Industry 101 | Regulation in the Electricity Industry: Pricing Regulation

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Beginning in the late 70s and early 80s, electricity utility regulatory systems have introduced a new form of regulation to incentivize firms to maximize efficiency – incentive regulation. Incentive regulation can be defined as how government regulators promote efficiency among electricity providers by offering rewards and penalties based on the level of result the electricity providers achieve.

Compared to the traditional cost-of-service regulation, incentive regulation will grant the firms with a reasonable amount of rewards under the condition they achieve a certain level of efficiency in electricity production. For instance, under the traditional cost-of-service regulation, the firm’s revenue is calculated by adding the operating cost to the capital cost multiplied by the rate of return, as shown in the formula below.

R = (B * r) + E + d + T

  • R – The amount of revenue the firm requires to cover all costs and expenses
  • B – The base rate the firm requires to cover costs of capital and assets utilized to provide service
  • r – Government permitted rate of earnings that scales with the base rate
  • E – The expense amount that the firm spent on supplies and labor to provide service
  • d – The expense amount that the firm spent on its depreciated capital
  • T – Taxes

PBR SimplifiedIn this case, as the firm’s capital cost (base rate) increases, so does their rate of return. For incentive regulation or performance-based regulation (PBR), a new element is added to the calculation of the revenue – rewards based on performance. In this form of regulation, the firm’s profit is no longer solely dependent upon the rate of return based on the capital costs, but also affected by the utility’s performance. Hence, as the utility’s performance improves, the firm will receive some level of rewards added to their revenue. Firms displaying poor performance will be subjected to a fee or fine, which will decrease their profit. This greatly weakens the link between the utility’s price and the utility’s cost of service.

Incentive regulation can be categorized into two main classes:

  • Targeted Plans
  • General Plans

Targeted plans will introduce the incentive regulation via a specific cost area that is of concern, such as energy efficiency spending and sales on the wholesale market. General plans, on the other hand, link the firm’s earning to the measure of performance in a particular area, such as safety, customer satisfaction, or service quality. Both of these types of regulations are focused on addressing a particular area of concern and incentivize firms to improve the performance or operation in that particular aspect. Common forms of incentive regulatory plans include:

  • Earning Sharing
  • Price Caps

An earning sharing mechanism tracks the actual earnings reported. If over a targeted level set by the government regulators, then these earnings will be shared by the shareholders and their customers. This form of regulation encourages firms to cut spending and expenses and improve efficiency and operation costs to achieve the targeted levels to improve their own returns.

A price cap is a form of incentive regulation where a benchmark is determined to reflect changes in price as a result of inflation and other factors. The general formula used to calculate the price would be multiplying the old price by one plus a measure of inflation minus productivity, as displayed below:

Pricing cap advantagePt = Pt-1 * (1 + RPI – X)

  • Pt – Price of the current period
  • Pt-1 – Price of the previous period
  • RPI – The measure of inflation
  • X – Productivity factor

In the formula above, X is the productivity factor that is determined based on the performance of other firms in the industry. Hence, this regulation system provides firms with an incentive for efficiency savings or price drops, whereas anything above the predicted rate of X will be passed on to the shareholders.

Incentive regulation has shown success in cutting the capital costs and deprecation costs of electricity firms. However, it does introduce new risks and challenges. In order to achieve additional cost savings to reach a certain level of performance, firms might take drastic measures to reduce their numbers.  For example, to reach the incentive threshold, many firms reduce their service quality in order to bring down their capital costs. This is a widely recognized problem, where regulators have designed many remedies to prevent service quality deterioration. Regulatory bodies may establish a service quality standard along with the incentive regulation to keep the quality in check.


A market-based rate is the price of a service or product based upon market condition. Traditionally, regulators used formulas to calculate revenue requirements for each firm based on their reports, which included operational expenses, gross value of utility’s tangible or intangible property plus accrued depreciation. In 2015, FERC granted market-based rate authorization for wholesale sales of electric energy, capacity and ancillary services by sellers that can demonstrate that they and their affiliates lack or have adequately mitigated horizontal and vertical market power.

In order to obtain market-based rate authority, the seller needs to submit two studies:

  • Pivotal Supplier Screen
  • Market Share Screen

If the seller does not pass both screens and the seller still wants market-based rate authority, the seller needs to submit a more detailed delivered price test (DPT). Failure of the DPT requires the seller to provide mitigation for its market power.

Metrics of the Market-Based Rate Authority Evaluation Process:

  • Graph with Pivotal Supply Screen
  • Market Share Screen, DPT
  • Mitigation for its Market Power

Pivotal Supplier Screen Process (Peak Supply Test)

According to FERC Order No. 697 (2007), “the second screen is the pivotal supplier screen, which evaluates the potential of a seller to exercise market power based on uncommitted capacity at the time of the balancing authority area’s annual peak demand. This screen focuses on the seller’s ability to exercise market power unilaterally. It examines whether the market demand can be met absent the seller during peak times. A seller is pivotal if demand cannot be met without some contribution of supply by the seller or its affiliates.”

Definition of Terms:

  • Total Uncommitted Capacity = Total Capacity-(Native Load + Operating Reserves + Long-term Sales) + Uncommitted Capacity imported into the relevant market.
  • Balancing Authority Area (BAA): The collection of generation, transmission, and loads within the metered boundaries of the balancing authority. The balancing authority maintains load resource balance within this area.
  • Wholesale Load at Peak: The annual peak in the relevant market minus the average daily peaks of load during the month of annual peak.
  • Net Uncommitted Supply = Total Uncommitted Capacity – Wholesale Load at Peak
  • Seller Uncommitted Supply < Net Uncommitted Supply

Wholesale Market Screen (Energy Supply Test)

The wholesale market screen compares the megawatts of uncommitted capacity owned or controlled by the seller to the uncommitted capacity of the entire relevant market for each of four seasons.

Metrics are similar to pivotal supply screen:

  • Applied to all seasons, both on-peak and off-peak periods
  • Allows for planned outage in each season

A threshold of 20% market share cannot be exceeded.

If the seller passes both indicative screens, a rebuttable presumption that the seller does not have significant horizontal market power is established.  Failure in either screen will lead seller to perform delivered price test.

Delivered Price Test (DPT)

DPT consists of three parts:

  • Pivotal Supplier Screen
  • Wholesale Market Screen
  • The Herfindahl-Hirschman Index (HHI)

FERC will use certain technical modifications in the implementation of the two indicative screens again. For HHI under DPT model, FERC adopts a threshold of 2,500 as a measurement of market share concentration that gives rise to market power concerns.

Mitigation Methods

If FERC still has concerns about a market-based rate applicant’s market power after performing the delivered price test, it allows the seller to propose a cost-based mitigation method. FERC will provide a default list of mitigation methods:

  • Sell at cost-base rate
  • Reduce supply via long-term contract for capacity and energy

Case Study:

FERC revoked authorization for Berkshire Hathaway Energy subsidiaries to sell wholesale power at market-based rates in four neighboring balancing authority areas in the West in June 2016 due to the fact that Berkshire failed to prove its affiliates do not exercise horizontal market power.

FERC ordered the companies to file revised tariffs limiting their market-based sales to regions outside the four areas within 30 days. The companies must also issue refunds for the period between January 9, 2015 and April 9, 2016.


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