Today, California – long a leader in encouraging wind power investment – may be at an inflection point that will determine whether it regains its luster as a preferred location to attract new investments in the wind sector. A snapshot of the market and the regulatory environment for wind power in the state may also predict how other regions will react to increasing penetration of renewables in the grid. To see where the state is headed, two key areas are worth watching closely: the future of the California renewable portfolio standard (RPS), and the market impact of low gas prices and falling solar power procurement costs against a longer-term backdrop of demand growth and plant retirements.
Nationally, development opportunities for new wind power projects have been enhanced for years by a number of factors, including the size, efficiency and reliability of modern wind turbine technology; federal tax incentives and state RPS mandates; the historically low cost of capital, particularly debt; and transmission upgrades and regulatory changes that together encourage integrating intermittent resources, connecting remote wind resources with load centers and balancing load requirements.
Prospects going forward are clouded by uncertainties about tax incentives and other public policies, about interest rates and the availability of risk capital, and about the falling cost of competing technologies. How California confronts these challenges may foreshadow national responses shaping the U.S. renewables market in the years to come.
In April 2011, California enacted a statutory RPS goal of 33% renewables by 2020. The state’s main challenge is to ensure adequate energy supplies at a reasonable cost while reducing greenhouse gas (GHG) emissions. California produces about 70% of the power it consumes (importing the rest from other states) and relies on renewable resources for about 17% of the total in-state generational output. Wind power accounts for about 6.6% of total in-state generation, and the state ranks second in installed wind capacity nationally, behind Texas and just ahead of Iowa.
According to the California Public Utilities Commission (CPUC), the state’s three large investor-owned utilities met their Compliance Period 1 goals of an average 20% RPS by the end of 2013 and are on track to achieve the 33% RPS by 2020, with little additional procurement of renewable power resources needed. The early subscription of contracts for the 2020 goal came as a result of the utilities’ taking full advantage of low bids for solar photovoltaic (PV) projects, given falling prices for most solar components and China’s subsidization of its solar exports. PV projects were further advantaged by utility payment structures that handsomely rewarded midday energy deliveries. Since 2011, the utilities overwhelmingly procured solar PV and relatively little wind. Including out-of-state projects serving California load, nearly 160 solar PV projects with an aggregate capacity of over 9 GW are permitted and slated to come online in the future (assuming they obtain financing and complete construction), in contrast to just nine new wind projects with an aggregate capacity of 1.2 GW. For that reason, many wind developers view California for the next couple of years as a market more for potential acquisitions than for greenfield development.
In evaluating future opportunities for investment in the state, however, it is critical to understand how this newly procured mix of renewable resources will affect the relative value of those resources going forward. Reducing GHG emissions remains a major policy goal for the governor and many legislators. The state legislature is currently considering whether to extend its current commitment to reduce California’s GHG emissions to 1990 levels by 2020 by establishing a far more substantial reduction target for 2030.
Whether or not the RPS target is raised, such a GHG goal would almost certainly require a major increase in renewable energy, which would create significant opportunities for investments in new wind energy capacity, especially if the increase relies on a diverse portfolio of renewable resources.
Utilities have argued that renewable energy generation is not a cost-effective way of achieving GHG reductions as compared to other options such as energy efficiency, forest replantation and transportation fuel switching. However, a study performed for California’s five major utilities by the research firm Energy and Environmental Economics (E3), released in January of this year, suggests that increasing the RPS could result in significant rate hikes. But a review and analysis of the E3 report by the California Wind Energy Association (CalWEA) determined that the E3 study provides a roadmap for achieving 50% renewable energy by 2030 with a relatively modest 2% or less impact on rates.
The E3 study focused on 50% RPS scenarios dominated by solar resources. The findings reveal that an over-reliance on one type of resource dramatically drives up overall costs. A more diverse renewables mix can dramatically lower total costs (including both procurement and integration costs), according to the CalWEA analysis. For instance, as the penetration of solar power increases, its capacity value declines as peak-demand times become saturated and additional capacity has only marginal market value. Under that scenario, integration costs also rise, as excess midday generation must be stored or dumped. Thus, the value of a more diverse portfolio – one including far more wind – becomes apparent.
The California Independent System Operator (CAISO) has also highlighted these issues. In a 2012 report, CAISO noted that during late afternoon periods when solar power is at maximum output, total generation might exceed the baseline output from must-run resources (like nuclear power plants) that are difficult to quickly ramp up and down. This overgeneration scenario creates system stability risks and curtailment issues, unless the power can be safely exported or stored. Similarly, solar output drops sharply before sunset, while peak demand typically continues well into the evening, thus requiring a very large and rapid late-afternoon increase in replacement output from other generating resources to meet load requirements.
Natural gas power plants are adept at handling these kinds of ramping and intra-hour variability needs, but at the cost of GHG emissions and excessive exposure to gas price volatility. Wind can play an important role here. Larger aggregations of wind turbines from multiple projects over large areas (including imported power from out-of-state wind plants) even out system imbalances and reduce uncertainty and variability on the grid.
The utilities are beginning to modify their price signals in recognition of the solar resources they have already acquired. The CPUC is expected to update the capacity values and integration costs of each renewable resource as soon as the 2014 round of renewables procurement is complete. Although the relative value of wind will likely increase as a means of reducing GHGs while maintaining system reliability, developers of solar and wind power alike have a common interest in articulating how increased RPS targets do not have to result in higher costs to ratepayers nor in adverse grid impacts.
The best methodology to capture the value of diversity in the pool of generating resources is a dynamic valuation that reflects the relative penetration of each technology under different load conditions. Regulators and policymakers in California, in the conversation on extending the RPS, are fostering an advanced understanding of how wind can continue to play a critical role in reducing GHG emissions while keeping retail rate increases down and bolstering system reliability.
One thing is for sure: Tomorrow will not look like yesterday. The current deflationary trends in solar panel and component prices and low natural gas prices will not last forever. The Obama administration and congressional leaders are considering expanding U.S. gas exports by speeding up the review of two dozen pending gas export applications, or by scrapping the need for such government approvals altogether, to help reduce European dependence on Russian natural gas and to boost export income. Increasing globalization of the U.S. gas market could increase the long-term risk of price volatility. Federal rules on GHG emissions may also increase end-user costs of energy produced by gas-fired power plants. These risks – gas price volatility and GHG emissions – are key arguments for extending the RPS in California and elsewhere.
Less supply, more demand
There is an increasing market interest in acquiring and repowering older wind farms in California. The Tehachapi, Altamont Pass and San Gorgonio regions account for the vast majority of California’s installed wind capacity. These three regions accounted for 30% of the world’s total wind energy output in the 1980s and 1990s, and many older turbines are thus ripe for reinvestment. For operating projects located on parcels managed by the U.S. Bureau of Land Management, repowering (and the resulting higher royalties to the bureau) may be key to extending expiring rights of way.
Generating capacity additions will also be needed to compensate for the retirement of older thermal and nuclear power plants. The Los Angeles Department of Water and Power is already implementing its plan to rely more on renewables (including purchased power) and to divest all coal assets.
The state’s many “once-through cooling” thermal plants will be retired or repowered as a result of State Water Board rules addressing the harmful effects of cooling water intake structures on marine life.
In addition, the June 2013 decision to permanently decommission the San Onofre Nuclear Generating Station (SONGS) in Southern California removes 2.2 GW of baseload capacity from the state’s grid. Although the CPUC approved a combination of additional gas capacity, distributed renewables and storage technology to maintain grid reliability, gas generation has increased overall. The loss of SONGS, a major GHG-free resource, will put added pressure on the state’s cap-and-trade market for declining GHG allowances.
In the meantime, gas plants and wind farms can have a symbiotic relationship. More wind farms, when producing, can reduce carbon emissions from gas-fired power plants that are readily ramped down in response to output from wind plants, which have a lower marginal cost of power. And low natural gas prices, in effect, reduce the all-in system cost of integrating intermittent resources like wind into the grid by providing cheaper flexible reserve capacity to balance intra-day and seasonal variations in renewables’ output.
Demand growth for power is already ramping up with the grinding slog out of the past five years of economic malaise, potentially increasing the valuations of wind farms and other generating assets. In California, despite hugely successful programs and price incentives for energy efficiency, demand for power will continue to increase, driven by economic growth and population growth, and now also by the gradual electrification of the parts of the state’s vast transportation network. California already accounts for more than one in four electric vehicle charging stations in the country. Early adoption of electric and plug-in hybrid cars (which together already exceed 2% of total vehicle sales in the state) and expanded rail transit all depend on a reliable and growing electric grid.
All of these factors create long-term opportunities for more investment in wind power and other renewables in the state. Higher penetration of a diverse mix of renewables, including expanded wind power resources, is a cost-effective way to meet the twin demands of more power and reduced GHG emissions. w
What’s In Store For California’s Wind Future?
By Allan T. Marks
Several market factors, such as raising its RPS, could impact the role wind plays in the state going forward.
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