Natural Gas and Electricity Decoupling in the U.S.

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As of late 2009, numerous U.S. states have experimented with and fully implemented decoupling. Generally speaking, the natural gas industry is more advanced than the electricity industry, consistent with its longer history of deregulation. The following discussion highlights some of the differences and similarities across these industries and among the variety of regulatory environments with respect to decoupling:

California Decoupling

California has the longest history with respect to decoupling. It has been in place for natural gas utilities for almost 30 years and likewise for electric utilities except for a multi-year suspension period during the restructuring era. California decoupling is only a small part of an extraordinarily complex regulatory framework that includes as many as seventeen different adjustment mechanisms that operate between general rate cases.

California’s decoupling system consists of a simple revenue cap, with the allowed distribution revenue requirement from the general rate case trued up without consideration to inflation, customer growth, or other factors. However, this is accompanied by use of a future test period in the rate case, an “attrition” case between rate cases that captures inflation and productivity adjustments as well as impacts of growth, and annual adjustments for return on equity.

Washington Decoupling

Washington experimented with electric decoupling beginning in 1990, with a mechanism for Puget Sound Power and Light Company (now Puget Sound Energy). The Puget mechanism divided costs into “base costs” which were adjusted annually on a revenue per customer basis, and “resource costs” which were adjusted annually to reflect changes in actual power supply costs, both fixed and variable. The mechanism was terminated after four years, primarily due to the rising level of resource costs.

Washington has recently approved partial and limited decoupling mechanisms for Cascade Natural Gas Company and Avista Utilities natural gas service:

The Cascade mechanism was adopted in January, 2007, and recalculates revenues based on normal weather conditions prior to determining if a decoupling adjustment is required. Because it does not protect the utility from earnings volatility caused by variations in weather, the Commission chose not to impose a cost of capital adjustment. It was approved for an initial three-year period.
The Avista mechanism is even more limited. Not only are sales restated to reflect normal weather, but new customer usage is completely excluded from the decoupling mechanism. This reflects evidence that much of the decline in usage per customer is caused by lower use by new customers, and that is accounted for in the utility’s line extension policy. The Avista mechanism was also approved for an initial three-year period.

Oregon Decoupling

Oregon approved a revenue-per-customer decoupling mechanism for Northwest Natural Gas in 2002, and expanded and extended it in 2005. Initially, the mechanism only allowed recovery of 90% of margin declines caused by lower sales. The Commission required a formal evaluation of the NWNG mechanism, prepared by Christensen Associates, which concluded, among other things, that decoupling was a primary contributor to a bond rating upgrade for NWNG.

Idaho Decoupling

The Idaho PUC approved a two-part decoupling mechanism in 2007 for Idaho Power Company:

The first part is a fixed cost per customer for energy delivery services.
The second part is a fixed cost per unit of energy, attributable to power supply. This is a limited decoupling mechanism, with sales adjusted to reflect normal weather prior to calculation of the decoupling adjustment. Any surcharge or credit is reflected on the customer bill as part of the energy conservation program charge.

Rate increases of more than 3 percent are not allowed (but, with weather restated to normal, it is pragmatically unlikely that any adjustment would reach this magnitude).

Utah Decoupling

In 2006, the Utah Public Service Commission approved a three-year pilot full decoupling mechanism for Questar Natural Gas Company, without a K factor or separate treatment of new customers. The Commission did not order a cost of capital adjustment, but did require that Questar begin the deferral accounting (for the decoupling adjustments, both up and down) with a $1.1 million credit in the customer’s favor.

Maryland Decoupling

Baltimore Gas & Electric Company (BGE) currently operates under a full decoupling program for its residential and general service gas customers. It applies revenue-per customer (RPC) mechanisms, based on a rate case test-year revenue requirement. The RPC is expressed as a function of average usage per customer per month. Revenue adjustments are made monthly, and any difference between actual and average use per month is reconciled in a future month.

In 2007, the Maryland Public Service Commission approved the decoupling proposal (“Bill Stabilization Adjustment Rider”) of the Potomac Electric Power Company (Pepco). Similar to the approach adopted for BGE, it is a full decoupling, revenue-per-customer program. Adjustments are made monthly, capped at ten percent, with any excess carried over to a future period. In recognition of the reduced risks that Pepco would face, the Commission lowered the company’s otherwise allowed return on equity by 50 basis points. It also approved a similar decoupling proposal for Delmarva Power (which, like Pepco, is a wholly-owned subsidiary of Pepco Holdings, Inc.).

MADRI Initiative

The Mid-Atlantic Distributed Resources Initiative (MADRI), a cooperative effort of state regulators in New Jersey, Delaware, the District of Columbia, Maryland, and Pennsylvania, developed a generic approach to decoupling, referred to as the Revenue Stability Model Rate Rider. It describes the mechanics of a full revenue-per-customer decoupling regime, and it was based largely on the BGE program. It in turn became the model for the Pepco and Delmarva plans

North Carolina Decoupling

North Carolina’s three major gas utilities were decoupled in November 2005. The Public Utilities Commission based its decision to do so on several findings:

Conservation has the potential to cause financial harm to a utility and its shareholders;
Decoupling offers better opportunities for the conservation of energy resources and savings for customers, thereby putting downward pressure on wholesale gas prices;
Decoupling better aligns the interests of the utility and its customers; and,
It reduces shareholder risk.

The PUC approved the decoupling mechanism as an experimental tariff – the Customer Utilization Tracker (CUT) – and limited it to no more than three years unless reauthorized by the PUC. It is a full revenue-per-customer decoupling mechanism for residential and commercial customer classes, adjusted semi-annually. The Commission excluded industrial customers from the CUT, citing their different usage patterns. The PUC required that the utilities make significant contributions toward conservation programs, and rejected the Attorney General’s argument that decoupling would penalize customers for conserving. Lastly, the Commission recognized the importance of volumetric rate structures and lower fixed customer charges. It rejected the “straight fixed-variable” rate design proposal, with its higher fixed charges, on the ground that customers’ bills should be tied to their usage.

New Jersey Decoupling

New Jersey Natural Gas and South Jersey Gas Companies proposed full revenue-per-customer decoupling mechanisms in 2005. The mechanisms, as proposed, would cover the revenue impacts resulting from sales deviations due to normal weather, energy efficiency, and other factors (e.g., economy). The difference between actual revenues and allowed revenues (the product of number of customers, average usage/customer, and price) would be recovered (or credited) through the new Conservation and Usage Adjustment (CUA) clause in the following year.

The cases were settled in 2006. Limited revenue-per-customer decoupling for only non-weather-related sales changes was approved. Termed the Conservation Incentive Program (CIP), it is being run as a three-year pilot. Revenue adjustments cannot exceed the amount by which the company reduces total costs of Basic Gas Supply Service (i.e., the commodity savings that result from company investments in energy efficiency). Revenue shortfalls that are in excess of the gas supply savings can be recovered in later periods, to the extent that there is room under the cap to do so.

Company-sponsored energy efficiency programs were greatly expanded, but, in an interesting twist, the settlement called for the costs of efficiency programs to be taken “below the line” (i.e., not included in the regulated cost of service, but rather paid for out of company earnings. This had the effect of reducing the companies’ returns on equity, in recognition of the reduced risk that they would then face.

Vermont Decoupling

In late 2006 the Vermont Public Service Board approved a modified revenue cap (partial decoupling) for Green Mountain Power Corporation (GMP). Its allowed base revenues (non-power costs) are pre-determined for each of the three years of the program in accordance with the terms of a memorandum of understanding signed between the utility and several parties. Changes in base revenues are capped at $1.25 million for 2008 and $1.5 million for 2009, although the caps can be exceeded, if necessary, for specified exogenous costs.

The company’s earnings are bounded by sharing collars: the first 75 basis points; up or down, are borne by GMP; the next 50 basis points are shared equally between the company and its customers; and anything after that is borne by the customers. Separately, the company’s power costs are subject to a quarterly fuel adjustment clause. Variances in costs of committed resources (owned units or contractual entitlements) are borne entirely by the customers. Variances up to $400,000 per quarter for non-committed (i.e., market) resources are covered by the company. Variances in excess of the $400,000 are covered by customers. However, if the total variance results in an adjustment of greater than $0.01/kWh,the excess will be carried over to a following quarter.