Illinois Approach to Regulating Distribution Utility of the Future

It is clear that the electric utility industry is in a state of transformation. It is also becoming increasingly clear that this does not signify the end of the electric grid.

Certainly it will cease to exist as we have historically known it over the past century. But this transformation is logically redefining the grid in a manner that increases its value to all participants in the industry.

This is an industry that is quickly moving from a monopoly system, based on one-way power flows from large central station generators, to a decentralized and increasingly competitive system featuring proactive consumers who can instantaneously, automatically, and without notice switch back and forth between being electricity loads and electricity sources. All this will require a highly reliable and resilient electricity grid to serve as the foundation (the backbone, if you will) of these emerging markets. Without it, these markets will not emerge and cannot exist.

Therefore, one necessary condition for a market transformation that ultimately benefits all is the continual upgrade and maintenance of the electric grid. This brings into question whether the current and traditional method of regulating public utilities best accommodates the anticipated changes in the electric distribution services industry.

Traditional cost of service regulation with periodic rate cases, and regulatory lag as the only incentive, is ill-equipped to accommodate this transition. The changes to this industry require a new regulatory approach that results in manageable levels of risk by avoiding undue review processes and unduly prescriptive oversight, while also providing incentives to perform.

When rapid changes in circumstances occur, both utilities and their customers will benefit from management that has the flexibility to adapt and respond. New regulatory models should encourage the innovation that will enable utilities to remain forward-looking and responsive to the challenges and opportunities of the evolving energy landscape.

A necessity for this is to transform the issue of the recovery of basic infrastructure costs. A lot has been said of alternative ratemaking approaches but the clearest most direct path is what has been happening in Illinois, which is in the fifth year of an annual performance-based formula process for setting rates for electric distribution services. And it is clear that this process is a success in meeting the objectives that were established at the onset and by any other reasonable measure for a distribution utility.

Given this approach is long past an experimental stage, we thought it useful to explain just how this process was created, and how it is designed and administered. And just how well it is working using the experience at Commonwealth Edison as an example.

Reliability and customer service performance are at historical highs. Customer satisfaction continues to climb. Total electric rates have remained below the overall inflation rate for the economy. And there have been two separate annual rate decreases although distribution rates have increased to cover the infrastructure investment since the last standard rate case.

It is important to understand that these outcomes did not come from simply instituting a formula ratemaking process. But it is the result of a regulatory package passed into law that provided utilities, customers and all other stakeholders a road to a better place.

In late 2011, Public Act 97-0616 was passed in Illinois which established a new section of the Illinois Public Utilities Act that included pillars for the future:

1. regulatory stability for electric distribution utilities;
2. an authorized level of infrastructure investment including the full deployment of smart meters; and
3. accountability of the utilities to deliver benefits to the customers and the state of Illinois, including a minimum number of jobs created as a result of infrastructure development and smart meter deployment.

The Formula Rate Process in Illinois

Formula ratemaking is an approach to setting the appropriate level of revenue recovery on an annual basis, or other time period, through a streamlined regulatory process. This approach provides the utility with more stability regarding recovery of actual costs, as opposed to periodic rate cases, and results in larger customer benefits with regular needed investments in the utility's infrastructure.

It is a streamlined regulatory process in Illinois primarily due to three components of the new law:

1. the allowed return on equity is a simple arithmetic calculation using a known and transparent market-based number added to a constant;
2. cost allocation and rate design are not dealt with as part of the annual formula filing; and 
3. the determination of a number of issues frequently litigated during periodic rate cases is settled by statute.

Advanced determination of these three components reduced the rate case litigation time and effort by over seventy percent.

The process in Illinois is simple and methodical. On or before May 1 of each year, the distribution utilities make a filing to set rates for the subsequent calendar year. For example, a May 1, 2016 filing will be for a rate year starting January 1, 2017.

Each annual filing has two major components.

The first component includes updated cost information. The second component is a reconciliation to true up the previously approved revenue requirement, which incorporated projections of investment, depreciation, and expense, with a new revenue requirement for the same period calculated with the then-available actual data.

Any differential will result in a corresponding credit or charge, with interest, to be included in the delivery service charges applicable beginning January 1 of the following year. In other words, each annual filing reconciles the revenue requirement reflected in rates for the prior year with what the revenue requirement would have been had the actual cost information been available. That is, with what would have been the result calculated using actual costs for the year being reconciled.

The formula is embodied in an approved tariff, which is used to determine the delivery service revenue requirement and the resulting delivery service charges to customers, as well as the cost components that form the inputs to those formulae. It does so with sufficient specificity for the process to operate in a standardized and transparent manner, and with annually updated inputs that reflect the utility's actual costs to be recovered during the applicable year.

The Illinois statute specifies the structure and a number of protocols to be followed by the formula:

1. Provide for the recovery of the utility's actual costs of delivery services, subject to those costs being prudently incurred and reasonable in amount consistent with Commission practice and law;

2. Reflect the utility's actual capital structure for the applicable calendar year subject to a determination of prudence and reasonableness consistent with Commission law and practice;

3. Include a formula-based cost of equity established as described below; and

4. Sets forth protocols for the following, subject to a determination of the reasonableness and prudence consistent with Commission practice and law, including:

a) Recovery of incentive compensation expense that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance. However, incentive compensation expense that is based on net income or an affiliate's earnings per share is not recoverable.

b) Recovery of pension and other post-employment benefits expense, provided that the costs are supported by an actuarial study.

c) An investment return on pension assets net of deferred tax benefits equal to the utility's long-term debt cost of capital as of the end of the applicable calendar year.

d) Recovery of expenses relating to certain regulatory proceedings.

e) Amortization over a five-year period of the full amount of each charge or credit that exceeds ten million dollars in the applicable calendar year relating to a workforce reduction program's severance costs, changes in accounting rules, changes in law, compliance with any Commission-initiated audit, or a single storm or other similar expense. However, any unamortized balance shall be reflected in the rate base.

f) Recovery of existing regulatory assets over the periods previously authorized by the Commission.

g) Historical weather normalized billing determinants.

h) Allocation methods for common costs consistent with previous Commission decisions.

The Allowed Return on Equity

The allowed return on equity is calculated as the sum of the following:

The average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds,

Plus, five hundred eighty basis points.

Suppose the utility's earned rate of return on common equity related to the provision of delivery services for the prior rate year is more than fifty basis points higher (or more than fifty basis points less) than the rate of return on common equity calculated above. Then the utility shall apply a credit (or charge) through the formula. The credit (or charge) reflects an amount equal to the value of that portion of the earned rate of return on common equity that is more than fifty basis points higher (or more than fifty basis points less) than the rate of return on common equity calculated for the prior year, adjusted for taxes.

Interclass Revenue Allocation

The delivery service rates charged to retail customers each year are derived from the formula-determined revenue requirement, using a cost allocation and rate design that is consistent with the most recent Commission order establishing interclass cost-of-service allocation and rate design. A separate "rate design investigation" is conducted by the Illinois Commerce Commission to determine these issues. This proceeding is to occur at least every three years.

The Role of the Commission

One criticism of formula rates in the past is that it bypasses the review of the public utility commission and results in "automatic" rate increases. This is not the case in Illinois.

The Commission continues to exercise regulatory authority over the utilities and their retail rates in a manner very similar to the standard rate case. The Commission reviews the utility's formula tariff to confirm that it complies with the law. Each annual Commission proceeding establishes the utility's future revenue requirements and reconciles actual and projected costs. The Illinois statute expressly preserves the Commission's authority to investigate the prudence and reasonableness of each utility's expenditures during the annual review, and further provides for periodic Commission review of delivery service rate design.

Within forty-five days of the May 1 filings, the Commission has always initiated a proceeding to review the costs in the update over an eight-month period, down from eleven months under the prior process, applying the same evidentiary standards as in previous rate cases. The Commission Staff or intervening parties present evidence regarding whether the costs were prudently incurred or reasonable in amount. And the utility presents evidence in its defense.

The parties to the case seek discovery from the utility under the Commission's ordinary rules. The Commission issues an order setting rates based on the review of the formula filing within two hundred forty days of the utility filing.

The review process must be based on the same evidentiary standards the Commission applies in a hearing to review a filing for a standard case. Including but not limited to those concerning the prudence and reasonableness of the costs.

Performance Metrics

The Commission's involvement also goes beyond evaluating utility rates.

As part of the law that instituted formula rates, participating utilities in Illinois were required to submit metrics to the Illinois Commerce Commission. They are designed to achieve ratably over a ten-year period, multiple performance improvements over baseline values:

• Frequency of customer interruptions;
• Duration of customer interruptions;
• Overall improvement in exceeding service reliability targets;
• Reduction in the number of estimated bills;
• Opportunities for minority-owned and female-owned businesses to participate as ComEd contractors; and
• Other performance improvement measures.

If the utility does not achieve the incremental annual performance goals for a given period, it must reduce its return on equity by up to thirty-eight basis points. Tariffs were put in place to establish this as part of the annual formula process.

On June 1 of each year, ComEd files a report with the Commission describing how it performed under each metric. The report is evaluated annually by the Commission. If ComEd fails to meet its incremental annual performance goals, it will earn a lower return on equity for the relevant twelve-month period as specified in the statute. In the case of ComEd, not all of the performance metrics have been achieved and basis point reductions have been assessed.

Initial Cap in Rate Increases

To alleviate concerns that the formula rate process would lead to automatic and excessive rate increases, the statute included a cap on increases during the early years. Suppose the total amount paid by a residential customer per kilowatt-hour (including delivery, transmission, energy, add-ons, etc., but exclusive of the effects of energy efficiency programs) rose between June 1, 2011 and May 31, 2014 by more than 2.5 percent per year, on average. Then the utility would no longer be allowed to use the formula for establishing its annual revenue requirement.

None of the utilities in Illinois exceeded this cap.

Infrastructure Investment Plan and AMI Reporting

As mentioned above, each utility participating in the program was required to make improvements in the distribution infrastructure and to deploy advanced metering infrastructure, AMI. At the outset, the utilities were required to file plans with the Commission detailing how they would satisfy their infrastructure investment commitments (Infrastructure Investment Plan) and a plan and schedule for deployment of the AMI (AMI Plan). 

Each year the utilities file status reports and updates on these plans for Commission and Stakeholder review. A key reporting component for the Infrastructure Investment Plan is the reporting on job creation as financial penalties will be assessed if these targets are not attained. For example, ComEd would be assessed a three thousand dollar penalty for each "job deficiency."

Significant deviation from the investment plan could lead to disqualification from the program. And, of course, all costs that utility incurs in connection with the infrastructure investment program are included in the formula rate updates and subject to Commission review for reasonableness.

The annual AMI deployment updates are reviewed by the Commission, which can choose to open an investigation regarding the report. If the Commission finds that the utility's progress in implementing the AMI Plan is materially deficient for the given Plan year, the Commission must issue an order within 90 days of the filing requiring ComEd to devise a corrective action plan to bring implementation back on schedule with the AMI Plan. This annual process continues until full deployment of AMI.

Other Requirements as Part of the Formula Legislation

There are numerous other conditions and requirements that resulted from this legislation that have benefited Illinois stakeholders since enactment. A Smart Grid Advisory Council was established to review progress on AMI deployment and other aspects of the program. The members of this Council are appointed by the Governor, legislative leaders, the Citizens Utility Board and several other interested parties with the intent of representing a cross section of stakeholders across the state. The statute required the Smart Grid Advisory Council to establish, and the utilities to finance, the creation of the Illinois Science and Energy Innovation Trust, whose mission is to jump-start energy-related business initiatives that will provide sustainable benefits to the state.

The utilities are required to offer an opt-in peak time rebate program designed to provide rebates to residential customers with smart meters that curtail their usage during peak periods.

With input from the Smart Grid Advisory Council, the utilities created and are maintaining administration of smart grid test beds, which facilitate the testing of smart grid technologies.

And the legislation required participating utilities to finance additional programs to assist low-income customers, and to expand energy efficiency investments for residential and small business customers.

Results of this Program Are Impressive

Using ComEd as an example, it is evident that the formula, and the entire program package, has been a success in attaining much-needed infrastructure upgrades and achieving customer benefits. ComEd is on the path to full deployment of AMI by the end of 2018, which will be three years ahead of the original schedule.

The full deployment of AMI will pay for itself without accounting for any change in customer behavior that will result from other programs it enables. Efficiency improvements on the customer operations side of the business will more than compensate for the cost of this program. And because of the formula, these benefits flow back to customers every year, automatically with the annual rate filings.

The infrastructure upgrades are stretching from one end of the territory to the other, and from the tops of poles to the deepest manhole. By the completion of this program, ComEd will:

• Inspect and test 3,200 miles of mainline cable with up to 500 miles of this cable being replaced;
• Inspect 32,000 manholes, and in the process, refurbish up to 28,000;
• Upgrade 4,200 miles of underground residential cable;
• Install 2,600 new distribution automation devices;
• Inspect over three quarters of a million wood poles with the expectation of replacing close to 20,000;
• Modernize sixteen substations; and
• Deploy four million smart meters.

All of this leads to direct customer benefits in the form of increased service reliability and improved economics as a result of fewer interruptions and shorter duration of the interrupts that do occur. The distribution automation, cable replacement and underground residential distribution programs at ComEd have already avoided close to two million customer interruptions.

Mainline cable faults and the System Average Interruption Frequency Index are best on record for the company. Recent storm-related customer interruptions have been decreased by twenty percent over previous years. Close to twenty million manual meter reads have been avoided.

Customer satisfaction, while a complex combination of many factors, is up significantly since passage of the legislation, reaching record levels in 2015. In 2012, ComEd ranked sixteenth out of sixteen among large Midwestern utilities by JD Power. By the end of JD Power's 2015 cycle, ComEd had improved by seventy-four points, representing one of the greatest improvements among large utilities across the country, and showing improvement in all but one category tracked in the survey.

Final Thoughts

The annual formula rate is working in Illinois to stabilize the distribution ratemaking process, leading to a consistent trajectory of investments to upgrade and maintain a healthy grid. These investments are already yielding significant benefits to customers. But they will provide even greater benefits in the future as the grid becomes the backbone of a transformed industry.

This has resulted from a collaborative effort among the utilities, a broad spectrum of stakeholders and a progressive Commission. Continuation of this focus will lay a strong foundation for what is yet to come for the customers of the future.

Lead image © 2016 Can Stock / MaxyM