California Plans a Carbon Diet

California Plans a Carbon Diet

January 01, 2009

By Heather Mehta, Briana Kobor and Dr. Robert Weisenmiller

Anyone who thinks that putting a program in place to cap carbon emissions in the United States will be easy should take a look at what is happening in California. The state became the first in the nation to adopt mandatory carbon controls in 2006. It is still struggling to put the regulatory framework in place to implement its program.

Carbon controls are widely expected to be adopted at the federal level by 2010. The California experience shows that developing the regulatory structure to implement controls will likely take years and will be fraught with challenges as the detailed regulations are developed.

The California law that controls emissions is called AB 32. It requires California to limit greenhouse gas emissions to 1990 levels by 2020. In December, more than two years after AB 32 became law, California took a significant step toward fulfilling the goal of AB 32 when the California Air Resources Board — called CARB — unanimously approved a so-called scoping plan that lays out how California will reduce its greenhouse gas emissions to reach the 2020 target. The plan is available on the CARB website .

California Data

California emits roughly 2% of worldwide greenhouse gas emissions, making the state the 15th largest emitter on the planet. However, the California economy is less carbon intensive than the national average. California represents about 13% of the US economy, but state greenhouse gas emissions account for only 7% of total US emissions.

The California transportation sector is the largest single source of emissions, constituting 38% of statewide emissions. Electricity is the second largest emitting sector with 23% of statewide emissions. The pie charts show average emissions during the period 2002 to 2004 in California by sector. California imports about a quarter of its electricity. However, because a good portion of imported power comes from coal-fired generation, imported power accounts for more than half of the emissions from the electricity sector.

The California emissions profile is different than the profile for the United States as a whole in one important respect: in-state electricity generation is responsible for 11% of California emissions, while on the national level, electricity generation is responsible for 40% of emissions, the largest of any sector.

There are two main reasons for this. First, California has aggressively pursued energy efficiency programs for many years. As a result, per-capita energy use in California has remained relatively flat since the 1970s while national per-capita energy use has risen dramatically. In 2005, national per-capita energy use was nearly twice that of California. Second, California is less dependent on coal for electricity generation with more hydro, renewables and natural gas in its power resource mix than the rest of the nation. Any national policy to reduce greenhouse gas emissions should affect national electricity markets more than the market in California.

Legal Framework

California has been moving to limit greenhouse gas emissions since 2002. The state legislature voted that year to require the state to adopt regulations to reduce emissions in the transportation sector, the state’s single largest source of emissions.

Meanwhile, Governor Arnold Schwarzenegger issued an executive order in 2005 that called for statewide emissions to be reduced to 2000 levels by 2010, 1990 levels by 2020 and 80% below 1990 levels by 2050. These goals were partially codified a year later in AB 32, which adopted the 2020 target and delegated implementation primarily to CARB.

Following the passage of AB 32, the California Environmental Quality Act — called CEQA — emerged as another policy front with climate change implications. Attorney General Jerry Brown and environmental groups filed lawsuits forcing the consideration of greenhouse gas emissions when land use permitting and planning take place.

In response, the state Senate passed legislation (SB 97) in 2007 requiring clear guidelines be implemented for taking greenhouse gas emissions in account under CEQA by January 1, 2010. Another bill enacted in September 2008 requires streamlining the CEQA process and adoption of strategies for sustainable communities by addressing transportation and housing.

The implementation details of AB 32 and these other laws will be developed in the months and years ahead.

The various laws leave no doubt that consideration of greenhouse gas emissions and their climate change implications is being built into every major policy decision in California. For example, the California Public Utilities Commission considered the emissions implications of the Sunrise transmission project in its recent decision approving the San Diego area transmission line. The California Energy Commission has opened an investigation into how best to incorporate consideration of greenhouse gas emissions impacts in its power plant siting cases.

The Scoping Plan

California emissions will be capped at 427 million metric tons of CO2-equivalent emissions (MMt) in 2020. Such a cap will require a reduction of 169 MMt, or roughly 30%, from projected business-as-usual emissions in 2020. This reflects an overall reduction of roughly 10% from recent emission levels.

CARB adopted its proposed scoping plan on December 11, 2008. The plan describes California’s strategy for meeting the emission reduction target. While the focus of this article is primarily on the electricity sector, the scoping plan includes measures for greenhouse gas reduction in other sectors, including separate measures directed at the transportation sector, creation of public goods charges and water use fees, and fees on gases with high global warming potential.

The strategy for reducing emissions from the power sector has several parts. The state will try to generate 33% of its electricity from renewable energy by 2020. It will expand existing energy efficiency programs and strengthen appliance standards. It will set a goal for increased use of combined heat and power technologies. It will link its cap-and-trade program with the Western Climate Initiative or WCI (see sidebar) to create a regional market for GHG emissions. The CPUC has already adopted some of these goals for the investor-owned utilities, but the scoping plan extends them to the municipal utilities as well.

The actual reduction measures aimed at the electricity sector embrace both command-and-control and market-based strategies for emissions reductions. To some extent, the command-and-control requirements for renewable energy, enhanced energy efficiency and combined heat and power are analogous to the tried approach of requiring the best available control technologies. However, a full command-and-control approach would lead to a struggle with the appropriate role for the market. “If there’s anything we know from history, we need a price signal to mobilize market forces,” said CARB member Daniel Sperling. “That means a carbon tax or cap-and-trade.” Given California’s disastrous experience with power market restructuring, there is a concern in many corners that a cap-and-trade program will lead to creative carbon market manipulation schemes to transfer money but not necessarily achieve real greenhouse gas emissions reductions. Chair Mary Nichols said: “Whenever someone says something is simple and easy, you should always hold onto your wallet.”

A cap-and-trade program is scheduled to come into effect for electricity and large industrial sources in 2012. Smaller industrial, residential, commercial and transportation sectors will follow in 2015. The scoping plan states that the cap-and-trade program will be used to meet 20% of the overall emission reduction goal and will regulate 80% of California emissions sources. CARB had initially indicated that it would pursue only the cap-and-trade program, giving less focus to consideration of a carbon tax policy. However, in the public meeting approving the scoping plan, several CARB members said a carbon tax is still a possibility if concerns arise over cap-and-trade implementation.

Issues for the Power Sector

The scoping plan is merely an overview of program strategies. The details are expected to take another two years to fill in. There are five big issues of concern to power companies.

One is what share of reductions will have to come from power plants. The scoping plan envisions that the electricity sector will contribute at least 40% of total reductions even though the electricity sector accounts for only 23% of statewide emissions. At the same time, CARB wants to reduce emissions in the transportation sector by promoting electrification of different forms of transportation (e.g. plug-in hybrid electric vehicles, electric forklifts, and truck stop electrification). Thus, the power sector is being asked to shoulder a substantial burden for the state efforts to reduce transportation emissions. The CPUC and the CEC encouraged CARB to allocate extra allowances to the electricity sector in recognition that transportation-specific electrification measures could lead to higher emissions in the power sector.

Another issue for power companies is the point of regulation. California faces special challenges in reducing emissions from the electricity sector because of the quantity of imported electricity generated from coal. In addition, California must anticipate legal challenges to its regulations from out-of-state owners of coal generation and coal producers on the grounds that these regulations may violate the interstate commerce clause of the US constitution.

Three basic approaches to the point of regulation were considered by CARB before issuing the scoping plan: a source-based approach, a load-based approach, and a first-jurisdictional-deliverer approach. The state is expected to adopt a first-jurisdictional-deliverer approach.

Under a source-based approach, the point of regulation is the generator. A key drawback to the source-based approach was that California has no legal jurisdiction to regulate emissions of out-of-state generators. An alternative would have been to follow a load-based approach, which would have regulated the load-serving entities that generate or buy electricity for delivery to their customers. While a load-based approach would account for out-of-state generation, it would have involved complex accounting and less direct reduction incentives than a source-based approach. The first-jurisdictional-deliverer approach is a middle ground. Under the first-jurisdictional-deliverer approach, the responsibility for compliance is assigned to the entity that owns the electricity as it is delivered into the California grid. The first-jurisdictional-deliverer of in-state electricity would be the generator. For a majority of imported power, the “deliverer” is the importer: an investor-owned or public utility or wholesale power marketer.

A third issue is how allowances will be distributed under the cap-and-trade program. The distribution scheme has the potential to confer a competitive advantage on particular businesses. Full administrative allocation has the potential to generate windfall profits for some entities while full auction could create a large financial burden of compliance.

The scoping plan calls a 100% auction of allowances “a worthwhile goal,” although there must be a transition to such a system. The WCI has recommended that a minimum of 10% of allowances be auctioned in the first compliance period, gradually increasing to an auction of at least 25% of allowances in 2020. The CEC and the CPUC want a much swifter transition. They are calling for 20% of allowances to be auctioned in 2012 increasing by another 20% each year thereafter until a 100% auction is reached in 2016.

The fourth big policy issue is offsets. CARB is considering whether to allow companies to use offsets to meet their emission reduction obligations. Offsets are emission reductions from uncapped sources beyond those required by direct regulations – for example, manure management or methane capture at landfills. Without any offsets, or with insufficient offsets, emitters will have to meet their obligations through direct emission cuts or through the purchase of allowances in the marketplace.

The WCI is recommending that states may use offsets for as much as 49% of reductions over the lifetime of the program without any rules on when polluters can use the offsets. In contrast, CARB will limit the use of offsets to each three-year compliance period. Thus far, CARB has determined that it will limit offsets to account for less than half of emission reductions, but has not finalized an offset percentage.

CARB identified two important purposes for offsets in the California program. First, offsets could potentially offer lower-cost emission reduction options for companies whose emissions are capped. This flexibility in meeting emission reduction goals is critical in the view of energy companies such as the investor-owned utilities. Second, offsets could achieve reductions from “uncapped” sources. The geographic scope of allowed offsets, including whether out-of-state or international offsets would be acceptable, is still undetermined.

Some parties to the CARB proceeding argue that CARB should not permit any offsets and other parties believe offsets should be limited to a very small percentage of the emission reduction targets. Opponents of offsets cite a number of reasons for supporting limitation or exclusion, including that limiting offsets will encourage investments in green energy and clean technology and will ensure the allowance market is robust by increasing demand for allowances.

The last big policy issue is contract “shuffling.” Many greenhouse gas emissions attributed to the supply of electricity in California are emissions from power plants in other states. California does not have the authority to regulate emissions from these plants, but it does have jurisdiction over entities that purchase power from these generators. This situation has led to some concerns over what has become known as contract shuffling.

Buyers of imported power could try to replace contracts for coal-fired power with contracts for hydro, wind or other carbon-neutral sources of power. If the sellers of power to California shuffle the allocation of types of power in their portfolios, then they could continue to offer the same coal-fired power to customers in other states. Carbon emissions in the region as a whole will not have changed. Cap-and-trade implementation in other states and provinces who have signed on to the WCI will help to ease this concern; however, under the current program, several western states will remain unregulated.

Potential Winners and Losers

When the dust settles, California could come out a winner or a loser. As a trailblazer for emissions controls, California should have a first-mover advantage in attracting clean technology businesses to the state. Where California could be the loser is if other neighboring states or even other US states opt not to adopt similar policies, and California simply becomes a high-cost state for both residents and businesses.

How state regulators react to the inevitable implementation delays and problems will also determine California’s success. California cannot afford to be on the bleeding edge of regulatory innovation again.

CARB is pinning substantial hope on renewable energy being able to deliver a significant amount of zero-emissions electricity to meet electricity demand. Of the 169 MMt in emission reductions required under the scoping plan, 21 MMt are expected to come from an increase in the amount of electricity generated from renewable energy. While not yet codified into law, the emphasis on a 33% percent renewable standard indicates that California remains serious about spurring new renewable development within its borders.

The concept of a 33% renewable standard has been discussed for several years now and was the subject of a November 2008 executive order signed by Governor Schwarzenegger. However, California is not on track to achieve even the current, legislatively-mandated target of 20% renewables by 2010. California renewable generation accounted for only 12% of retail electricity deliveries in 2007, roughly the same amount as when the standard of 20% by 2010 was made law. The CEC reports that the primary reason for this failure is insufficient transmission infrastructure. Over the past few years, utilities have signed contracts for renewable generation, but the interconnection queue to connect new generating facilities to the inadequate grid has been clogged, preventing timely connection.

CARB is also relying heavily on enhanced energy efficiency. California has a record of success with energy efficiency that stretches over three decades. CARB, the CEC and CPUC have established very aggressive energy efficiency goals that may prove difficult to reach. For example, in September, the CPUC adopted the state’s first long-term energy efficiency strategic plan calling for, among other goals, that all new residential home construction be zero net energy by 2020 and all new commercial buildings be zero net energy by 2030. The investor-owned utilities could benefit from the heavy emphasis on energy efficiency given the substantial incentives already in place for the utilities to achieve energy efficiency targets, but they will be challenged to meet these new goals.

Another potential winner may be combined heat and power, or cogeneration, which has languished in California for the past two decades. The scoping plan set a target of adding 4,000 megawatts of cogeneration capacity by 2020 to offset 30,000 GWhs of electricity demand that would otherwise be met by traditional power sources. In the coming year, the CPUC and CEC will begin new proceedings to address market barriers to increased use of cogeneration, both investor- and municipally-owned utility procurement of cogenerated electricity, eligibility criteria like maximum megawatt capacity to qualify for cogenerator incentives, and a way for cogenerators to sell excess electricity to the grid. Once the CPUC and CEC have addressed these issues through their respective proceedings, CARB plans to evaluate whether additional methods will be necessary for meeting its goal.

In terms of potential losers, the holders of long-term fixed-price contracts may be unable to adapt to the new market. The new emission caps create an obligation for power plant owners that in many cases was not contemplated when long-term power purchase agreements were negotiated. Holders of fixed-price contracts have no means to increase revenues to offset higher costs incurred to reduce emissions. The only alternative for these entities may be to reduce output. This, in turn, could have implications for reliability of the grid.

Owners and operators of coal-fired power plants and other carbon-intensive fuels will see their competitive positions eroded. A number of municipally-owned utilities in southern California, including the Los Angeles Department of Water and Power, rely heavily on out-of-state coal-fired power plants in their resource mixes. These entities have argued passionately that the plan for a cap-and-trade strategy could amount to a wealth transfer from them to investor-owned utilities. LADWP analyzed the scoping plan and concluded that PG&E (which has very low greenhouse gas emissions) would stand to reap $3.2 billion from the sale of allowances while LADWP would pay $2.2 billion a year to purchase allowances. LADWP would rather invest these billions in energy efficiency and renewable generation projects and not, as LADWP has stated, provide a “subsidy” to PG&E for its emission reduction efforts.

Finally, the utility sector may struggle in the face of increasing costs. Utilities will be obligated to purchase more renewable power and implement aggressive energy efficiency measures. The utilities are also likely to require an enhanced and smarter grid system. The utility rate base could be expanded considerably through the addition of smart meters and smart grids with additional distribution, transmission and storage systems. These expenditures, combined with required purchase of allowances and offsets, could substantially increase utility revenue requirements. In addition, the utility sector faces a significant challenge posed by the CARB proposal to reduce emissions in the transportation sector through electrification. This proposal holds the possibility of shifting the burden for emission reductions to the power sector. With large-scale transportation electrification, demand for electricity will increase at the same time the scoping plan calls for decreasing electricity emissions. In the end, utility ratepayers may prove the real losers as utilities raise electricity rates to cover increased costs associated with environmental compliance.