Power generation and delivery is a highly capital-intensive industry. The utility franchise system in place today stems from the need for certainty that major investment in new power plants and T&D infrastructure will be recouped reliably over time from entities the facilities were designed to serve. However, the monopoly vision is starting to blur, while T&D planners contend with the retirement of ancient central station power plants and an ever-morphing array of renewables and distributed generation power sources.
The canary has been tweeting a long time about our aging and now non-optimal transmission and delivery systems. The level of investment as well as the difficulty of planning and completing new delivery systems almost certainly means we have one shot at getting the next generation of T&D asset investments correct. So, how do we do it? The one certainty is this: The revenues for the T&D business flow through our long lines, substations and delivery systems, so we know we must get those right.
Distribution Innovation
Society’s need today for electric power is constant, and our electric delivery system has been and largely will continue to be the sinew that makes electric power on demand a reality. That said, there are always forces at work to change the status quo.
New York is one of a number of states focused on the distribution side of the electric business as a means to encourage renewables and distributed energy development in the face of waning federal incentives and huge T&D upgrade requirements. The Reforming the Energy Vision program, spearheaded by the New York Public Service Commission, challenges utilities to craft their distribution upgrade plans to stimulate new distributed energy resources (DERs) to be owned and operated by customers and third parties.
Another example of state-driven innovation is the recent passage of California Assembly Bill 327. The state’s three investor-owned electric utilities may need to modify efforts underway to upgrade their centralized electric grid infrastructure to finance and deploy DERs and energy management systems. DERs may be owned by customers, third parties or the host utility, and may include solar, wind, geothermal, electric vehicle infrastructure, and energy storage and microgrid technologies. A key upshot is these technologies will force an overhaul of rate structures and transform the pricing and sale of electricity and services.
Michael Albrecht, a contributor to T&D World, suggests the goal of regulators and officials in innovating states is to transform the traditional utility structure into distribution service platform providers, load management utilities and, presumably, utilities of the future.
Some utilities are seeing the legislation pushing such transformative business models as opportunity. ComEd sees distribution-side legislative initiatives in Illinois as a logical extension of investments and programs it has already made in smart grid technology. Southern California Edison is using the legislative mandates to propose studies on its feeder circuits to determine optimal sites for DER construction and integration, thereby leading to more intelligent, future-focused distribution upgrade investments.
Focus on Transmission
While a number of states have been focused on distribution system changes that stimulate local jobs and green energy projects, utility decision makers have been faced with a changing landscape on the transmission side, as well. Federal Energy Regulatory Commission (FERC) Order 1000 requires a competitive solicitation process for new transmission investment, with consideration given to cost and societal benefits of the project.
Order 1000 requires a highly transparent and vetted interregional coordination process for planning and cost allocation. The few regional transmission organizations that have implemented or tested parts of the new process are seeing a significant increase in project proposal submissions as well as a related increase in processing work to conduct and analyze competitive solicitations.
Industry experts suggest the Environmental Protection Agency’s Clean Power Plan may be the real acid test for Order 1000 because the plan encourages a change in the resource mix potentially favoring renewables. Major transmission upgrades in different parts of the country would be needed, with only a few years to iron out the wrinkles of the Order 1000 implementation before that can happen.
We have experienced complications in delivering timely transmission infrastructure projects in the past, with interregional and cross-state projects being particularly difficult. The formation of our independent system operators has lubricated the process, but pre-Order 1000 project experience demonstrates completing transmission projects to address lingering bottlenecks is not yet optimized. The jury is still out on whether FERC Order 1000 will speed the process.
The Greatest Challenge
Perhaps the greatest challenge our industry faces is not new business models or new FERC regulations but the aging of our energy infrastructure. The American Society of Civil Engineers (ASCE) prepares a report card-style rating of America’s infrastructure every four years. The last report, issued in 2013, gave America a D+ rating for our electric grid, based on the continued deterioration of our systems and a lag in needed investment for new T&D infrastructure. ASCE predicts we will have a transmission investment deficit of $37 billion and a distribution infrastructure deficit of $57 billion by 2020.
The U.S. Department of Energy’s “Year-in-Review: 2014 Energy Infrastructure Events and Expansions” report cited 15 major outage events affecting 250,000 or more customers; all were weather related. The same report lists 119 small and medium outage events (10,000 customers to 250,000 customers) for the year. Equipment failure was the second-greatest cause following weather for the small and medium events.
While the need for more storm hardening was an obvious conclusion from recent spikes in serious weather-related outage events, a less obvious conclusion cited in interviews with James Dukart was the contribution of aging infrastructure to the problems. Years of use ravishes both seen and unseen portions of towers, cables, network components and foundations. Moreover, time deteriorates component adequacy relative to new load scopes and other modernized standards and customer requirements. Advanced transmission technologies — including fiber-optic communications, advanced conductor technology, enhanced power device monitoring and energy storage devices — are essential to meeting future requirements.
We are at year 48 of a hypothetical 50-year life (originally a 30-year life) for much of our T&D system. We cannot wait for it to fall down around us. We need to upgrade and add transmission, replace worn out transformers and breakers, storm harden, make the system cybersecure and modernize our distribution infrastructure. To wait longer would result in ever-escalating maintenance and system operating costs, and simply tempt fate on recovery from the next 200-year storm.
There are a lot of moving parts at play in the T&D space, and there are many great minds at work on how to proceed. The canary is still tweeting (he has not yet fallen off the perch), but we know time and the capital resources available are limited. A successful outcome necessitates we get all the great minds working together — our legislators, our regulators, our customers and even our competitors — to refurbish, rebuild and enhance our T&D systems to meet the requirements of future generations.
