When Successful Procurement Policies Fail

California is approaching a tipping point with respect to the near-term economic viability of existing non-utility generation. The procurement policies and practices implemented in response to the statewide energy crisis over a decade ago have evolved into market conditions that do not offer “uncontracted” existing resources with sufficient and stable enough revenue streams to recover going-forward costs. Continued adherence to these policies will subject such resources to an increasing risk of economic retirement, threatening long-term reliability and potentially costing electric consumers billions of dollars.

How We Got Here

In the wake of the rolling blackouts, price spikes, bankruptcies, and bailouts that marked the California energy crisis, state policy placed the highest priority on ensuring the availability of sufficient capacity to meet local and system reliability needs. As a result, debt and equity investors would no longer financially support the development of new resources as “merchant” plants and financing became available only to non-utility generation projects with a power purchase agreement (PPA) already in place.

The regulatory response was the creation of a so-called hybrid market in which utility and non-utility generation filled an administratively determined long-term “need.” Resulting procurement policies and practices achieved the primary objective—significant new generation resources—but resulted in a flawed long-term market structure.

These policies limited the availability of long-term PPAs to new resources. As a consequence, relatively new, efficient generation resources developed in the late 1990s are deprived of a realistic opportunity to obtain long-term contracts. They are relegated to short-term bilateral markets for resource adequacy capacity, and energy and ancillary services markets.

The Math No Longer Works

The “success” of these policies is the current oversupply of resource adequacy capacity at both system and local levels and downward pressure on the compensation available in the short-term bilateral market. Prices in the daily and other short-term energy markets are uncertain and will likely decline as additional renewable resources come online to meet the state’s Renewables Portfolio Standard (RPS).

In a 2010 report addressing the operational requirements necessary to reliably integrate a 20% RPS requirement, the California Independent System Operator (CAISO) concluded that “The combination of increased production of wind and solar energy will lead to displacement of energy from thermal (gas-fired) generation in both the daily off-peak and on-peak hours. Due to this displacement and to simultaneous reduction in market clearing prices, there may be significant reductions in energy market revenues to thermal generation across the operating day in all seasons.”

The expansion of the RPS requirement to 33% by 2020 will exacerbate the challenges confronting uncontracted existing resources to cover going-forward costs. Economic reality dictates that if the compensation from available markets is insufficient to ensure the recovery of going-forward costs, resources will shut down.

Market Flaws Exposed

The addition of increasing amounts of intermittent renewable resources on the system has necessitated a rethinking of traditional resource adequacy requirements. Previously, resource adequacy focused on the procurement of generic capacity; the focus today needs to be on resource flexibility.

CAISO projects that existing gas-fired plants will experience a significant increase in “cycling” and a double-digit percentage reduction in revenues. These projections assume that most uncontracted existing resources will remain available to help meet renewable integration needs. Thus, while market compensation is dropping, the CAISO projections show increasing reliance on these resources for integrating renewable resources.

Given the current oversupply of generic capacity, some resources may not be “needed” for three to five years. If existing resources assumed to be available shut down in the near term, substantial amounts of new replacement resources costing billions of dollars will likely be necessary to maintain reliability within the next five years.

The specter that relatively new, efficient generation resources might retire for economic reasons demonstrates a fundamental flaw in the market: On the one hand, inadequate revenue streams subject uncontracted existing resources to an increasing risk of economic retirement, while on the other hand, the continuing availability of these resources is critical to future system reliability.

Crafting a Solution

In California, a diverse cross section of stakeholders recognize fundamental problems permeate the state’s energy markets and need to be fixed. Policies that restrict new resource procurement to meet planning reserve margins undervalue existing resources to provide renewable integration services. The market structure must evolve to ensure the ongoing availability of the existing gas-fired generation fleet to help integrate renewables.

Under consideration is the creation of multiyear forward procurement obligations. Such obligations would be designed to provide stable revenue flow for existing resources over a five- to seven-year period and reduce the likelihood that resources needed for future renewable integration would prematurely shut down for economic reasons.

Paying a resource now because it will be needed some time in the future is a foreign concept to an industry built on 20th-century concepts of ratebase and “used and useful.” However, in light of the nation’s commitment to intermittent renewable resources, and given the alternative—increased reliability risk and high resource replacement costs—it is a concept deserving full attention.

Steven F. Greenwald  (stevegreenwald@dwt.com) and  Jeffrey P. Gray  (jeffgray@dwt.com) are partners in Davis Wright Tremaine’s Energy Practices Group. Davis Wright Tremaine represents independent power producers participating in California’s energy markets.