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

An update from Sara Bergan and Sarah Johnson Phillips

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO₂) Geologic Sequestration (GS) Wells See Pre-publication Rule

The rule finalizes minimum federal requirements under the Safe Drinking Water Act for underground injection of carbon dioxide (CO₂) for GS purposes. It establishes a new class of well, Class VI, and sets minimum technical criteria  for projects. The guidance covers steps from permitting and site characterization to ongoing monitoring of the CO₂ stream, injection wells and CO₂ plume to well plugging, post-injection site care and site closure. All criteria are set for the purposes of protecting underground sources of drinking water (USDW) only. The rule covers owners and operators of new CO₂ injection wells used for Class VI GS as well as those transitioning CO₂ injection wells from Class I,II, or V to Class VI GS.   Notably the final rule, as changed or clarified from the earlier proposed rule, provides for the following:

• Independent primacy exclusively for Class VI wells under subparagraph §145.1(i) of the final rule;
• Adaptive rulemaking whereby EPA will review the rulemaking every 6 years to make changes as necessary to incorporate new research, data and information about GS technologies;
• Reevaluation of the Area of Review (AoR) for GS projects every 5 years in order to address concerns about the inherent uncertainties in modeling CO₂ movement and with emerging GS technology;
• Requirement that owners or operators use direct methods to monitor for pressure changes in the injection zone and to supplement with indirect, geophysical techniques; and
• Clarification of the requirements necessary to ensure financial resources are available to protect USDWs from endangerment over the long term.

The Final Rule will be published in the Federal Register. Information on the Final Rule and earlier actions can also be found at www.regulations.gov, under Docket ID No. EPA-HQ-OW-2008-0390.

Final Rule: Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide See Pre-publication Rule

EPA amended the Greenhouse Gas (GHG) Reporting Program, 40 CFR part 98, to cover GHG monitoring and reporting requirements for owners and operators of facilities conducting GS activities (subpart RR) and of any other facility conducting CO₂ injection (subpart UU). The data collected under the GHG Reporting Program will inform EPA policy decisions under the Clean Air Act related to the use of CO₂ capture and sequestration (CCS) for mitigating GHG emissions. Owners or operators of GS facilities are required to develop and implement a site-specific Monitoring, Reporting and Verification (MRV) plan that would be used to verify the amount of CO₂ sequestered and quantify any emissions leaks.

All UIC permitted Class VI wells will be covered under subpart RR. Enhanced oil and gas recovery (EOR) projects using CO₂ will be covered under subpart UU, but could be covered by subpart RR if they choose to opt in or apply for a Class VI well permit. Opting into subpart RR would not, for example, require an existing EOR project with a UIC Class II well permit to obtain a Classs VI permit.

The EPA approval process for the purposes of GHG reporting and verification is separate from the UIC permitting process, and the GHG reporting requirements were developed to minimize overlap with the UIC requirements.  Despite the effort to avoid overlap, both programs require regular reporting on the quantity of CO₂ injected (flow rate) but at different frequencies and specifications. There may also be overlap in monitoring for CO₂ leakage to the surface, although the UIC purpose in doing so is to protect USDWs whereas the GHG program’s purpose is to assess the efficacy of GS as a climate change mitigation strategy. The GHG rule is drafted to build upon the UIC requirements and accept information obtained under the UIC program where feasible. Research and development projects meeting eligibility requirements are exempt from reporting under subpart RR.

The Final Rule will be published in the Federal Register. Information on the Final Rule and earlier actions can also be found at www.regulations.gov under Docket ID No. EPA-HQ-OAR-2009-0926.

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An update on Oklahoma from Laura Suesser and Sara Bergan:

The Oklahoma legislature passed three bills (H.B. 2973, S.B. 1787, and H.B. 3028) in 2010 that affect the renewable energy industry. Two have already gone into effect and the third will go into effect on January 1, 2011. A summary of each bill is included below.

The Oklahoma Wind Energy Development Act (the “Act”), H.B. 2973, becomes effective on January 1, 2011 and will be codified in Okla. Stat. tit. 17 §§160.11-17 (2010). The Act includes the following:

• Decommissioning: Decommissioning requirements apply to any wind energy facility entering into or renewing a power purchase agreement (PPA) on or after January 1, 2011. If energy is not being sold under a PPA, the requirements apply to wind energy facilities which commence construction on or after January 1, 2011. The requirements include:
  • Restoration: Owners of a wind energy facility must remove wind energy equipment (to a depth of 30”) and restore land surfaces to substantially the same pre-construction condition (excluding roads) within 12 months of abandonment of a project or the end of the useful life of the equipment.
  • Cost Estimate and Posting of Financial Security: After the 15th year of operation, facility owners must file a professional estimate of the decommissioning costs together with a financial security (either a surety bond, collateral bond, parent guaranty or letter of credit) to cover such costs. Those failing to so file may incur an administrative penalty of up to $1,500/day.
•  Payment Statements and Access to Records: Any owner or operator making payments to landowners based on the amount of electrical energy produced is required to deliver a statement to the landowner, within 10 business days of payment, explaining the payment calculation and a means for the landowner to confirm its accuracy. Landowners have the right to inspect owner/operator records to confirm the accuracy of payments for up to 24 months following payment. Records must be made available for review within the state of Oklahoma.  
•  Insurance:   Owners or operators are required to obtain commercial general liability insurance policy with limits consistent with prevailing industry standards (or a combination of self insurance and excess liability insurance policy), which name the landowner as an additional insured and certificates of insurance must be delivered to landowner prior to commencing construction of the facility.

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Last week, the U.S. Department of the Interior's Bureau of Reclamation ("Reclamation") issued a draft report titled "Hydropower Resource Assessment at Existing Reclamation Facilities" (the "Resource Assessment") for public comment.  The Resource Assessment provides information on 530 exiting Reclamation sites and makes a preliminary determination about whether or not hydropower development at each facility would be economically viable.

To determine economic viability, Reclamation developed a Hydropower Assessment Tool which requires simple inputs of daily flows, headwater and tail water elevations.  According to Reclamation, the result is "valid information on potential hydropower production and economic viability."  Although the Resource Assessment does not claim to provide feasibility-level analyses for the sites, it does consider potential regulatory constraints related to water supply, fish and wildlife considerations, effects on Native Americans, water quality, and recreation, and adds the cost of mitigation to a projected total development cost for each site.  The Resource Assessment also provides benefit-cost ratios that both include and exclude renewable energy incentive prices. 

Importantly, Reclamation stated that the Resource Assessment is "targeted towards municipalities and private developers that could further evaluate the potential to increase hydropower production at Reclamation sites."  This is an indication that the federal government does not intend to develop the 192 sites that Reclamation identified as having hydropower potential.  Although this in itself is good news for developers, there's more.  For many of the Reclamation sites, developers would proceed under a Lease of Power Privilege Agreement rather than the Federal Energy Regulatory Commission licensing process set out in Part I of the Federal Power Act.  Such a lease would allow the developer to use the Reclamation facility for the purpose of generating electricity for up to 40 years. 

Comments may be submitted to Mr. Michael Pulskamp, Bureau of Reclamation, Denver Federal Center, Bldg. 67, P.O. Box 25007, Denver, Colorado 80225, or email to mpulskamp@usbr.gov.  Comments must be submitted by December 6, 2010.

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A legal update from our colleagues Seth Hilton, John McKinsey and Allison Smith:

The results are in on the California election, and it's supportive of renewable energy. The two most important developments: Jerry Brown prevailed over Meg Whitman in the gubernatorial race and Proposition 23 failed. The election appears to have been, in part, an affirmation of California's quest to expand its use of renewable energy.

Proposition 23 would have suspended the California Global Warming Solutions Act (AB 32) until the state's unemployment rate dropped to 5.5% or less for four consecutive quarters. Given that California's current unemployment rate is about 12% and the unemployment rate has been below 5.5% for four consecutive quarters only three times since 1980, Proposition 23 would have likely halted the implementation of AB 32 indefinitely. AB 32 mandates a reduction in greenhouse gas emissions to 1990 levels by 2020. More importantly for the renewably energy industry, the current mandate for 33% of the state's electricity to come from renewable energy resources by 2020 hinges almost entirely on AB 32. The California Air Resources Board (ARB), pursuant to its authority under AB 32 and following the edict of Governor Schwarzenegger's Executive Orders S-21-09 and S-14-08, is implementing a "33% by 2020" renewable energy standard (RES).

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Yesterday, the Oregon Department of Energy issued is final administrative rules for the biomass producer /collector tax credit. The new permanent rules can be viewed at the following link: http://oregon.gov/ENERGY/RENEW/Biomass/docs/BPC_PermRules.pdf/oregon.gov/ENERGY/RENEW/Biomass/docs/BPC_PermRules.pdf

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The California Air Resources Board (ARB) has issued its proposed greenhouse gas cap-and-trade program, pursuant to the California Global Warming Solutions Act (AB 32). The proposed regulation builds on the conceptual framework for ARB’s cap-and-trade program, released in November 2009. The 45-day public comment period on the regulation opened yesterday and closes on December 15, 2010. Whether by design or happenstance, ARB released this latest on the cap-and-trade program just before Californians will vote today on whether to suspend AB 32 under ballot box Proposition 23. Proposition 23 would suspend AB 32 until California’s unemployment rate dropped to 5.5% or less, for four consecutive quarters. Given that the state’s current unemployment rate is about 12%, and the unemployment rate has been below 5.5% for four consecutive quarters only three times since 1980, Proposition 23 could halt the implementation of AB 32 indefinitely.

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