California moved closer in late October to capping greenhouse gas emissions from power plants in the state. New caps on carbon dioxide (CO2) and other greenhouse gas emissions from power plants are expected to take effect starting on January 1, 2013 with more far-reaching restrictions soon to follow.

The California Air Resources Board — called CARB — voted unanimously on October 20 to limit greenhouse gas emissions and create a comprehensive statewide cap-and-trade program. The California Office of Administrative Law must now review the program to ensure that it complies with the state Administrative Procedures Act.

The board is implementing a program that the state legislature adopted in 2006 in a bill that Californians call AB 32. The bill requires the state to reduce greenhouse gas emissions to 1990 levels by 2020, and it requires CARB to implement a program by the end of this year to achieve this goal. AB 32 was signed by then-Governor Arnold Schwarzenegger. California voters defeated a ballot initiative in November 2010 that would have overturned it.

The program caps the amount of CO2 and other greenhouse gases that power plants, refineries, chemical companies, cement plants and other affected emitters are allowed to release each year. Each covered emitter will be issued a permit allowing it to emit a set amount of greenhouse gases per year. The program is market based because anyone who can reduce his emissions more efficiently or less expensively can earn income by selling his unneeded emission allowances to those whose emissions are harder or more expensive to control. As the cap on overall permitted emissions ratchets down over time, the value of the permits should rise and the overall level of greenhouse gases entering the atmosphere should fall.

Initially the program will cover only the power and manufacturing sectors (including refineries but only for their “direct emissions”). By 2015, the program will expand to cover a far broader range of emitters than is covered by existing cap-andtrade programs in other US states and Europe with its scope set eventually to reach 85% of the California economy, including not only electricity generation and manufacturing, but also such sources as refineries, pipelines and fuel distributors. By way of comparison, the Regional Greenhouse Gas Initiative that currently covers 10 northeastern and mid-Atlantic states (New Jersey announced it would withdraw by year’s end) only covers emissions from power plants.

Beginning in January 2013, the program will require “covered entities” — defined to include the 600 largest emitters, such as power plants, refineries and distributors of both natural gas and transportation fuels — to hold and ultimately surrender emission allowances equal to their greenhouse gas emissions by 2015. Each allowance permits the holder to emit one metric ton of CO2-equivalent. The number of allowances issued by the state annually will equal the cap on overall emissions. That cap will decrease at a set rate through 2020. Compliance obligations for covered entities begin in 2013 and, as the cap tightens, market pressure from fewer available allowances should, in theory, require covered entities to reduce their emissions or pay the market price to comply.

The program will have an effect beyond California’s borders by imposing compliance obligations on emissions associated with electricity, natural gas and other fuels imported from other states into California. This is the first regulatory program to regulate suppliers of power and fuels in other states who sell into the California market.

The new rules cover “first deliverers of electricity,” who include not only in-state electricity generating facilities, but also “electricity importers.” “Electricity importers” are defined as “facilities physically located outside the state of California with the first point of interconnection to a California balancing authority’s transmission and distribution system.” Thus, even facilities located entirely outside California may be required to comply if their energy is sold in the state.

Similarly, the program may apply to out-of-state suppliers of natural gas and other fuels whose products sold in California reach an annual threshold of 25,000 tons or more of CO2-equivalent from emissions from combustion or oxidation of the fuels.

Initially, CARB will distribute most allowances for free among the covered entities according to a complex set of factors such as regulatory exposure of various sectors and efficiency goals. As time passes, an increasing proportion of allowances will be sold in quarterly auctions. As more allowances enter the market via auctions and the overall cap is lowered, the cost of emitting greenhouse gas for many covered entities should increase.

The new CARB rules should limit wild swings and increase stability in the auction market. To prevent prices from falling too low, the early auctions will have a price floor of $10 per allowance, adjusted over time. Unsold allowances are returned to the state’s “auction holding account” and will be re-sold at later auctions, subject to the limitation that only 25% of an auction’s total volume may include such re-auctioned allowances.

To prevent prices from rising too high too quickly, most allowances will be given away initially for free. As auctions account for distribution of progressively more allowances, there will be an allowance price containment reserve. This reserve will offer allowances for sale six weeks after each auction at set price tiers ranging from $40 to $50 a ton at first, adjusted over time.

The CARB program establishes three compliance periods. The first runs from 2013 to 2014, the second from 2015 to 2017 and the third from 2018 to 2020. Each covered entity must true up its allowances with its emissions for the prior compliance period by November 1 of the following year (for example, by November 1, 2015 for the first compliance period). However, the program requires that covered entities surrender allowances equal to at least 30% of the previous year’s emissions by November 1 in years that are not true-up compliance years.

The program also creates a domestic offset market. Covered entities can meet, or “offset,” up to 8% of their compliance obligations by surrendering valid greenhouse gas offset credits. Unlike reductions in emissions by the regulated entities themselves, the reductions backed by such offset credits may be generated by anyone anywhere in the country. However, to qualify under AB 32, the offset credits may only be obtained in three ways. First, certain “early action offset credits” generated between 2005 and 2014 pursuant to the protocols of the Climate Action Reserve may be converted into credits that CARB will issue. Second, CARB expects to issue its own offset protocols. Third, CARB expects to allow use of credits registered under some third-party offset project registries.

California receives nearly a quarter of its power from outof- state sources. Regulated entities often hold a broad array of generating facilities. The program attempts to prevent circumvention of compliance obligations by what CARB calls “resource shuffling.” This basically amounts to importing power from out-of state power plants with fewer greenhouse gas emissions for use in California while exporting more emissions- heavy power from California to avoid its regulation.

According to The New York Times, of the 121 million tons of greenhouse gas emissions associated with the California economy in 2010, 37% came from the power industry, 28% from refineries, 10% from oil and gas extraction, 9% from stationary combustion, including industries from glass makers to sawmills to dairies, 9% from electrical cogeneration, and 5% from the cement industry. With the effective date of the program approaching and the first allowance auction scheduled for August 15, 2012, the requirements may give large emitters an incentive to hedge their exposure early rather than wait for the auction.

Utility MACT

The deadline for the US Environmental Protection Agency to define what it considers the “maximum achievable control technology” or “MACT” for controlling certain emissions from coal-fired power plants has been pushed back to December 16.

The agency received more than 900,000 comments to its proposed rule. EPA estimates that about 10,000 megawatts of coal-fired power may be taken out of service as a result of the rule to install MACT at such facilities, although many believe the number will be much higher. There are concerns about the potential effect on grid reliability if so many power plants are retired. The Federal Energy Regulatory Commission will hold a technical conference on November 29 and 30 on the reliability of the US bulk-power system, including the potential impact of the new EPA rules.

The EPA “utility MACT” rule describes pollution control equipment that will have to be used at certain power plants to reduce acid gases, non-mercury metals and mercury. MACT for existing power plants is determined based on the average emissions of a subset of best-performing facilities.

Existing air emissions controls already used at the facilities to reduce emissions of particulate matter, SO2 and NOx also help reduce mercury emissions. A October 2009 report by the US General Accounting Office, an arm of Congress, entitled “Clean Air Act: Mercury Control Technologies at Coal- Fired Power Plants Have Achieved Substantial Emissions Reductions,” said roughly 25% of existing coal-fired power units achieve at least a 90% reduction in mercury emissions through exiting pollution controls. The efficiency of existing controls with respect to mercury depends on a number of variables including plant configuration and type of coal burned. Additional controls like activated carbon injection may be needed to increase the efficiency of these systems with respect to mercury removal.

The additional controls can be very expensive to install and maintain. Developers and lenders will have to take their calculators out to figure the costs.

Cross-State Air Pollution Rule

The US Environmental Protection Agency released an ambitious “cross-state air pollution rule — called “CSAPR” and pronounced “Casper”) — to replace the “clean air interstate rule” — called “CAIR” that was struck down by a US appeals court in 2008.

CSAPR will impose emissions caps that will require reductions in SO2 and NOx emissions from existing power plants in 27 states mostly east of the Mississippi River, but as far west as Texas.

CSAPR addresses the interstate transport of SO2 and NOx from upwind to downwind states. Tension is building between industrial, upwind states over what they see as new costly regulations that will shackle their economies for the benefit of downwind states with big cities.

The new rules go into effect on January 1, 2012.

Critics in the upwind states fear the rules could lead to rolling blackouts during peak summer months. They also complain that the capital outlay some power plants will have to spend on pollution control to comply will significantly increase the cost of electricity.

Reaction to the new rules has been swift. Numerous parties asked EPA to reconsider the rules before the October 7 deadline for such requests. Ameren, a large mid-western utility headquartered in St. Louis, said it will close two power plants primarily due to the expected costs of complying.

A number of lawsuits have been filed to block the new rules and have been largely consolidated in EME Homer City Generation L.P. v. EPA before the US appeals court in Washington, D.C. Seven northeastern (downwind) states moved on October 19 to intervene in the case to defend the rule.

Cooling Water Intake Structures

Compliance with an EPA proposed rule on cooling water intake structures could be very costly and lead to retirement of some older power plants, particularly after the costs are added to the expected costs to comply with CSAPR and utility MACT.

Many older power plants use oncethrough cooling. The alternative is closedcycle cooling that uses much less water because the cooling water is recycled. Facilities with once-through cooling will face much higher costs to comply with the new rule on cooling water intake structures. The government is concerned about impingement and entrainment of aquatic organisms. Impingement occurs when aquatic organisms are trapped against cooling water intake screens. Entrainment occurs when such organisms are drawn into a facility.

The proposed regulations would apply to existing facilities with permits to discharge storm or wastewaters and that have water intake structures with design intake flows of more than two million gallons of water per day and that use at least 25% of that water exclusively for cooling.  

Compliance with impingement restrictions may require installation of additional screens and reduction of water intake flow rates. New units at existing facilities would probably be required to install technology equivalent to closed-cycle cooling. A final rule is not expected until July 2012, and some facilities may have up to eight years to comply with the requirements.