Restructuring in the Ontario Electricity Industry – 1989 - 2002

Why did Restructuring happen in the Ontario electricity business?

The trend that sees infrastructure monopolies such as highways, telephone systems, and gas pipelines, becoming common carrier, open access facilities, and not the delivery systems of a monopoly supplier has been ongoing for many years. 

It was only natural that this trend would be expressed in the electricity industry.  It is happening at an uneven pace throughout the world as different jurisdictions come to accept that past practice is not the best way to go forward.

Nuclear Power was more expensive than forecast

“Our children will enjoy in their homes electrical energy too cheap to meter.”.

Rear Admiral Lewis Strauss, Chair, US Atomic Energy Commission, as reported in the NY Times, Sept. 17, 1954

Three Mile Island proved that nuclear power was safe for bystanders, but very dangerous for investors.  It may have been the worst nuclear accident to ever occur in the West, but nobody was hurt and there was no downstream radiation damage.  Under extreme and unpredicted stress, the containment held.

However, General Public Utilities Treasurer John Graham wrote in The Journal of Commercial Bank Lending, May 1980, ( in an article describing the re-financing of GPU after the TMI accident),

“The discussion of whether to recommend a moratorium on new nuclear plants in the Report by the President’s Commission on Three Mile Island is somewhat irrelevant.  I do not believe that there is a board of directors of an electric utility in the country which would now approve a nuclear plant as a new initiative.”.

A major revenue producing asset had become a major unfunded liability overnight.  Even if there were no casualties, no private sector utility could ever accept such a financial risk.

Across the U.S., nuclear stations faced huge cost over runs and long delays.  Utilities abandoned half finished nuclear facilities because of costs.  Performance targets were not met.  Maintenance costs were higher that expected.  Capacity factors were lower than expected.  Nuclear utilities came under financial pressure. 

In Ontario, the Darlington nuclear project had many delays. The cost of a new generating station is not reflected in the rate base until it is “commissioned”.  Before commissioning, interest on construction costs accumulates.  Delay adds to costs by increasing interest accumulated before start-up.  The longer it takes to build a station, the more it costs.  With a capital intensive technology with long lead times, such as nuclear power, this can be a lot of additional debt.

When the first Darlington unit was brought on line, important problems surfaced about rotor design (it cracked) and pump design (vibrations were shaking fuel bundles apart).  More delay, more costs.  For a brief period, concern was expressed inside Ontario Hydro that the entire project might have to be written off.

If there were any economies of scale in the modern electricity business, they have been overwhelmed by the long lead times and inflexible operations of the mega-projects. Forecasts of long term demand were unreliable.  This was a special problem for very large projects given the unpredictable construction times and costs.

History of Restructuring in Ontario

December 1989 - Ontario Hydro launched its 25-year Demand / Supply Plan (the DSP), to spend $60 billion, mostly on new nuclear plants.

January 1992 - Hydro announces the "Update" to the DSP - basically a repudiation of the original plan. 

February 1993 - the DSP is withdrawn from the Environmental Assessment Board. Hydro Chair Maurice Strong releases "Hydro 21", initiating the process of fundamental redesign of the Ontario electricity business.  The separation of generation from transmission is considered.

May 1996 - Report of the Macdonald Commission recommends a competitive electricity business.

August 1997 - Ontario Hydro releases the Andognini Report harshly critical of the management of Hydro's nuclear program. Hydro president Alan Kupcis resigns.  Hydro Chair William Farlinger criticizes Hydro’s “nuclear cult”.  Seven reactors (Pickering “A” and Bruce “A”) are scheduled to be "laid-up" so that Hydro can devote its resources to improve the operations of the remaining reactors. 

November 1997 - The provincial government releases "Directions for Change" that mandates the creation of "The Ontario Electricity Market Design Committee" to provide input for drafting new legislation.

Friday, February 13 1998 - First meeting of the MDC.  The MDC was a stakeholder body including representatives of generators (both Hydro and independents), transmitters, retail utilities (both large and small), consumers (large and small), marketers, gas suppliers, a coalition of environment groups, lawyers, and academics.  This pattern of stakeholder involvement has been a hallmark of the entire Ontario electricity design process.  The IMO Board and Technical panel (sets the Market Rules) are stakeholder bodies.

October 1998 – The Ontario government passes Bill 35 “The Energy Competition Act”.

April 1, 1999 – Launch of the successor companies to Ontario Hydro. Ontario Power Generation Incorporated (owns the generation assets – immediately dubbed OPiGI), Ontario Hydro Networks Corporation (owns the wires – quickly dubbed OiHNC – now called Hydro One), the Independent Market Operator – the IMO, Ontario Electricity Finance Corp (OEFC is a creature of the Ministry of Finance and manages the provincially guaranteed debt).

July 2000 – Government delays the start of the competitive market (original target - fall 2000).

May 2002 – The Market opens

December 2002 – The Market closes

The Ontario Electricity Business Before Restructuring

Ontario Hydro was a self-regulating Provincial Crown Corporation that had a legal monopoly on the generation and transmission of electricity in Ontario.  It was permitted to enter into Power Purchase Agreements with Non-Utility Generators (NUGs), but was under no obligation to do so. 

The physical system was controlled by the Clarkson Control System (now the Independent Electricity System Operator) west of Toronto.

The Local Distribution Companies (LDCs) served the end use customers.  The bulk of these were owned by the municipalities as Municipal Electrical Utilities (MEUs).  Ontario Hydro Retail served low density rural and remote communities

MEUs and industrial customers connected directly to the high voltage transmission system bought wholesale electricity from Ontario Hydro.  The MEUs retailed the electricity to consumers.  Ontario Hydro dictated both the wholesale and the retail price.  Hydro’s rate proposals could be reviewed by the Ontario Energy Board, but the OEB had no mandate other than to comment.

Ontario Hydro had very substantial debt resulting from its nuclear construction program.  That is perfectly normal for a large utility – Ontario Hydro was not exceptional.  In general, the greater a utility’s reliance on nuclear power, the greater the debt problems.  The MEUs were largely debt free at the start of restructuring.

The New Structure

On April 1, 1999, Ontario Hydro was split into “successor” companies.  The transmission system had always been the delivery asset of Ontario Hydro’s generation.  Its function was to serve the needs of the generators.  The single most import aspect of the new structure was the separation of the generation from the transmission and to open the possibility that other generators could use the transmission system to bring power to market.

Ontario Power Generation (briefly known as Ontario Power Generation Incorporated until people started calling it OPiGI) owns the generation assets of Ontario Hydro.  The transmission system is owned by Hydro One (once know as Ontario Hydro Networks, or Servco) that has a separate Board of Directors.

Both are wholly owned, provincial corporations, but they have been incorporated as businesses and given mandates to behave as if they were commercial companies.

What changed?

The Clarkson control centre became the Independent Market Operator (now the IESO).  It still controls the physical system. In addition, it administers the financial settlements system resembling a commodity or stock trading market that allows competitive electrical generation.

Under the monopoly, generation dispatch was set by Hydro’s maintenance outage schedule, internal management issues, and environmental limits.  When the market opens, dispatch order will be set by a bidding process (adjusted for transmission limits). 

The commodity price for wholesale electricity will be set in the market operated by the IMO.  To participate in the IMO controlled market, you need a licence from the OEB.  Participants can be generators, transmitters, distributors, or marketers.

The rates for transmission, distribution, and system operation will be expressed separately on customer bills and regulated by the OEB. 

The IMO Board of Directors represented the same stakeholders as the MDC.  The Market Rules for the IMO controlled market are set by the IMO Technical Panel (another stakeholder group).  Market Participant behaviour is supervised by the IMO Market Surveillance Panel.

There will also be retail competition.  Customers will be permitted to choose their electricity supplier.  Customers also have the right to ignore the market completely.  In this case their LDC will provide them with a standard offering.  This is the “smoothed spot pass through” – an average of the spot market price over a period of time. The LDC is also required to provide a billing and settlements system for the competitive retail market.

The LDCs are required to separate into non-competitive (regulated by the OEB – manages the wires, provides default supply, sends the bills) and competitive (un-regulated – provides fixed price contracts and other energy services such as hot water heaters and meters) companies. 

Finalizing LDC preparations for retail competition is an important factor in delaying the opening of the market.