T&D Investment Considerations Supporting the Future Electric Grid

The utility industry is facing more challenges to its traditional business model since the heyday of deregulation in the late 90's.  Those of us in the industry at that time can remember the rush to separate the "retail" side of the business from the traditional poles and wires company that would remain to ensure the lights stayed on.  This time around, the remaining vertically-integrated, traditionally-regulated utilities are dealing with the question of how to build and maintain an enhanced grid which supports more distributed generation, two-way operation and communication, new energy storage systems, and to serve as the platform for the deployment and integration of future technologies and new services.   

There are multiple possible paths to the new future-state, but today's Asset Managers must keep in mind that with all of the potential changes ahead, one thing will not change—the need to maintain grid reliability fully supporting a utility's charter to provide safe, reliable electric service at an affordable price.   

This article will review considerations related to the identification and funding of required infrastructure investments in the current T & D system, with particular emphasis on the funding of distribution system enhancements outside of traditional capital recovery or rate case mechanisms.  We will review the work underway in various states to explore the new business and regulatory models required to support the continued improvement and adaptation of the grid and the implementation of successful solutions to the many challenges ahead for the industry.      Also discussed are the different cost recovery mechanisms already in place which allow utilities to accelerate the recovery of targeted system investments, and how these can serve as a template for others to pursue similar grid investment strategies in their own states.

The Impending Demise of the Grid—or Not

The industry space is filled with scenarios similar to one outlined by the Rocky Mountain Institute in 2014 which asked the question "Will the Electricity Grid Become Optional?" (Renewable Energy World; Guccione & Bronski, Rocky Mountain Institute, March 6, 2014). The article goes on to describe what it calls "the economics of grid defection" in which off-grid systems reach parity with, or are cheaper than,  retail electric rates, resulting in a utility death spiral where customers defect, the regulated revenue stream declines, the utility raises rates to recover costs, which in turn drives even more customers off the grid.   Certainly this is one possible future scenario, but we think the far more likely outcome will be the adaptation or reshaping of the grid over time to support the demands of the new energy marketplace.      

Before the industry can move toward a new "adapted grid," we should first consider the current state of the T & D system.  In their 2015 "State of the Electric Utility" survey, Utility Dive asked 433 U.S. electric utility executives about the three most pressing challenges for their utility.  Old Infrastructure took the top spot at 47%.  It's likely this response not only refers to traditional infrastructure investments, but also to the current state of grid automation or grid intelligence and the acknowledgement that further enhancements are needed here as well.    Our focus for this discussion is on the T & D "backbone" and the supporting fact that in 2013, the American Society of Civil Engineers gave the U.S. energy infrastructure a grade of D+.  This statistic is reinforced by a 2014 Osmose and North American Wood Pole Council joint survey on Pole Plant Management Best Practices which indicated the top three biggest concerns of utility Asset Managers are Current Condition of Assets, Age of Assets, and Unaddressed System Maintenance Needs.   At a more detailed level, this concern is further validated by Osmose's national pole inspection data which indicates the average age of the (distribution) wood pole plant in the U.S. is 35.8 years.  With the average age for a pole requiring reinforcement or replacement at 47.6 years without any in-service remedial treatment, it's not surprising that Asset Managers are looking ahead and seeing trouble on the horizon, and the issue is certainly broader than just wood poles. 

I Need a New Rate Schedule for This...

How will utilities fund the infrastructure improvements needed to keep the basic aspects of the grid functioning as well as the new investments required for grid adaptation, especially in light of future projections for lower revenue growth which may impose investment constraints?   It starts with a consideration of how regulatory models will need to evolve to support continued system improvements, achieving, as realistically as possible, a 'win-win' scenario for all key stakeholders.   The recently-released report from the GridWise Alliance prepared for the Department of Energy (The Future of the Grid - Evolving to Meet America's Needs; December, 2014) lays out this challenge in very clear terms when they discuss the need for continued regulatory certainty and clarity around investment cost recovery.  Will we continue with company profitability being based on the traditional method of utilities deploying capital with an authorized ROE, or will it instead be determined by what value or level of performance the utility is delivering around a set of defined and mutually agreed-upon metrics?  Whichever model emerges, there will be a need for attractive and timely cost recovery mechanisms outside of the traditional rate case environment.    

Performance-Based Ratemaking, Part Deux?

Several states are already moving toward a new regulatory construct.  New York's well-publicized effort is titled "Reforming the Energy Vision."  While the ratemaking track is still a work in progress and the initial draft proposals from the NYPSC staff are not expected until June 1, 2015, there is already consideration being given to creative or non-traditional ways that utilities might be able to capitalize and treat new types of investments as regulatory assets, recovering the costs associated with these investments over shorter periods of time.      

In California, utilities are expected to file their respective Distribution Resource Plans (DRP's) with the CPUC on July 1, 2015.     The original order instituting rulemaking referenced its purpose was to "evaluate the IOU's existing and future electric distribution infrastructure and planning procedures with respect to incorporating Distributed Energy Resources into the planning and operation of their electric distribution systems."   Also being considered as part of this effort is how the Commission would approve proposed spending, along with the adoption of "criteria, benchmarks, and accountability mechanisms to evaluate the success of any investment authorized pursuant to a distribution resources plan."  

Minnesota recently kicked off its own regulatory review process titled the "e21 Initiative."  It's stated aim is to "develop a more customer-centric and sustainable framework for utility regulation in Minnesota that better aligns how utilities earn revenue with public policy goals, new customer expectations, and the changing technology landscape."  Their December, 2014 report acknowledges the current ratemaking system is not set up to either compensate providers for the range of services they offer, or charge others for the cost of "grid services" they use, nor does it make it easy for a utility to keep pace with technological change.  One of the core recommendations is the adoption of a multi-year, performance-based regulatory framework which recognizes that the two main ways a utility currently earns revenue—the sale of electricity and the addition of large capital projects to the rate base, will need to change in the future.  

Supportive Regulatory Elements Already Benefitting Many Utilities and Their Customers  

Several states have already implemented regulatory frameworks or mechanisms which lend themselves to more timely cost recovery for necessary system improvements, reduce the need for frequent rate cases, and reflect the reality that a high "regulatory cost" can discourage a utility from moving forward with plans or programs which might otherwise benefit its customers. 

Most of these alternative measures to traditional Cost of Service regulation have several key components in common:

  1. Focused mechanisms which allow for recovery of identified (and prudent/well-justified) system investments, or provide for enhanced utility performance incentives
  2. Regular reporting, verification and benchmarking, and a high degree of transparency
  3. Elimination of regulatory lag and the time and cost involved in an extended rate proceeding
  4.  A focus on plans and initiatives which enhance reliability and improve system performance, ultimately benefiting rate payers and resulting in lower long-term system operating costs

Mississippi's Performance Evaluation Plan (PEP) is one current approach to a ratemaking process which establishes performance measures and allows for a performance-adjusted ROI within established percentage bands or ranges based on utility performance.   This has helped limit the scope and frequency of rate cases and provided financial incentives for the utilities to pursue strategies which improve service or reduce costs. 

The Massachusetts Department of Public Utilities 2014 order on Grid Modernization Plan (GMP) development provides a framework for utilities to recover costs through a capital expenditure tracker mechanism for investments outlined and justified in a utility's Short-Term Investment Plan (STIP), which is in turn supported by a comprehensive business case.   One of the underlying points made in the order was the commission's concern that "under conventional cost-of-service ratemaking, electric distribution companies may not have the proper incentives for making investments to attain our grid modernization objectives.  We are persuaded that short-term, targeted cost recovery treatment is required to remove impediments to some grid modernization investments."

Illinois legislation in place since 2011 (Energy Infrastructure Modernization Act, or EIMA) allows the state's two IOU's to operate under performance-based ratemaking for distribution if they make substantial infrastructure investments.  Wood pole inspection, treatment and replacement programs are included as part of the specific system investments outlined, along with underground system refurbishment and replacement. 

An approach like Pennsylvania's Act 11 passed in 2012 allows utilities to petition the PUC to approve implementation of a Distribution System Improvement Charge (DISC) which ties to their Long-Term Infrastructure Improvement Plans (LTIIP's) and provides for "the timely recovery of the reasonable and prudent costs incurred to repair, improve or replace eligible property in order to ensure and maintain adequate, efficient, safe, reliable and reasonable services."  Pennsylvania utilities which have taken advantage of this have been able to improve their storm hardening and resiliency programs, accelerate the replacement of aging underground cable, and implement other targeted reliability programs.  These types of recovery mechanisms are very similar in nature  to the Targeted Infrastructure Replacement Fund programs (TIRF's) in place in several states for natural gas LDC's which allow for accelerated distribution (pipeline) infrastructure replacement. These recovery mechanisms require utilities to file detailed, long-term infrastructure improvement plans that illustrate where investments will be made and the anticipated benefits. Spending and results are reported by the utility to the PUC, which monitors progress and ensures accountability for achieving the original plans.

Both Ohio (Enhanced Service Reliability Rider - ESSR) and Indiana (Transmission, Distribution and Storage System Improvement Charge - TDSIC) have similar frameworks in place which allow utilities to recover (or petition to recover) investment costs on a more frequent basis.

This is by no means a comprehensive overview of all the possible frameworks which are in place or being discussed nationally which relate to this topic, nor does it delve into the different considerations which must be taken into account when looking at the issues from the perspective of a municipal/governmental or electric cooperative utility given their different ownership and governance structures. The point, however, is that clearly there is substantial thought being given to these issues around the country, from a variety of industry stakeholders and representing numerous and varied perspectives and points of view.  Further, there are precedents established that appear to be working effectively to stimulate additional investments in the grid, helping ensure reliability and adaptability for the long-term.   While the issues involved are highly complex and the ultimate regulation will evolve differently and vary from state-to-state, Osmose is confident the resulting regulatory templates and tools that are put in place will allow for workable and equitable solutions to the numerous issues related to evolving grid functionality and new energy market requirements. 

In the meantime, utilities operating in states that do not currently have a forward-looking regulatory approach that provides a mechanism for more timely cost recovery of T & D infrastructure upgrades have several possible templates to explore.  These can be used as a basis for preliminary plan development, and as a framework to engage and work cooperatively with their regulators to quantify the benefits and costs related to the initiation of new programs to make sure their systems are better prepared.    

Back to That Old Infrastructure Problem...  

In anticipation of these coming changes, the importance of optimizing assets that are already in place deserves increased attention.  The decisions that utilities are making today will either enhance or limit their future ability to keep up with the changes we know are coming.  If companies are still struggling to address issues related to the basic upkeep of infrastructure five or ten years down the road, how are we also going to fund the other grid enhancements required to create an even more complex and multi-functional system?  The need for more comprehensive and long-term investment programs that are well-supported by accurate financial and risk-based planning models is a clear priority for the industry 

Summary

The electric grid is not a relic whose days are numbered, but rather the incredibly valuable framework for an evolving and adaptive network which in the future will support two-way energy flow, incorporate new sources of distributed generation, new energy storage systems, and ensure the continued delivery of safe, reliable and affordable electric service.   To quote that same Rocky Mountain Institute article referenced earlier in this paper, "the future of the grid need not be an either/or between central and distributed generation.  It can and should be a network that combines the best of both."

Utility companies, working in cooperation with their regulators and other industry stakeholders, will be at the forefront of creating and building the framework to make the grid integration process work, and not left just holding on to a much smaller group of unprofitable customers in a high-cost environment.  They will be able to successfully build a business around serving customers in the new energy marketplace.

While likely to evolve in fits and starts and be more than a bit messy, new regulatory models will emerge as a result of the many initiatives and frameworks either already in place, or being currently discussed at the state level which will provide both the clarity and the certainty needed for utilities to continue to successfully operate and be compensated for the value they provide to remain viable and attractive to continued investment. 

Utilities in states without favorable cost recovery mechanisms or frameworks outside of the traditional rate case environment can benefit from a review of the regulatory frameworks in other states which may be more supportive of their efforts to deal with their own aging infrastructure issues or grid modernization initiatives.

The T & D system will still be the backbone of the new grid and in particular, the Distribution system will be an even more critical part since it will be at the local delivery level, not the bulk transmission level, where many of these grid enhancements will take place.  Given this ongoing role, utilities need to pay even more attention to optimizing the condition and performance of the existing T & D system to ensure they can fund the implementation of the new technologies and system enhancements required for a successful transition to the grid of the future.