Like a physician with her stethoscope at the outset of a check-up, astute shareholders and directors should use the level and trend of a utility’s market-to-book ratio (MtB) as one of the first...
IRP Meets RPS
New green mandates force portfolio planners to re-think their models.
In the past year, six states either have passed mandatory renewable portfolio standards (RPS) or added RPS through voluntary utility commitments, bringing the total number of states with RPS to 33—or two-thirds of all states. The U.S. Senate and House have introduced legislation to create a national RPS, although to date nothing has materialized. These initiatives, combined with a general evolution towards a “green” society, are having a significant impact on energy companies and their resource-planning processes.
Quantifying the impacts of RPS on utility integrated resource plans (IRP) sounds straight forward—just add more wind, solar, hydro, biomass, etc., to the plan and everything should be good to go. The reality is not quite so simple.
To understand the impacts of RPS on a utility’s IRP process, resource planners need to go back to the basics and make sure they understand the IRP process itself.
IRP came into vogue in the 1980s, went out of fashion in the late 1990s (market competition was supposed to take care of all of the industry’s capacity needs), and now is back again with several states requiring their utilities to file IRPs. Some states never abandoned the requirement.
However, between losing expertise from an aging workforce and the previous lack of a firm requirement to file an IRP, a number of utilities are out of practice and need to revisit their IRP processes to make sure they align with current best practices.
Traditional integrated resource planning focuses on developing a series of plans that allow the utility to meet its future energy requirements. Planners are seeking to balance risk and return by selecting the least-cost plan with the level of risk that fits the company’s risk profile—usually the least-cost, lowest-risk plan. Plan options typically include new generating-unit construction, long-term purchased-power agreements, demand response, and transmission expansion. Reliability is a key constraint and is expressed as a minimum reserve margin, a maximum un-served energy level, or a loss-of-load hours.
These days, virtually all IRPs involve environmental compliance planning. This adds additional constraints and complexities, such as increasing plan options to consider renewable energy, retrofits of existing units, and retirement or replacement. Hard emissions limits on minimum renewable energy or maximum emissions released may be imposed, and these must be examined as part of the IRP process. Evolving markets for purchasing credits for renewable energy and emission allowances also need to be considered.
Regulatory uncertainties around environmental issues—such as a recent D.C. Court of Appeals ruling that invalidated the EPA’s Clean Air Interstate Rule (CAIR)—along with ongoing changes in RPS rules and other regulatory and market factors need to be examined and factored into final IRP planning decisions.
Evaluating the numerous plans, their countless variations ( i.e., what and when to build or retire, where to build, how