The Race for the Green: How Renewable Portfolio Standards Could Affect US Utility Credit Quality

Anne Selting, Director, Corporate & Government Ratings, Standard & Poor's

THE RAPID GROWTH OF RENEWABLE portfolio standards (RPS) has become one of the most interesting trends in the US electric utility sector, and is among the most significant developments in the industry since electric restructuring began nearly a decade ago. RPS are laws or regulatory commission directives that require utilities to acquire a certain percentage of their power supply from renewable sources such as wind or solar. According to the Lawrence Berkeley Laboratories, a US Dept. of Energy (DoE) facility, RPS now apply to roughly 40% of US electric load.

RPS are moving utilities and other load serving entities squarely away from least-cost procurement and toward acquiring often above-market renewable generation in unprecedented quantities. At the same time, consumers have yet to fully experience the cost and retail rate impacts of this shift. The standards are in their infancy, and, in many states, interim targets will not become meaningful for several years (except in California, where utilities are lagging behind short-term goals). As a result, the feasibility and cost ramifications, while imminent, have not yet arrived in most RPS states.

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. In addition, not all utilities will be able to achieve RPS requirements on the schedule required, which could lead to penalties for utilities and create an impression that power companies are not receptive to green policy goals.

RPS' original objectives were aimed at achieving greater fuel diversity, jumpstarting renewable technologies, and creating jobs, particularly in states with wind and solar companies. But with calls for greenhouse gas reductions becoming increasingly urgent, RPS have also been promoted as a way to achieve emissions cuts in advance of efforts to pass federal carbon regulations.

Credit Implications of RPS

The proliferation of RPS is reminiscent of restructuring and deregulation in the late 1990s that fast-tracked major changes in the utility sector. 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 entail minimal disruption to the sector.

In fact, the lack of verifiable cost data in states that have aggressive renewable standards raises the question as to whether RPS have become popular precisely because there is little price transparency. After all, one of the lessons learned as part of retail choice is that when electric customers are allowed to choose a supplier that offers "green" generation for a premium, very few elect to do so.

This leads to the chief risk RPS imply for credit quality—the potential for consumer backlash if RPS come with a high price tag. The increased likelihood that carbon regulation will be implemented may result in policy makers determining that RPS are not needed, because at sufficiently high carbon prices, utility procurement choices would include renewables without a mandate. While this could over time lead to a relaxation of RPS, how future RPS policies may be modified is an unknown. What is certain is that by fast-tracking RPS efforts, consumers will begin to pay for RPS at the same time utilities are incurring other significant costs including: escalating fuel costs, rising operations and maintenance expense, and an unprecedented wave of capital spending. Collectively, we expect these expenses to substantially increase retail electric rates in coming years, which will pressure the regulatory compact and stress customer satisfaction. This risk is largest in states that have aggressive RPS. Coincidentally, high RPS states tend to be those that also have some of the highest retail electric rates in the nation (Table 1).

Table 1. Ten highest US residential retail rates by state.* Source: Energy Information Administration

A Long and Possibly Hard Road

A look at the current level of renewable capacity and generation in the US underscores the challenge that RPS pose for utilities. According to the US Energy Information Agency (EIA) renewable energy facilities generated about 385 billion kilowatt-hours (kWh) of power in 2006, or about 9% of total US generation. But this figure includes conventional hydro, which not all states with RPS consider to be "green." Chart 1 provides the most conservative estimate of renewable production from existing sources, which excludes conventional hydro and indicates that only about 2.4% of US generation last year was from renewable resources.

Chart 1. Total electric power industry net generation by source, 2007.

On a capacity basis, renewables are an equally small component of US resources. Net US summer installed capacity in 2006 totaled 988,000 megawatts (MW), according to the EIA. Of this total, just 24,000 MW or about 2.4% is renewable capacity (again excluding conventional hydro).

Trade press headlines create the impression that massive investment in renewables is leading to substantial changes in the contribution of renewables to US generation. Due to the benefit of federal production tax credits (PTC) and RPS mandates, wind generation has been undergoing an enormous expansion. The American Energy Wind Association (AWEA) says that the US added an impressive 5,244 MW of new wind capacity in 2007, more than double that added in 2006, which was also a record year. US wind project capacity is now about 17,000 MW, according to the AWEA. On a generation basis, the EIA reported that for the 11 months ending November 2007, the power produced by wind turbines in the US jumped by 21.4%, compared with the same period in 2006.

Despite this gust of development, wind generation remains an infinitesimal fraction of US generation. In fact, there has been virtually no change in the contribution of wind to total US generation—just 0.6% in 2006 and an estimated 0.8% in 2007. And, for all but wind generation, the growth of renewables has had a negligible impact on US power supply over the past 15 years (Table 2).

Table 2. Growth of US renewable generation, 1993-2007 (000 megawatt hours). Source: Energy Information Administration

Feasibility Issues May Stop Utilities from Reaching Goals

While more complex assumptions can be made, the simple estimates provided above underscore that irrespective of the exact megawattage that will be needed to be brought on line, meeting just the RPS currently in force will require an unprecedented ramp-up in renewable generation development. In doing so, feasibility constraints that limit utilities' prospects to meet the targets are inevitable, some of which are clear today.

PTC expiration could slow renewable investment

A significant factor that could complicate the ability to meet RPS is the fate of the 1.9 cents/kWh PTC for wind and the 30% investment tax credit (ITC) for solar generation. The role of tax concessions in stimulating renewable investment cannot be underestimated; in the case of wind, it can lower the total project costs by as much as 30% to 50%. Last granted by Congress in 2006, the PTC applies over the first 10 years of a project, but must be on line by the end of 2008 to receive the incentive. To date, Congressional efforts to extend the credit's life beyond the end of this year have been unsuccessful. If lawmakers do not renew these subsidies, investment in renewable technologies may not rise to the levels required to meet RPS, unless utilities are willing to make up for the lost benefits by paying higher costs for renewables. A Navigant Consulting study found a 73% to 93% drop in new wind capacity in the years following the PTC lapse (2000, 2002, and 2004). It forecasts that without a PTC extension, 2009 wind installations could fall from an estimated 6,500 MW to as low as 500 MW. The consultant also forecasts solar investment to be similarly affected. Not extending the PTC could also create a significant supply/demand imbalance because RPS targets are not linked to the availability of the PTC and ITC. This could prove to be a major oversight.

Type, quality, and quantity of renewables vary across the US

Feasibility issues may be even more profound than the economics of renewables sans the PTC. RPS vary in what they "count" as renewables, e.g., whether existing generation can be used, if hydroelectric generation is considered renewable, if all generation must be produced in state, or if utilities may purchase renewable energy credits (REC) to reach targets. (A REC is a tradable right to claim the environmental attributes associated with renewable electricity produced by a specific generation facility.) The details of RPS then are important in determining feasibility.

Transmission has proven to be an obstacle

Most renewable resources are located in remote regions, far from load centers and require additional investment in transmission infrastructure. Nationally, transmission investment is lagging, despite the efforts of the Federal Energy Regulatory Commission and other agencies to encourage the build out of new transmission. Planning and permitting large transmission projects requires years, and often requires approval from federal, state, and local governments.

Finally, the usual problems in siting new generation can also afflict renewables. Wind generation is alleged to destroy bird habitats and faces aesthetic challenges. (Opposition to offshore wind has stalled development in Massachusetts, for example.) Local opposition to transmission needed to support renewables can also delay projects, and long interconnection queues have also been a problem for developers.

Without Carbon Regulation, the Cost Gap Between Renewables and Conventional Resources Continues

The economics of conventional versus renewable generation are fundamentally what's behind the costs of RPS compliance because utilities typically meet RPS by using green power to serve a portion of load growth that would otherwise be met with fossil-fuel resources. As a result, the difference between the cost of new-build and renewable options is a good approximation of the direct cost differential. While incorporating carbon prices could change the relative costs of these technologies, as shown in Table 3, today's renewable generation costs are generally more expensive than most new conventional alternatives. But it is important to note that these costs are based on 2007 information, and relative differences can change rapidly and are location-specific.

Table 3. Cost estimates of renewables versus conventional generation, 2007.*

Wind generation costs up sharply in 2008

We expect wind to continue to be the dominant technology that utilities use to meet RPS. While renewable technology costs generally have been falling over the past decade, an important development that has not attracted significant attention is that wind generation—often the most economic renewable resource—has experienced recent and sharp cost increases.

Solar is also in the RPS mix

We expect solar investment to pick up dramatically in the next few years, but at far higher prices than existed when wind capacity began to expand. Of the states that have RPS requirements, 12 have some sort of mandate for solar development. Even in the areas of the country with the best solar resources (Southern California, Southern Nevada, Arizona, and parts of New Mexico) solar is expensive. The California Energy Commission estimates that the levelized cost of a parabolic trough is in the range of $280/MWh. While central station solar projects can be as low as $160/MWh in prime areas of the southwest, costs quickly rise to as high as $351/MWh in the eastern parts of the US, according to estimates provided by a solar developer. High costs are in part due to the need for greater economies in solar equipment manufacturing, but are also tied to low capacity factors, which range from 25% to 29%.

Will Electric Customers Understand the Price Tag?

Taken as a whole, studies that have tried to project RPS costs concern us because they suggest that RPS implementation is virtually costless. In March 2007, the Lawrence Berkeley Labs published a review of 26 separate studies that examined the projected costs of RPS in 18 states. About 70% of the studies predicted that retail rate impacts of RPS would be less than 1% in the year each state meets its end-date target. Six studies predicted RPS would actually lower customer electric rates. The most "expensive" RPS targets were found to be in Arizona and New York, where studies predicted 9% and 6% increases in retail electric rates.

Even at large penetration levels, such studies typically conclude that the impact on retail rate effects will be negligible. In 2005, for example, a study by the Center for Resource Solutions (CRS) examined the costs to implement a 33% RPS in California by 2020. Its base-case results predicted that the effect on retail rates from 2011-2020 would be only 0.57% over the period (or just $1.3 billion in increased costs on a net present value (NPV) basis), and rate savings would occur between 2020 and 2030.

Quantifying the costs of RPS on retail rates is not a straightforward exercise and requires making assumptions about a host of unknowns. Yet, it would be reasonable for us to expect that RPS will cost something to implement, given the cost gap between conventional generation and renewables (which has only grown in recent years due to wind capital costs), the need for added transmission to achieve RPS, and the costs to integrate intermittent renewable resources into the grid.

From a credit perspective, it is troubling that there is very little public data that assess the actual costs incurred to date to implement RPS. Compliance reports that state commissions or legislatures require to document RPS progress are nearly universally silent on what costs utilities have incurred to meet RPS. This is of particular concern in California, where RPS contract data is considered commercially sensitive. There has been no public disclosure of information necessary to calculate the above-market costs of RPS. Due to delays in getting projects on line, these costs will likely occur in a swell in 2010 and 2011. It is unclear if policymakers have a sense of overall rate impacts on customer bills, although CPUC staff do possess the data required to make these estimates.

Summing Up

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. We instead suspect that the green marathon will be a difficult race for utilities to run, with possibly painful results for credit quality.