Distributed generation offers T&D cost management

Michael J. Zimmer

Baker & McKenzie

With utility restructuring, integrated utilities are building for the future using regulated companies as they spin off generation into unregulated subsidiaries or divest themselves of traditional generation assets. Regulated transmission and distribution (T&D) companies will continue to serve the roles of power transmission and distribution based upon the utility`s revenues generated by the size of its asset base. This will be coupled with the new regulatory environment dictating the recovery of such investment, while managing the new post restructuring marketplace. Distributed generation can enable electric utilities to increase system capacity without some of the negative considerations associated with longer lead time investments.

Moreover, distributed generation could evolve as an important, timely tool in the management of congestion management. Recent research has attracted thoughtful utility planners and regulators in assessing the management of risks caused by T&D system demand uncertainty through use of distributed generation resources. This is an option which should be reserved for the future along with other management strategies in the T&D business. There are some uncertainties according to the research in several key areas which will evolve over the next several years including: the evaluation of distributed generation resources with even shorter useful lives such as DSM programs, the integration of combined strategies which utilize a mix of both distributed generation and traditional T&D investments. More precise analysis of distributed resource cost uncertainty and evaluation of the impacts of eliminating utilities` obligation to maintain sufficient T&D capacity with movement to a more open, market-based regime for the future will be required. Opportunities also exist to expand upon these principles in international markets building upon successful experiences in other markets and in the United States. While the various strategies appear attractive, much work needs to be done in capturing additional opportunities beyond traditional generation sales of energy and capacity originally envisioned by distributed generation marketers building upon the next stage from the total energy and packaged cogeneration experiences of the prior decades.

FERC leadership

In recent rulemaking issued by the Federal Energy Regulatory Commission (FERC) on regional transmission organizations (RTOs), all new RTOs once formulated will have up to a three-year time period to develop congestion management strategies. Where time pressures exist and opportunities require shorter term strategies, distributed generation could be a critical part of the solution. The resolution of congestion management, while historically postponed, will be accelerated in a post-RTO world and the widest array of development and management strategies should be properly available. The flexibility of the shorter lead time and smaller scale construction requirements of distributed generation makes it an attractive option in meeting new regulatory challenges in regional operations. Moreover, the cost in a risk adverse environment is more manageable particularly where demand and margin uncertainty exists because of the struggles in a post restructured world, a new and uncertain inflationary environment and with T&D growth in the future.

FERC has noted in prior orders as well as in its rulemaking governing RTOs, that markets based on locational marginal pricing and financial rights for firm transmission service provide a sound framework for efficient congestion management. However, FERC has also recognized that it does not intend to mandate a single corporate form for RTOs and will furthermore not require a specific market approach to resolve congestion management issues. FERC has stated, “It is our intent to give RTOs considerable flexibility in experimenting with different market approaches to managing congestion.” FERC noted it believes a workable market approach to congestion management should generally establish clear and tradable rights for transmission usage, promotion of efficient regional dispatch, support for the emergence for secondary markets for transmission rights, and provide market participants with the opportunity to hedge locational differences in energy prices. Several of these approaches provide the predicates and intellectual support for consideration of distributed generation as a strategic option in addressing the challenges of congestion management for the future.

The challenge for energy developers and marketers will be to build portfolios of distributed generation resources or loads that can be served on an interruptible basis that will be capable of timely dispatch based on price signals. This could be done in conjunction with existing or future financial instruments available to hedge prices as well as the other advantages offered by distributed generation. These strategies could also reduce investments in T&D expenses to create reliability and efficiency gains. In the early 1990s, Pacific Gas & Electric Co. and other electric utilities initiated a review of strategically located generation, storage or demand side management resources to defer or avoid the expenses of investment in T&D projects. While the initial analyses proved encouraging, successful implementation of distributed generation projects were few. This is because the strategic assessments were driven internally within the engineering as opposed to the strategic planning, rate and financial units in the companies. Engineers primarily driven by responsibilities for reliability of the grid were hostile and in some instances reluctant to relinquish control to distributed generation resources and rely upon such strategies to maintain the grid`s ability to handle peak demand requirements.

Timing is attractive

Similar to the initial review of repowering in the 1990s, the timing and initial review within the utility industry has not been opportune. With the impetus for restructuring occurring in major markets and with over 40 states exploring some form of retail restructuring and competition, new impetus for distributed generation has arisen. Moreover, newly formed or structured T&D companies, which have been proposed or established, have begun the internal assessments of how to reduce capital expenses to be competitive in their evaluation of future wire, poles and substation expense strategies. A critical factor is the financial and strategic assessment dimension within the companies.

Moreover, the future pattern of state regulation of T&D investments is another critical issue for concern. If the state is imposing a traditional rate of return form of regulation based on cost of service and embedded investments and assets, then a T&D company will have little regulatory incentive to defer or avoid capital expenses for T&D investments or use of third party investment strategies. If the state regulatory commission is leaning towards a performance-based regulatory regime focusing on the least cost approach for utility investments, then regulatory and other discrete incentives for distributed generation in those jurisdictions could unfold. States leading in implementing performance based regulation include New Jersey, New York, California and Illinois. This form and pattern of regulation would reward the avoidance of more expensive capital upgrades for T&D investments. Under such an approach, T&D companies should be more open to third party alternatives, built upon development, leasing, temporary portable generation or dispersed power generation sited and managed by customers in a marketplace that should support credible third party service providers. Utility subsidiaries and affiliates could provide new leadership in these areas.

Thus, evolving patterns of state regulation will be critical factors in determining the future of distributed generation over:

– Siting;

– Environmental regulation;

– Performance-based regulation of utilities;

– Interconnection standards and impediments;

– Backup and standby power rates; and

– Tax policies.

Already, the technology solution has occurred. The market-based dimension has appeared. There really is not a major federal regulatory issue except for the uncertainty raised by the potential repeal of Public Utilities Regulatory Policies Act (PURPA) and the variety of exemptions provided from state and federal regulation under Section 210(e) of PURPA, which could impose a residual chilling effect upon distributed generation for the future. The states are in control of the issues and the management of how deeply distributed generation will penetrate in existing markets. Recent sources have forecast that the distributed generation market could range from 5 percent to 50 percent of new generation capacity by the year 2010. This is a highly uncertain foundation for business strategic planning initiatives. However, the outcome should be more clear in the next five years in quantifying future market opportunities based upon the resolution of these key state regulatory considerations and increased strategic planning impacting the viability of T&D avoidance strategies using distributed generation technologies.

Previous articleELP Volume 78 Issue 2
Next articleELP Volume 78 Issue 3

No posts to display