Managing Regulated Customers in Albertas Retail Choice Environment
By Jim Joyce
On June 8th of this year, the Government of Alberta announced that beginning July 2006, a new 5-year Regulated Rate Option (RRO) would be put in place for residential, farm, and small commercial electricity customers in the province. Customers with loads above 250,000 Kw's are not eligible and must purchase their electricity from a competitive supplier.
Prior to this announcement, RRO tariffs were in place until June 30, 2006. Only 7% of the province's households have opted for a competitive rate, which means 93% of the province's eligible customers are purchasing their energy on the basis of the RRO. These RRO customers are primarily being served from 3 RRO Providers Enmax Energy (owned by the City of Calgary), EPCOR (owned by the City of Edmonton), and Direct Energy (a unit of Centrica PLC).
The RRO tariff must be approved by the Alberta Energy & Utilities Board (AEUB). In the past, the RRO providers have been encouraged to sit down with approved intervener groups and enter into a negotiated settlement on a process for acquiring hedges in a reasonable fashion that ensures consumers are not paying above-market prices. The key points negotiated were:
- the underlying load (demand) forecast and the assumptions that went into that load forecast;
- the type of hedges that need to be acquired (available hedges for the Alberta market are predominately financial but can include products that cover full-load, on-peak, off-peak and base-load volumes);
- the pricing of any residual risks after all of the hedges are acquired;
- the timing of any hedge implementation; and
- the maximum that the Utility can pay for a hedge (usually a formula-driven price using current market pricing as a guideline).
For 2005 and 2006, Alberta passed a law that stated the RRO tariff could not flow through spot electricity prices. This was meant to shield customers from the volatility of the spot market. The regulators interpreted that to mean that any costs of month-ahead hedges (or longer) can be put into rates, but anything shorter than month-ahead could not be put into rates. The RRO providers had a choice. They could buy block On-peak and Baseload hedges and have significant hourly mismatches between the hedges and load, or they could purchase a full-load hedge from the marketplace.
Recently, RiskAdvisory acted as an Independent Advisor to Enmax Energy and their interveners. The interveners included the Consumers Coalition of Alberta, the Utilities Consumer Advocate, and the Public Institutional Consumers of Alberta. As the Independent Advisor, RiskAdvisory provided the following services:
- Analyses for all parties on request;
- Sounding board for new ideas;
- Mediation during negotiation process;
- Negotiated Settlement documentation coordination;
- RFP coordination for any RFP required to obtain hedges;
- Review of quarterly rate applications; and
- Information provision of information requested by AEUB.
During the negotiation phase, the most contentious issue was how to price the residual load that is not covered by hedges. Since forward markets trade only in block products, and price discovery is non-existent at the hourly level, the parties had to determine how to price the hourly residual load in a fair manner. This had to include not only the cost of the energy, but also had to take into account a risk premium that the Utility should expect given that it has to carry a significant risk into the month.
In an effort to get the most efficient pricing, the parties agreed to hold a series of RFP's to purchase a Full-Load product from the marketplace. In essence, Enmax would acquire a fixed-for-floating swap from the market. The floating price would be the hourly Alberta market price as published by the Alberta Electric System Operator. The volume of the swap would change each hour and would be a percentage of the hourly load attributable to Enmax's Regulated Rate Customers.
The main concern voiced by all parties was liquidity of the product. Since the Alberta market is fairly illiquid, certain rules had to be established to ensure that Enmax did not pay an imprudent amount for this type of product. Certain parameters and rules for the RFP were agreed to in the negotiated settlement and RiskAdvisory was charged with following those rules when it conducted the RFP.
At the onset of the RFP, an Expression of Interest letter was sent to all known parties dealing in the Alberta marketplace. Since this was something of a new product for Alberta, we were unsure if the market had an appetite. We were extremely satisfied with the number of counterparties that expressed an interest, so the RFP went to the next stage which was to send historical data to all interested counterparties. The historical data gave the history of the actual Regulated Rate Load broken down into residential and commercial classes for the prior 3 years. Each potential counterparty was then forced to make assumptions on attrition, load growth, switching rates, etc., to determine what the future may look like.
After the counterparties had time to review the data, they were asked if they had any questions and to the best of Enmax's ability, those questions were answered in a timely manner. To Enmax's credit, they went above and beyond the call of duty to ensure that each counterparty's concerns was heard and dealt with in an appropriate manner. Much of the success of the RFP was the result of their actions.
Counterparties were all given the same contract which they agreed to sign if they won any volumes in the RFP. As can be expected, this raised some issues for counterparties and Enmax dealt with these as they arose. Certain credit features were built into the contract including margining terms and remedies in case of defaults. The goal was to have all counterparties agree to the same contract terms so that no single party got an advantage in the RFP. We wanted the RFP to be judged on price only, not a combination of price and contractual terms. After several negotiating sessions with lawyers from the various counterparties, a short-form ISDA type document was agreed upon.
The last stage of the RFP was actually holding the RFP. The RFP was broken into 2005 volumes and 2006 volumes. Counterparties were asked to respond by sending prices and associated volumes. Counterparties were able to put staggered bids into the RFP, but they had to bid a minimum 1.5% in each price tranche. The maximum volume in each price tranche was 100%. This meant that the possibility existed for a single counterparty to win 100% of the volume.
In the end, the RFP's had a significant number of responses and there were multiple parties who were given a piece of the volume. 100% of the volume for both years was taken up in the RFP. Prices came in below expectations and showed that the counterparties behaved in a commercially responsible manner and were able to price all of the risks associated with floating volumes in an extremely efficient manner. This resulted in significant savings for consumers within the City of Calgary on their power bills.
The RFP also gave some feedback to direct marketers who now had a reference benchmark price from which to provide power in a competitive market.
An agreement has yet to be reached on how to implement post-2006 RRO hedges, but it certainly seems that the marketplace has evolved enough to handle the intricacies that RRO load entails.
For more information concerning RFP coordination and negotiated settlements with consumer groups in your jurisdiction, please contact Leigh Parkinson of the RiskAdvisory consulting practice at (403) 263-7475 or lparkinson@riskadvisory.com .