A High-Wire Act: Balancing a Modern Grid with Regulated Assets

This article is part 3 of the series: Electricity Evolution

High-wire act
 

This is the third explainer in a six-part collaboration between Ben Bovarnick (FES ’18) and Sara Harari (FES ’19, SOM ’19). The collection closely examines the barriers facing adoption of new, advanced energy technologies that can revolutionize electric-grid operations and utility business models and spark potential solutions to elicit faster transformation in this expansive industry.


Look at the electrical systems around you. You might not know it, but from power plants with towering smokestacks to wires across the nation, the grid is changing faster than ever before. Now guess who pays for all that infrastructure. Did you guess the utility? If so, guess again. Actually, as a utility customer, you pay for it!

When utilities make investments approved by state regulators, the cost of the investment plus a reasonable ROI is spread out over the useful life of the equipment and bundled into your electricity rate. This process of funding utility projects is called rate basing.

However, this traditional model of cost recovery does not support utility adoption of advanced energy technologies. This is because the financial outcomes of innovation are hard to predict. Utilities and regulators face two main challenges when it comes to financing advanced energy projects: 1.) how regulators assess new projects and 2.) how utilities recoup new investments.

Challenge 1: How Regulators Assess New Projects

Investing in traditional electric infrastructure is straightforward. If a regulator approves the proposed investment in a transformer, both the regulator and the utility know exactly how to depreciate the asset. They also know what outcomes to expect if the asset is managed properly.

Every few years, utility companies publish multi-year investment plans known as Integrated Resource Plans. These plans include proposals for traditional and advanced energy projects.

For example, DTE Energy recently filed a Distribution Operations Five‐Year (2018‐2022) Investment and Maintenance Plan with the Michigan Public Service Commission. This plan proposed investing in a range of activities that included installation of an Advanced Distribution Management (ADM) System that would facilitate large-scale integration of distributed energy resources.

Now, the Michigan Public Service Commission will review the plan. They may approve the plan in its entirety, aspects of the plan, or return the plan for revisions. If DTE Energy moves forward with its implementation, these investments can then be included in the ratebase.

Advanced-energy-technology projects, such as DTE Energy’s ADM system, can be much riskier than a transformer. This is because the ROI is uncertain. Utilities want to be adequately compensated for taking this additional risk and often seek to incorporate this into their electric rates.

Regulators evaluate the potential benefits of projects to ensure that increases to electric rates are appropriately aligned with the benefits of new investments. If a technology’s benefits are too uncertain or expensive, regulators may reject the project. This can be a major stumbling block for developers of new energy technologies who are looking for a toehold in the market.

And yet regulators are right to be cautious. Inaccurate evaluation of new projects can leave shareholders and customers on the hook for cost overruns in failed endeavors.

Perhaps the most dramatic recent example of this is the Kemper “clean coal” power plant in Mississippi. It was hailed by the Obama administration as the future of coal. However, after 7 years and $7 billion, Mississippi Power requested permission to pass on additional costs. (This $7 billion included $800 million that regulators approved to be passed on to ratepayers.)

The Kemper project is an example of a scenario where an unexpected cost overrun occurred due to the use of new technologies.

Regulators refused and recommended the facility stop developing the plant’s coal gasification facility. Without backing from the regulators, the only way Mississippi Power could continue the project as designed was to finance cost overruns without ratebasing. Mississippi Power responded by suspending the “clean coal” aspect of the plant.

Projects like this demonstrate the difficulty regulators face when evaluating utility proposals for advanced energy technologies.

How should regulators determine whether the financial risk of unproven technology is worth the hypothetical benefit to their ratepayers?

Despite these challenges, recent utility investment plans linked to by Greentech Media highlight grid-modernization projects as important components of future system investments. Utility regulators are still learning how to best accommodate utility requests to include new technology investments in rate cases, particularly if these requests will result in significant rate increases to customer electric bills.

Challenge 2: How Utilities Recoup Investments

Historically, when new technology investments were identified and integrated into a utility’s rate base, they tended to be capital-intensive. This technology was straightforward to rate base and therefore appealing to utilities.

We met with Richard Kauffman, chairman of energy & finance for New York and chair of New York State Energy Research and Development Authority (NYSERDA), to talk about the difficulties utilities face in incorporating new technology.

Kauffman spoke about the need to align utility incentives with the modern reality of an uncertain grid. “We’ve ended up with an industry that has financial incentive to deploy capital but is so nervous about reliability that they’re deterred from adopting new technology that is non-capital - such as IT - or would displace traditional technology.”

This is not the fault of utilities, but rather of the historical utility business model, Kauffman said.

To encourage utilities to embrace new technologies and business models, states are reforming utility regulatory policies nationwide.

These regulatory reforms are typically designed to reduce the risk associated with new pilot projects through a combination of:

  1. favorable treatment of rate basing pilot projects
  2. new mandates for adoption of new technologies
  3. financial incentives to ensure project viability

In conversations with Josh Gould, part of Consolidated Edison’s (ConEd) Utility of the Future group, we discussed the impact this is having on the utility business model. In the aftermath of Superstorm Sandy, New York regulators launched Reforming the Energy Vision (REV). REV is designed to reform utility business models and incentivize wider adoption of advanced energy infrastructure.

REV employs a unique cost-recovery mechanism that allows utilities to recover the cost of pilot projects, encouraging more creativity in developing new projects.

For example, ConEd funded the Brooklyn-Queens Demand Management (BQDM) project. Through a supplemental charge on ratepayers’ electric bills, the BQDM project includes a series of pilot programs designed to defer investment in a $1 billion substation.

The New York Public Service Commission allowed ConEd to include a monthly adjustment clause charge on electric rates to cover the cost of the $200 million of energy efficiency and demand response investments. These increases were significantly less than the rate increase that would have covered the cost of the substation.

With REV, ConEd and other New York utilities have begun to move away from the capital-intensive, traditional investments Kauffman described. However, due to utilities’ risk aversion, changing the policy landscape for utilities is not sufficient to guarantee new technology pilots and wide-scale adoption.

New technologies are on a playing field competing against systems that operators are already intimately familiar with and which they say can claim decades of proven success.

How to Address these Challenges

These challenges expose the inadequacy of the rate basing financial structure. Rather than allowing utilities to recoup investments that may improve grid reliability in a cost-effective manner, rate basing may in fact prevent investment in advanced energy technologies.

Regulators, lacking a framework to evaluate new technologies, can be hesitant to approve new projects if they are unsure about the impact to ratepayers.

Current approaches to financing new investments are a significant barrier to adoption of new technology. Rate basing assets allows utilities to invest virtually risk free in capital-intensive assets, but this comes at the cost of flexibility and adaptability. Grid modernization initiatives like NY REV should produce an electricity sector that is nimbler.

Based on our conversations with energy-industry professionals, we’ve found three main ways to overcome the challenges in financing advanced-energy technologies:

  1. Consider new models of risk-sharing to induce investment in pilot projects, which are often necessary to deploy new technology but carry inflated risks.
  2. Rethink the utility incentive structure to encourage investments in cost-effective new technologies rather than the current model which supports high capital investments.
  3. Improve information sharing of successful pilot projects and new business models across regions, accelerating technology adoption at both the utility and regulator level.

As utilities, policymakers, regulators, and other stakeholders consider how to modernize their electricity infrastructure systems, all players should keep these challenges in mind and carefully consider ways to address them. States and utilities should consider new approaches to utility investments in cutting-edge technology, and how to draw energy-technology innovators into electricity markets.

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