1999 to 2003: FERC rules adapt to industry restructuring, deregulation

• 1879 to 1895
• 1896 to 1928
• 1927 to 1936
• 1927 to 1969
• 1970 to 1978
• 1978 to 1996
• 1999 to 2003

by Jeff Hein

(Note: This article is the last in a series about the history of the U.S. electric utility industry. Hein developed this material as part of his master's thesis research.)

Three years after the 1996 Order No. 888 was issued, the Federal Energy Regulatory Commission determined, via GENCO reports, that substantial barriers to functional deregulation still existed and needed to be corrected. Order No. 888 had two primary shortcomings: inefficient operation and expansion of the transmission system and continued transmission system access discrimination.

FERC Order No. 2000

To address these shortcomings, in December 1999 FERC issued Order No. 2000, its second attempt at wide-sweeping changes in how the electric utility industry operated. FERC anticipated many benefits including lower electricity prices plus a creation of lighter-handed regulation.

FERC believed that transmission would be more effective and efficient if it were planned and operated on a regional, multi-state scale. All states within an interconnection are impacted by disturbances within it, as seen during the Western Interconnection disturbances in Summer 1996—and more recently the Northeast blackout in August 2003. FERC asserted in 1999 that ISOs should be larger, due in part to the 1996 disturbances. To that end, it called for regional transmission organizations.

Under FERC's plan, RTOs would be larger, appropriately sized versions of their ISO predecessors with the same responsibilities. An RTO would operate the transmission facilities with it's geographical scope, the control area. RTO guidelines would end transmission system access discrimination, FERC believed.

RTOs, ISOs differ

The RTO operating guidelines, or criteria, included four characteristics and eight functions. The four characteristics are:

• Independence
• Geographic scope and regional configuration
• Operational authority
• Short-term reliability

The RTO functions are:

• Tariff administration and design
• Congestion management
• Parallel path flow
• Ancillary services
• OASIS calculations
• Market monitoring
• Planning and expansion
• Interregional coordination

FERC required ISOs already in operation to prove they met these criteria to gain approval as an RTO.

According to FERC, differences exist between RTOs and ISOs. RTOs could be non-profit organizations, previously organized as ISOs or they could be Transcos—regulated for-profit organizations. FERC encouraged transmission owners to voluntarily hand over control of their facilities to an RTO of which they were a member.

Around this time, independent transmission companies began to appear on the American scene. These new firms did not own generation or distribution assets. FERC specified that ITCs could participate as RTO members or form their own RTOs. FERC called for the resulting RTOs to be operating by Dec. 15, 2001.

After Order No. 2000, proposed RTOs were typically geographically larger than their ISO predecessors, but were still not as large as FERC believed necessary to be truly effective.

FERC originally envisioned five RTOs for the entire U.S. transmission system—Northeast, Southeast, Midwest, Texas and the entire Western Interconnection. This did not occur. Instead 13 separate, non-continuous RTOs (PDF) were initially proposed, each with its own unique transmission and wholesale market rules.

The result was a problem, which occurred at the boundaries of neighboring RTOs. Due to their different operating rules, neighboring systems had difficulties resolving schedules and payments for electrical service between RTOs. These seams issues allowed continued transmission access discrimination and hindered restructuring, as reported to FERC by GENCOS.

Inadequate RTO geographical scope continued to plague FERC's restructuring efforts. To correct this, FERC issued the Standard Market Design Notice of Proposed Rulemaking on July 31, 2002.

SMD to eliminate seams

The primary goal of SMD, later renamed the wholesale power market platform, was to eliminate seam problems by standardizing the way generation and transmission markets operate. This design would "effectively" create the FERC-preferred larger RTOs by standardizing how RTOs would function. Many believed SMD would improve market oversight, promote transmission planning and expansion, lower the cost of electricity and create a framework for cooperative state and Federal regulation.

To accomplish this goal, SMD provisions called for the creation of independent transmission providers to replace RTOs. ITPs would retain many RTO responsibilities plus others to accomplish the primary goal of SMD. Under the SMD proposal, investor-owned utilities had to file new transmission tariffs. Community, co-op-owned and Federal utilities would follow reciprocity guidelines established under Order No. 888. Locational marginal pricing and congestion revenue rights were introduced to address transmission pricing policies for transmission congestion. Under SMD, FERC asserted it had jurisdictional authority over bundled transmission. Finally, FERC proposed to develop resource adequacy guidelines and a regional planning process to sustain a viable electrical power system.

Some states and utilities in the Northeast, Midwest and Texas, approved of SMD while many in the Southeast and West did not. SMD opponents voiced strong opposition. Their concerns included: jurisdictional overreach by FERC; destabilizing economic effects (cost shifting) and participant funding; incomplete operational specifics of how the markets will work; and failure to acknowledge regional differences.

Congress became involved in the debate over SMD, via the comprehensive energy bill. As a compromise, FERC issued a white paper on April 28, 2003, addressing issues from the initial SMD ruling.

Key features outlined in the white paper (29 KB PDF) include:

• The formation of RTOs
• Ensuring that all independent transmission organizations have sound wholesale market rules
• Varying implementation schedules depending on regional needs and regional difference.

According to FERC, its proposal has taken into consideration the experiences in this country and abroad in electric market design, including:

• The effects of supply shortages
• Demand that does not respond to high prices
• Lack of price transparency in the marketplace
• The importance of market monitoring and market power mitigation
• Industry continues functioning, future unknown

Throughout the years of restructuring efforts, electric utilities have kept the nation's electric system functioning and America running. Transmission infrastructure investment continues to decline, due to delays in creating a final restructuring plan. In its 2003 reliability assessment, NERC reported that system capacity appears to be adequate for the time being.

Today, the U.S. electric utility industry is mired in politics and regional debates, yet the demands on the interconnected power grid continue to grow. Our nation depends on a viable electric utility industry and bulk power system for its security, economy and way of life. While these debates and political discussions continue, the viability of our nation's bulk power system, upon which we depend, hangs in the balance.

(Note: Hein was a substation engineer in Western's Engineering group at CSO.)