Natural gas is being left out initially in California’s preliminary recommended auction for greenhouse gas (GHG) emissions allowances as part of a proposed cap-and-trade system for lowering the energy sector’s carbon footprint in the state by 2020 under a climate change law’s mandate. However, there is no consensus on this or other issues, such as cost, treatment of public-sector utilities, and the needed safeguards and monitoring of the allowance trading market.
Many of the lingering issues will be addressed jointly by the California Energy Commission (CEC) and the California Public Utilities Commission (CPUC) in the next six months as they continue joint proceedings. Both agencies unanimously endorsed the preliminary recommendation at their last business meetings. In taking their actions, both bodies recognized that ultimately there has to be a national GHG emissions cap-and-trade program, while utility and financial experts were offering somewhat conflicting views on California’s initial attempt to unleash a market-based global climate change mitigation effort.
With an estimated 40% of the electricity supplies nationally now coming from utilities operating under goals for using more renewable-based power, the full costs and impacts on utilities and consumers have not been assessed, according to a report released last week by Standard & Poor’s Ratings Services (S&P). Longer term utility credit quality and grid reliability lurk behind unanswered questions, S&P’s report asserts.
The California energy agencies’ initial joint recommendations sent to the California Air Resources Board (CARB), the lead agency as designated by the 2006 Global Warming Solutions Act (AB 32), stressed the need to require energy providers — electric and natural gas — to greatly increase their energy efficiency and renewable energy programs as inherently the most cost-effective way to reduce carbon emissions.
While critics are raising concerns about tying the electric industry to a cap-and-trade system after the state’s disastrous experience in 2000-01 with the power industry restructuring and the widespread wholesale market manipulation that led to its undoing, CPUC and CEC officials are convinced cap-and-trade will produce larger carbon emission reductions than a traditional regulation-driven command-and-control approach. The state’s largest daily newspaper and a leading energy industry free-market economist have expressed doubts, though.
Trading tons of emissions can be done with less risk of market manipulation than the trading of wholesale electricity, according to a Southern California Edison Co. (SCE) executive who spoke with NGI before the CPUC and CEC actions. That’s because emissions allowances can be saved but electricity cannot be stored. Gary Stern, SCE marketing strategy and retail pricing director, said electricity’s lack of storage creates a problem in commodity markets, but emissions don’t carry that same baggage.
CEC commissioners, while labeling the proposal sent to CARB as “interim,” have hailed the advent of a GHG emissions limit with corresponding trading of allowances as an historic step and a “very important opportunity” to provide input to CARB.
Private-sector utilities similarly are lining up behind the proposal, but public-sector utilities are opposed to the trading, or auctioning, of emissions credits, seeing it as a slippery slope that could send the state’s power sector descending into the market trading manipulation morass of 2000-2001.
Public-sector utilities indicate that they think they can diminish their own carbon footprints enough through greatly stepped-up energy efficiency and more generation from renewable sources. Private-sector utilities agree this is a key to keeping down the cost of the GHG reduction efforts, but they don’t think it is realistic — at least for the private-sector utilities — to do that without a cap-and-trade system or some form of carbon tax.
Although the CPUC action was unanimous, Commissioner Timothy Simon, the newest of the five members, indicated that he agreed with many of the munis’ concerns, and he warned his CPUC colleagues to remember their state constitutional limitations, which restrict their jurisdiction to private-sector utilities.
“I intend to closely monitor the second phase of these proceedings to assure that munis are treated appropriately,” Simon said. “I caution this commission that our jurisdiction ends at the investor-owned utilities.”
CPUC President Michael Peevey acknowledged the public-private sector split, noting that generally, most of the public-sector utilities, with the exception of the Sacramento Municipal Utility District (SMUD), have a higher carbon-intensity in their generation portfolios than the state’s private-sector utilities and SMUD.
“Our intent [at the CPUC and CEC] is to make sure real GHG emissions reductions are accomplished equitably and cost-effectively, and it is not our intention to punish market participants based on their past investments or decisions made prior to the passage of AB 32 [such as heavy coal-fired generation],” Peevey said. “That said, I would note that California’s retail electricity providers are starting off in very different positions with respect to GHG emissions.
“Many municipally owned utilities in Southern California in particular, including the Los Angeles Department of Water and Power, have a GHG intensity close to 600 tons of carbon dioxide-per-gigawatt-hour of electricity, and the investor-owned utilities and some munis, such as SMUD, have a GHG intensive of 300 tons or less, or 50% less.”
Peevey said all of the utilities must be involved in the program and officials will carefully consider the cost and equity implications of the utilities’ differing starting points.
A more difficult part of cap-and-trade to deal with may be the cost. Edison’s Stern thinks ultimately it will cause retail power rates to rise as the state tries to stretch the level of GHG emission reductions — 1990 levels by 2020. The higher costs are a reality whether it’s done with a market or with more command-and-control regulations, Stern said. “It could be a costly proposition, so ultimately, we ought to be considering some cost controls.”
Similarly, greater reliance on renewable energy sources of power mean higher costs across the board as outlined in the S&P report.
So-called renewable portfolio standards (RPS) setting goals for future percentages of renewable-based power in individual state and utility generation portfolios are leading to the acceptance of more above-market-priced power, according to the S&P report, “The Race for the Green: How Renewable Portfolio Standards Could Affect U.S. Utility Credit Quality.”
With the exception of California, most state’s RPS goals are far off and their feasibility and cost ramifications have not arrived for the most part, said S&P, although it thinks some of those impacts are “imminent.” In California, where the short-term goals have been around for awhile, utilities are lagging behind, the rating agency said.
“We are concerned that the costs of RPS compliance have often not been quantified and that absorbing the full costs of RPS in retail rates could have credit implications for some companies,” said S&P’s Anne Selting, a San Francisco-based credit analyst.
Separately, S&P March 7 released a paper on “The Credit Cost of Going Green for U.S. Electric Utilities” in which it postulated that ratings impacts will depend on several interrelated factors, including what’s done to curb GHG emissions and how fast the costs come in the years ahead.
“While it is possible that RPS will prove to be feasible, economic and successful in every state, there is no compelling evidence that suggests this will be the case,” the S&P renewable impact report said. “We instead suspect that the green marathon will be a difficult race for utilities to run, with possibly painful results for credit quality.”
S&P likens the current rush of states to develop RPS standards to what happened a decade earlier in the industry rush to restructure and deregulate. It fast-tracked major industry changes. “Just as deregulation was nearly universally hailed, so has been the case with RPS, which is typically discussed in unimpeachable terms that suggest a sizable shift toward renewable generation can occur quickly, will carry little rate impact, and entails minimal disruption to the sector,” S&P said.
But in reality, S&P said, what it called the “lack of verifiable cost data” in states with some of the most aggressive RPS programs raises the question as to whether renewables have become popular because there is little price scrutiny. The biggest risk for future utility credit quality is the increasing chances for consumer backlash, S&P said.
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