks for CO2 storage, and uncertainties regarding public acceptance are barriers to the near-term deployment of commercial-scale CCS projects in California.

4.     There is a need for clear rules under AB 32 regarding the treatment of CO2 emission reductions from CCS projects involving capped and uncapped emission sources.

5.     Multiple state and federal agencies are currently responsible for permitting CCS projects in California.

6.     There is a need for clear, efficient, and consistent regulatory requirements and authority for permitting all phases of CCS projects in California, including CO2 capture, transport, and storage.

7.     Standards are needed to ensure the safe and effective operation of geologic storage projects.

8.     Consistent requirements are needed for monitoring, measuring, verifying, and reporting injected CO2, and releases, if any, and for GHG accounting protocols necessary to comply with federal and state laws and policies to reduce CO2 emissions.

9.     There is a need to establish clear financial responsibility for the stewardship of geologic storage sites during the (a) operating phase; (b) post-injection (pre-closure) monitoring phase; and (c) post-closure phase.

10. The right to use subsurface pore space for geologic storage needs to be clarified.

11. There is a need to address any potential environmental justice aspects of CCS projects.

12. There is a need for increased public understanding of CCS benefits and risks.

13. Absent new initiatives, economic barriers to early CCS deployment will delay the technological learning needed to drive down the costs of CCS. 

 Key Recommendations (see pages 4-5 of Findings and Recommendations by the California Carbon Capture and Storage Review Panel, December 2010):

To ensure that CCS can play a role in meeting California’s requirements for GHG emission reductions:

1.   The State should recognize appropriately regulated CCS as a measure that can safely and effectively reduce atmospheric emissions of CO₂ from relevant stationary sources, including power plants and other industrial sources. To that end, and conditioned on compliance with all applicable federal and state requirements, ARB should: (a) for capped sources under AB 32, recognize CO₂ sequestered by CCS projects as having not been emitted to the atmosphere (with the result that an allowance is not required to be held for each ton of CO₂ that is captured and geologically stored) and define accounting protocols for sequestered CO₂ and (b) for uncapped sources under AB 32, decide whether offset protocols for CCS projects within the State should be adopted.

To address regulatory and permitting issues related to CCS projects:

2.      The State should evaluate current EPA regulations and determine which, if any, State agency should seek “primacy” for permitting Class VI wells under the UIC program.

3.      The State should designate the California Energy Commission (Energy Commission) as the lead agency under the California Environmental Quality Act (“CEQA”) for preventing significant environmental impacts in CCS projects (both new and retrofit projects).

4.      The State should clarify that the State Fire Marshall is indeed the lead agency for regulating the safety and operation of intrastate CO₂ pipelines.

5.      The Energy Commission should consult with the responsible permitting agencies in carrying out its responsibilities as the CEQA lead agency for CCS projects. Specifically, the Energy Commission should:

a.       Designate the Division of Oil, Gas and Geothermal Resources (DOGGR) to be the responsible agency for activities related to the subsurface.

b.      Coordinate the development of performance standards for CCS sites that would include design requirements and other operational measurements consistent with the goals of protecting the groundwater and preventing emissions of CO₂ to the atmosphere.

c.       Designate the California Air Resources Board as the responsible agency for air-related aspects of CO₂ monitoring, reporting, and verification (MRV) requirements.

d.      Designate the State Fire Marshall as the responsible agency for CO₂ pipelines.

e.       Designate the State Water Board as the responsible agency for impacts to water quality.

f.       Designate other agencies as appropriate.

To address key legal issues and uncertainties related to CCS projects:

6.   The State should consider legislation establishing an industry-funded trust fund to manage and be responsible for geologic site operations in the post-closure stewardship phase. In addition, California should proactively participate in federal legislative efforts to enact similar post-closure stewardship programs under federal law.

7.   The State legislature should declare that the surface owner is the owner of the subsurface “pore space” needed to store CO₂. The legislature should further establish procedures for aggregating and adjudicating the use of, and compensation for, pore space for CCS projects.

8.   The State should consider whether legislation is needed to extend to CO₂ transportation infrastructure for CCS projects the current authority for acquiring the rights of way for the siting of transportation infrastructure for natural gas storage projects.

To ensure the safe, equitable, and cost-effective use of CCS in California:

9.   It should be State policy that the burdens and benefits of CCS be shared equally among all Californians. Toward this end, the permitting authority shall endeavor to reduce, as much as possible, any disparate impacts to residents of any particular geographic area or any particular socioeconomic class.

10.                       The Panel endorses the need for a well-thought-out and well-funded public outreach program to ensure that the risks and benefits of CCS technology are effectively communicated to the public.

11.                       The State legislature should establish that any cost allocation mechanisms for CCS projects should be spread as broadly as possible across all Californians.

12.                       The State should evaluate a variety of different types of incentives for early CCS projects in California and consider implementing those that are most cost-effective.

The Basics: the Emissions Cap and Covered Entities

• The Cap-and-Trade Program regulates sources that emit carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexaflouride, and nitrogen trifluoride. Only sources that emit more than 25,000 metric tons of carbon dioxide equivalents (“MT CO2e”) per year, termed “covered entities,” potentially have compliance obligations under the Cap-and-Trade Program. 
• An entity’s emissions for purposes of compliance with the Cap-and-Trade Program are based its emissions reported under ARB’s Mandatory Reporting Program. Entities failing to report will still be assigned a place in the schedule by ARB.
• The Cap-and-Trade Program establishes an overall cap on GHG emissions that will decline over the period of the Program, leading to overall reductions by 2020 of approximately 18 to 27 million MT CO2e (“MMTCO2e”).
• The initial emissions cap is set at 165.8 MMTCO2e, based on the total emissions of covered entities with obligations during the initial three-year period of the Program. This initial cap will decrease two percent each year to reach 159.7 MMTCO2e by the end of 2014. At the beginning of 2015, the cap will increase to 394.5 MMTCO2e to include emissions from fuel combustion, which are accounted for through the inclusion of distributors of transportation fuels, natural gas, and other fuels. From 2015, the cap will decline by three percent annually, to 334.2 MMTCO2e in 2020.
• Large industrial entities, including refineries, cement plants, chemical plants, etc., are included in the Program starting in 2012, if they emit more than 25,000 MT CO2e per year. 
• The electricity sector is also included in the Program in 2012. While investor-owned and publicly-owned utilities will receive emissions allowances from ARB, electricity producers and importers are the entities within the electricity sector with compliance obligations. Through an auction by the utilities, producers and importers will obtain allowances to meet their compliance obligations. Compliance obligations are measured at the point of generation for electricity generated in state. For distributors of imported electricity, compliance obligations will be based on emissions from a particular facility where it is known; where the generator is unknown, a default emission factor will be used, based on the average emissions associated with the available electricity generation that could be sold on the spot market into California.
• Starting in 2015, natural gas suppliers will be included in the Program if their total deliveries in California, minus those amounts that are already accounted for through covered sources like electrical generators, exceed 25,000 MT CO2e . Transportation fuel suppliers will have to account for the total emissions of the fuel that they sell or distribute for consumption in California. Liquefied Petroleum Gas (LPG) producers, including fractioners and refiners and LPG importers, will have compliance obligations for emissions resulting from full combustion or oxidation of all fuels sold or distributed in California. 
• Certain electricity generators with GHG emissions are excluded from compliance obligations, even if their emissions put them over the 25,000 MT CO2e threshold. Combined heat and power facilities have a compliance obligation if their emissions exceed 25,000 MT CO2e. However, biomass energy facilities, including those using biomass fuel derived from landfills, wastewater treatment facilities, or at waste-to-energy facilities, are excluded from compliance obligations if the biomass fuel is reported and verified pursuant to the ARB Mandatory Reporting Regulation. If fossil fuels or unverified biomass-derived fuel supplement the use of verified biomass at a facility, the facility will be subject to compliance obligations for those supplemental fuels.
• Any entity that does not meet the 25,000 MT CO2e threshold can opt in during any compliance period and receive allowance allocations on the same terms as other participants in its sector, along with corresponding compliance obligations.
• Any covered entity whose emissions exceed 25,000 MT CO2e during any year of a compliance period has a compliance obligation for that period and the next compliance period, unless a shift down of all sources of GHG emissions is made.

Compliance

• The Program is divided into three-year compliance periods. The first compliance period is January 2012 to December 2014 and includes the electricity providers and large industrial sources described above. The second compliance period is January 2015 to December 2017 and includes fuel distributors for the first time. The third compliance period, with all covered entities, runs until 2020.   
• Each covered entity must surrender compliance instruments equal to its actual emissions during a compliance period. Covered entities can meet compliance obligations with allowances and offsets. Each allowance allows the emission of one metric ton of CO₂e each year. 
• At the end of each year for the first two years of a compliance period, the complying entity will surrender compliance instruments equal to 30% of its emissions for the compliance period. At the end of the full three-year period the entity submits instruments equal to the balance of its compliance obligation which is the total emissions for the three-year period, less the amount covered during the first two payments. 
• A failure to submit the adequate number of allowances (or offsets) when required will be considered excess emissions and the covered entity will then be required to surrender four allowances for each failure to submit a compliance instrument. 
• An offset represents reduction or removal of GHG emissions from activities not covered by the Cap-and-Trade Program. These offsets are issued by ARB or programs linked to the Cap-and-Trade Program, e.g. projects developed under the offset protocols discussed below. Each offset also represents a metric ton of CO₂e. 
• The amount of external offsets allowed for compliance is limited to 8% of an entity’s total compliance obligation.

Allocation of Allowances and Auctioning

• The Cap-and-Trade Program provides for the free allocation of allowances during the first three years, with an increasingly greater percentage of allowances auctioned as the Program continues. 
• Free allocations are being made to the industrial sector to ease the transition to manufacturing processes that produce less carbon emissions and to minimize the likelihood of “leakage” due to the shifting of production from California manufacturers to other states due to the inability of California facilities to pass the extra cost of compliance onto their customers. During the first compliance period, each industrial sector will receive free allocations equal to about 90% of that sector’s total emissions. In subsequent compliance periods, the total allocation will decrease, providing less transition assistance. Each industry has been evaluated for the likelihood of leakage, and those with a greater risk of leakage will continue to receive some free allocations even during later compliance periods.
• As noted above, the Program will allocate free allowances to utilities, which are required to use the proceeds from auctioning these allowances to generators for the benefit of their rate-payers. The Program assumes that independent generators will pass the cost of the allowances they must buy through to purchasers of their electricity.
• There will also be the advanced auctioning of 2% of ARB’s total allowance budget for use by covered entities in future compliance periods. 
• The bulk of the auctioning of allowances will occur in the second and third compliance periods, as allowances will likely be auctioned for most types of fuels distributors, rather than freely allocated.
• ARB is working on a market tracking system to manage allowances and offsets, including tracking compliance instrument ownership and submittals and transactions of compliance instruments.   
• California’s Program may eventually link to other cap-and-trade programs such as the Western Climate Initiative or the Regional Greenhouse Gas Initiative in the northeast.

Offset Protocols

• ARB approved four offset protocols on December 16, 2010: (1) the U.S. forest projects protocol, (2) the livestock manure digester products projects protocol, (3) the urban forests projects protocol and (4) the ozone depleting substances protocol. 
• In addition to future projects developed under those protocols, certain existing projects will be able to generate offsets. 
• ARB will consider additional offset protocols that will available to generate offsets. One of the first protocols that will be worked on is related to international programs to reduce emissions from deforestation and forest degradation in developing countries. California has entered into a memorandum of understanding with the states of Chiapas, Mexico and Acre, Brazil whereby preservation of forests in these states could generate offset credits available to covered sources in the Cap-and-Trade Program.

California ARB's request for a waiver is premised on the Clean Air Act provision that allows states to enact stricter motor vehicle emission standards than the federal government's, provided EPA has approved a waiver for the state to do so.  Under the Clean Air Act, EPA must grant a waiver unless it finds that the state:

• was arbitrary and capricious in its finding that its proposed standards are in the aggregate at least as protective of public health and welfare as applicable federal standards,
• does not need such standards to meet compelling and extraordinary conditions, or
• has proposed standards not consistent with section 202(a) of the Clean Air Act.

In denying ARB's original waiver request, the EPA administrator at the time, Stephen Johnson, noted that President Bush had just signed an energy bill that would work to reduce emissions throughout the U.S. and that increased fuel economy standards.  The energy bill increased fuel efficiency for new cars and light trucks by 40% by 202, to an average of 35 mpg.  This is in fact the biggest increase by Congress in fuel economy standards since the program was created in 1975.  As Johnson announced in December 2007, "The Bush administration is moving forward with a clear national solution, not a confusing patchwork of state rules."  It's true that if the waiver is granted, California would enact a more stringent fuel economy standard than in any other state.  But, 16 other states have pledged that if California can move forward with its higher standard, they would in turn adopt California's standard as their own.